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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, 1998
[ ] 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 62-1423071
(State or Other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
280 FORT SANDERS WEST BLVD., SUITE 200
KNOXVILLE, TENNESSEE 37922
(Address of Principal Executive Offices) (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. [ ]
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The Registrant's total revenues for the year ended December 31, 1998, were
$3,527,854.
As of March 24, 1999, the aggregate market value of the voting and non-
voting common equity held by non-affiliates of the Registrant was
approximately $15,265,904. This amount is based on the sale price of
$5.125 per share for the registrant's stock as of such date.
As of March 24, 1999, the Registrant had outstanding 4,019,308 shares of
Common Stock, no par value.
Portions of the Registrant's definitive proxy statement to be filed no
later than April 30, 1999 for the Registrant's annual meeting of
shareholders are incorporated by reference into Part III of this Report.
Transitional Small Business Disclosure Format (check one): Yes _____
No __X__
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PART I
ITEM 1. DESCRIPTION OF BUSINESS.
GENERAL.
Energy Search, Incorporated ("Energy Search" or the "Company") was
organized as a Tennessee corporation in 1990. The Company is 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 1998, 95% of the
Company's production was natural gas. Commencing in January 1997, the
Company shifted its focus from drilling primarily for Tennessee limited
partnerships which it sponsored ("Affiliated Drilling Partnerships") to
developing reserves for its own account. As a result of this shift, daily
net paid production for the Company averaged approximately 2.99 million
cubic feet equivalent per day ("MMcfed") in 1998, and currently exceeds 3.0
MMcfed. The Company drilled 20 gross wells in 1998 (19 net to the
Company), all of which were successfully completed. According to the 1998
year-end reserve report prepared by Wright & Company, the Company's
independent certified petroleum engineers, as of December 31, 1998 the
Company had proven natural gas reserves of 43.8 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 $30.8
million. Proven reserves have increased 42.3% for 1998 compared to the
amount reported for 1997 as a direct result of successful drilling and
acquisitions. SEC PV-10 proven reserve value has decreased 4.94% for 1998
compared to 1997 despite the increase in total reserves as a result of the
decrease in the price of the natural gas commodity. The Company's future
growth is anticipated to be driven by development, exploitation and
controlled exploration drilling on its existing properties and the
continuation of an opportunistic acquisition strategy in the Appalachian
Basin region. The Company drills primarily developmental wells and, on
occasion, step out or exploratory wells to develop new areas.
The Company's operations presently are focused 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. The Company currently enjoys 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 has
commanded a premium price relative to natural gas produced in areas such as
the Gulf Coast and Mid-Continent regions of the United States. In 1998,
the Company experienced an approximate 50<cent> per Mcf positive premium to the
NYMX Henry Hub quote.
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Throughout the 1990s, the Company averaged drilling of approximately 25 to
35 wells per year. Until February of 1997, substantially all of the
Company's wells were drilled in joint ventures with Affiliated Drilling
Partnerships which raised over $40.0 million in investor capital and were
syndicated primarily by the Company's affiliate, Equity Financial
Corporation ("EFC"), a member of the National Association of Securities
Dealers, Inc. ("NASD"). The Affiliated Drilling Partnerships participated
primarily in development drilling in Washington, Athens and Meigs Counties,
Ohio. The Company has drilled over 200 wells with Affiliated Drilling
Partnerships. In 1998, the Company sponsored only one Affiliated Drilling
Partnership which was capitalized with $120,000 in investor capital.
Management's business plan for the Company currently anticipates the
drilling of approximately 25 to 50 wells per year over the next five
years. This drilling is expected to be capitalized through additional
long-term debt, net cash flow, the proceeds of future equity offerings
and, to a limited extent, proceeds from the sponsorship of Affiliated
Drilling Partnerships. Management believes it can maintain the planned
level of drilling activity in the foreseeable future. Management plans to
continue drilling and development activities primarily for the Company's
own account which should enable the Company to expand its activities and
operations. This plan, management believes, should result in the continued
growth of the Company's proved natural gas and oil reserves, net cash flow
and shareholder value. As the Company's revenues and net cash flows grow,
the Company intends to expand its drilling activities and continue to
evaluate and execute natural gas and oil property acquisitions.
ACQUISITIONS IN 1998
In May of 1998, the Company acquired an approximately 24,000 acre lease in
Raleigh County, West Virginia to develop coalbed methane gas. Since May of
1998, the Company has leased approximately 8,000 additional acres for
coalbed methane development in this area. The leases were acquired at an
initial aggregate cost of approximately $165,000 and contain certain
drilling commitments. While at this time unproven, the Company's coalbed
methane leases are proximate to coalbed methane properties in southwestern
West Virginia currently being successfully exploited by other companies.
In June of 1998, the Company acquired 56 natural gas and oil wells together
with associated leasehold interests and equipment located in southeastern
Ohio from Viking Resources Corporation at a cost of $1,750,000. Since this
acquisition, the Company has begun remediating and increasing production
from the wells. Management believes these wells have additional
enhancement potential, as well as unexploited uphole reserves.
In a transaction completed in June of 1998, the Company acquired from
certain individuals the working interest and overriding royalty interest in
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various oil and natural gas wells located in southeastern Ohio. These
wells originally were drilled and operated by the Company for Affiliated
Drilling Partnerships. As consideration for these purchases, the Company
issued 10,114 shares of its common stock and paid $121,543 in cash.
In a transaction completed in September of 1998, the Company acquired from
the earliest five Affiliated Drilling Partnerships their working interests
in various natural gas and oil wells located in southeastern Ohio and
operated and owned jointly with the Company. As consideration for these
purchases, the Company issued 221,453 shares of its common stock and paid
$507,193 in cash.
BUSINESS STRATEGY
The Company's objective is to maximize shareholder value by growing
reserves, production, cash flow and earnings through active development of
its existing properties and through the opportunistic acquisition of
Appalachian properties with underexploited value. Fundamental to the
execution of the Company's strategy is its focus on the Appalachian Basin
region and its foundation of experienced technical personnel strengthened
by a high level of financial and transactional experience.
GEOGRAPHIC AND NATURAL GAS FOCUS. The Company focuses on natural gas in
the Appalachian Basin. Unlike many exploration and production companies,
the Company has concentrated on one region and is one of only a few
publicly traded pure Appalachian Basin natural gas producers. The Company
believes 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 and
premium pricing and economics. This geographic focus has enabled the
Company 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 is expected to continue to increase market share relative to
other fossil fuels due to its efficiency and its 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 and residential and commercial
heating. In addition, the Company believes 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.
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ACQUISITION OF PROPERTIES WITH UNDEREXPLOITED VALUE. The Company employs
an acquisition strategy of purchasing Appalachian Basin natural gas
properties from large independents 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. The Company uses its in-house landmen and network of
relationships in the region to discover acquisitions that are not widely
advertised. The Company also believes its standing and reputation in the
region have induced prospects to approach the Company for potential
acquisitions.
FOCUS ON DEVELOPMENT AND EXPLOITATION WITH CONTROLLED EXPLORATION. The
Company integrates its reservoir and production engineering expertise with
its geological interpretation abilities to enhance the results of its
exploration and production business. The Company's ability to integrate
geophysics with detailed geology, reservoir engineering and production
engineering allows it to identify multiple development and exploratory
prospects in mature producing fields that were not identified by previous
operators and to identify multiple horizon wells that have previously been
unexploited. The Company has 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 its
experience on these properties and on independent reports from its
petroleum engineers, the Company believes these properties may yield
significant additional recoverable reserves.
CONTROL OF OPERATIONS. The Company operates and maintains a majority
working interest position in each of its core properties. Consequently,
the Company can control directly all aspects of drilling, completion and
production. In addition, the Company intends to maintain a low cost
overhead structure by controlling the timing of the development of its
properties. By operating its producing wells, the Company believes it is
well positioned to control the expenses and timing of development and
exploitation of such properties and better manage cost reduction efforts.
INTEGRATION. In addition to maintaining operational control of drilling
activities, the Company operates and controls significantly all gas
gathering and pipeline systems throughout its fields through which its
production is delivered to market. The Company believes that through this
integration it has been able 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. The Company is actively examining additional integration
possibilities for transmission, gathering and marketing of natural gas to
continue this integration of its natural gas business.
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EMPLOYMENT OF TECHNOLOGY. The Company uses advanced technology in both its
development and exploration activities to reduce drilling risks and finding
costs and to prioritize its drilling prospects based on return potential.
Specifically, the Company uses GeoGraphix for determining well location,
mapping and possible viability of potential leases. GeoGraphix is one of
the top programs used for mapping reserve geology and overall reserve
evaluation. The Company also has a proprietary database of over 25,000
wells that has been integrated into GeoGraphix making the program a
powerful planning tool. The Company has spent years developing this
extensive proprietary database and has a full time employee dedicated to
accumulating and inputting data from its drilling experiences and from
public and other records to form this database.
MARKET FOR OIL AND NATURAL GAS
GENERAL. The revenues generated from the Company's oil and natural gas
operations are highly dependent upon the prices of and the demand for its
natural gas and oil production. In 1998, prices for both natural gas and
oil were significantly depressed. The prices received by the Company in
any year for its natural gas and oil production depend upon numerous
factors beyond the Company's 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 and domestic
government regulation, legislation and regulatory policies. Decreases in
the prices of natural gas and oil, as occurred in 1998, have an adverse
effect on the carrying value of the Company's proved reserves, and the
Company's revenues, profitability and cash flow.
Although the Company has not entered into any crude oil or natural gas
price swaps or other traditional hedging transactions for the purpose of
reducing its exposure to future price fluctuations, it does diversify its
natural gas sales contracts to provide the Company with a portfolio of
contracts including fixed rate contracts and variable price contracts.
This diversification lessens the volatility of the price experienced by the
Company. As of March 24, 1999 approximately 25% of the Company's natural
gas sale contracts are for a fixed price with the balance being on varying
index pricing.
Although the Company currently is not experiencing any involuntary
curtailments of its oil or natural gas production, market, economic and
regulatory factors in the future may materially affect the Company's
ability to sell its oil or natural gas production. Due to the availability
of other markets and pipeline connections, the Company does not believe
that the loss of any single oil or natural gas customer would have a
material adverse effect on the Company's results of operations.
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NATURAL GAS SALES. Natural gas produced from completed wells must be
transported through pipeline systems to get to market. In the Company's
primary fields of operations in southeastern Ohio substantially all the
Company's completed wells are connected to the Company's natural gas
gathering system (the "Ohio Gas Gathering System") which collects the
natural gas from wells in the field, sends it through compressor stations
to enhance transportability and delivers it to the East Ohio Company
interstate pipeline and to Columbia Gas Company interstate pipeline. Much
of the Ohio Gas Gathering System is owned by ESI Pipeline Operating L.P.,
an affiliate of the Company (the "Pipeline Operating Partnership"). The
Company, for its own account and on behalf of the Affiliated Drilling
Partnerships it manages, has entered into a gas servicing agreement (the
"Gas Servicing Agreement") with the Pipeline Operating Partnership pursuant
to which all natural gas produced from wells connected to the Ohio Gas
Gathering System is purchased by the Pipeline Operating Partnership and
subsequently resold. The price received by the Company for its natural gas
is a function of what the Pipeline Operating Partnership sells it for on
the market (i.e. the "Adjusted Gas Price Spread"). The Gas Servicing
Agreement thus provides for natural gas purchased from the Company and
Affiliated Drilling Partnerships on a "net back" basis. As of December 31,
1998, the Adjusted Gas Price Spread with respect to the Gas Servicing
Agreement was approximately 55<cent> per Mcf.
Natural gas produced from the Company's wells is sold by the Pipeline
Operating Partnership pursuant to one or more natural gas sales contracts
to natural gas marketers, interstate or intrastate pipelines, local
utilities or industrial end users in the Appalachian Basin. For the fiscal
year ended December 31, 1998, gross natural gas prices received by the
Company for its natural gas ranged from $1.64 to $3.98 per Mcf before
royalties and gathering and transportation costs.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its 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, little investigation of record title is made at the time of
acquisition (other than a preliminary review of local records).
Investigations, including a title opinion of legal counsel, generally are
made before commencement of drilling operations. To the extent title
opinions or other investigations reflect title defects, the Company, rather
than the mineral owner, typically is responsible to cure any such title
defects at the Company's expense. If the Company were unable to remedy or
cure title defect of a nature such that it would not be prudent to commence
drilling operations on the property, the Company could suffer a loss of its
entire investment in such property. The Company's properties are subject
to customary royalty, overriding royalty, carried, net profits, working and
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other similar interests, liens incident to operating agreements, liens for
current taxes and other burdens. In addition, the Company's credit
facility is secured by certain oil and natural gas interests and other
properties of the Company.
REGULATION AND ENVIRONMENTAL MATTERS
GENERAL REGULATION. Oil and natural gas exploration, production and
related operations are subject to extensive rules and regulations
promulgated by federal, state and local agencies. Failure to comply with
such rules and regulations can result in substantial penalties. The
regulatory burden on the oil and gas industry increases the Company's cost
of doing business and affects its profitability. Although the Company
believes it is in substantial compliance with all applicable laws and
regulations, because such rules and regulations frequently are amended or
interpreted, the Company is unable to predict the future cost or impact of
complying with such laws.
Environmental enforcement efforts with respect to natural gas and oil
operations recently have increased and it can be anticipated that such
regulation will expand and have a greater impact on future natural gas and
oil operations. There is no assurance that laws and regulations enacted in
the future will not adversely affect the Company's exploration for, and
production and transmission of, oil and natural gas. Such legislation
and/or actions of local, state and federal governments could have a
material adverse effect on the Company in the future. Management believes
that the Company has complied in all material respects with applicable
regulatory requirements of the states in which it operates. To date, the
Company has received no material notice of violation or complaint
concerning its compliance with federal, state or local laws respecting the
environment. There can be no assurance, however, that the Company's
business operations will not result in violations of environmental laws or
related liabilities 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 such wells. The statutes and regulations also
may limit the rate at which oil and gas can be produced from certain
properties. In Ohio and West Virginia, where most of the Company's natural
gas and oil properties are located, such regulation is by the Ohio
Department of Natural Resources and the West Virginia Division of
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Environmental Protection Office of Oil and Gas, respectively. Each of
these agencies has been granted broad regulatory and enforcement powers
which are likely to create additional financial and operational burdens on
natural gas and oil operations like those of the Company. Ohio and West
Virginia also have enacted other pollution and environmental control laws
which have become increasingly burdensome in recent years.
FEDERAL REGULATION. The Company's sales of natural gas are affected by the
availability, terms and cost of transportation. The price and terms for
access to pipeline transportation are subject to extensive regulation. The
Federal Energy Regulatory Commission ("FERC") regulates the transportation
and sale for resale of natural gas in interstate commerce pursuant to the
Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the
past, the federal government has regulated the prices at which oil and
natural gas can be sold. While sales by producers of natural gas and all
sales of oil and natural gas liquids currently can be made at uncontrolled
market prices, Congress could reenact price controls in the future.
In recent years, FERC has undertaken various initiatives to increase
competition within the natural gas industry. As a result of initiatives
like FERC Order 636, issued in April 1992 and its progeny, the interstate
natural gas transportation and marketing system has been substantially
restructured to remove various barriers and practices that historically
limited non-pipeline natural gas sellers, including producers, from
effectively competing with interstate pipelines for sales to local
distribution companies and large industrial and commercial customers. The
most significant provisions of Order No. 636 require that interstate
pipelines provide transportation separate or "unbundled" from their sales
service, and require that pipelines provide firm and interruptible
transportation service on an open access basis that is equal for all
natural gas supplies. In many instances, the result of Order No. 636 and
related initiatives has been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in
favor of providing only storage and transportation services. Although
Order No. 636 has largely been upheld on appeal, several appeals remain
pending in related restructuring proceedings. It is difficult to predict
when these remaining appeals will be completed or their impact on the
Company.
FERC 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 FERC
authorization to charge negotiated rates as one such alternative. In
February 1997, FERC announced a broad inquiry into issues facing the
natural gas industry to assist FERC in establishing regulatory goals and
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priorities in the post-Order No. 636 environment. While the changes being
considered by federal and state regulators would affect the Company 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, FERC, state commissions
and the courts. The natural gas industry historically has been very
heavily regulated; therefore, there is no assurance that the less stringent
regulatory approach recently pursued by FERC and Congress will continue.
The price the Company receives from the sale of oil and natural gas liquids
is affected by the cost of transporting products to markets. Effective
January 1, 1995, FERC implemented regulations establishing an indexing
system for transportation rates for oil pipelines, which, generally, would
index such rates to inflation, subject to certain conditions and
limitations. The Company is not able to predict with certainty the effect,
if any, of these regulations on its operations. However, the regulations
may increase transportation costs or reduce well head prices for oil and
natural gas liquids.
ENVIRONMENTAL REGULATION. The Company's operations and properties are
subject to extensive and changing federal, state and local laws and
regulations relating to environmental protection, including the generation,
storage, handling, emission, transportation and discharge of materials into
the environment, and relating to safety and health. The recent trend in
environmental legislation and regulation generally is toward stricter
standards, and this trend likely will continue. These laws and regulations
may 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; and impose substantial liabilities for pollution resulting
from the Company's operations. The permits required for various of the
Company's operations are subject to revocation, modification and renewal by
issuing authorities. Governmental authorities have the power to enforce
compliance with their regulations, and violators are subject to civil and
criminal penalties or injunction. Management believes that the Company is
in substantial compliance with current applicable environmental laws and
regulations, and that the Company has no material commitments for capital
expenditures to comply with existing environmental requirements.
Nevertheless, changes in existing environmental laws and regulations or in
interpretations thereof could have a significant impact on the Company, as
well as the oil and gas industry in general and thus the Company is unable
to predict the ultimate cost and effects of such continued compliance in
the future.
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The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA") and comparable state statutes impose strict, joint and several
liability on certain classes of persons who are considered to have
contributed to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of a disposal site or sites
where a release occurred and companies that disposed or arranged for the
disposal of the hazardous substances released at the site. Under CERCLA
such persons or companies may be liable for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for the neighboring
land owners and other third parties to file claims for personal injury,
property damage and recovery of response costs allegedly caused by the
hazardous substances released into the environment. The Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes govern
the disposal of "solid waste" and "hazardous waste" and authorize
imposition of substantial civil and criminal penalties for noncompliance.
Although CERCLA currently excludes petroleum from its definition of
"hazardous substance," state laws affecting the Company's operations impose
clean-up liability relating to petroleum and petroleum-related products.
In addition, although RCRA classifies certain oil field wastes as "non-
hazardous," such exploration and production wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent
handling and disposal requirements.
The Company has acquired leasehold interests in numerous properties that
for many years have produced oil and natural gas. Although the Company
believes that the previous owners of these interests used operating and
disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or
under the properties. In addition, most of the Company's properties are
operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes is not under the Company's control. These
properties and the wastes disposed thereon may be subject to CERCLA, RCRA
and analogous state laws. Notwithstanding the Company's lack of control
over properties operated by others, the failure of the operator to comply
with applicable environmental regulations may, in certain circumstances,
adversely impact the Company.
The Federal Clean Water Act and analogous state laws require permits to be
obtained to authorize discharge into surface waters or to construct
facilities in wetland areas. With respect to certain of its operations,
the Company is required to maintain such permits or meet general permit
requirements. The Environmental Protection Agency ("EPA") has adopted
regulations concerning discharges of storm water runoff. This program
requires covered facilities to obtain individual permits, participate in a
group or seek coverage under an EPA general permit. The Company believes
that it will be able to obtain, or be included under, such permits, where
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necessary, and to make minor modifications to existing facilities and
operations that would not have a material effect on the Company.
COMPETITION
The oil and natural gas industry is highly competitive in all of its
phases. The Company competes with many other companies in the search for
and acquisition of oil and natural gas properties and leases for
exploration and development, and also competes with other companies in its
activities as drilling contractor and natural gas marketers. The Company's
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 the Company and have been
engaged in the exploration and production business for a much longer time
than the Company. Such companies may be able to pay more for leases on oil
and natural gas properties and exploratory prospects, as well as to define,
evaluate, bid for or purchase a greater number of properties and prospects
than the Company's financial or human resources would permit. The Company
will be required to maintain and enhance its ability to conduct its
operations, to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Competition among oil
and gas companies for favorable oil and natural gas prospects can be
expected to continue. It is anticipated that the cost of acquiring oil and
natural gas properties may increase appreciably.
The Company competes with a number of other companies which offer interests
in drilling partnerships with a wide range of investment objectives and
program structures. Competition for investment capital for both public and
private drilling programs is intense.
OPERATING HAZARDS AND UNINSURED RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that
the Company will recover all or any portion of its 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. The
Company's drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, many of which are beyond the Company's control,
including title problems, weather conditions, compliance with governmental
requirements and shortages or delays in the delivery of equipment and
services. The Company's future drilling activities may not be successful
and, if unsuccessful, may have a material adverse effect on the Company's
future results of operations and financial condition.
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The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, craterings, pipeline ruptures and spills,
uncontrollable flows of oil, natural gas or well fluids, any of which can
result in the loss of hydrocarbons, environmental pollution, personal
injury claims and other damage to properties of the Company and others.
The Company maintains insurance against some but not necessarily all of the
risks described above. In particular, the insurance maintained by the
Company 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. The Company may elect to self-insure
if management believes that the cost of insurance, although available, is
excessive relative to the risks presented. In addition, pollution and
environmental risks generally are not fully insurable. The occurrence of
an event that is not covered, or not fully covered, by insurance could have
a material adverse effect on the Company's business, financial condition
and results of operations.
OFFICES AND EMPLOYEES
The Company's 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 the Company and its Affiliated Drilling Partnerships are
performed. The Company's main field office is located at 217 Second
Street, Marietta, Ohio. Geological, engineering and exploration and
production activities are coordinated from the Marietta office.
As of March 24, 1999, the Company had 20 full-time and three part-time
employees. As drilling production activities increase, the Company intends
to hire additional technical, operational and administrative personnel as
appropriate. None of the Company's employees are represented by any labor
union. The Company believes its relations with its employees are good.
From time to time, the Company uses 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. The Company believes that this use of third-
party service providers enhances its ability to contain general and
administrative expenses.
ACTIVITIES WITH AFFILIATED DRILLING PARTNERSHIPS
The Company operates approximately 110-miles of gas gathering systems
servicing its primary areas of operation in Ohio and West Virginia. A
-12-
<PAGE>
portion of the gas gathering systems (approximately 92 miles of pipeline)
is owned by a Tennessee limited partnership (the "Pipeline Operating
Partnership") which is comprised of the Company, as managing general
partner owning a 28.74% general partner interest, and a single limited
partner which is a Tennessee limited partnership (the "Pipeline Income
Partnership") for which the Company also serves as managing general
partner. The Pipeline Income Partnership was syndicated by EFC and
capitalized with investor funds raised in a private offering conducted in
1992 and 1993.
The Affiliated Drilling Partnerships have engaged in primarily development
drilling in southeastern Ohio and southern West Virginia. All of the
Affiliated Drilling Partnerships were structured in a similar fashion. The
Affiliated Drilling Partnerships typically enter into a joint venture with
the Company to drill and develop the wells (the "ADP Wells.") The joint
venture is evidenced by a joint drilling and operating agreement (the
"JDOA") between the Company, as participant, project manager and driller-
operator, and the Affiliated Drilling Partnership, as participant. Pursuant
to the JDOA, drillsites are selected by the Company from its lease
inventory. The Company is obligated to contribute drillsites to the joint
ventures evidenced by the JDOA for each Affiliated Drillings Partnership on
a drillsite-by-drillsite basis. No Affiliated Drilling Partnership has any
right to develop any acreage "proved up" by the drilling of a well on its
drillsite. The Company, as driller-operator, has discretion under the JDOA
to select the target geological formation and depth of the ADP Wells to be
drilled, and to make all operational decisions regarding drilling,
completion (if warranted) or plugging and abandonment of the ADP Wells.
ADP Wells are drilled on a "functional allocation" basis. Pursuant to this
arrangement, the Affiliated Drilling Partnership contributes to the joint
venture drilling funds for intangible drilling costs in exchange for direct
ownership of a working interest in the ADP Wells. The Company, on the
other hand, contributes the drillsite, tangible well equipment, excess
intangible drilling funds in the event of cost overruns and services in
exchange for direct ownership of a working interest in the ADP Wells. The
allocation of the percentage of the working interest owned between the
Affiliated Drilling Partnership and the Company varies somewhat from
program to program, but is generally based on the Company's estimate of the
relative value contributed. The Company's direct ownership of the working
interest of an ADP Well ranges in various Affiliate Drilling Partnerships
from approximately 7.0% to 20.0%. Under the JDOA, the Company, in its
capacity as driller-operator under the JDOA, agrees to drill and complete
(if warranted) or plug and abandon the ADP Wells on a "turnkey" basis for a
"fixed price" or "adjustable fixed price" (based on depth of the well and
number of zones stimulated). If actual well development costs exceed the
"turnkey price" or "adjustable turnkey price," the Company may experience a
loss on drilling operations. However, if actual drilling costs are less
-13-
<PAGE>
than the "turnkey price" or "adjustable turnkey price" received, the
Company may realize a profit. Typically under a JDOA, the drilling funds
are pre-paid to the Company, in its capacity as driller-operator, to allow
the Company the opportunity to inventory drill sites, maintain a field
office and line up drilling rigs, related equipment and crews.
After ADP Wells are drilled and completed in its primary field of
operations, a flow line is constructed and the well is hooked up to the
Company's gas gathering system so that natural gas produced from the wells
can be transported to market. The Company is responsible for managing all
production operations concerning the wells and the gas gathering system.
Such operations on the wells include equipment repairs and maintenance,
well swabbing, production chart reading, accounting and administration.
For performing such services, the Company generally receives a monthly,
per-producing-well "tending" fee, is reimbursed, generally at cost, for
equipment and generally charges standard rates for services provided to the
wells. With respect to the gas gathering system, the Company maintains and
repairs the equipment, monitors and reads gas meters, negotiates gas sales
contracts and otherwise manages the system. For performing these services,
the Company currently receives from the Pipeline Operating Partnership a
monthly fee and is reimbursed for materials, services and administrative
overhead contributed toward managing the system. The Company believes that
the monthly fee is adequate compensation for the services provided to the
Pipeline Operating Partnership. The Company, as the managing general
partner in the Pipeline Operating Partnership, maintains a 28.74% interest
in such partnership entitling it to 28.74% of the net revenues of the
Pipeline Operating Partnership. The remaining 71.26% interest in the
Pipeline Operating Partnership is owned by an affiliated limited
partnership (the "Pipeline Income Partnership") of which the Company serves
as general partner and owns a 3.5% interest.
After an ADP Well has been completed and produced, and when a well is no
longer capable of production in commercial quantities, the Company, as
operator under the JDOA, is responsible for plugging the well and restoring
the drillsite. Costs of plugging and restoration are shared by the
participants under a JDOA according to the particular agreement. The
Company's ownership interest in the wells results from, among other things,
its furnishing of the tangible well equipment. Accordingly, the Company is
responsible, under the JDOA, for paying reclamation costs allocable to such
tangible well equipment and is entitled to reclaim any salvageable tangible
well equipment.
ACTIVITIES OF EQUITY FINANCIAL CORPORATION
EFC, a wholly-owned subsidiary of the Company, is a securities brokerage
firm and member of the NASD. It is engaged primarily in the business of
providing investment services and products to its clients. Charles P.
-14-
<PAGE>
Torrey, Jr., Chief Executive Officer of the Company, and Robert L. Remine,
Chief Financial Officer of the Company, are each licensed agents and
principals of EFC. Messrs. Torrey and Remine founded EFC in 1985. EFC has
five additional licensed sales agents. EFC maintains offices adjacent to
the Company offices in Knoxville, Tennessee.
At times, EFC has served as placement agent for the private placement of
the Company's securities, including, common stock, preferred stock and
partnership interests in Affiliated Drilling Partnerships. For these
services, EFC has received placement fees and sales commissions. The
Company believes these fees and commissions are consistent with NASD
requirements and commensurate with what would be charged by unrelated firms
performing similar services.
ITEM 2. DESCRIPTION OF PROPERTY.
COMPANY OIL AND NATURAL GAS ASSETS
As of December 31, 1998, the Company partially owned and operated
approximately 468 gross wells (403.4 net) and partially owned and operated
approximately 110 miles of natural gas gathering systems. The Company has
144,948 gross acres (122,210 net) of oil and natural gas leases in Ohio and
West Virginia in the heart of the Appalachian Basin. For the year ended
December 31, 1998, the Company had net average daily paid production of
approximately 2.99 MMcfed. As of the date of this Form 10-KSB, the
Company's gross production of natural gas exceeded 3.0 MMcfed.
Following is a general summary of the Company's primary natural gas and oil
assets.
The Company acquired approximately 17,000 lease acres (the "Beaver Lease")
in Raleigh County, West Virginia on which the Company has drilled 28 wells.
The Company plans to continue drilling the Beaver Lease for its own account
and to exploit other similar opportunities in the area. The Company also
has production on approximately 1,700 additional acres in Wood, Gilmer and
Ritchie Counties, West Virginia.
In 1998 the Company acquired approximately 32,000 lease acres on which to
develop coalbed methane gas in Raleigh County, West Virginia. The Company
has not commenced drilling of these leases to date. However, permits have
been issued and the Company anticipates drilling 5 to 10 coalbed methane
wells to meet minimum drilling obligations in 1999.
The Company acquired lease acres on which to drill natural gas and oil
wells on approximately 60,000 acres of mostly contiguous property located
in Fayette and Raleigh Counties, West Virginia. The Company acquired the
drilling rights in December 1998 and has not yet commenced drilling
-15-
<PAGE>
activities. The lease agreement contains a minimum drilling commitment to
maintain the lease and the Company plans to drill the initial two wells to
meet the current commitment on this lease in March of 1999.
The Company acquired a variety of leases in southeastern Ohio. The leases
consist of what the Company calls "fields," for example the Simmons field
(the "Simmons Field"), comprised of approximately 9,000 acres of oil and
natural gas properties, the Bartlett, Torch and Churchtown fields, all of
which are accumulations of many small lease tracts from individual owners
into relatively contiguous field operation areas, and the Viking field,
which is an accumulation of approximate 2,000 acres (the "Viking Field").
All of these areas are located in Washington, Athens, Morgan and Meigs
Counties, Ohio.
GAS GATHERING SYSTEMS. Throughout its various fields of operation in Ohio
and West Virginia, the Company partially owns and operates approximately
110-miles of pipeline and natural gas gathering systems of which
approximately 92 miles are owned by the Pipeline Operating Partnership.
Substantially all wells drilled and completed by the Company are connected
to these natural gas gathering systems which collects the natural gas from
the wells, sends it through one or more compressor stations to enhance
transportability and delivers it to interstate pipeline carriers.
OIL AND NATURAL GAS RESERVES
The Company's oil and natural gas reserves are located in Ohio and West
Virginia. Proved reserves represent estimated quantities of crude oil and
natural gas which geological and engineering data demonstrate to be
reasonably certain to be recoverable in the future from known reservoirs
under existing economic and operating conditions. Proved developed oil and
natural gas reserves are proved reserves that can be expected to be
recovered through existing wells using existing equipment and operating
methods. Proved undeveloped reserves are proved reserves expected to be
recovered from new wells on undrilled acreage, or from existing wells at
depths below the present bottom of the wells.
The following table summarizes information with respect to the estimated
net proved oil and natural gas reserves as reviewed, evaluated and
certified by the independent engineers and/or a geologist attributable to
the Company's interests in oil and natural gas properties as of December
31, 1998, 1997 and 1996. The year-end reserve report for December 31, 1996
was prepared by Kim A. Walbe, independent certified geologist. The year-
end reserve reports for December 31, 1997 and December 31, 1998 were
prepared by Wright & Company, Inc., independent certified petroleum
engineers.
-16-
<PAGE>
The reserve amounts in the following tables represent well interests and
reserves directly owned 100% by the Company. While the Company and
Affiliated Drilling Partnerships may each own separate percentages of the
entire working interest in certain wells, their respective percentage
ownership is separate and direct. No reserves included as owned by the
Company are owned indirectly through any Affiliated Drilling Partnership.
<TABLE>
TOTAL ESTIMATED NET RESERVE QUANTITIES
<CAPTION>
AT DECEMBER 31,
----------------------------------------------------------------
1998 1997 1996
-------------- -------------- -------------
COMPANY - TOTAL
- ---------------
<S> <C> <C> <C>
Total Proved Reserves:<F1>
Oil (Bbls) 44,554 23,624 16,736
Natural Gas (Mcf) 43,493,054 30,609,977 15,692,300
Equivalent Bbls (BOE)<F2> 7,293,396 5,125,287 2,632,120
Equivalent Mcf (Mcfe)<F2> 43,760,378 30,751,721 15,792,716
Total Proved Undeveloped Reserves:<F1>
Oil (Bbls) -- -- 11
Natural Gas (Mcf)<F2> 27,502,100 19,417,960 14,543,536
Equivalent Bbls (BOE)<F2> 4,583,683 3,236,327 2,423,934
Equivalent Mcf (Mcfe)<F2> 27,502,100 19,417,960 14,543,602
Total Proved Developed Reserves:<F1>
Oil (Bbls) 44,554 23,624 16,725
Natural Gas (Mcf) 15,990,954 11,192,017 1,148,764
Equivalent Bbls (BOE)<F2> 2,709,713 1,888,960 208,186
Equivalent Mcf (Mcfe)<F2> 16,258,278 11,333,761 1,249,114
- ---------------------
<FN>
<F1> Reserves are net to the Company's interest. Applicable royalties have
been deducted from these volumes.
<F2> After conversion on the basis of 6.0 Mcf of natural gas to 1.0 barrel
of crude oil.
</FN>
</TABLE>
The Company's estimated proved reserves have not been filed with or
included in reports to any federal agency.
-17-
<PAGE>
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 the proved developed producing, proved developed
non-producing and proved undeveloped reserves of the Company.
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 $9.00 per barrel of oil and $2.80 per Mcf of
natural gas. For the fiscal year ended December 31, 1998, gross natural gas
prices received by the Company for its natural gas ranged from $1.64 to
$3.98 per Mcf before royalties and gathering and transportation costs.
<TABLE>
ESTIMATED DISCOUNTED PRESENT VALUE OF FUTURE NET CASH FLOWS
FROM PROVED OIL AND NATURAL AS RESERVES
<CAPTION>
AT DECEMBER 31,
--------------------------------------------------------------
1998 1997 1996
------------ ----------- -----------
COMPANY - TOTAL
- ---------------
<S> <C> <C> <C>
Proved Developed Producing
Oil (Bbl) 44,554 23,624 13,859
Natural Gas (Mcf) 14,589,660 7,475,526 943,584
Proved Developed Non-Producing
Oil (Bbl) -- -- 2,866
Natural Gas (Mcf) 1,401,294 3,716,491 205,180
Proved Undeveloped
Oil (Bbl) -- -- 11
Natural Gas (Mcf) 27,502,100 19,417,960 14,543,536
Estimated Future Net Cash Flows
Before Income Taxes
Proved Producing $30,863,380 $20,212,160 $ 2,356,125
Proved Non-Producing 2,452,715 9,575,898 362,073
Proved Undeveloped 44,136,160 41,354,112 33,605,186
----------- ----------- -----------
Total $77,452,255 $71,142,170 $36,323,384
=========== =========== ===========
-18-
<PAGE>
Estimated Future Net Cash Flows
Before Income Taxes Discounted at 10%
Proved Producing $15,852,520 $ 9,703,797 $ 1,434,504
Proved Non-Producing 876,363 4,748,113 227,129
Proved Undeveloped 14,032,700 17,909,290 19,665,164
----------- ------------ -----------
Total $30,761,583 $32,361,200 $21,326,797
=========== =========== ===========
</TABLE>
For additional information concerning the discounted future net cash flows
to be derived from the Company's reserves, see the Supplemental Information
to Consolidated Financial Statements incorporated herein.
In accordance with applicable requirements of the Securities and Exchange
Commission, estimates of the Company's proved reserves and future cash
flows are made using sales prices estimated to be in effect as of the date
of such 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 meaningfulness of such estimates is 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 subsequent to the date of
such estimate. Accordingly, reserve estimates are often different from the
quantities of oil and natural gas that are ultimately recovered. While the
Company believes that reserve estimates presented in this Form 10-KSB are
reasonable, the estimates should be viewed with the understanding that
subsequent reservoir performance, the timing and success of future
development drilling and changes in pricing structure or market demand will
affect the reserve estimates.
In general, the volume of production from oil and gas properties declines
as reserves are depleted. Except to the extent the Company acquires
properties containing proven reserves or conducts successful exploration
and development activities, or both, the proven reserves of the Company
-19-
<PAGE>
will decline as reserves are produced. The Company's future oil and
natural gas production is, therefore, highly dependent upon its level of
success in acquiring or developing additional reserves.
PRODUCING WELLS
The following table sets forth certain information regarding the Company's
ownership, as of December 31, 1998, of productive wells in Ohio and West
Virginia. For purposes of this table, productive wells are producing wells
and wells capable of production. A gross well is a well in which a working
interest is owned by the Company. The number of gross wells is the total
number of wells in which the Company owns a working interest. A net well
is deemed 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 owned by the Company in gross wells expressed
as whole numbers and fractions thereof.
The well amounts in the tables below represent well interests directly
owned 100% by the Company. While the Company and Affiliated Drilling
Partnerships may each own separate percentages of the entire working
interest in certain wells, their respective percentage ownership is
separate and direct. No well interests included as owned by the Company
are owned indirectly through any Affiliated Drilling Partnership.
<TABLE>
PRODUCTIVE WELL SUMMARY
<CAPTION>
OIL NATURAL GAS TOTAL
--------------------- ----------------------- ----------------
REGION GROSS NET GROSS<F1> NET GROSS NET
------ ------- ----- --------- ----- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Ohio 9 5.7 414 363.9 423 369.6
West Virginia 1 1.0 44 32.8 45 33.8
-- --- --- ----- --- -----
Total 10 6.7 458 396.7 468 403.4
== === === ===== === =====
- --------------------------------
<FN>
<F1> Of the wells reported, 304 gross wells had multiple completions or
were producing from more than one geological formation.
</FN>
</TABLE>
-20-
<PAGE>
PRODUCTION VOLUMES, AVERAGE PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes of, average sales prices received for, and average production costs
associated with, the Company's sales of oil and natural gas for the periods
indicated.
<TABLE>
<CAPTION>
AT DECEMBER 31,
-----------------------------------------------------------------
1998 1997 1996
-------------- -------------- ------------
<S> <C> <C> <C>
NET PRODUCTION:
Oil (Bbls) 7,859 1,158 957
Natural Gas (Mcf) 1,045,201 321,264 109,120
Total (BOE) 182,059 54,702 19,144
Total (Mcfe) 1,092,355 328,212 114,862
AVERAGE SALES PRICE:
Oil ($/Bbl) $11.74 $18.06 $19.41
Natural Gas ($/Mcf) 2.41 2.43 2.48
AVERAGE PRODUCTION LIFTING COST:
($/Mcfe) <F1> $.61 $.84 $1.49
- --------------------
<FN>
<F1> Includes direct lifting costs (labor, repairs and maintenance,
materials and supplies) and property and severance taxes.
</FN>
</TABLE>
The production volumes set forth in the table above reflect net production
volumes from Company 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 set
forth in the Company's Consolidated Statement of Operations 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 the
Company's account (excluding revenues payable to landowner and overriding
royalty interests).
The information presented in the above tables for 1997 and 1996 has been
adjusted to be consistent with the current year presentation.
-21-
<PAGE>
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities on its Ohio and West Virginia properties during the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------
1998 1997 1996
-------------- -------------- --------------
<S> <C> <C> <C>
Development Costs $ 6,607,991 $ 5,683,356 $ 1,066,814
Exploration Costs 218,369 84,616 288,376
Property Acquisition Costs 4,560,556 1,535,173 72,640
</TABLE>
RECENT DRILLING ACTIVITIES
The Company has drilled or participated in the drilling of wells in its
Ohio and West Virginia properties as set out in the table below for the
periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
1998 1997 1996
-------------------- -------------------- -----------------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
OHIO
- ----
DEVELOPMENT WELLS
Oil 0 0 0.0 0.0 0.0 0.0
Natural Gas 16 15.7 8.0 3.8 17.0 3.5
Dry 0 0 0.0 0.0 1.0 0.2
-- ---- ---- ---- ---- ----
Total 16 15.7 8.0 3.8 18.0 3.7
-22-
<PAGE>
EXPLORATORY WELLS
Oil 0 0 0.0 0.0 0.0 0.0
Natural Gas 0 0 1.0 0.1 1.0 0.1
Dry 0 0 0 0.0 0.0 0.0
-- ---- ---- ---- ---- ----
Total 0 0 1.0 0.1 1.0 0.1
WEST VIRGINIA
- -------------
DEVELOPMENT WELLS
Oil 0 0 0.0 0.0 0.0 0.0
Natural Gas 4 4 24.0 20.1 4.0 0.8
Dry 0 0 3.0 3.0 0.0 0.0
-- ---- ---- ---- ---- ----
Total 4 4 27.0 23.1 4.0 0.8
EXPLORATORY WELLS
Oil 0 0 0.0 0.0 0.0 0.0
Natural Gas 0 0 1.0 1.0 0.0 0.0
Dry 0 0 0.0 0.0 0.0 0.0
-- ---- ---- ---- ---- ----
Total 0 0 1.0 1.0 0.0 0.0
</TABLE>
As of March 24, 1999, the Company was in the process of drilling one well
in southeastern Ohio, and was preparing several locations for drilling in
Ohio and West Virginia.
OIL AND NATURAL GAS LEASES
LEASEHOLD ACREAGE. As of December 31, 1998, the Company owned or
controlled oil and natural gas leasehold acres located in Washington,
Athens, Meigs and Morgan Counties, Ohio, and in Gilmer, Ritchie, Wood and
Raleigh Counties, West Virginia, and coalbed methane leasehold acreage in
Fayette and Raleigh Counties, West Virginia.
The following table sets forth certain information regarding the Company's
developed and undeveloped leasehold acreage as of December 31, 1998.
-23-
<PAGE>
<TABLE>
LEASEHOLD ACREAGE
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
------------------- --------------------- ------------------------
REGION GROSS NET GROSS NET GROSS NET
- ------ ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Ohio 29,369 17,064 4,359 4,359 33,728 21,423
West Virginia 18,766 14,093 92,454 86,694 111,220 100,787
------ ------ ------- ------ ------- -------
Total 48,135 31,157 96,813 91,053 144,948 122,210
====== ====== ======= ====== ======= =======
</TABLE>
For purposes of this above table, Developed Acreage is defined as acreage
that is held by existing production, has no further drilling obligations or
delay rentals due and embodies, in its aggregate, off setting drilling
locations.
Substantially all of the Company's 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 7.5%. Thus,
the net revenue interest of the Company's Ohio and West Virginia leases
generally ranges from 87.5% to 80.0%.
ITEM 3. LEGAL PROCEEDINGS.
Neither the Company, its properties, nor any of its directors or officers,
is involved in any material litigation or administrative proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
During the fourth quarter of 1998, no matter was submitted 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.
The Company's common stock is quoted on the Nasdaq SmallCap Market under
the ticker symbol "EGAS."
On June 17, 1998, the Board of Directors authorized the Company to
repurchase up to a total of 100,000 shares of its Common Stock in open
-24-
<PAGE>
market transactions if management deemed it prudent to do so. The Company
has not repurchased any shares through December 31, 1998. Repurchase of
common stock is contingent upon market conditions. The Company has set
June 17, 1999 as the expiration date for the repurchase program. No share
purchases are contemplated at this time.
The following table sets forth the high and low sale prices for the
Company's common stock for the periods indicated, all as reported by the
Nasdaq SmallCap Market:
<TABLE>
<CAPTION>
HIGH LOW
---- ---
<S> <C> <C> <C>
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
Year Ended December 31, 1997:
First Quarter . . . . . . . . . . . . . . . . . . $ -- $ --
Second Quarter. . . . . . . . . . . . . . . . . . 9.81 6.75
Third Quarter . . . . . . . . . . . . . . . . . . 9.25 8.00
Fourth Quarter. . . . . . . . . . . . . . . . . . 11.50 8.00
</TABLE>
The estimated number of holders of common stock of the Company was
approximately 1,600 as of March 24, 1999.
The Company has not paid any dividends on its common stock and currently
intends to retain earnings for the future operation and development of its
use in its business. Therefore, the Company does not expect to declare
cash dividends in the foreseeable future.
In August of 1998, the Company initiated a private placement offering of up
to 700,000 shares of 9% redeemable convertible preferred stock at an issue
price of $7.50 per share. In November of 1998, the offering was amended to
offer up to 800,000 shares of preferred stock at an issue price of $6.50,
subject to downward adjustment if the price of the Company's common stock
closed at less than $6.50 per share as of the termination of the offering.
The offering was terminated on December 18, 1998, and the issue price of
the preferred stock was adjusted to $5.50 per share to reflect the closing
price of the Company's common stock as of such date. The Company raised
$847,707, net of issue costs of $117,793, and sold 175,547 shares of
preferred stock under the offering.
-25-
<PAGE>
The shares of 9% redeemable convertible preferred stock have a liquidation
and dividend preference over the Company's 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. The preferred
stock automatically will convert to common stock if the Company is acquired
or is the subject of a business combination in which substantially all
assets of the Company are acquired by unaffiliated purchasers or greater
that 50% of the outstanding beneficial interest of the Company's common
stock is acquired by unaffiliated purchasers ("Business Combination").
The holders of the shares of preferred stock may require the Company to
redeem the preferred stock if, at any time before October 1, 1999, the
Company publicly announces that it will be acquired or is the subject of a
Business Combination. The redemption price in such an event will be 100%
of the issue price of the preferred stock plus accrued and unpaid
dividends.
The shares of preferred stock are redeemable at the sole option of the
Company at any time after September 30, 1999, provided the average trading
closing price for the Company's common stock exceeds 130% of the original
issue price of the preferred stock over any five consecutive trading day
period commencing 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. The Company will provide the holders of
preferred stock 30 days written notice of its intent to redeem the
preferred stock during which time the holders of preferred stock may, at
their option, convert their preferred stock to common stock.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION.
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
1995
This discussion and analysis of financial condition and results of
operations, and other sections of this Form 10-KSB, contain forward-looking
statements that are based on management's beliefs, assumptions, current
expectations, estimates and projections about the oil and gas industry, the
economy and about the Company itself. Words such as "anticipates,"
"believes," "estimates," "expects," "forecasts," "intends," "is likely,"
"plans," "predicts," "projects," variations of such words and similar
expressions are intended to identify such forward-looking statements.
These statements are not guarantees of future performance and involve
certain risks, uncertainties and assumptions that are difficult to predict
with regard to timing, extent, likelihood and degree of occurrence.
Therefore, actual results and outcomes may materially differ from what may
be expressed or forecasted in such forward-looking statements.
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Furthermore, the Company undertakes no obligation to update, amend or
clarify forward-looking statements, whether as a result of new information,
future events or otherwise.
Important factors that could cause actual results to differ materially from
the forward-looking statements include, but are not limited to, changes in
production volumes, worldwide demand and commodity prices for petroleum
natural resources; the timing and extent of the Company's success in
discovering, acquiring, developing and producing natural gas and oil
reserves; risks incident to the drilling and operation of natural gas and
oil wells; future production and development costs; the effect of existing
and future laws, governmental regulations and the political and economic
climate of the United States; the effect of hedging activities; conditions
in the capital markets; and the effects of the Year 2000 issues on the
Company's business. Other risks are discussed elsewhere in this Form 10-
KSB, including those risks described under the headings "Description of
Business--Market for Oil and Gas," "--Regulation and Environmental Matters"
and "--Operating Hazards and Uninsured Risks."
OVERVIEW
The Company is 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. Since
its inception, the Company has drilled over 200 wells in the Appalachian
Basin with more than a 90% completion rate. The Company initially drilled
wells primarily for Affiliated Drilling Partnerships retaining only a small
portion of each for the Company. During the last two years since going
public, the Company has grown primarily through opportunistic acquisitions
of Appalachian properties for its own account and the subsequent drilling
development, exploitation and exploration of these properties, resulting in
significant increases in its reserves and production. In 1998, 95% of the
Company's production was natural gas. In January 1997, the Company shifted
its focus from being primarily a driller-operator for limited partnerships
in which it took a small working interest to an independent energy company
developing reserves for its own account. Daily net paid production for 1998
was approximately 2.99 MMcfed. The Company drilled 20 gross wells in 1998
(19 net to the Company), of which all were successfully completed.
According to the year-end reserve report prepared by the Company's
independent certified petroleum engineers, Wright & Company, the Company as
of December 31, 1998 had proven natural gas reserves of approximately 43.8
Bcfe with a SEC PV-10 of approximately $30.8 million. Proven reserves have
increased 42.3% for 1998 compared to the amount reported for 1997 as a
direct result of successful drilling and acquisitions. SEC PV-10 proven
reserve value has decreased 4.94% in 1998 compared to 1997 despite the
increase in total reserves as a result of the decrease in the price of the
natural gas commodity.
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The Company's future growth is expected to be driven by development,
exploitation and controlled exploration drilling on its existing properties
and the continuation of an opportunistic acquisition strategy in the
Appalachian Basin region. The Company has over 150 developmental well
sites to drill on its existing leasehold acreage. All of these sites are
located in fields with established production histories.
In December 1998, the Company competed the private placement of 175,547
shares of 9% redeemable convertible preferred stock of the Company at a
price of $5.50 per share. Net offering proceeds were $847,707. See
"Market For Common Equity and Related Stockholder Matters" for a
description of the terms of the preferred stock.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO THE YEAR ENDED DECEMBER 31, 1997
FINANCIAL CONDITION
Total assets increased $8,902,709 or 55.2% from December 31, 1997 to
December 31, 1998 primarily due to a $10,563,876 net increase in oil and
gas properties and after an offsetting decrease of $1,653,195 in current
assets.
Current assets for the year ended December 31, 1998 decreased $1,653,195 to
$1,666,856, or a 49.8% decrease compared to current assets for the year
ended December 31, 1997. The decrease in current assets is due primarily
to a decrease in cash of $1,656,567 to $595,749 or 73.5% for the year
ended December 31, 1998. This is due to the Company's continued
expenditures of cash for drilling and development of wells in its Beaver
Lease and Churchtown lease areas as well as enhancement efforts and
development of wells in its Simmons Field and Viking Field. See "--Cash
Flow from Operations, Investing and Financing Activities" for further
discussion.
Oil and gas properties for the year ended December 31, 1998 increased
$10,563,876 to $20,264,760 or 108.9% from the amount reported at December
31, 1997. The increase is primarily a result of continued successful
drilling activity for the Company's own account, and the acquisition by the
Company of oil and gas lease interests in proven properties.
The Company increased capital expenditures for drilling and well related
equipment from December 31, 1997 to December 31, 1998 in the amount of
$3,256,434. The increase is primarily a result of increased Company
drilling and the acquisition of oil and gas equipment of approximately
$980,000 from Viking Resources Corporation in June of 1998.
Proven properties increased $8,619,025 to $13,165,858 or 189.6% from the
amount reported at December 31, 1997. The increase is primarily due to the
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acquisition by the Company of oil and gas leases interests in proven
properties and the capitalization of intangible drilling costs
(approximately $5,031,559) associated with the Company drilled wells. In
May 1998, the Company acquired from certain individuals the working
interest and overriding royalty interest in certain natural gas wells
operated by the Company in southeastern Ohio. The total purchase
consideration for the well interests was $227,740 comprised of $106,197
(10,114 shares) in Company common stock and $121,543 in cash. In June
1998, the Company purchased approximately $773,000 in proven properties
from Viking Resources Corporation. In the third quarter of 1998, the
Company purchased all of the working interests in a total of 145 gross
natural gas or oil wells located in southeastern Ohio in consideration for
cash and Company common stock. The aggregate purchase price was $2,223,941
comprised of $1,716,748 in Company common stock (221,453 shares) and
$507,193 in cash.
Total liabilities increased $6,708,242 or 308.5% from December 31, 1997 to
December 31, 1998, due primarily to an increase in long-term debt of
$7,565,774. See "--Liquidity & Capital Resources" for further discussion.
This increase in long-term debt was used primarily to fund the drilling,
development and enhancement efforts on Company wells described above, as
well as for acquisitions of oil and gas properties. Current liabilities
decreased $857,532 to $1,179,084 or 42.1% from December 31, 1997 to
December 31, 1998 primarily due to a decrease in accounts payable and
accrued expenses of $724,071 to $632,677 at December 31, 1998, a decrease
of 53.4%.
RESULTS OF OPERATIONS
For the year ended December 31, 1998, the Company had a net loss after tax
of $394,428, compared to net loss after tax of $367,281 for the year ended
December 31, 1997.
For the year ended December 31, 1998, total net revenues increased
$1,187,828 or 53.2% from $2,232,670 to $3,420,498 for the same period in
1997 due primarily to an increase in oil and gas revenue, and after an
offsetting decrease in turnkey revenue, management fees and other revenue.
For the year ended December 31, 1998, net turnkey revenue decreased
$408,624 or 85.9% as compared to the amounts reported for the year ended
December 31, 1997. Net turnkey revenue is drilling profit recognized upon
the drilling to total depth of wells in Affiliated Drilling Partnerships.
The Company drilled to total depth 12 gross wells attributable to
Affiliated Drilling Partnerships for which turnkey revenues were recognized
for the 12 months ended December 31, 1997. In 1998, the Company drilled to
total depth and recognized revenue for only one gross well for the 1998
Affiliated Drilling Partnership. This is a decrease of 11 gross wells for
the year ending December 31, 1998.
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Oil and gas revenue increased $1,798,919 to $2,597,875 for the year ended
December 31, 1998, an increase of 225.2% over that reported as of December
31, 1997. This increase is consistent with the Company's changing focus to
drilling wells for its own account. The increase in oil and gas revenue
is a result of the higher number of wells drilled for the Company's own
account, the purchase of proven producing properties from Lomak and Viking
Resources Corporation in November 1997 and May 1998, respectively, and the
purchase of working interests and overriding royalty interests in the third
quarter of 1998, all resulting in increased production and revenues. Net
paid production increased from approximately 0.9 MMcfed in 1997 to
approximately 3.0 MMcfed in 1998. The Company has concluded that certain
of the wells it initially drilled on the Beaver Lease are in need of
substantial remediation to achieve desired rates of production. The
remediation project is in the process of being designed and is expected to
commence in the later part of 1999 if capital funds become available. The
cost of the remediation project is not yet known.
Management anticipates continued growth in oil and gas revenues; however,
management does not expect the growth to continue at the same high levels
reflected in 1998. The continued growth of the Company's oil and gas
revenues and reserves will be dependent on future drilling success, capital
raising efforts and the pricing of the Company's primary commodity product,
natural gas.
Management fees for the year ended December 31, 1998, decreased $119,004 to
$145,586, a decrease of 45.0% over that reported as of December 31, 1997.
This decrease is result of the purchase of the working interests owned by
Affiliated Drilling Partnerships discussed earlier and the reduction in the
management fee charged to the Pipeline Operating L.P. from $5,000 per month
in 1997 to $2,500 per month in 1998. This decrease in management fees is
expected to continue.
Other revenue decreased $83,463 for the year ended December 31, 1998, a
decrease of 12.0% over that reported for the same period in 1997. This
decrease is due primarily to a decrease in the gross operating commission
revenue earned by EFC of approximately $32,465 to $463,666, a decrease of
7.0% over that reported for the same period in 1997. EFC has been a
profitable segment of the Company's operation. For the year ended December
31, 1998, EFC had a net loss of approximately $7,000. The Company expects
EFC to be marginally profitable in 1999. If EFC is not profitable at year
end 1999, management will evaluate the continued viability of EFC. See
"Description of Business--Activities of Equity Financial Corporation" for
further discussion of EFC. Interest income decreased approximately
$116,298 due to the decrease in the Company's cash balances, and
transportation revenue increased approximately $82,173 due to increased
production and transportation rates.
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Total operating expenses increased $1,134,599 or 40.1% for the year ended
December 31, 1998 over the year ended December 31, 1997. This increase is
due primarily to an increase in production expenses associated with the
larger number of wells now operated of $386,465 or 140.8%, an increase in
exploration costs associated with increased drilling of $125,908 or 163.9%,
and an increase in depreciation, depletion and amortization expense
associated with the larger number of net wells now owned by the Company of
$994,518 or 178.5%. These increases are due to the increase in Company
owned and operated wells as discussed above.
General and administrative (G&A) expenses decreased $659,273 to $1,156,890
or 36.3% for the year ended December 31, 1998. This net decrease is
primarily a result of the change in business plan of the Company to drill
primarily for the account of the Company. Certain costs directly related
to drilling of Company wells have been included in the cost of oil and gas
properties. An offsetting increase in G&A expenses is due primarily to the
inclusion of EFC's G&A of approximately $464,758 into the G&A costs of the
Company, an increase in expense of $62,313 over that reported for the same
period in 1997.
Other income and expense changed from a net income of $48,195 for the year
ended December 31, 1997 to a net expense of $85,481 for the year ended
December 31, 1998. The change is primarily a result of an increase in
program reimbursements of $112,453. This cost fluctuates based on
production of partnership wells for which the Company is the managing
general partner and, absent successful remediation efforts, will continue
at a similar amount during 1999. The Company is evaluating the cost
effectiveness of these remediation efforts.
CASH FLOW FROM OPERATIONS, INVESTING AND FINANCING ACTIVITIES
The Company provided $244,823 of net cash flow from operating activities
for year ended December 31, 1998 and used $1,778,762 of net cash flow from
operating activities for the same period in 1997. Cash was absorbed by a
loss of $394,428 and a loss of $367,281 for the year ended December 31,
1998 and 1997, respectively. Cash was absorbed by a decrease in drilling
advances of $1,335,124 for the year ended December 31, 1997. Cash was used
by a decrease in accounts payable and accrued expenses of $724,071 for the
year ended December 31, 1998. Cash was provided by a decrease in accounts
receivable and amounts due from partnerships of $139,876 for the year ended
December 31, 1998. Cash was used by an increase in accounts receivable and
other assets of $456,070 and $167,123, respectively, for the year ended
December 31, 1997. The decrease in accounts receivable for the year ended
December 31, 1997 was a result of the collection of the year-end Affiliated
Drilling Partnership receivable. The decrease in other assets was due to
the prepaid stock offering costs of $265,948 being charged against the
common stock account when the Company's public offering closed. Cash was
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provided for the year ended December 31, 1997 by an increase in accounts
payable and accrued expenses of $323,286. Cash was provided by
depreciation, depletion and amortization (DDA) of $1,551,685 and $557,167
in 1998 and 1997, respectively. The increase in DDA is a direct result of
increased drilling and gas operations.
For the year ended December 31, 1998, cash flows used for investing
activities increased from $7,117,384 for the year ended December 31, 1997
to $10,099,654. 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 and contributions to Affiliated Drilling
Partnerships of $34,510. The only cash flow from investing activities for
the year ended December 31, 1998 were distributions from Affiliated
Drilling Partnerships of $77,006. The more significant uses of cash flows
for investing activities for the year ended December 31, 1997 were
purchases of proven properties of $4,129,663, purchases of wells and
related equipment of $2,513,051, purchases of other property and equipment
of $251,244 and contributions to Affiliated Drilling Partnerships of
$318,100. The only significant cash flow from investing activities for the
year ended December 31, 1997 were distributions from Affiliated Drilling
Partnerships of $92,426.
Cash flows from financing activities decreased $2,899,131 or 26.1% to a
level of $8,198,264 for the year ended December 31, 1998. The significant
source of financing activities in 1998 was proceeds from incurring long-
term debt in the amount of $7,599,093, and the net proceeds from the sale
of 9% convertible redeemable preferred stock in the amount of $847,707.
The majority of the funds were used for the Company's continued development
of its Beaver Lease and Churchtown lease area, 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
acquisition of working interests from the Affiliated Drilling Partnerships
discussed earlier. The primary cause of the decrease in cash flows from
financing activities was the decrease in net proceeds from the issuance of
common stock from $11,466,661 in 1997 to a net expense of $64,155 in 1998,
a decrease of $11,530,816. The other significant uses of cash flows from
financing activities were the payments on long-term debt of $166,780 and
$439,391 in 1998 and 1997, respectively.
LIQUIDITY AND CAPITAL RESOURCES
The primary source of funds has been net proceeds from the issuance of
common stock in two offerings in 1997 raising approximately $11,200,000,
net of costs, borrowing against the Company's Bank One credit facility in
the amount of approximately $7,750,000, and the issuance of 9% convertible
redeemable preferred stock raising approximately $847,707, net of offering
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costs. The proceeds from these sources have been spent on Company
operations, including developing the Beaver Lease and the Simmons Field,
the acquisition of proven producing properties from Viking Resources
Corporation, the purchase of working interests and overriding royalty
interests from certain individuals and Affiliated Drilling Partnerships and
other developmental drilling activities in the southeastern Ohio and
Southern West Virginia areas.
The Company expects turnkey revenues to remain level or decrease. There
can be no assurance that the Company will realize any additional funds by
the sponsoring of an Affiliated Drilling Partnership in 1999.
The Company intends to fund its budgeted capital expenditures in 1999
primarily from cash flow from operations and borrowings. The Company
has in place a Bank One credit facility with a credit limit which has been
expanded subsequent to December 31, 1998 by $1,000,000 to a total of
$8,800,000 and upon which $7,749,776 was drawn down as of December 31,
1998. The Bank One credit facility is collateralized by a first lien on
the Company's oil and natural gas properties. Interest is payable at prime
plus 1.50% per annum. The Bank One credit facility includes a principal
reduction of $75,000 per month commencing on September 1, 1999. The Company
also has outstanding a note payable to SunTrust Bank in the principal amount
of $500,000, collateraized by certain equipment, payable in monthly
installments of principal and interest at 7.75% per annum, with unpaid
principal balance due December 5, 2003. The Company is subject to various
loan covenants in connection with its credit facilities including
requirements on its tangible net worth, debt to tangible net worth, limits
on partnership subsidies, restrictions on payment of dividends and general
and administrative expenses.
The Company has experienced and expects to continue to experience
substantial working capital requirements due primarily to the Company's
active exploration and development programs. The Company plans to
commence development of its coalbed methane leases in 1999. The Company
believes that cash flow from operations and borrowings under existing or
contemplated additional credit facilities should allow the Company to
implement its present business strategy in 1999. If sufficient capital
resources are not available to the Company, its drilling of new wells and
property development activities would be substantially curtailed.
EFFECTS OF COMMODITY PRICING AND INFLATION
The Company's revenues, profitability, future growth and ability to borrow
funds or obtain additional capital, and the carrying value of its
properties, substantially are dependent on prevailing prices of natural gas
and oil. The Company cannot predict future natural gas and oil price
movements with certainty. Declines in prices received for natural gas and
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oil may have an adverse effect on the Company's financial condition,
liquidity, ability to finance capital expenditures and results of
operations. Lower prices also may impact the amount of reserves that can
be produced economically by the Company. If the price of natural gas and
oil increases (decreases), there could be a corresponding increase
(decrease) in the operating cost that the Company is required to bear
for operations, as well as an increase (decrease) in revenues. Recent
rates of inflation have had a minimal effect on the Company.
ENVIRONMENTAL AND OTHER REGULATORY MATTERS
The Company's business is subject to certain 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 the Company believes it is
in substantial compliance with all applicable laws and regulations, the
requirements imposed by laws and regulations may change. The Company is
unable to predict the ultimate cost of compliance with these requirements.
Inability to meet environmental requirements could materially adversely
affect the Company's business, financial condition and results of
operations. Compliance with governmental laws and regulations applicable
to the Company has not had a material adverse effect on the earnings or
competitive position of the Company to date. Future regulations may add to
the cost of, or limit, drilling activity.
YEAR 2000 READINESS DISCLOSURE
This Year 2000 Readiness Disclosure is based upon and partially repeats
information provided by the Company's outside consultants and others
regarding the Year 2000 readiness of the Company and its customers,
suppliers, financial institutions and other parties. Although the Company
believes this information to be accurate, it has not independently verified
such information.
STATE OF READINESS. The Company is acutely aware of and has assessed and
will continue to assess the impact of the Year 2000 issue on the Company's
reporting systems and operations. The Year 2000 issue exists because many
computer systems and applications abbreviate dates by eliminating the first
two digits of the year, assuming that these two digits would always be
"19." Unless corrected, this shortcut may cause problems with some
computer systems and equipment with embedded computer chips
The Company has developed a plan to identify those systems that could be
effected by the Year 2000 problem. Management has identified and assessed
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the Year 2000 problem with respect to both information technology (I.T.)
and non-information technology (Non-I.T.) system issues. Management has
concluded that it has minimal Non-I.T. system issues which affect day to
day operations. The primary I.T. Systems for the Company are its
accounting software system and its geological/engineering software
products.
The Company's current accounting system is not presently Year 2000 ready.
The Company has, along with outside consultants, evaluated its current
system in comparison with four alternative systems and has concluded that a
change in systems is required to assure readiness for the Year 2000. The
new accounting (I.T.) software chosen is Sherware, Inc. which has been
purchased at a cost of $2,740. Installation and data conversion to the new
system will start in April 1999 and is expected to be fully operational by
June 1999 at an all inclusive cost of approximately $5,000 to $7,000. This
cost includes cost of software purchase, installation, conversion of data
from the old to the new system and training of staff in the operation of
the new system.
The Company uses two primary non-accounting software products, a
specialized engineering software, the Aries System, for the evaluation of
production and reserves and the GeoGraphix System geologic software for
reservoir evaluation and modeling. The Company is advised by the
manufacturers that both of these systems are currently Year 2000 compliant.
Lastly, the Company has evaluated Year 2000 issues relating to third
parties with whom the Company does business. These relate primarily to
financial institutions, vendors of products and vendors to whom the Company
sells goods in its normal business operations.
Vendors generally include suppliers of well equipment and services.
Management does not expect the ability of these vendors to supply goods and
services to be adversely affected by the Year 2000 event. The vendor's
billing and invoice systems may experience change and/or delays during the
transition, however. Gas marketers to whom the Company sells its end
product likewise have advised the Company that they are aware of the Year
2000 issue and are or will timely be Year 2000 compliant. Management does
not expect an adverse impact on the Company's day to day operations as a
result of third parties' unreadiness. There is no assurance that the
systems of other companies on which the Company's systems rely will be
converted in a timely manner. Unreadiness by these third parties could
expose the Company to the potential for loss and impairment of business
processes and activities. The Company is assessing these risks and is
creating contingency plans intended to address perceived risks. If such
modifications and conversions are not made, or are not completed in a
timely manner, the Year 2000 issue could have an adverse impact on the
operations of the Company.
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COST TO ADDRESS THE COMPANY'S YEAR 2000 ISSUES. As of March 24, 1999, the
Company has spent approximately $10,000 on identifying and assessing the
Year 2000 issue in connection with the Company's computer programs and
applications, which includes extensive internal personnel hours in
researching the Year 2000 issue and evaluating readiness. Financial
expenditure on outside consultants to date has been minimal. As discussed
above, the decision to change the Company I.T. accounting software system
will be at a total estimated cost of approximately $5,000 to $7,000.
Total anticipated costs of Year 2000 compliance activities is not expected
to exceed $25,000. This amount will be paid from the operating capital
budget and would represent less than one percent of the Company's expected
total general and administrative (G & A) expenses for the year.
Based on currently available information, management does not anticipate
that the costs to address the Year 2000 issue will have a material adverse
effect on the Company's financial condition, results of operations or
liquidity. However, the extent to which the computer operations and other
systems of the Company's important third parties are adversely affected
could, in turn, affect the Company's ability to communicate with third
parties and could have a material adverse effect on the operations of the
Company.
RISKS OF THE COMPANY'S YEAR 2000 ISSUES. The Company does not reasonably
expect any material lost revenue as a result of the Year 2000 issue. The
most likely worst case scenario would be a delay in financial analytical
abilities of the Company in the event of a delay in implementing the new
I.T. financial software system. Similar delays in third party vendor
invoicing and/or gas marketing reporting and/or payment could be
temporarily experienced. Management does not expect the Year 2000 to have
a materially adverse effect on the Company's results of operation,
liquidity or financial condition.
THE COMPANY'S CONTINGENCY PLAN. The Company is implementing its new
internal accounting system and expects it and all other internal systems to
be fully Year 2000 compliant and tested by June 1999. At that time, the
Company will evaluate further the need and extent to which a "contingency
plan" should be developed with respect to Year 2000 readiness.
If the Company's plans as outlined above are not successful, there could be
a disruption of the Company's ability to render distributions and complete
monthly accounting functions as well as a possible slowdown of certain
computer-dependent processes.
The costs of becoming Year 2000 compliant as outlined above and the date
that the Company expects to complete the Year 2000 modifications are based
on management's best estimates. There can be no guarantee that these
estimates will be achieved and actual results could differ from those
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anticipated. Specific factors that might cause differences include, but
are not limited to, the ability of other companies on which the Company's
systems rely to modify or convert their systems to be Year 2000 compliant,
the ability to locate and correct all relevant computer codes and the
ability of vendors with whom the Company deals to timely become Year 2000
compliant.
ITEM 7. FINANCIAL STATEMENTS.
The response to this Item is set forth herein in a separate section to this
Form 10-KSB, beginning on Page F-1.
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.
There is incorporated by reference herein in response to this Item the
material under the heading "Board of Directors" and "Section 16(a)
Beneficial Ownership Reporting Compliance" in the Company's definitive
proxy statement for its 1999 annual meeting of shareholders to be held on
June 17, 1999.
ITEM 10. EXECUTIVE COMPENSATION.
There is incorporated by reference herein in response to this Item the
material under the heading "Executive Compensation," "Employment Agreements
and Termination of Employment and Change in Control Arrangements" and
"Compensation Committee Report on Executive Compensation" in the Company's
definitive proxy statement for its 1999 annual meeting of shareholders to
be held on June 17, 1999.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
There is incorporated by reference herein in response to this Item the
material under the heading "Ownership of Common Stock" and "Securities
Ownership of Management" in the Company's definitive proxy statement for
its 1999 annual meeting of shareholders to be held on June 17, 1999.
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ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
There is incorporated by reference herein in response to this Item the
material under the heading "Certain Relationships and Related Transactions"
in the Company's definitive proxy statement for its 1999 annual meeting of
shareholders to be held on June 17, 1999.
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<F1>
3.2 Bylaws of the Registrant<F2>
4.1 Specimen of Common Stock Certificate<F3>
4.2 Specimen of Redeemable Series A Common Stock Purchase
Warrant Certificate<F3>
4.3 Specimen of Underwriters' Warrant Certificate<F3>
4.4 Charter (See Exhibit 3.1)
4.5 Bylaws (See Exhibit 3.2)
9.1 Shareholder Voting Agreement and Irrevocable Proxy<F3>
10.1 Energy Search Natural Gas 1995-A L.P. Limited Partnership
Agreement, dated December 31, 1995<F3>
10.2 Energy Search Natural Gas 1995-A L.P. Joint Drilling and
Operating Agreement, dated December 31, 1995<F3>
10.3 Energy Search Natural Gas 1996 L.P.-Limited Partnership
Agreement, dated June 10, 1996<F3>
10.4 Energy Search Natural Gas 1996 L.P.-Joint Drilling and
Operating Agreement, dated June 10, 1996<F3>
10.5 ESI Pipeline Operating Partnership-Limited Partnership
Agreement, dated January 7, 1993<F3>
10.6 Energy Search Natural Gas Pipeline Income Partnership-
Limited Partnership Agreement, dated January 7, 1993<F3>
10.7 Gas Servicing Agreement between the Registrant and ESI
Pipeline Operating L.P., dated January 5, 1993<F3>
10.8 Selling Agreement-Class B Convertible Preferred Shares
between Registrant and Equity Financial Corporation, dated
March 4, 1996<F3>
10.9 Selling Agreement-Class A and Class B Preferred Shares
between Registrant and Equity Financial Corporation, dated
March 4, 1996<F3>
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<PAGE>
10.10 Selling Agreement-Variable Rate Subordinated Debentures
between Registrant and Equity Financial Corporation, dated
September 19, 1994<F3>
10.11 Aircraft Lease between Charles P. Torrey, Jr. and the
Registrant dated February 1, 1995<F3>
10.12 Beaver Coal Company Lease between Beaver Coal Company
Limited and the Registrant, dated September 15, 1996<F3>
10.13 Employment Agreements with officers and key employees of the
Registrant
(a) John M. Johnston<F3><F*>
(b) Robert L. Remine<F3><F*>
(c) Charles P. Torrey, Jr.<F3><F*>
(d) Richard S. Cooper<F3><F*>
(e) Michael W. Mooney<F4><F*>
10.14 Promissory Notes of Executive Officers in Favor of
Registrant
(a) Charles P. Torrey, Jr.<F3>
(b) Robert L. Remine<F3>
(c) Richard S. Cooper<F3>
10.15 Stock Option Plan<F3><F*>
10.16 Outside Directors' Stock Option Plan<F3><F*>
10.17 Form of Lock-Up Agreement<F3>
10.18 Stock Option and Restricted Stock Plan of 1998<F1><F*>
10.19 Form of Indemnification Agreement<F1><F*>
10.20 1998 Stock Option and Restricted Stock Plan for Outside
Advisors and Consultants<F5>
11.1 Statement Regarding Computation of Earnings Per Common Share
21.1 Subsidiaries<F4>
23.1 Consent of Experts and Counsel
(a) Consent of Independent Accountant, Plante & Moran, LLP,
CPA
(b) Consent of Independent Geologist, Kim A. Walbe
(c) Consent of Independent Petroleum Consultant, Wright &
Company, Inc.
27.1 Financial Data Schedule
- ----------------------
<F*> Management contract or compensatory plan or arrangement
<F1> Previously filed with the Company's Definitive Proxy Statement filed
on April 28, 1998 with the Securities and Exchange Commission, and
here incorporated by reference.
<F2> Previously filed with the Company's Form 10-QSB for the quarter ended
June 30, 1998.
-39-
<PAGE>
<F3> Previously filed with the Company's Registration Statement on Form SB-
2 (Registration No. 333-12755) filed with the Securities and Exchange
Commission, and here incorporated by reference.
<F4> Previously filed with the Company's Form 10-KSB Annual Report for the
fiscal year ended December 31, 1997, and here incorporated by
reference.
<F5> Previously filed with the Company's Form 10-QSB Quarterly Report for
the quarter ended September 30, 1998, and here incorporated by
reference.
ITEM 13(B). REPORTS ON FORM 8-K
The Company filed no reports on Form 8-K during the fourth quarter of 1998.
-40-
<PAGE>
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.
ENERGY SEARCH, INCORPORATED
Date: March 30, 1999 /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. Chief Executive Officer and March 30, 1999
Charles P. Torrey, Jr. Director (Principal Executive
Officer)
/s/Richard S. Cooper President and Director March 30, 1999
Richard S. Cooper
/s/Robert L. Remine Secretary, Treasurer and Director March 30, 1999
Robert L. Remine (Principal Financial and
Accounting Officer)
-41-
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
CONTENTS
REPORT LETTER F-2
FINANCIAL STATEMENTS
Consolidated Balance Sheet F-3
Consolidated Statement of Operations F-4
Consolidated Statement of Stockholders' Equity F-5
Consolidated Statement of Cash Flows F-6-7
Notes to Consolidated Financial Statements F-8-25
REPORT LETTER F-27
ADDITIONAL INFORMATION
Cost Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities F-28
Estimates of Natural Gas and Oil Reserves F-28-31
F-1
<PAGE>
Independent Auditor's Report
To the Stockholders 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, 1998 and 1997
and the related statements of operations, stockholders' 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, 1998 and 1997 and the results
of its operations and its cash flows for the years then ended, in
conformity with generally accepted accounting principles.
/s/ Plante & Moran, LLP
Grand Rapids, Michigan
March 12, 1999
F-2
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
<TABLE>
CONSOLIDATED BALANCE SHEET
<CAPTION>
DECEMBER 31,
-----------------------------
1998 1997
----------- -----------
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 595,749 $ 2,252,316
Accounts receivable (Note I) 980,881 976,065
Other current assets 90,226 91,670
----------- -----------
Total current assets 1,666,856 3,320,051
OIL AND GAS PROPERTIES
Proven properties 13,165,858 4,546,833
Unproven properties 209,616 193,965
Wells and related equipment 11,357,198 8,100,764
Less accumulated depreciation, depletion and amortization (4,467,912) (3,140,678)
----------- -----------
Net oil and gas properties 20,264,760 9,700,884
OTHER ASSETS
Other property and equipment - Net (Note C) 287,746 363,180
Investments in related partnerships (Note B) 1,713,267 1,863,095
Deferred tax asset (Note D) 886,000 650,400
Other 204,780 223,090
----------- -----------
Total other assets 3,091,793 3,099,765
----------- -----------
Total assets $25,023,409 $16,120,700
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long-term debt (Note E) $ 546,407 $ 679,868
Accounts payable and accrued liabilities 632,677 1,356,748
----------- -----------
Total current liabilities 1,179,084 2,036,616
LONG-TERM DEBT - less current portion (Note E) 7,703,369 137,595
F-3
<PAGE>
STOCKHOLDERS' EQUITY (Notes F, G, H and J)
Preferred stock (no par value, 5,000,000 shares authorized;
issued and outstanding: 175,547 shares of 9%
redeemable convertible) 847,707 --
Common stock (no par value, 25,000,000 shares
authorized; 4,017,308 and 3,768,241 shares issued
and outstanding at December 31, 1998 and 1997,
respectively) 17,206,862 15,448,073
Accumulated deficit (1,913,613) (1,501,584)
----------- -----------
Total stockholders' equity 16,140,956 13,946,489
----------- -----------
Total liabilities and stockholders' equity $25,023,409 $16,120,700
=========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
F-4
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
<TABLE>
CONSOLIDATED STATEMENT OF OPERATIONS
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1998 1997
---------- ----------
<S> <C> <C>
REVENUE
Oil and gas sales $2,597,875 $ 798,956
Management fees (Note I) 145,586 264,590
Net turnkey revenue 67,312 475,936
Other revenue (Note L) 609,725 693,188
---------- ----------
Total revenue 3,420,498 2,232,670
OPERATING EXPENSES
Production costs 661,036 274,571
Exploration costs 202,718 76,810
Depreciation, depletion and amortization 1,551,685 557,167
Interest 392,716 105,735
General and administrative 1,156,890 1,816,163
---------- ----------
Total operating expenses 3,965,045 2,830,446
---------- ----------
NET (LOSS) FROM OPERATIONS (544,547) (597,776)
OTHER INCOME (EXPENSE)
Program subsidies (Note I) (192,837) (80,384)
Gain on sale of assets -- 4,785
Equity in income of related partnerships (Note B) 107,356 123,794
---------- ----------
Total other income (expense) (85,481) 48,195
---------- ----------
NET (LOSS) BEFORE INCOME TAXES (630,028) (549,581)
INCOME TAX BENEFIT (Note D) 235,600 182,300
---------- ----------
NET (LOSS) $ (394,428) $ (367,281)
========== ==========
F-5
<PAGE>
BASIC NET (LOSS) PER COMMON SHARE $ (0.11) $ (0.14)
========== ==========
DILUTED NET (LOSS) PER COMMON SHARE $ (0.11) $ (0.14)
========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-6
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
<TABLE>
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<CAPTION>
PREFERRED STOCK COMMON STOCK
----------------------- ---------------------
ACCUMULATED
SHARES AMOUNT SHARES AMOUNT DEFICIT TOTAL
------ --------- ---------- ------ ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
BALANCE-January 1, 1997 450,000 $ 4,246,160 1,100,000 $ 1,200 $(1,074,554) $ 3,172,806
Issuance of common stock (Note G) -- -- 1,755,761 11,178,273 -- 11,178,273
Conversion of preferred stock A and B to
common stock (Note F) (450,000) (4,246,160) 900,000 4,246,160 -- --
Exercise of pre-IPO warrants -- -- 12,480 22,440 -- 22,440
Dividends on preferred stock A -- -- -- -- (59,749) (59,749)
Net loss for the year ended December 31,
1997 -- -- -- -- (367,281) (367,281)
--------- ----------- ---------- ----------- ----------- -----------
BALANCE - December 31, 1997 -- -- 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
========= =========== ========== =========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
F-7
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
<TABLE>
CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1997
----------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $ (394,428) $ (367,281)
Adjustments to reconcile net loss to net cash from (used in)
operating activities:
Depreciation, depletion and amortization expense 1,551,685 557,167
Dry holes and abandonments of previously
capitalized oil and gas properties 43,033 2,865
Gain on sale of assets -- (4,785)
Equity in income of related partnerships (107,356) (123,794)
Increase in deferred taxes (235,600) (182,300)
(Increase) decrease in assets:
Accounts receivable and due from partnerships 139,876 (456,070)
Other current assets 1,444 (25,603)
Other assets (29,760) (167,123)
Increase (decrease) in liabilities:
Accounts payable and accrued liabilities (724,071) 323,286
Drilling advances -- (1,335,124)
----------- -----------
Net cash provided by (used in) operating
activities 224,823 (1,778,762)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of proven properties (6,839,114) (4,129,663)
Proceeds from sale of other property and equipment -- 10,054
Purchase of wells and related equipment (3,256,434) (2,513,051)
Purchase of other property and equipment (30,951) (251,244)
Distributions from affiliated partnerships 77,006 92,426
Contributions to affiliated partnerships (34,510) (318,100)
Purchase of oil and gas leases (15,651) (7,806)
----------- -----------
Net cash used in investing activities (10,099,654) (7,117,384)
</TABLE>
See Notes to Consolidated Financial Statements.
F-8
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
<TABLE>
CONSOLIDATED STATEMENT OF CASH FLOWS (CONTINUED)
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1997
----------- -----------
<S> <C> <C>
CASH FLOWS FROM FINANCING ACTIVITIES
Gross proceeds from issuance of common stock -- $13,249,727
Gross proceeds from issuance of preferred stock $ 956,500 --
Payments on stock issuance costs - common stock (64,155) (1,783,066)
Payments on stock issuance costs - preferred stock (117,793) --
Proceeds from issuance of long-term debt 7,599,093 129,874
Payment of dividends on preferred stock (17,601) (59,749)
Payments on long-term debt (166,780) (439,391)
----------- -----------
Net cash provided by financing activities 8,198,264 11,097,395
----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (1,656,567) 2,201,249
CASH AND CASH EQUIVALENTS - Beginning of year 2,252,316 51,067
----------- -----------
CASH AND CASH EQUIVALENTS - End of year $ 595,749 $ 2,252,316
=========== ===========
SUPPLEMENTAL CASH FLOW DISCLOSURE
Cash paid for interest $ 392,716 $ 120,017
Cash paid for income taxes $ 100,370 $ 20,391
Significant noncash activities:
Issuance of common stock for purchase of properties $ 1,822,944 $ --
Conversion of preferred to common stock (Note F) $ -- $ 4,246,160
</TABLE>
See Notes to Consolidated Financial Statements.
F-9
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS - Energy Search, Incorporated and Subsidiary (the
"Company") consists of Energy Search, Incorporated ("ESI") and Equity
Financial Corporation ("EFC"), a wholly owned subsidiary acquired May 1,
1997.
ESI is 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. ESI's revenue
is primarily derived from: the sale of natural gas and crude oil from
wells in which it has working interest; the transmission of natural
gas through a pipeline and gathering system owned by an affiliated
partnership in which ESI has an ownership interest; 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, and the formation and
management of oil and gas partnerships (Affiliated Drilling
Partnerships).
In 1997, ESI transitioned from being primarily a driller-operator for
syndicated Affiliated Drilling Partnerships to an energy company
developing reserves for its own account. The shift of its primary
operational focus was financed from public funds raised through an
initial public offering (Note G) and funds raised through a private
placement. While the Company anticipates the continued sponsoring of
Affiliated Drilling Partnerships on a limited basis, management's
primary focus will be the development of its own reserves and
acquisition of primarily proved undeveloped properties for
exploitation.
EFC is engaged in the operations of providing investment advice and
brokering and dealing in stocks, bonds, and other securities in the
east Tennessee region. EFC uses a clearing broker on a fully
disclosed basis to execute trades.
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements
include the accounts of ESI and its wholly owned subsidiary, EFC,
since the date of acquisition. All significant inter-company balances
and transactions have been eliminated in consolidation.
ESTIMATES - The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
F-10
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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 - ESI uses 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, such capitalized costs are charged to expense, as dry hole
costs, at that time.
Prior to 1997, wells were drilled with capital raised primarily
through limited partnerships. Under the terms of the partnership and
drilling contracts, ESI did not capitalize intangible drilling costs
since these costs were the responsibility of the contracting parties.
Intangible drilling costs are the expense for labor, fuel, repair,
hauling, rig rental and supplies used in the drilling of a well. ESI
does capitalize all tangible drilling costs when incurred, since they
retain ownership of the well equipment. Tangible costs are equipment
such as casing, tubing, pumps, tanks and other equipment installed on
a well.
Prior to 1997, the Company incurred certain lease acquisition
costs (e.g. landman expenses), which were part of the costs of
acquiring and developing leases for the Affiliated Drilling
Partnerships, that were offset against turnkey revenues. In 1998, the
Company has incurred similar costs; however, some of these costs have
been incurred and capitalized in connection with properties acquired
by the Company for its own portfolio. These costs include indirect
costs that management believes are related to the acquisition,
exploration and development of oil and gas properties. In 1998 and
1997, the Company capitalized approximately $1,353,000 and $437,000 of
F-11
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
indirect costs, respectively, and in 1998 $166,000 of interest costs
were capitalized to proven properties.
For 1997 and future years, all intangible and tangible drilling costs
for successful development wells drilled with the Company's capital
will be capitalized. Costs incurred to operate and maintain wells and
equipment and to lift oil and gas to the surface are generally expensed.
Oil and gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is
recognized at time of impairment. Because the individual wells are
generally insignificant and the Company's business is primarily
drilling 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. Oil and gas properties are
depreciated and depleted 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 - Other property and equipment are
recorded at cost. Major additions and improvements are capitalized,
while repairs, replacements and maintenance that do not improve or
extend the life of the respective assets are expensed. Depreciation
is computed under the double-declining balance method over the
estimated useful lives.
INVESTMENTS IN RELATED PARTNERSHIPS - Investments in related
partnerships are accounted for by the equity method. ESI, as the
managing general partner of the oil and gas partnerships, makes
initial capital contributions to the partnerships in accordance with
provisions in the respective placement memorandum governing the
activities of the particular partnership. Income or losses are
allocated to the investments according to ESI's ownership interest in
the partnerships, and distributions or withdrawals are deducted from
the investments (see Note B for additional partnership information).
TURNKEY DRILLING REVENUE - ESI enters into contracts with the
affiliated oil and gas partnerships to drill oil and gas wells under
turnkey agreements. Under the terms of the contracts, ESI provides
F-12
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
all tangible well equipment and receives 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 ESI in order to finance the drilling activity. ESI initially
defers the full amount of the drilling advances and recognizes
drilling revenue as the wells are completed. Drilling expenses are
netted against turnkey drilling revenue and were $47,888 in 1998 and
$2,209,872 in 1997.
INCOME TAXES - The Company accounts for income taxes following the
liability method. A current tax liability or asset is recognized for
the estimated taxes payable or refundable on tax returns. Deferred
tax liabilities or assets are recognized for the estimated future tax
effect of temporary differences between book and tax accounting and
operating loss and tax credit carryforwards. Valuation allowances are
established when necessary to reduce deferred tax assets to the amount
expected to be realized.
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 the Company 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 - The Company has stock option and stock
warrant plans (Notes H and J). Options and warrants granted to employees
are accounted for using the intrinsic value method, under which
compensation expense is recorded at the amount by which the market
price of the underlying stock at the grant date exceeds the exercise
price of an option. Options and warrants granted to non-employees are
accounted for using the fair value method.
F-13
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
BASIC NET (LOSS) PER COMMON SHARE - Basic net (loss) per common share
is based on net (loss) available to common stockholders (net income
less preferred stock dividends) divided by the weighted average number
of common shares outstanding during the period.
DILUTED NET (LOSS) PER COMMON SHARE - Diluted net (loss) per common
share is based on net (loss) before dividends divided by the weighted
average number of common shares outstanding plus dilutive potential
common shares, 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 common share in 1998 or 1997
because to do so would have been antidilutive.
CASH EQUIVALENTS - The Company considers all highly liquid investments
with a maturity of three months or less when purchased to be cash
equivalents.
RECLASSIFICATIONS - Certain reclassifications have been made to 1997
amounts to conform to 1998 presentations.
NOTE B - AFFILIATED OIL AND GAS PARTNERSHIPS
Since 1989, ESI has sponsored the formation of partnerships for the
purpose of conducting oil and gas exploration, development, and
production activities on certain oil and gas properties. Such
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., and the Natural Gas/Tax
Credit 1992-A L.P., all of which were liquidated in 1998 through the
Company's acquisition of the affiliated partnership working interests
(Note G).
ESI has also sponsored the following partnerships: the 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., the
Energy Search Natural Gas 1996-A L.P., the Energy Search Natural Gas
F-14
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE B - AFFILIATED OIL AND GAS PARTNERSHIPS (CONTINUED)
1997 L.P., the Energy Search Natural Gas 1997-A L.P., and the Energy
Search Natural Gas 1998 L.P. ESI serves as managing general partner
of these partnerships and, as such, has full and exclusive
discretion in the management and control of the partnerships. The
turnkey drilling and operating agreements that ESI enters into with
the partnerships provide that the partnerships pay for the intangible
drilling costs of the wells at an agreed-upon price per well. ESI
provides 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. ESI's interests in
the limited partnerships ranges from 1 percent to 9 percent at
December 31, 1998 and from 0.5 percent to 9 percent at December
31,1997.
In 1993, ESI sponsored the formation of the ESI Pipeline Operating
L.P. (the Operating Partnership), which purchased a portion of ESI's
gas pipeline and gathering system. ESI contributed its remaining
interest in the pipeline system to the new partnership in exchange for
an ownership interest in the Operating Partnership. ESI has advanced
funds to the Operating Partnership for each extension of the pipeline.
ESI has no legal obligation to continue to advance funds in the
future. ESI provided a guaranteed 10 percent 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, ESI sponsored the formation of the ESI Natural Gas
Pipeline Income L.P. (the Pipeline Partnership). The Pipeline
Partnership made a capital contribution to the Operating Partnership
to finance the initial purchase of ESI's pipeline system. In turn,
the Pipeline Partnership received an ownership interest in the
Operating Partnership. ESI serves as managing general partner for
both the Operating Partnership and Pipeline Partnership and, as such,
has full and exclusive discretion in the management of and control of
the partnerships. The Operating Partnership earns revenue by charging
gas wells a transportation fee based on the volume of gas moved through
the pipeline system. Substantially all of these gas wells are operated by
F-15
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE B - AFFILIATED OIL AND GAS PARTNERSHIPS (CONTINUED)
ESI. As of December 31, 1998 and 1997, the Pipeline Partnership owned
approximately 51 percent of the Operating Partnership, with ESI owning
the remaining 49 percent.
Total assets and equity of the related partnerships in the aggregate
were approximately $4,779,900 and $4,737,051, respectively, at
December 31, 1998, and $5,813,197 and $5,772,464, respectively, at
December 31, 1997.
ESI's share of revenue and net income for its equity investees for
the years ended December 31, 1998 and 1997, are given below. In
the case of each equity investee, the net income (loss) from
continuing operations equals the net income (loss).
F-16
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
<TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE B - AFFILIATED OIL AND GAS PARTNERSHIPS (CONTINUED)
<CAPTION>
NET INCOME (LOSS) FROM
REVENUE CONTINUING OPERATIONS
------------------------------- -----------------------------
EQUITY INVESTEE 1998 1997 1998 1997
- ------------------------------------ ------------- ------------ -------------- -------------
<S> <C> <C> <C> <C>
Energy Search Natural Gas
Pipeline Income, L.P. $ 4,673 $ 75 $ 4,673 $ (79)
ESI Pipeline Operating L.P. 86,059 117,357 78,978 86,290
Energy Search Natural Gas
1993 L.P. 2,604 4,572 2,596 4,375
Energy Search Natural Gas
1993-A L.P. 5,338 8,931 5,338 8,541
Energy Search Natural Gas
1994 L.P. 5,695 10,684 5,677 10,387
Energy Search Natural Gas
1994-A L.P. 502 656 502 617
Energy Search Natural Gas
1995 L.P. 3,741 6,921 3,741 6,642
Energy Search Natural Gas
1995-A L.P. 3,272 6,454 3,272 6,287
Energy Search Natural Gas
1996 L.P. 1,247 536 1,247 510
Energy Search Natural Gas
1996-A L.P. 360 123 360 105
Energy Search Natural Gas
1997 L.P. 668 118 668 117
F-17
<PAGE>
Energy Search Natural Gas
1997-A L.P. 318 -- 304 --
Energy Search Natural Gas
1998 L.P. -- -- -- --
</TABLE>
F-18
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE C - PROPERTY AND EQUIPMENT
The principal categories of property and equipment are as follows:
<TABLE>
<CAPTION>
DEPRECIABLE
1998 1997 LIFE-YEARS
--------------- -------------- ---------------
<S> <C> <C> <C> <C>
Machinery and equipment $ 41,005 $ 39,941 5
Office furniture, equipment
and software 311,657 281,770 5
Airplane 165,932 165,932 5
Vehicles 218,645 218,645 5
---------- ----------
Total cost 737,239 706,288
Less accumulated depreciation 449,493 343,108
---------- ----------
Net carrying amount $ 287,746 $ 363,180
========== ==========
</TABLE>
Depreciation expense totaled $106,385 and $74,750 for the years ended
December 31, 1998 and 1997, respectively.
NOTE D - INCOME TAXES
ESI and its subsidiary file a consolidated federal income tax return.
The following is a summary of the provisions for income taxes for
years ended December 31:
<TABLE>
<CAPTION>
1998 1997
-------- --------
<S> <C> <C> <C>
Deferred tax benefit $235,600 $182,300
======== ========
</TABLE>
F-19
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE D - INCOME TAXES (CONTINUED)
The following is a reconciliation of the statutory federal income tax
rate to the Company's effective tax rate:
<TABLE>
<CAPTION>
1998 1997
------ ------
<S> <C> <C> <C>
Income tax at federal statutory rate 34.0% 34.0%
State income tax, net of federal benefit 6.0% 6.0%
Other (2.6)% (6.8)%
----- -----
Actual effective tax rate 37.4% 33.2%
===== =====
</TABLE>
The significant components of ESI's deferred tax assets and
liabilities are as follows:
F-20
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE D - INCOME TAXES (CONTINUED)
<TABLE>
<CAPTION>
1998 1997
---------- ----------
<S> <C> <C> <C>
Deferred tax assets:
Allowance for uncollectible accounts -- $ 59,000
Accounting for equity investments $ 128,900 177,000
Federal net operating loss 1,771,100 2,213,800
State net operating loss 99,600 125,800
Geological and engineering costs 106,900 --
---------- ----------
Total deferred tax asset 2,106,500 2,575,600
Valuation allowance for deferred tax assets -- --
Deferred tax liabilities:
Depreciation and pooling of capital 832,900 784,200
Intangible drilling costs 349,200 1,126,000
Other 38,400 15,000
---------- ----------
Total deferred tax liabilities 1,220,500 1,925,200
---------- ----------
Net deferred tax asset $ 886,000 $ 650,400
========== ==========
</TABLE>
At December 31, 1998, the Company has federal and state operating
loss carryforwards of approximately $5,200,000 and $1,700,000
respectively, that expire in the years 2005 to 2018. These
carryforwards are available to offset future taxable income.
F-21
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE E - LONG-TERM DEBT
Long-term debt consisted of the following at December 31:
<TABLE>
<CAPTION>
1998 1997
---------- --------
<S> <C> <C> <C>
Line of credit at bank, available balance of
$7,800,000 and $920,000 at December 31, 1998 and
1997, respectively. Collateralized by lien on oil
and gas property, interest payable at prime plus
1.25% and 1.75% at December 31, 1998 and 1997
(a 9.0% and 10.25% effective rate, respectively).
Principal payments begin September 30, 1999, payable
in 48 equal monthly payments of principal plus interest $7,749,776 $650,684
Note payable to bank, collateralized by equipment,
payable in monthly installments of $3,600, including
interest at prime plus 0.5%, which was 9% at
December 31, 1997. This note was refinanced in 1998 -- 166,779
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. 500,000 --
---------- --------
Total 8,249,776 817,463
Less current portion 546,407 679,868
---------- --------
Total long-term debt $7,703,369 $137,595
========== ========
</TABLE>
The Company is subject to various loan covenants in connection with
bank notes payable described above including requirements on its
tangible net worth, debt to tangible net worth, limits on partnership
subsidies, restrictions on payment of dividends and general and
administrative costs.
F-22
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE E - LONG-TERM DEBT (CONTINUED)
Principal maturities of long-term debt at December 31, 1998 are as
follows:
<TABLE>
<CAPTION>
<S> <C> <C>
1999 $ 546,407
2000 2,006,182
2001 2,011,880
2002 2,017,944
2003 1,667,363
----------
Total $8,249,776
==========
</TABLE>
NOTE F - PREFERRED STOCK
CLASS A AND B PREFERRED STOCK - Class A and B preferred stock was
converted to common stock in 1997 in conjunction with the successful
initial public offering of ESI's common stock.
REDEEMABLE CONVERTIBLE PREFERRED STOCK - In 1998, the Company
initiated a private placement offering of up to 800,000 shares of 9%
redeemable convertible preferred stock. The offering was terminated
on December 18, 1998, and the issue price of the preferred stock was
adjusted to $5.50 per share according to the terms of the offering.
The Company raised $847,707, net of issue costs of $117,793, and sold
175,547 shares of preferred stock under the offering.
The preferred shares enjoy a liquidation and dividend preference over
the Company's common stock and are convertible to common stock at the
option of the holder at any time at a rate of 1.0 common share for
each preferred share converted. Conversion of the preferred shares to
common stock will automatically occur in the event the Company is
acquired or is the subject of a business combination in which
substantially all assets of the Company are acquired by unaffiliated
F-23
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE F - PREFERRED STOCK (CONTINUED)
purchasers or greater than 50% of the outstanding beneficial interest
of the Company's common stock is acquired by unaffiliated purchasers.
The holders of preferred shares may require the Company to redeem the
preferred shares if, at any time prior to October 1, 1999, the Company
publicly announces that it will be acquired or is the subject of a
business combination, as defined above. The redemption price in such
an event will be 100% of the issue price of the preferred shares plus
accrued and unpaid dividends.
The preferred shares are redeemable at the sole option of the Company
any time after September 30, 1999, provided the average trading
closing price for the Company's common stock exceeds 130% of the issue
price of the preferred shares over any 5 consecutive trading day
period commencing after September 30, 1999. The redemption price for
the preferred shares will be 100% of the issue price for the preferred
shares, plus accrued but unpaid dividends. The Company will provide
the holders of preferred shares 30 days written notice of its intent
to redeem the preferred shares during which time the holders may, at
their option, convert their preferred shares to common stock.
NOTE G - COMMON STOCK
INITIAL PUBLIC OFFERING - In January 1997, the Company registered its
stock in a public offering of 1,000,000 common shares and raised
$6,501,491 net of $1,498,509 for underwriter fees, professional fees,
and various other costs associated with this stock offering.
REGULATION D OFFERING - On October 27, 1997, the Company completed a
private offering of 749,961 shares of common stock and raised
$4,620,867, net of $628,900 for underwriter fees, professional fees,
and various other costs associated with this stock offering.
AFFILIATED PARTNERSHIP ROLL-UP - Effective June 30, 1998, the Company
closed the acquisition of working interests (the "Subject Interests")
in a total of 145 gross natural gas or oil wells that were being operated
by the Company. The Subject 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
F-24
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE G - COMMON STOCK (CONTINUED)
L.P., the Natural Gas/Tax Credit 1992 L.P., and the Natural Gas/Tax
Credit 1992-A L.P. The Company paid aggregate purchase consideration
amounting to $2,223,941 for the Subject Interests, which was comprised
of $1,716,748 in Company common stock (221,453 shares) and $507,193 in
cash.
The Company's acquisition of the Subject Interests from affiliated
partnerships followed a group of smaller transactions (the "Minor
Interest Acquisitions") pursuant to which the Company acquired minor
working interests and overriding royalty interests in the wells from
nine individuals. The Minor Interest Acquisitions had an effective
date of April 16, 1998. The Company paid aggregate purchase
consideration amounting to $227,740 for the Minor Interest
Acquisitions, which was comprised of $106,197 in Company common stock
(10,114 shares) and $121,543 in cash.
NOTE H - STOCK WARRANT PLANS
SERIES A WARRANTS - As part of ESI's public offering, the Board of
Directors issued 1,000,000 Series A warrants included in units that
consist of one share of common stock and one Series A warrant. The
Board issued additional Series A warrants consisting of 100,000 units
pursuant to the Underwriters' over-allotment option, and 100,000
"representative's" warrants pursuant to Underwriters' compensation.
An equivalent number of shares of common stock has been authorized and
reserved for issuance upon exercise of such Series A warrants.
Each Series A warrant entitles the holder to purchase one share of
common stock at an exercise price of $9.60 per unit exercisable at any
time after February 28, 1998, until January 30, 2002. The Series A
warrants could not be traded separately until July 24, 1997. The
warrants are subject to redemption by the Company at a price of $.05
per Series A warrant on 30 days written notice at any time after July
24, 1998, provided that the closing sale price per share for the
common stock has equaled or exceeded 200 percent of the offering price
per unit for 20 consecutive trading days within the 30-day period
immediately preceding such notice.
F-25
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE H - STOCK WARRANT PLANS (CONTINUED)
REGULATION D WARRANTS - As part of ESI's private offering of common
stock that took place in October 1997, 74,996 warrants were issued to
unaffiliated parties pursuant to the Placement Agent Agreement. The
warrants entitle each holder to purchase one share of common stock and
are exercisable at $7 per share at any time up to October 27, 2002.
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,
1998.
The following is a summary of stock warrant activity:
<TABLE>
<CAPTION>
NUMBER OF EXERCISE
WARRANTS PRICE EXPIRATION DATE
------------------------------------------
<S> <C> <C> <C> <C>
Outstanding - January 1, 1997 - $ -
Granted 1,200,000 9.60 January 30, 2002
Granted 74,996 7.00 October 27, 2002
---------
Outstanding - December 31, 1997 and 1998 1,274,996
---------
</TABLE>
None of the consideration received in the above stock offerings
was specifically allocated to the warrants.
NOTE I - RELATED-PARTY TRANSACTIONS
Because of the nature of ESI's business, a significant number of
transactions are with related parties.
F-26
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE I - RELATED PARTY TRANSACTIONS (CONTINUED)
During 1998 and 1997, ESI received $115,200 and $1,156,800, respectively,
from affiliated oil and gas partnerships for drilling costs which were
the responsibility of the affiliated oil and gas partnerships. Included
in accounts receivable at December 31, 1998 and 1997 is $59,002 and
$781,553 respectively, due from affiliated partnerships.
In its role as operator of the oil and gas wells owned by various
related partnerships, ESI charges a monthly wellhead and
administrative fee of between $100 and $300 for each producing well.
These fees totaled $110,856 and $239,433 for 1998 and 1997,
respectively. In its role as general partner of the Operating
Partnership (Note B), ESI charges the partnership a management fee of
$2,500 and $5,000 per month for 1998 and 1997, respectively. These fees
totaled $35,000 and $60,000 for 1998 and 1997, respectively.
Subsequent to December 31, 1998 the Company issued a note totaling
$225,000 to three officers for their interests in various properties
and their rights to invest in future properties.
The Company, in its discretion and given the business environment
existing at the time, chose not to collect certain amounts due from
partnerships and also paid certain expenses due to others on behalf of
partnerships. ESI is under no legal or contractual obligation to
continue this activity, and there is no expectation that it will
continue in future years.
F-27
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE I - RELATED PARTY TRANSACTIONS (CONTINUED)
The following is a summary of expenses paid on behalf of the
partnerships and advances forgiven for the years ended December 31:
<TABLE>
<CAPTION>
1998 1997
-------- --------
<S> <C> <C> <C>
Expenses paid on behalf of partnership $192,837 $ 80,384
======== ========
Advances forgiven $ 820 $ 11,728
======== ========
</TABLE>
ESI has the contractual right to charge partnership administrative
fees and production operating fees in excess of the aggregate amounts
charged to the partnerships during 1998 and 1997.
NOTE J - EMPLOYEE BENEFIT AND STOCK-BASED COMPENSATION PLANS
EMPLOYEE BENEFIT PLAN - The Company sponsors a simplified employee
pension plan (SEP) for qualifying employees. Employee contributions to
individual retirement plans may not exceed the greater of 15 percent of
employee earnings or $22,500 per year per employee. The Company
contributed $38,792 and $25,370 to the SEP during 1998 and 1997,
respectively.
NON-EMPLOYEE OPTIONS - The Company issued 2,500 options each to the
two outside directors during both 1998 and 1997. Options issued in
1998 and 1997 entitle the holder to purchase one share of common
stock at an exercise price of $5.25 and $6.50, respectively, and the
options expire January 30, 2002. The Company also issued 2,500
options to an outside consultant in 1998 for past services rendered.
The options entitle the holder to purchase one share of common stock
at an exercise price of $6.50 and expire January 30, 2002. During
1998 and 1997, $6,700 and $2,400, was charged to expense related to
these non-employee options, respectively.
F-28
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE J - EMPLOYEE BENEFIT AND STOCK-BASED COMPENSATION PLANS (CONTINUED)
EMPLOYEE OPTION PLAN - The Company has a fixed employee stock-based
compensation plan under which the Company granted options for 55,650
shares of restricted common stock in 1997. The exercise price of
each option is $6.50 per share. The options expire January 30, 2002
and vest immediately upon grant.
In addition, the Company has 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 is
$8.00 per share. The term of the options is five years starting in
1998 and the warrants vest at 4,500 shares per year.
OFFICER WARRANT PLAN - The Company also has a fixed executive officer
stock-based compensation plan under which executive officers have
been granted warrants for the purchase of up to 450,000 shares of
restricted common stock. The exercise price of each warrant is $8.00
per share, which equaled the market price of the Company's stock on
the date of grant. The term of the warrants is five years starting in
1997 and the warrants vest at 30,000 shares per officer per year.
The Company applies intrinsic value accounting to its fixed stock-
based compensation plans. Accordingly, no compensation cost has been
recognized for the fixed plans in 1998 and 1997. Had compensation
cost been determined using the fair value method, net loss would have
been $(551,517) and $(476,563) for 1998 and 1997, respectively, and
basic and fully diluted loss per share would have been $(.15) and $(.18)
for 1998 and 1997, respectively. The fair value of the warrants and
options was determined using the Black-Scholes model with application
of an additional 30 percent discount due to the fact that the shares are
restricted. Assumptions made in estimating the fair value include:
risk-free interest rate of 6 percent, expected expiration of the
warrants of January 30, 2002, expected price volatility of 20 percent
and dividend yield of 0 percent.
F-29
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
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 1998.
<TABLE>
<CAPTION>
WEIGHTED
AVERAGE
NUMBER OF SHARES EXERCISE PRICE
------------------ --------------
<S> <C> <C> <C>
Outstanding at January 1, 1997 27,950 $ 3.57
Granted 505,650 7.84
Expired (15,470) 10.00
Exercised (12,480) 3.59
-------- ------
Outstanding - December 31, 1997 505,650 7.84
Granted 22,500 8.00
-------- ------
Outstanding - December 31, 1998 $528,150 $ 7.84
======== ======
Exercisable at December 31, 1998 $240,150 $ 7.65
======== ======
Weighted average per share fair value
of options granted during 1998 $ 1.66
========
</TABLE>
F-30
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE J - EMPLOYEE BENEFIT AND STOCK-BASED COMPENSATION PLANS (CONTINUED)
The following is a summary of the status of the fixed options
outstanding at December 31, 1998.
<TABLE>
<CAPTION>
OUTSTANDING OPTIONS EXERCISABLE OPTIONS
------------------------------------------------ ---------------------------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
EXERCISE REMAINING EXERCISE REMAINING
PRICE NUMBER CONTRACTUAL LIFE PRICE NUMBER CONTRACTUAL LIFE
-------- ------ ---------------- -------- ------ ----------------
<S> <C> <C> <C> <C> <C> <C>
$6.50 55,650 4 $6.50 55,650 4
$8.00 472,500 4 $8.00 184,500 4
</TABLE>
NOTE K - COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS
As general partner in various affiliated oil and gas partnerships, the
Company is 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 such contingencies that
may arise would not be material to the financial statements.
CONCENTRATIONS OF CREDIT RISK - The Company extends credit to
affiliated partnerships in the normal course of business. Within this
industry, certain concentrations of credit risk exist. ESI, in its
role as operator of co-owned properties, assumes responsibility for
payment to vendors for goods and services related to joint operations
and extends 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 the
Company's overall credit risk. However, management believes that its
accounts receivable are well diversified, thereby reducing potential
risk to the Company.
F-31
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE K - COMMITMENTS, CONTINGENCIES AND CONCENTRATIONS (CONTINUED)
GEOGRAPHIC CONCENTRATION - The Company plans to increase its oil and
gas reserves by continued developmental drilling in southeastern Ohio
in the area serviced by its gas gathering system, its Dupont Field and
its Beaver Coal Company Lease in Wood and Raleigh counties, West
Virginia, respectively. The Company may also undertake activities
elsewhere in the Appalachian Basin and the mid-continent region of the
United States. It plans to drill an increasing number of wells for
its own account, while at the same time continuing to drill wells with
future affiliated drilling partnerships to be syndicated on a private
placement basis.
NOTE L - BUSINESS SEGMENTS
The Company adopted SFAS No. 131, DISCLOSURES ABOUT SEGMENTS OF AN
ENTERPRISE AND RELATED INFORMATION, in 1997 which changes the way the
Company reports information about its operating segments. The
information for 1997 has been restated from the prior year's
presentation in order to conform to the 1998 presentation.
The Company's operations are classified into two principal industry
segments. Oil and gas operations and brokerage services. The oil and
gas operations are conducted entirely through Energy Search, Incorporated
which is the primary industry segment. The brokerage services are
conducted exclusively through Equity Financial Corporation. See Note A
for a description of the operations and accounting policies of each
Company. The following is a summary of segment information for 1998
and 1997.
F-32
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE L - BUSINESS SEGMENTS (CONTINUED)
<TABLE>
<CAPTION>
OIL & GAS BROKERAGE
1998 OPERATIONS SERVICES TOTALS
-------------------------------- ----------- -------- -----------
<S> <C> <C> <C> <C>
Revenues $ 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
</TABLE>
F-33
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997 (CONTINUED)
NOTE L - BUSINESS SEGMENTS (CONTINUED)
<TABLE>
<CAPTION>
OIL & GAS BROKERAGE
1997 OPERATIONS SERVICES TOTALS
-------------------------------- ----------- -------- -----------
<S> <C> <C> <C> <C>
Revenues $ 1,640,139 $592,531 $ 2,232,670
Segment profit (loss) (494,371) 127,090 (367,281)
Intersegment revenue -- 92,400 92,400
Total assets 15,810,516 310,184 16,120,700
Capital expenditures 6,901,159 605 6,901,764
Equity method income 123,794 -- 123,794
Interest expense 105,735 -- 105,735
Depreciation, depletion
and amortization 552,471 4,696 557,167
</TABLE>
F-34
<PAGE>
ADDITIONAL INFORMATION
===========================================================================
F-35
<PAGE>
To the Stockholders of
Energy Search, Incorporated and Subsidiary
We have audited the financial statements of Energy Search, Incorporated and
Subsidiary for the years ended December 31, 1998 and 1997. The accompanying
schedules of Costs Incurred in Oil and Gas Producing Activities and Estimates
of Natural Gas and Oil Reserves on pages F-28 through F-31 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.
/s/ Plante & Moran, LLP
Grand Rapids, Michigan
March 12, 1999
F-36
<PAGE>
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1998 1997
---------- ----------
<S> <C> <C>
Property acquisition costs $4,560,556 $1,535,173
========== ==========
Exploration costs $ 218,369 $ 84,616
========== ==========
Developments costs $6,607,991 $5,683,356
========== ==========
</TABLE>
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 the
Company's engineer as of December 31, 1998 and 1997. They do not purport
to reflect realizable values or fair market values of ESI's reserves. ESI
emphasizes 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.
F-37
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
SUPPLEMENTARY INFORMATION (UNAUDITED)
ESTIMATES OF NATURAL GAS AND OIL RESERVES (CONTINUED)
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 percent per year to
reflect the estimated timing of the future cash flows.
<TABLE>
<CAPTION>
OIL (BBL) GAS (MCF)
--------- ------------
<S> <C> <C>
Proven, developed and undeveloped reserves:
January 1, 1997 16,736 15,692,300
Revisions and other changes (12,583) (1,608,121)
Extensions and discoveries -- 4,649,023
Purchases and sales of reserves 20,600 12,099,800
Production (1,129) (223,025)
-------- ------------
December 31, 1997 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
======== ============
Proven developed reserves <F1>:
December 31, 1997 23,624 11,192,017
December 31, 1998 44,554 15,990,954
Equity interest in proven reserves <F2>:
December 31, 1997 268 138,228
December 31, 1998 103 124,326
- -------------------------
F-38
<PAGE>
<FN>
<F1> These reserves are owned directly by the Company.
<F2> These are reserves owned indirectly by the Company through its interests
in affiliated partnerships.
</FN>
</TABLE>
F-39
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
SUPPLEMENTARY INFORMATION (UNAUDITED)
ESTIMATES OF NATURAL GAS AND OIL RESERVES (CONTINUED)
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1998 1997
------------ ------------
<S> <C> <C>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE PRETAX NET CASH FLOWS
Future cash inflows $121,902,800 $105,929,500
Future production costs (23,279,515) (18,076,980)
Future development costs (21,171,030) (16,710,350)
------------ ------------
Future pretax net cash flows 77,452,255 71,142,170
10% annual discount for estimated timing of cash flows (46,690,672) (38,780,970)
------------ ------------
Standardized measure of discounted future pretax net
cash flows relating to proven oil and gas reserves $ 30,761,583 $ 32,361,200
============ ============
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
Future cash inflows $121,902,800 $105,929,500
Future production costs (23,279,515) (18,076,980)
Future development costs (21,171,030) (16,710,350)
Future income taxes (23,610,860) (22,149,426)
------------ ------------
Future net cash flows 53,841,395 48,992,744
10% annual discount for estimated timing of cash flows (29,975,411) (24,897,377)
------------ ------------
Standardized measure of discounted future net cash flows
relating to proven oil and gas reserves $ 23,865,984 $ 24,095,367
============ ============
ESI's share of equity method investors' standardized measure
of discounted future cash flows $ 124,376 $ 181,570
============ ============
</TABLE>
F-40
<PAGE>
ENERGY SEARCH, INCORPORATED AND SUBSIDIARY
- ---------------------------------------------------------------------------
SUPPLEMENTARY INFORMATION (UNAUDITED)
ESTIMATES OF NATURAL GAS AND OIL RESERVES (CONTINUED)
The following reconciles the change in the standardized measure of
discounted future net cash flows for the year ended December 31,
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Beginning of year $ 24,095,367 $ 15,172,758
Sales of oil and gas produced, net of production costs (2,444,574) (524,385)
Extensions, discoveries, and improved recovery -
Less related costs 9,806,445 4,853,796
Revisions of previous quantity estimates (2,632,622) (394,343)
Changes in prices (12,778,261) 1,231,832
Net change from purchases and sales of minerals in place 6,498,274 10,716,000
Net change in income taxes (1,461,434) (11,258,007)
Accretion of discount (2,409,537) (1,517,276)
Other 5,192,326 5,814,992
------------ ------------
End of year $ 23,865,984 $ 24,095,367
============ ============
</TABLE>
F-41
<PAGE>
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
3.1 Fourth Amended and Restated Charter of the Registrant<F1>
3.2 Bylaws of the Registrant<F2>
4.1 Specimen of Common Stock Certificate<F3>
4.2 Specimen of Redeemable Series A Common Stock Purchase
Warrant Certificate<F3>
4.3 Specimen of Underwriters' Warrant Certificate<F3>
4.4 Charter (See Exhibit 3.1)
4.5 Bylaws (See Exhibit 3.2)
9.1 Shareholder Voting Agreement and Irrevocable Proxy<F3>
10.1 Energy Search Natural Gas 1995-A L.P. Limited Partnership
Agreement, dated December 31, 1995<F3>
10.2 Energy Search Natural Gas 1995-A L.P. Joint Drilling and
Operating Agreement, dated December 31, 1995<F3>
10.3 Energy Search Natural Gas 1996 L.P.-Limited Partnership
Agreement, dated June 10, 1996<F3>
10.4 Energy Search Natural Gas 1996 L.P.-Joint Drilling and
Operating Agreement, dated June 10, 1996<F3>
10.5 ESI Pipeline Operating Partnership-Limited Partnership
Agreement, dated January 7, 1993<F3>
10.6 Energy Search Natural Gas Pipeline Income Partnership-
Limited Partnership Agreement, dated January 7, 1993<F3>
10.7 Gas Servicing Agreement between the Registrant and ESI
Pipeline Operating L.P., dated January 5, 1993<F3>
10.8 Selling Agreement-Class B Convertible Preferred Shares
between Registrant and Equity Financial Corporation, dated
March 4, 1996<F3>
10.9 Selling Agreement-Class A and Class B Preferred Shares
between Registrant and Equity Financial Corporation, dated
March 4, 1996<F3>
10.10 Selling Agreement-Variable Rate Subordinated Debentures
between Registrant and Equity Financial Corporation, dated
September 19, 1994<F3>
10.11 Aircraft Lease between Charles P. Torrey, Jr. and the
Registrant dated February 1, 1995<F3>
10.12 Beaver Coal Company Lease between Beaver Coal Company
Limited and the Registrant, dated September 15, 1996<F3>
10.13 Employment Agreements with officers and key employees of the
Registrant
(a) John M. Johnston<F3><F*>
(b) Robert L. Remine<F3><F*>
(c) Charles P. Torrey, Jr.<F3><F*>
(d) Richard S. Cooper<F3><F*>
(e) Michael W. Mooney<F4><F*>
i
<PAGE>
10.14 Promissory Notes of Executive Officers in Favor of
Registrant
(a) Charles P. Torrey, Jr.<F3>
(b) Robert L. Remine<F3>
(c) Richard S. Cooper<F3>
10.15 Stock Option Plan<F3><F*>
10.16 Outside Directors' Stock Option Plan<F3><F*>
10.17 Form of Lock-Up Agreement<F3>
10.18 Stock Option and Restricted Stock Plan of 1998<F1><F*>
10.19 Form of Indemnification Agreement<F1><F*>
10.20 1998 Stock Option and Restricted Stock Plan for Outside
Advisors and Consultants<F5>
11.1 Statement Regarding Computation of Earnings Per Common Share
21.1 Subsidiaries<F4>
23.1 Consent of Experts and Counsel
(a) Consent of Independent Accountant, Plante & Moran, LLP,
CPA
(b) Consent of Independent Geologist, Kim A. Walbe
(c) Consent of Independent Petroleum Consultant, Wright &
Company, Inc.
27.1 Financial Data Schedule
- ----------------------
<F*> Management contract or compensatory plan or arrangement
<F1> Previously filed with the Company's Definitive Proxy Statement filed
on April 28, 1998 with the Securities and Exchange Commission, and
here incorporated by reference.
<F2> Previously filed with the Company's Form 10-QSB for the quarter ended
June 30, 1998.
<F3> Previously filed with the Company's Registration Statement on Form SB-
2 (Registration No. 333-12755) filed with the Securities and Exchange
Commission, and here incorporated by reference.
<F4> Previously filed with the Company's Form 10-KSB Annual Report for the
fiscal year ended December 31, 1997, and here incorporated by
reference.
<F5> Previously filed with the Company's Form 10-QSB Quarterly Report for
the quarter ended September 30, 1998, and here incorporated by
reference.
ii
<PAGE>
EXHIBIT 11.1
ENERGY SEARCH, INCORPORATED
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1998
-----------------
<S> <C>
BASIC EARNINGS (LOSS) PER
SHARE
Net income (loss) (394,428)
Payment of dividends on preferred stock 17,601
Shares
Weighted average shares outstanding 3,868,752
Basic earnings (loss) per share (.11)
DILUTED EARNINGS (LOSS) PER
SHARE
Net income (loss) (394,428)
Payment of dividends on preferred stock 17,601
Shares
Weighted average shares outstanding 3,868,752
Diluted earnings (loss) per share (.11)
</TABLE>
<PAGE>
EXHIBIT 23.1(a)
CONSENT OF INDEPENDENT ACCOUNTANT
We hereby consent to the references to our firm and to our report dated
March 12, 1999 on the financial statements of the Company for the years
ended December 31, 1997 and December 31, 1998 ("Report") contained in the
Annual Report on Form 10-KSB of Energy Search, Incorporated (the "Company")
for the fiscal year ended December 31, 1998 (the "1998 10-KSB"). We further
consent to the use in the 1998 10-KSB of our report on Supplementary
Information dated December 31, 1998 (the "Report on Supplementary
Information") which is presented as supplementary information to the
December 31, 1998 financial statements of the Company. We also hereby
consent to the incorporation by reference of our Report and the Report on
Supplementary Information contained in the 1998 10-KSB into the Company's
Registration Statement on Form S-3 (No. 333-58407).
PLANTE & MORAN, LLP
By: /S/ JONATHAN M. CHISM
Jonathan M. Chism, CPA
March 29, 1999
Grand Rapids, MI
<PAGE>
EXHIBIT 23.1(b)
CONSENT OF INDEPENDENT GEOLOGIST
I hereby consent to the references to my firm and to my reserve
estimates contained in the Annual Report on Form 10-KSB of Energy Search,
Incorporated (the "Company") for the fiscal year ended December 31, 1998.
My estimates of the reserves of the Company are contained in my report
dated August 31, 1997 on the oil and gas reserves of the Company as of
December 31, 1996. I hereby consent to the incorporation by reference of
my report and the estimates contained in the Annual Report on Form 10-KSB
for the fiscal year ended December 31, 1998 into the Company's Registration
Statement on Form S-3 (No. 333-58407).
WALBE & ASSOCIATES, INC.
By: /S/ KIM A. WALBE
Kim A. Walbe, President
March 29, 1999
Charleston, WV
<PAGE>
EXHIBIT 23.1(c)
CONSENT OF INDEPENDENT PETROLEUM CONSULTANT
We hereby consent to our reserves estimates contained in the
Annual Report of Form 10-KSB of Energy Search Incorporated (the "Company")
for the fiscal year ended December 31, 1998 (the "1998 10-KSB"). Our
estimates of the oil and gas reserves of the Company are contained in our
report dated March 2, 1999 on the oil and gas reserves of the Company as of
January 1, 1999 (the "1999 Report"), as well as our report dated March 4,
1998 on the oil and gas reserves of the Company as of January 1, 1998 (the
"1998 Report"). We also hereby consent to the reference in the 1998 10-KSB
to Wright & Company, Inc. as experts in oil and gas analysis. We further
consent to the incorporation by reference of our 1999 Report and 1998
Report and our oil and gas reserves estimates contained in the 1998 10-KSB
into the Company's Registration Statement on Form S-3 (No. 333-58407).
Wright & Company, Inc.
By: /S/ D. RANDALL WRIGHT
D. Randall Wright
President
March 30, 1999
Brentwood, TN
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND> THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM THE FORM 10-KSB FOR ENERGY SEARCH, INCORPORATED AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 595,749
<SECURITIES> 0
<RECEIVABLES> 980,881
<ALLOWANCES> 0
<INVENTORY> 61,984
<CURRENT-ASSETS> 1,666,856
<PP&E> 25,469,911
<DEPRECIATION> (4,917,405)
<TOTAL-ASSETS> 25,023,409
<CURRENT-LIABILITIES> 1,179,084
<BONDS> 7,703,369
<COMMON> 17,206,862
0
847,707
<OTHER-SE> (1,913,613)
<TOTAL-LIABILITY-AND-EQUITY> 25,023,409
<SALES> 2,597,875
<TOTAL-REVENUES> 3,527,854
<CGS> 68,845
<TOTAL-COSTS> 3,571,509
<OTHER-EXPENSES> 192,837
<LOSS-PROVISION> 820
<INTEREST-EXPENSE> 392,716
<INCOME-PRETAX> (630,028)
<INCOME-TAX> 235,600
<INCOME-CONTINUING> (394,428)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (394,428)
<EPS-PRIMARY> (.11)
<EPS-DILUTED> (.11)
</TABLE>
