<PAGE> 1
FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended March 31, 1998
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________to __________
COMMISSION FILE NUMBER 0-18691
NORTH COAST ENERGY, INC.
(Exact name of Registrant as specified in its charter)
DELAWARE 34-1594000
(State of incorporation) (I.R.S.Employer
Identification No.)
1993 CASE PARKWAY
TWINSBURG, OHIO 44087-2343
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (330) 425-2330
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
(Title of class)
SERIES A 6% CONVERTIBLE NON-CUMULATIVE PREFERRED STOCK, $0.01 PAR VALUE
(Title of class)
SERIES B CUMULATIVE CONVERTIBLE PREFERRED STOCK, $0.01 PAR VALUE
(Title of class)
WARRANTS TO PURCHASE COMMON STOCK, $0.01 PAR VALUE
(Title of class)
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Indicate by check mark whether the Registrant (1) has filed all Reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to the filing
requirements for the past 90 days.
Yes X. NO _____.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. ____
As of June 22, 1998, the Registrant had outstanding 16,617,881 shares of Common
Stock, 74,491 shares of Series A Preferred Stock, 268,264 shares of Series B
Preferred Stock.
The aggregate market value of Common Stock held by non-affiliates of the
Registrant at June 22, 1998 was $5,873,697 which value has been computed on the
basis of $1.03 per share of Common Stock, the mean between the closing bid and
ask price as reported for that day on the NASDAQ system.
DOCUMENTS OR PARTS THEREOF INCORPORATED BY REFERENCE
Part of Form 10-K
-----------------
Part III (Items 10, 11, 12, and 13)
Document Incorporated by Reference
----------------------------------
Portions of the Registrant's definitive Proxy Statement to be used in connection
with its 1998 Annual Meeting of Stockholders.
Except as otherwise indicated, the information contained in this Report is as of
March 31, 1998.
<PAGE> 3
PART I
ITEM 1. BUSINESS.
GENERAL
North Coast Energy, Inc., a Delaware corporation ("North Coast" or the
"Company"), is an independent natural gas and oil company engaged in
exploration, development and production activities primarily in the Appalachian
Basin. The Company's strategy focuses primarily on its acquisition of proved
undeveloped properties and on the drilling and development of such properties.
The Company develops these properties in conjunction with drilling programs
("Drilling Programs") which the Company sponsors and manages. The Drilling
Programs are funded through the sale of partnership interests to investors and
by contributions from the Company. The Company currently obtains an interest of
approximately 20% in each Drilling Program for which it contributes (either in
cash or in kind) organizational and tangible equipment costs and drill sites. As
used in this Annual Report on Form 10-K, the terms "Company" and "North Coast"
mean North Coast Energy, Inc., its subsidiaries and predecessors, unless the
context otherwise requires.
As of March 31, 1998, the Company serves as the managing general partner
of 27 Drilling Programs and operates 691 wells, 374 of which are operated for
the Drilling Programs. In connection with the drilling and development of the
wells it operates, North Coast currently owns approximately 202 miles of natural
gas gathering pipelines which transport gas from 604 wells. At March 31, 1998,
the Company had estimated net proved reserves of approximately 17.8 Bcf of
natural gas and 135,700 barrels of oil.
The Company began operations in 1981 with the formation of its first
Drilling Program. In 1987, the Company expanded its operations by acquiring
Capital Oil & Gas, Inc. which also operated in the Appalachian Basin. In 1990,
the Company acquired the assets and properties of 21 Drilling Programs which it
had sponsored through an exchange offer (the "Exchange Offer") through which the
Company issued publicly traded stock listed on NASDAQ. Subsequently, the Company
has continued its original business strategy and now serves as the managing
general partner of 27 Drilling Programs.
Subsidiaries. The Company's sole active subsidiary is NCE Securities, Inc.
("NCE Securities"), a member of the NASD and a broker dealer registered with the
SEC and licensed in three states. NCE Securities' only business activity is the
performance of its responsibilities as placement agent and, to a limited degree,
the sale of partnership interests in North Coast sponsored Drilling Programs.
EXPLORATION AND DEVELOPMENT
Exploration and development activities conducted by the Company have
involved the acquisition of proved undeveloped oil and gas properties and the
drilling and development of such properties in conjunction with Drilling
Programs and joint ventures. Management has chosen to sponsor limited
partnerships and joint ventures to increase the funds available to the Company
and enable it to engage in a greater number of drilling opportunities. In
addition, the Drilling Programs add to the Company's reserves and produce
additional sources of income for the Company, including revenues from serving as
general contractor for drilling operations, management services, oilfield
service operations, and gas-gathering and marketing services which are provided
to the Drilling Programs.
The Company's strategy focuses on increasing its natural gas and oil
reserves, as well as production, drilling and oil field service revenues, by
acquiring undeveloped oil and gas properties in the Appalachian Basin and
financing and conducting the drilling and development of these properties in
conjunction with the Drilling Programs. While the Company is pursuing its
strategy of increasing reserves through drilling and development in conjunction
with the Drilling Programs, it continues to review potential acquisitions,
including other gas and oil companies or partnerships and producing properties.
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AREAS OF OPERATION
The Appalachian Basin is located in close proximity to major natural gas
markets in the northeast United States. This proximity to a substantial number
of large commercial and industrial gas markets, coupled with the relatively
stable nature of Appalachian Basin production and the availability of
transportation facilities has resulted in generally higher wellhead prices for
Appalachian natural gas than those prices available in the Gulf Coast and
Mid-continent regions. The Appalachian Basin is the oldest gas and oil producing
region in the United States and includes portions of Ohio, Pennsylvania, New
York, West Virginia, Kentucky and Tennessee. Historically, most production in
the Appalachian Basin has been from wells drilled to a number of relatively
shallow blanket formations at depths of 1,000 to 7,500 feet. These formations
are generally characterized as long-lived reserves that produce for more than 20
years.
To date, the Company's drilling operations in the Appalachian Basin have
principally involved drilling to the Clinton/Medina sandstone geologic
formation. This formation is an oil and gas bearing sandstone formation, which
underlies a large section of eastern Ohio and western Pennsylvania in varying
thicknesses and at depths ranging generally from 2,800 to 7,500 feet.
Substantially all of the wells that the Company drills in this area have
estimated depths of between 3,500 and 6,700 feet. The Clinton/Medina formation
is generally characterized by low permeability (the ability of gas and oil
bearing rock to flow gas and oil) and low porosity (capacity of rock to hold oil
and gas). Generally, in a productive well, both oil and gas initially are
produced at rates that rapidly decline after the first one or two years.
Although Clinton/Medina wells generally produce for many years, a substantial
portion of the total well production can be expected within the first several
years of full production.
Certain of the Company's leaseholds are in the Upper Devonian age
sandstone geological formations of Washington, Warren, McKean, Potter and
Clearfield counties in Pennsylvania, which are a series of oil and gas bearing
sands underlying eastern Ohio, western Pennsylvania and northern West Virginia.
The Balltown, Cooper, and Bradford Sandstone's, among others, are sandstone
formations of Upper Devonian age. Common productive depths range between
approximately 1,000 feet and 5,000 feet. The Company's target zones typically
range from 1,600 feet to 4,500 feet in depth. Historically, Upper Devonian wells
generally have long production lives, and many wells drilled in these formations
near the turn of the century are still in production.
The Company also maintains leasehold acreage in portions of Pennsylvania
and West Virginia with other potential producing formations. Although there are
variances in the nature and characteristics of these producing formations, they
are generally typical of the Appalachian area.
ACQUISITION OF PROPERTIES
North Coast continually evaluates undeveloped prospects originated by its
staff or other independent geologists as well as other gas and oil companies. If
review of a prospect indicates that it may be geologically and economically
attractive, the Company will attempt to obtain a lease of the mineral rights on
the acreage.
Typically, the Company will acquire the entire working interest in a lease
in consideration of paying a lease bonus and annual rentals subject to a
landowner's royalty and, where the property is acquired through a third party,
possibly an overriding royalty interest. After obtaining these drilling rights,
the Company continues to evaluate the properties for potential drilling.
Substantially all of the Company's drilling operations are currently conducted
in conjunction with the Drilling Programs. If a prospect is selected for
drilling through a Drilling Program, the Company assigns the minimum required
acreage for a well to such entity. In such a case, the Company retains the
balance of the leasehold acreage for future drilling.
In 1994, the Company acquired certain oil and gas interests in Erie and
Crawford Counties in northwestern Pennsylvania previously owned by a private
company. These properties included the entire working interest in 163 producing
wells, 43 miles of gas gathering lines and additional drilling locations.
In 1998, the Company acquired certain oil and gas interests and operations
in 28 wells in Ohio and Pennsylvania previously owned by an employee of the
Company and also acquired seven wells and a gathering
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system from Lomak Petroleum, an affiliate of the Company. The Company also
acquired additional interests in certain of its older Drilling Programs by
offering to its investors an exit strategy from the Drilling Programs. The
Company currently structures the agreements with the Drilling Programs such that
the investor may present their interest to the Company for purchase on a
predetermined pricing formula after a five-year holding period.
The Company intends to continue to review potential acquisitions of oil
and gas properties, but had no commitment with respect to any material
acquisition at March 31, 1998.
DRILLING PROGRAMS
From the Company's inception in 1981 through March 31, 1998, North Coast
has sponsored 48 Drilling Programs to engage in oil and gas drilling and
development operations. Public Drilling Programs accounted for seven of these
programs, while 41 were sold through private placements. Twenty-one of the
twenty-two partnerships were dissolved as a result of the Exchange Offer and,
the Company currently is managing 27 Drilling Programs.
Each Drilling Program has been conducted as a separate limited partnership
with the Company serving as managing general partner of each. To maintain the
marketability of its Drilling Programs, the Company continually reviews program
structure and performance and makes modifications from program to program, as it
deems appropriate. These modifications have included changes to the compensation
arrangements between the Company and the Drilling Programs, including charges
for its drilling and administrative services, and changes in the Company's
interest in the Drilling Programs.
The Company acts as operator and general contractor for drilling and
production operations, undertaking to drill and complete Drilling Program wells
and to serve as operator for producing wells for producing well operations. In
the Drilling Programs, typically the entire working interest in the leasehold is
acquired by the program, although only the minimum required acreage for a well
is assigned by the Company to the Drilling Program.
As managing general partner, North Coast is subject to full liability for
the obligations of the Drilling Programs although it is indemnified by each
program to the extent of the assets of the Drilling Programs under certain
circumstances. The partnership interests in the Drilling Programs constitute
securities and the Company is subject to potential liability for failure to
comply with applicable federal and state securities laws and regulations.
Typically, each Drilling Program is structured as a "functional
allocation" program whereby the non-industry investors contribute cash in an
aggregate amount equal to the intangible drilling and development costs to be
incurred for the Drilling Program's wells. The Company contributes the drill
sites to the Drilling Program and agrees to contribute all tangible equipment
necessary to drill, complete and produce each well, as well as organizational
and syndication costs of the Drilling Program. The allocation of partnership
revenues in each Drilling Program may vary depending upon the structure chosen
by the Company, with the Company's percentage interest ranging from 20% to 40%.
Interests in North Coast's Drilling Programs are sold to investors through
securities dealers registered with the NASD. In each program, NCE Securities,
Inc., acts as placement agent and enters into selling agreements with a number
of broker-dealers to assist it in selling the interests.
The Drilling Programs raised $6.5 million during fiscal 1996, $3.0
million during fiscal 1997 and $2.7 million during fiscal 1998 from investors.
The Company attributes these decreases to the uncertainties related to natural
gas prices and the purchase of approximately 47% of the Company's voting stock
outstanding on September 4, 1996 by Lomak Petroleum, Inc. ("Lomak"). The Company
intends to continue its efforts to market its Drilling Programs and increase the
number of wells drilled and operated. If these efforts are unsuccessful, the
Company would anticipate seeking alternatives including joint ventures with
industry partners and the financing of drilling activity through internal cash
flow and other financing alternatives.
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DRILLING SERVICES
The Company enters into turnkey contracts with the Drilling Programs to
drill program wells. Pursuant to these drilling contracts, the Company is
responsible for the drilling and development of the wells. The Company
subcontracts with third parties for the performance of a substantial portion of
the operations required to drill, complete and equip these wells for production.
Although the Company manages and supervises all necessary drilling and related
service and equipment operations on these wells, there are a number of third
party services to obtain, including contract drilling, fracturing, logging and
pipeline construction which are performed by subcontractors who specialize in
those operations. Since the Company contracts with the Drilling Programs on a
turnkey (fixed price) basis, the Company is responsible for drilling and
completing the wells, regardless of the actual cost. Consequently, the Company
is subject to the risk that prices incurred in the actual drilling and
development operations could increase beyond its contract price thereby
rendering its drilling contracts less profitable or unprofitable. Moreover,
difficulties encountered in drilling and completion operations can substantially
increase costs sometimes without recourse for the Company. The Company
continually monitors the cost incurred in drilling, completion and production
operations and reviews its turnkey contract prices for each Drilling Program in
order to reduce the risk of unprofitable drilling operations. These turnkey
drilling prices are subject to change based on competition, the return sought by
Drilling Programs investors, the Company's revenue and profit considerations and
other industry conditions.
OIL FIELD SERVICE OPERATIONS
As of March 31, 1998, the Company operated 691 wells, all of which were
located in Ohio and Pennsylvania. As operator of producing wells, the Company is
responsible for the maintenance and verification of all production records,
contracting for oil and gas sales, distribution of production proceeds and
information, and compliance with various state and federal regulations.
Generally, the Company provides the routine day-to-day production operations for
producing wells and also subcontracts certain oil field operations.
The Company receives a monthly operating fee for each producing well it
operates and is reimbursed for most third party costs associated with operations
and production of the wells. The Drilling Programs each pay the Company their
specified operating fee based upon the investors' aggregate interest in the
Drilling Program wells, exclusive of the Company's ownership interest.
GAS-GATHERING ACTIVITIES
In connection with the drilling and development of the wells that it
operates, the Company has constructed and owns approximately 202 miles of
natural gas-gathering pipelines in various counties throughout eastern Ohio and
western Pennsylvania. These pipelines carry natural gas from the wellhead to the
gas transmission systems of various utilities for sale to such utilities, to
natural gas brokers purchasing gas for resale to others or to industrial
purchasers pursuant to self-help gas purchase arrangements. These systems
gathered gas from 604 wells as of March 31, 1998. The Company continues its
construction of new pipelines and the establishment of compressor facilities in
order to expand the number of purchasers available to the Company.
For such gas-gathering services, the Company collects certain allowances
from public utilities, end-users or other natural gas purchasers (including
natural gas brokers). These gathering fees or transportation allowances averaged
approximately $.20 per Mcf of natural gas at March 31, 1998.
MARKETS
The ability of the Company to market oil and gas depends to an extent, on
factors beyond its control. The potential effects of governmental regulation and
market factors including alternative domestic and imported energy sources,
available pipeline capacity, and general market conditions are not entirely
predictable.
Natural Gas. Natural gas is generally sold pursuant to individually
negotiated gas purchase contracts, which vary in length from spot market sales
of a single day to term agreements that may extend several years.
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Customers of the Company purchasing natural gas include marketing affiliates of
the major pipeline companies, natural gas marketing companies, and a variety of
commercial/public authorities, industrial, and institutional end users who
ultimately consume the gas. Gas purchase contracts define the terms and
conditions unique to each of these sales. The price received for natural gas
sold on the spot market may vary daily reflecting changing market conditions.
As discussed, the deliverability and price of natural gas are subject to
both governmental regulation and supply/demand forces. During the past several
years' regional surplus and shortage of natural gas situations have occurred,
resulting in wide fluctuations in the prices achieved.
The lengths of the contracts as defined in the "Term" provision in the
Company's gas purchase agreements vary widely. Additionally, several of the
Company's contracts provide for monthly pricing which are derived from published
NYMEX or Appalachian price indexes. The Columbia Transmission (TCO) and
Consolidated Natural Gas (CNG) Index prices, which create a basis for spot sales
prices in the Mid Atlantic and northeastern United States, ranged from $2.00 to
$3.59 per Mcf during fiscal 1998. As of March 31, 1998, approximately one-third
of the Company's natural gas contracts are fixed price contracts with industrial
end-users. The prices received from these contracts range between $1.97 and
$4.43 per Mcf, with one-half of these contracts being committed for less than
one year. The remainder of the Company's natural gas contracts are with
utilities and marketers. Approximately 90% of the wells operated by the Company,
which produce gas to fulfill the contractual obligations to utilities and
marketers during the summer months, contain fixed prices ranging from $1.75 to
$3.15 per Mcf. In addition, one-third of these wells contain market sensitive
provisions during the winter months. The range of Appalachian unit pricing
during the winter of 1997/1998 was from $2.12 to $3.59 per Mcf. For the twelve
months ended March 31, 1998, the Company received an average price of $2.50 per
Mcf of gas sold.
Due to the seasonal supply and demand market pressures, prices paid by
purchasers will continue to fluctuate for the next several years. The Company
has pursued a strategy of varying the length and pricing provisions of its gas
purchase contracts so as to maintain flexibility to react to those fluctuating
prices. Due to rising market conditions, the duration of recently renegotiated
fixed price contracts has been limited to a year or less. Should market trends
change, the Company will endeavor to commit a larger portion of its natural gas
to longer-term arrangements to optimize revenues derived from these sales.
During the past several years, an over abundance of natural gas supplies
and promulgation of State and Federal regulations pertaining to the sale,
transportation, and marketing of natural gas resulted in increasing competition
and declining prices. It is likely that supply and demand factors will continue
to be the driving force in the evolving marketplace.
Crude Oil. Oil produced from the Company's properties is generally sold at
the prevailing field price to one or more of a number of unaffiliated purchasers
in the area. Generally, purchase contracts for the sale of oil are cancelable on
30 days notice. The price paid by these purchasers is generally an established,
or "posted," price that is offered to all producers. The Company received an
average price of $16.18 per barrel for its oil during fiscal 1998; however,
during the last several years prices paid for crude oil have fluctuated
substantially. The price posted for purchase contracts for the sale of oil at
March 31, 1998 was $13.25. Future oil prices are difficult to predict due to the
impact of worldwide economic trends, coupled with supply and demand variables,
and such non-economic factors as the impact of political considerations on OPEC
pricing policies and the possibility of supply interruptions. To the extent that
the prices, which the Company receives for its crude oil, decline from current
levels, revenues from oil production will be reduced accordingly.
COMPETITION
The gas and oil industry is highly competitive in all phases. The Company
encounters strong competition from other independent oil companies in acquiring
economically desirable properties as well as in marketing production therefrom
and obtaining external financing. Many of the Company's competitors may have
financial resources, personnel and facilities substantially greater than those
of the Company.
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REGULATION
Exploration and Production. The exploration, production and sale of
natural gas and oil are subject to various types of local, state and federal
laws and regulations. Such laws and regulations govern a wide range of matters,
including the drilling and spacing of wells, allowable rates of production,
restoration of surface areas, plugging and abandonment of wells and requirements
for the operation of wells. Such regulations may adversely affect the rate at
which the Company's wells produce gas and oil. In addition, legislation and new
regulations concerning gas and oil exploration and production operations are
constantly being reviewed and proposed. Most of the states in which the Company
owns and operates properties have laws and regulations governing several of the
matters enumerated above. Compliance with the laws and regulations affecting the
gas and oil industry generally increases the Company's cost of doing business
and consequently affects its profitability.
Environmental Matters. The discharge of oil, gas or other pollutants into
the air, soil or water may give rise to liabilities to the government and third
parties and may require the Company to incur costs to remedy the discharge.
Natural gas, oil or other pollutants (including salt water brine) may be
discharged in many ways, including from a well or drilling equipment at a drill
site, leakage from pipelines or other gathering and transportation facilities,
leakage from storage tanks and sudden discharges from damage or explosion at
natural gas facilities or gas and oil wells. Discharged hydrocarbons may migrate
through soil to water supplies or adjoining property, giving rise to additional
liabilities. A variety of federal and state laws and regulations govern the
environmental aspects of natural gas and oil production, transportation and
processing and may, in addition to other laws, impose liability in the event of
discharges (whether or not accidental), failure to notify the proper authorities
of a discharge, and other noncompliance with those laws. Compliance with such
laws and regulations may increase the cost of gas and oil exploration,
development and production although the Company does not currently anticipate
that compliance will have a material adverse effect on capital expenditures or
earnings of the Company.
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry. The
Company believes its present activities substantially comply, in all material
respects, with existing environmental laws and regulations. Nevertheless, no
assurance can be given that environmental laws will not, in the future, result
in a curtailment of production or material increase in the cost of production,
development or exploration or otherwise adversely affect the Company's
operations and financial condition. Although the Company maintains liability
insurance coverage for certain liabilities from pollution, such environmental
risks generally are not fully insurable; the amount of such coverage is
currently $1,000,000 and is provided on a "claims made" basis.
Marketing and Transportation. The interstate transportation and sale for
resale of natural gas is regulated by the Federal Energy Regulatory Commission
(the "FERC") under the Natural Gas Act of 1938 ("NGA"). The wellhead price of
natural gas is also regulated by FERC under the authority of the Natural Gas
Policy Act of 1978 ("NGPA"). The Natural Gas Wellhead Decontrol Act of 1989 (the
"Decontrol Act"), which was enacted on July 26, 1989, eliminated all gas price
regulation effective January 1, 1993. In addition, FERC recently has proposed
several rules or orders concerning transportation and marketing of natural gas.
The impact of these rules and other regulatory developments on the Company
cannot be predicted.
In 1992, the Federal Energy Regulatory Commission (FERC) finalized Order
636, regulations pertaining to the restructuring of the interstate
transportation of natural gas. Pipelines serving this function have since been
required to "unbundle" the various components of their service offerings, which
include gathering, transportation, storage, and balancing services. In their
current capacity, pipeline companies must provide their customers with only the
specific service desired, on a non-discriminatory basis. Although North Coast is
not an interstate pipeline, the Company believes the changes brought about by
Order 636 have increased competition in the marketplace, resulting in greater
market volatility.
Various rules, regulations and orders, as well as statutory provisions may
affect the price of natural gas production and the transportation and marketing
of natural gas.
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OPERATING HAZARDS AND UNINSURED RISKS
The Company's gas and oil operations are subject to all operating hazards
and risks normally incident to drilling for and producing gas and oil, such as
encountering unusual formations and pressures, blow-outs, environmental
pollution, and personal injury. The Company will maintain such insurance
coverage as it believes to be appropriate, taking into account the size of the
Company and its proposed operations. The Company currently does not maintain
insurance coverage for physical loss or damage to equipment located on the wells
or for selected properties (such as crude oil stored in tanks). The Company's
insurance policies also have standard exclusions. Losses can occur from an
uninsurable risk or in amounts more than existing insurance coverage. The
occurrence of an event, which is not insured or not fully insured, could have an
adverse impact on the Company's revenues and earnings.
EMPLOYEES
At March 31, 1998, the Company had 40 employees, including 15 field
employees. No employees are represented by a union and the Company believes that
it maintains good relations with its employees.
FORWARD-LOOKING STATEMENTS.
This Annual Report on Form 10-K contains forward-looking statements that
involve risks and uncertainties. The Company's actual results may differ
significantly from the results discussed in the forward-looking statements.
Factors that may cause such a difference include, but are not limited to, the
competition within the oil and gas industry, the price of oil and gas in the
Appalachian Basin area, the weather in the Company's geographic region, possible
acquisitions by the Company, the cost of the locating and drilling oil and gas
wells in the Appalachian Basin area, the amount of funds raised in the fiscal
1999 Drilling Programs, and the ability to locate productive oil and gas
prospects for development by the Company.
ITEM 2. PROPERTIES.
OIL AND GAS PROPERTIES
In the following tables, "gross" refers to the total acres or wells in
which the Company has a working interest and "net" refers to gross acres or
wells multiplied by the Company's percentage working interests therein. Royalty
interests held by the Company will not affect the Company's working interests
(net wells) in its properties and will not be reflected in net wells.
PROVED RESERVES. The following table reflects the estimates of
the Company's Proved Reserves as of March 31, 1998.
RESERVES
<TABLE>
<CAPTION>
Oil Reserves (Bbls):
<S> <C>
Proved Developed 126,700
Proved Undeveloped 9,000
----------
Total 135,700
Gas Reserves (Mcf):
Proved Developed 15,087,000
Proved Undeveloped 2,715,000
----------
Total 17,802,000
</TABLE>
Production. The following table summarizes the net oil and gas production
(on a rounded basis), average
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sales prices, and average production (operating) expenses per equivalent unit of
production for the periods indicated.
PRODUCTION
<TABLE>
<CAPTION>
Production Sales Price Average Operating
Years Ended Oil Gas Cost per Equivalent
March 31: (Bbls) (Mcf) Per Bbl Per Mcf Mcf (1)
- --------- ----- ----- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
1996 14,100 1,166,000 $17.01 $2.24 $.64 (2)
1997 16,200 1,153,000 $20.65 $2.43 $.62 (2)
1998 13,900 1,116,000 $16.18 $2.50 $.70 (3)
</TABLE>
(1) For calculation of average operating cost per equivalent Mcf, the
standard ratio of 6:1 for gas to oil was used.
(2) Includes costs of the Company's enhancement program and rework of two
wells in the Gulf Coast area of interest.
(3) Includes costs for the rework of ten wells located in Pennsylvania and
relocation of production facilities in Louisiana.
PRODUCTIVE WELLS. The following table sets forth the number of gross and
net productive oil and gas wells of the Company as of March 31, 1998. Wells are
classified as gas or oil according to their predominant product stream.
PRODUCTIVE WELLS
<TABLE>
<CAPTION>
Gross Wells (1) Net Wells
Oil Gas Total Oil Gas Total
--- --- ----- --- --- -----
<S> <C> <C> <C> <C> <C> <C>
26 699 725 9.76 338.37 348.13
</TABLE>
(1) Gross wells include 18 wells in which the Company owns only a royalty
interest.
ACREAGE. The following table sets forth the Developed and
Undeveloped Acreage of the Company, on both a gross and net basis, as of
March 31, 1998.
LEASEHOLD ACREAGE
Total Leasehold Acreage:
Gross Acres 69,500
Net Acres 34,700
Developed Acreage:
Gross Acres 39,400
Net Acres 19,700
Proved Undeveloped Acreage:
Gross Acres 1,300
Net Acres 700
Drilling Activity. The following table sets forth the results of drilling
activities on the Company's properties. Such information and the results of
prior drilling activities should not be considered as necessarily indicative of
future performance, nor should it be assumed that there is necessarily any
correlation between the number of productive wells drilled and the oil and gas
reserves generated thereby.
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All wells were drilled by March 31st of their respective years and are
reflected in the Drilling Activities table. Wells in which the Company owns only
a royalty interest are not reflected in the table below.
DRILLING ACTIVITIES
Fiscal year ended March 31,
- ---------------------------
<TABLE>
<CAPTION>
1996 1997 1998
---- ---- ----
Exploratory Wells (1)
Productive
<S> <C> <C> <C>
Gross 0 0 0
Net 0 0 0
Dry
Gross 0 0 0
Net 0 0 0
Development Wells (2)
Productive (3)
Gross 52 20 17
Net 9.80 3.88 4.72
Dry
Gross 0 0 0
Net 0 0 0
Total Wells (4)
Productive
Gross 52 20 17
Net 9.80 3.88 4.72
Dry
Gross 0 0 0
Net 0 0 0
</TABLE>
(1) Exploratory Wells are those wells drilled outside the confines of a known
productive reservoir area.
(2) Development Wells are those wells drilled within the confines of a known
productive reservoir.
(3) The number of productive wells for fiscal 1998 includes two gross and net
wells as productive development wells that are awaiting pipeline connection
or well completion operations at March 31, 1998.
(4) Total Wells is the sum of the Exploratory and Development Wells.
FACILITIES
The Company owns a 12,000 square foot building, its corporate
headquarters, in Twinsburg, Ohio. The office facility is in a centralized
location, which during fiscal 1997 allowed the Company to relocate certain
operations and its personnel from its Cleveland and Youngstown offices. The
Youngstown facility owned by the Company is used for field operations.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings to which the Company is a
party or to which any of its property is subject.
9
<PAGE> 12
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
During the fourth quarter of the fiscal year ended March 31, 1998, there
were no matters submitted to a vote of security holders through the solicitation
of proxies or otherwise.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
The Common Stock is traded on the NASDAQ Small Cap Market under the symbol
"NCEB". The following tables sets forth, for the fiscal periods indicated the
high and low bid and ask prices for the Common Stock.
Common Stock
(Amounts rounded to the nearest 32nd)
<TABLE>
<CAPTION>
High Low
---- ---
Bid Ask Bid Ask
--- --- --- ---
FISCAL 1997
<S> <C> <C> <C> <C>
First Quarter....................... $1 1/16 $1 3/16 $1/2 $ 3/4
Second Quarter...................... 1 7/16 1 5/8 5/8 3/4
Third Quarter....................... 1 5/16 1 1/2 7/8 1 1/16
Fourth Quarter...................... 1 3/16 1 3/8 5/8 3/4
FISCAL 1998
First Quarter....................... $1 $1 1/32 $11/16 $ 3/4
Second Quarter...................... 1 3/16 1 5/16 13/16 27/32
Third Quarter....................... 31/32 1 1/32 19/32 11/16
Fourth Quarter...................... 1 1 1/32 17/32 5/8
</TABLE>
As of June 22, 1998, there were approximately 16,617,881 shares of Common
Stock outstanding, which were held by approximately 1,300 holders of record.
Holders of Series A Preferred Stock (convertible to 2.3 shares of Common
Stock) are entitled to receive semi-annual non-cumulative cash dividends at an
annual rate of $.60 per share. Such dividends are payable on June 1 and December
1 of each year. The holders of Series B Preferred Stock (currently convertible
to 6.47 shares of Common Stock) are entitled to receive quarterly cumulative
cash dividends at an annual rate of $1.00 per share. For the year ended March
31, 1998, the Company paid $67,066 in aggregate cash dividends on its Series B
Preferred Stock.
Whenever distributions on the Series B Preferred Stock have not been paid
for an amount equal to six quarterly dividend payments, the number of directors
of the Company may be increased, and the holders of the Series B will be
entitled to elect such additional directors on the Board of Directors. Such
voting right will terminate when all such distributions accrued and in default
have been paid in full or set apart of payment. The Company has dividends in
arrears on its Series B Preferred Stock of $335,330 at March 31, 1998.
The Company has never paid any cash dividends on its Common Stock and is
currently restricted from paying cash dividends on any of its capital stock
under the terms of its reducing revolving credit facility. The Company currently
intends to retain future earnings in order to provide funds for use in the
operation of its business.
10
<PAGE> 13
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth-selected financial data for the Company for
each of the five fiscal years ended March 31, 1994, 1995, 1996, 1997 and 1998.
<TABLE>
<CAPTION>
Years Ended March 31
(In thousands, except per share amounts)
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Revenues $ 12,834 $ 15,275 $ 10,860 $ 9,665 $ 8,591
Net Income (Loss) 652 295 (1,254) 292 262
Net Income (Loss) per Share(1) .00 (.05) (.24) (.02) (.00)
Total Assets 15,796 21,136 20,243 21,229 22,312
Long-term Debt (less current portion) 3,626 6,197 8,955 10,721 7,171
</TABLE>
(1) Net Income (Loss) per share has been restated to reflect stock
dividends.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
OVERVIEW
The Company is engaged in the exploration, development and production of
natural gas and oil, primarily in conjunction with the Drilling Programs it
sponsors and manages. The Company derives its revenues from its own oil and gas
production and turnkey drilling, well operations, gas gathering, transportation
and gas marketing services performed under contract with the Drilling Programs.
Since inception, the Company has raised approximately $84,000,000 from the
sale of partnership interests, which has resulted in the formation of 48
partnerships.
Several factors may affect the amount of the Company's revenues with
respect to the activities of the Drilling Programs. The amount of funds raised
by each Drilling Program determines the number of wells for which the Company
receives drilling revenues. The Company continually monitors the cost incurred
in drilling, completion and production operations and reviews its turnkey
contract prices for each Drilling Program in order to reduce the risk of
unprofitable drilling operations to the Company and the economic considerations
of the investors in the Drilling Programs. The turnkey drilling contract price
between the Drilling Programs and the Company may vary among Drilling Programs
depending on competition and other cost factors and the returns sought by
investors in the Drilling Programs. The Company's capital availability, as well
as revenue and profit considerations, may result in the Company changing its
percentage interest ownership in future Drilling Programs.
The Company's growth depends on a number of factors, including its
continued ability to raise Drilling Program funds from non-industry investors to
increase the number of wells from which the Company will receive production,
contract drilling and service-related revenues and the Company's ability to
maintain adequate liquidity to provide its contributions to new Drilling
Programs and to acquire additional proved undeveloped or proved producing
properties. The Company's growth is also dependent on several external factors,
including the price at which gas, and to a lesser extent oil, can be found and
sold.
The Company's proved developed natural gas reserves increased to 15 Bcf
for fiscal 1998 from 14.5 Bcf for fiscal 1997 while proved developed oil
reserves increased to 126,700 barrels from 120,200 barrels, respectively. The
increase in proved developed natural gas reserves resulted from the purchase of
partnership interests from certain of the Company's Drilling Program investors
and working interests in certain wells from unrelated parties coupled with
upward revisions of the gas reserves of the Company's existing wells. The proved
gas reserves (developed and undeveloped) increased to 17.8 Bcf for fiscal 1998
from 17 Bcf for fiscal 1997. The increase in proved gas reserves was due to the
increases mentioned previously for the proved developed reserves coupled with
the upward revision to
11
<PAGE> 14
the proved undeveloped reserves for drilling locations that were proved through
the Company's recent drilling programs. Proved oil reserves (developed and
undeveloped) increased to 135,700 barrels at March 31, 1998 from 120,200 barrels
at March 31, 1997 due primarily to the upward revision of 26,400 barrels for
fiscal 1998. The Company recognizes as proved undeveloped reserves the potential
oil and gas which can reasonably be expected to be recovered from drillable
locations which the Company owned (or had rights to) at fiscal year end which
are offsetting locations to wells that have indicated commercial production in
the objective formation and which the Company fully expects to drill in the very
near future. Changes in the Standardized Measure of Discounted Future Net Cash
Flows are set forth in Note 11 of the Company's financial statements. The above
mentioned additions and sales of natural gas, coupled with the development costs
associated with undeveloped acreage, create timing differences which are
reflected in the Other category of the Standardized Measure. Of the Company's
total proved reserves, approximately 85% are proved developed and approximately
15% are proved undeveloped based upon equivalent unit Mcfs. Proved undeveloped
acreage requires considerable capital expenditures to develop. Management of the
Company believes that a significant percentage of the proved undeveloped
reserves should be recovered in future years, although no assurance of such
recovery can be given.
The following table is a review of the results of operations of the
Company for the fiscal years ended March 31, 1996, 1997 and 1998. All items in
the table are calculated as a percentage of total revenues.
<TABLE>
<CAPTION>
Revenues: 1996 1997 1998
---- ---- -----
<S> <C> <C> <C>
Oil and gas production 26% 32% 35%
Drilling revenues 50 39 34
Well operating, transportation and other 15 19 19
Administrative and agency fees 8 9 11
Other 1 1 1
---- ---- ----
Total Revenues 100% 100% 100%
---- ---- ----
Expenses:
Oil and gas production expenses 7% 8% 10%
Drilling costs 38 29 29
Oil and gas operations 8 10 7
General and administrative expenses 26 24 26
Depreciation, depletion, amortization,
impairment and other 30 14 14
Abandonment of oil and gas properties 1 1 1
Provision (credit) for income taxes (6) 0 0
Other 7 11 10
---- ---- ----
Total Expenses 111% 97% 97%
---- ---- ----
Net Income (Loss) (11)% 3% 3%
==== ==== ====
</TABLE>
The following discussion and analysis reviews the results of operations
and financial condition for the Company for the years ended March 31, 1996 1997
and 1998. This review should be read in conjunction with the Financial
Statements and other financial data presented elsewhere herein.
COMPARISON OF FISCAL 1998 TO FISCAL 1997
REVENUES
Oil and gas production revenues decreased $123,627 (4%) to $3,013,929 for
fiscal 1998 compared to $3,137,556 for the prior corresponding period. The
decrease in oil and gas production revenues was a result of a decrease in oil
revenues of approximately $110,000 due to a decrease in the oil production and
in the average price received for oil by the Company between comparable periods.
For fiscal 1998 the Company received an average price of $16.18 per barrel of
oil and $2.50 per Mcf of natural gas compared to an average price of $20.65 per
barrel of oil and $2.43 per Mcf of natural gas received during fiscal 1997.
12
<PAGE> 15
Drilling Revenues for the period decreased by $795,259 (21%) for fiscal
1998 compared to fiscal 1997 due to the decrease in the number of wells
recognized in revenue. The Company recognized revenues for fiscal 1998
on 20 wells as compared to 29 wells for fiscal 1997. The decrease in the number
of wells recognized in drilling revenues was primarily due to the higher number
of carryover wells at the end of fiscal 1996 compared to fiscal 1997. The
Company has two wells in work-in-progress at fiscal year ended 1998 compared to
five at fiscal year ended 1997.
Revenues generated from well operating, transportation and other decreased
$237,198 (13%) for fiscal 1998 compared to fiscal 1997. This decrease was
primarily due to a decrease in unaffiliated third party gas sales. The
unaffiliated third party gas sales fluctuate from year to year based upon the
availability of these types of transactions.
Revenue from administrative and agency fees, which are based on a
percentage of the total investor capital raised in all of the Drilling Programs,
increased by $81,727 (9%) for fiscal 1998 compared to fiscal 1997 due to the
formation of the Drilling Programs in fiscal 1998. The administrative fees
derived from the fiscal 1998 Drilling Programs were charged a rate equal to 4.5%
of total capital raised compared to the prior years programs which are charged
an annual fee equal to 2% of total capital raised.
EXPENSES
Oil and gas production expense increased $63,183 (8%) for fiscal 1998 as
compared to fiscal 1997. This increase was primarily due to additional costs
incurred with relocation of certain production facilities in the Gulf Coast area
and costs associated with reworking wells in Pennsylvania.
Drilling costs for fiscal 1998 compared to fiscal 1997 decreased $360,027
(13%) due to the decreased number of wells completed between comparable periods.
The profit margin on drilling revenue decreased to 16% for fiscal 1998 compared
to 24% for fiscal 1997. The decrease in the drilling profit margin between
comparable periods was due to actual completion costs over the estimated
accruals from wells recognized in drilling income coupled with increased general
and administrative costs allocated to drilling activities. Net drilling income
decreased approximately $435,000 between fiscal year ends due to the fewer
number of wells drilled and completed.
Oil and gas operations expense decreased $324,271 (33%) for fiscal 1998 as
compared to fiscal 1997. This decrease was primarily due to reduced natural gas
purchases associated with unaffiliated third party gas sales.
Interest expense decreased to $839,342 for fiscal 1998 from $1,055,409 for
fiscal 1997. This decrease was primarily due to the reduction of the borrowings
under the Company's Credit Facility and other debt by utilizing funds received
from the sale of common stock. At March 31, 1998, $6,565,265 was outstanding
under the Company's Credit Facility, as compared to $8,640,000 at March 31,
1997.
Net income was $262,138 for fiscal 1998 compared to $291,750 for fiscal
1997. The decrease reflects the decreased drilling activity and production
revenues between comparable periods.
COMPARISON OF FISCAL 1997 TO FISCAL 1996
REVENUES
Oil and gas production revenues increased $288,946 (10%) to $3,137,556 for
fiscal 1997 compared to $2,848,610 for the prior corresponding period. Oil and
gas production was relatively constant between years. The increase in production
revenues was primarily attributable to an average increase in gas prices of 8.5%
and an increase of oil prices of 21%. For fiscal 1997 the Company received an
average price of $20.65 per barrel of oil and $2.43 per Mcf of natural gas
compared to an average price of $17.01 per barrel of oil and $2.24 per Mcf of
natural gas received during fiscal 1996.
13
<PAGE> 16
Drilling Revenues for the period decreased by $1,706,734 (31%) for fiscal
1997 compared to fiscal 1996 due to the decrease in the number of wells
recognized in revenue. The Company recognized revenues for fiscal 1997 on 29
wells as compared to 45 wells for fiscal 1996. The decrease in the number of
wells recognized in drilling revenues was due to the decrease of $3,444,500 in
the amount of funds raised in the fiscal 1997 Drilling Programs of $3,015,500 as
compared to $6,460,000 for the fiscal 1996 Drilling Programs. Management of the
Company believes that this reduction was caused by the uncertainties arising
from the purchase of North Coast common stock by Lomak, a stockholder of the
Company. The Company had five wells in work-in-progress at year ended 1997
compared to 14 at year ended 1996.
Revenues generated from well operating, transportation and other increased
$249,337 (15%) for fiscal 1997 compared to fiscal 1996. This increase was
primarily due to an increase in unaffiliated third party gas sales. The
unaffiliated third party gas sales fluctuate from year to year based upon the
availability of these types of transactions and Company resources available. The
increase was also due to increases in well operating revenue and compression
revenue from the Company's five compressor stations.
EXPENSES
Drilling costs for fiscal 1997 compared to fiscal 1996 decreased
$1,284,173 (31%) due to the decreased number of wells completed between
comparable periods. The gross profit margin was 24% for both fiscal periods
presented. Net drilling income decreased approximately $423,000 between fiscal
year ends due to the fewer number of wells drilled and completed.
Oil and gas operations expense increased $95,918 (11%) for fiscal 1997 as
compared to fiscal 1996. This increase was primarily due to the increase in gas
purchases related to unaffiliated third party gas sales as discussed above.
General and administrative expenses decreased $570,768 (20%) for fiscal
1997 compared with fiscal 1996 despite incurring $311,000 in expenses associated
with the litigation with Lomak and the Company's offer to convert its Preferred
stock. The Lomak litigation was settled on November 12, 1996. This decrease in
general and administrative expenses was primarily due to costs savings derived
from reduced salaries and employee benefits when the Company reduced the size of
its staff. In addition, the staff reductions resulted in certain changes in job
responsibility resulting in additional general and administrative costs being
allocated to production expense and oil and gas operations.
Depreciation, depletion, amortization, impairment and other decreased
$1,912,789 (58%) for fiscal 1997 compared to fiscal 1996. This decrease was
primarily due to the implementation of the Statement of Financial Accounting
Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of" during fiscal 1996 which resulted
in an impairment of $1,561,776 for fiscal 1996 without a corresponding
impairment for 1997. In addition, the adoption of SFAS #121 resulted in a
decreased basis of existing properties being depleted for future periods.
Interest expense increased to $1,055,409 for fiscal 1997 from $772,731 for
fiscal 1996. This increase was primarily due to the Company's additional
borrowings on its reducing revolving credit facility. At March 31, 1997,
$8,640,000 was outstanding under the Company's Credit Facility compared to
$7,560,000 at March 31, 1996.
Operating income for the fiscal year ended 1997 increased $2,482,650 to
$1,267,176 compared to an operating loss of $1,215,474 for the fiscal year ended
1996. Net income increased $1,546,168 for fiscal 1997 to $291,750 as compared to
a net loss of $1,254,418 for fiscal 1996. These increases in operating income
and net income are primarily due to the decrease in general and administrative
expenses, depreciation, depletion, amortization, impairment and other as well as
increases in oil and gas production and well operating, transportation and
other.
14
<PAGE> 17
INFLATION AND CHANGES IN PRICES
While the costs of operations have been and will continue to be affected
by inflation, oil and gas prices have fluctuated during recent years and
generally have not followed the same pattern as inflation. With today's global
economy, especially in the area of oil and natural gas, Management believes that
other forces of the economy and world events, such as OPEC, the weather,
economic factors, and the effects of supply of natural gas in the United States
and regionally have a more immediate effect on current pricing than inflation.
The Company received an average price of $16.18 and $20.65 per barrel for fiscal
1998 and 1997, respectively, and $2.50 and $2.43 per Mcf for natural gas for
fiscal 1998 and 1997, respectively. On average, Appalachian natural gas prices
decreased $0.30/Mcf from fiscal year 1997 to fiscal year 1998. However, the
Company experienced a $0.07/Mcf increase for its natural gas during this period.
The increase the Company received can be attributed to a change in marketing
strategy including (1) aggressively targeting small to medium-sized commercial
end-users, (2) balancing the remainder of the Company's gas prices between spot
Appalachian based prices and Nymex based prices. This strategy allows the
Company the greatest opportunity to exceed the average regional prices, while
minimizing the effects of a negative fluctuation. The industry-wide weakness of
natural gas prices can be attributed to the effects of El Nino. Most of the
country experienced a relatively mild winter, which lessened demand for natural
gas. Although it is anticipated that there will be a decline in gas prices
during the summer months, the demand for gas by storage facilities, coupled with
the anticipated nationwide hot summer, may keep gas prices above last summer's.
Other variables potentially effecting gas prices are increased competition from
Canadian gas, effects of gas storage and possibly Federal Energy Regulatory
Commission ("FERC") Order 636. The FERC Order may have contributed to the lower
spot market prices by mandating an unbundling of pipeline service and allowing
open access to a variety of geographical markets. Management cannot predict what
long-term effects FERC Order 636 will have on either spot market prices or
longer term gas contracts.
Currently, the Company sells natural gas under both fixed price contracts
and on the spot market. The spot market price the Company receives for gas
production is related to several variables, including the weather and the
effects of gas storage. The Company anticipates that spot market prices will
continue to fluctuate in response to various factors, primarily weather and
market conditions.
In an effort to position itself to take advantage of future increases in
demand for natural gas, the Company continues to construct new pipeline systems
in the Appalachian Basin and to contract with other pipeline systems in the
region to transport natural gas production from Company wells.
LIQUIDITY AND CAPITAL RESOURCES
The Company's working capital was $782,000 at March 31, 1998 compared to
$325,000 at March 31, 1997. The increase of $457,000 in working capital from
March 31, 1997 reflects the Company's improved cash position from the sale of 5
million shares of Common Stock on September 4, 1997. As of March 31, 1998, the
Company had $6,565,265 outstanding under its Credit Facility. North Coast's
current ratio was 1.32 to 1.0 at March 31, 1998 and 1.11 to 1.0 at March 31,
1997.
The following table summarizes the Company's financial position at March
31, 1997 and 1998:
<TABLE>
<CAPTION>
(Amounts in Thousands) 1997 1998
--------------- ----------------
Amount % Amount %
------- --- ------- ---
<S> <C> <C> <C> <C>
Working capital $ 325 2 $ 782 4
Property and equipment 17,901 97 18,789 95
Other 151 1 275 1
------- --- ------- ---
Total $18,377 100 $19,846 100
======= === ======= ===
Long-term debt $10,720 58 $ 7,171 36
Deferred income taxes 347 2 336 2
Stockholders' equity 7,310 40 12,339 62
------- --- ------- ---
Total $18,377 100 $19,846 100
======= === ======= ===
</TABLE>
15
<PAGE> 18
CAPITAL RESOURCES AND REQUIREMENTS
The oil and gas exploration and development activities of North Coast
historically have been financed through the Drilling Programs, through
internally generated funds, and from bank financing.
The following table summarizes the Company's Statements of Cash Flows for
the years ended March 31, 1996, 1997 and 1998:
<TABLE>
<CAPTION>
(Amounts in Thousands) 1996 1997 1998
------------ --------------- ---------------
Dollars % Dollars % Dollars %
------ --- ------- --- ------- ---
<S> <C> <C> <C> <C> <C> <C>
Net cash provided by operating activities $1,049 27% $1,162 48% $ 1,176 45%
Net cash used for investing activities (3,377) (87) (1,827) (76) (2,122) (81)
Net cash provided by financing activities 1,513 39 616 26 1,022 39
------ --- ------- --- ------- ---
Increase (decrease) in cash and cash equivalents $ (815) (21)% $ (49) ( 2)% $ 76 3%
====== === ======= === ======= ===
</TABLE>
(1) All items in the previous table are calculated as a percentage of total cash
sources. Total cash sources include the following items, if positive: cash
flow from operations before working capital changes, changes in working
capital, net cash provided by investing activities and net cash provided by
financing activities, plus any decrease in cash and cash equivalents.
As the above table indicates, the Company's cash flow provided by
operating activities remained relatively constant at $1,176,000 for fiscal 1998
compared to $1,162,000 for fiscal 1997.
Net cash used for investing activities increased from $1,827,000 (76% of
cash sources) for fiscal 1997 to $2,122,000 (81% of cash sources) for fiscal
1998. The increase of only $295,000 reflects the corporate building purchased
during fiscal 1997. During fiscal 1998 the Company purchased additional
interests in certain of its older Drilling Programs, purchased interests and
operations in 35 wells, and continued to purchase tangible equipment to fulfill
its obligations to the partnerships it sponsors.
Net cash provided by financing activities increased by $406,000 from
fiscal 1997 to fiscal 1998. This increase reflects the sale of $5,000,000 of
Common Stock, reduced dividends paid on the Preferred Stock, the repayment of
loans to Lomak Petroleum, Inc. and the reduction of borrowings under the credit
facility.
On February 9, 1998, the Company entered an agreement ("Credit Agreement")
with ING (US) Capital Corporation to replace the $20,000,000 revolving credit
facility ("Credit Facility") with its previous lender. The Credit Agreement
provides for a borrowing base which is determined semiannually by the lender
based upon the Company's financial position, oil and gas reserves, as well as
outstanding letters of credit ($290,000 at March 31, 1998), as defined. The
Credit Agreement requires payment of an agent fee (0.75% for Credit Agreement)
on amounts available and 1/2% commitment fee on amounts not borrowed up to the
available line. At March 31, 1998, the Company's borrowing base was $10,000,000
subject to reduction for the outstanding letters of credit. Available borrowings
under the facility at March 31, 1998 were $3,144,735 and may subsequently change
based upon the semiannual reserve study and borrowing base determination (see
Note 4 to the Company's March 31, 1998 financial statements). The Credit
Facility provides that the payment of dividends with respect to the Common Stock
of the Company is prohibited. As of March 31, 1998, the Company had $6,565,265
outstanding under the Credit Facility, and was in compliance with its loan
covenants. Amounts borrowed under the Credit Facility bear interest at the prime
rate of the lending bank plus 1% or LIBOR plus 2.75%. The revolving line of
credit is reviewed semi-annually and extended by an amendment to the current
facility or converted to a term loan on July 1, 1999.
The amounts borrowed under its reducing revolving line of credit are
secured by the Company's receivables, inventory, equipment and a first mortgage
on certain of the Company's interests in oil and gas wells and reserves. The
mortgage notes are secured by certain land and buildings.
16
<PAGE> 19
In addition, at March 31, 1998, the Company had approximately $52,571
outstanding under a mortgage note payable. The mortgage note bears interest at
the rate of 8% and requires the Company to make monthly payments of
approximately $1,019 through July 2003. The Company purchased a building for its
headquarters and entered a mortgage note on May 13, 1996 for $540,000 over a
15-year term with an interest rate of 8.58% to be renegotiated every five years.
The amount outstanding under the mortgage note at March 31, 1998 was $507,404.
On September 4, 1997 the Company sold 5,747,127 shares of its Common Stock
for $5 million to NUON International bv, a limited liability company organized
under the laws of the Netherlands ("NUON"), pursuant to the terms of a stock
purchase agreement ("Agreement") by and between the Company and NUON dated
August 1, 1997. The Company also issued 134,000 warrants representing the right
of the holder to purchase one share of Common Stock for $0.875 per share in
connection with the sale of Common Stock to NUON. Pursuant to the terms of the
Agreement and subject to the satisfaction of certain conditions, including the
development of a plan of complementary business, NUON may purchase an additional
5,747,127 shares of Common Stock by each of September 30, 1998 and September 30,
1999. The Company is also obligated to issue 134,000 warrants on each occasion
NUON purchases an additional 5,747,127 shares. The additional warrants represent
the right to purchase one share of Common Stock for $0.875 per share.
A portion of the proceeds from the sale of Common Stock was utilized to
repay existing subordinated indebtedness in the amount of $1,475,537 plus
interest of $50,506 owed to Lomak with the remaining proceeds used for working
capital and to reduce the amount outstanding under the Company's Credit
Facility.
Subsequent to March 31, 1998, the Company acquired certain assets and
assumed certain obligations of Kelt Ohio, Inc., headquartered in Cambridge,
Ohio. The acquisition was made pursuant to a Purchase and Sale Agreement dated
April 8, 1998 as amended May 12, 1998. The purchase price for the acquired
assets was approximately $16 million. The acquired assets include approximately
900 natural gas and oil wells and Kelt's brine disposal facilities, drilling and
service rigs, natural gas compressors and gas gathering systems, and a large
inventory of oilfield service equipment and supplies. The Company funded the
acquisition using cash and an increase in its existing line of credit.
Approximately $15 million of the total purchase price was financed under a
recently expanded credit facility with the remaining amount paid in cash. An
amended credit facility dated May 29, 1998 expands the Company's borrowing base
to $25 million. The credit agreement calls for payments to reduce the Credit
Facility to $20 million by July 1, 1999 if NUON International bv, the Company's
largest stockholder, does not exercise its option to purchase an additional $5
million in common stock by September 4, 1998. The balance availability under the
Credit Facility is $1.2 million as of June 8, 1998.
Management of the Company believes that general economic conditions and
various sources of available capital, including current available borrowings
under the Credit Facility and the expected funds to be received from NUON, will
be sufficient to fund the Company's operations and meet debt service
requirements through fiscal 1999.
In the event that available borrowings under the Credit Facility are not
sufficient, NUON does not exercise its option to purchase additional Common
Stock or additional financing cannot be obtained; the Company would need to
conserve cash resources. In order to accomplish this objective, the Company
believes that it would be necessary to take various actions, including reducing
the amount of capital raised in future Drilling Programs, the introduction of
additional cost cutting measures and the possible sale of certain assets.
Management of the Company believes that measures of this type may have a
material adverse effect on the Company.
YEAR 2000
The Company has developed an action plan and identified the resources
needed to convert the majority of its computer systems and software applications
to achieve a year 2000 date conversion with no effect on customers or disruption
to business operations. Implementation of the plan has begun and the Company
anticipates completion of testing or replacement of systems by the end of fiscal
1999. The Company estimates that the cost to complete these efforts, which
primarily includes the purchase of software and hardware upgrades under normal
maintenance agreements with third party vendors, will approximate $60,000, and
will be expended primarily in fiscal 1999. In
17
<PAGE> 20
addition, the Company has discussed with its vendors and customers the need to
be 2000 compliant. Although the Company has no reason to believe that its
vendors and customers will not be compliant by the year 2000, the Company is
unable to determine the extent to which year 2000 issues will effect its vendors
and customers, and the Company continues to discuss with its vendors and
customers the need for implementing procedures to address this issue.
ACCOUNTING STANDARDS
In February 1997, the Financial Accounting Standards Board issued SFAS No.
131, "Disclosures about Segments of an Enterprise and Related Information" which
may require the Company to report certain information about operating segments
including product, services and geographical areas. SFAS No. 131 is required to
be adopted for financial statements with fiscal years beginning after December
15, 1997. The Company has not determined the impact, if any, of this standard.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA.
The following pages contain the Financial Statements and supplementary data
required by Item 8 of Part II of Form 10-K.
18
<PAGE> 21
NORTH COAST ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
F-1
<PAGE> 22
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
INDEX TO FINANCIAL STATEMENTS
-----------------------------
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS F-3
FINANCIAL STATEMENTS:
Consolidated balance sheets F-4 - F-5
Consolidated statements of operations F-6
Consolidated statements of stockholders' equity F-7 - F-8
Consolidated statements of cash flows F-9 - F-10
Notes to consolidated financial statements F-11 - F-29
All other financial statement schedules have been
appropriately omitted if the information is not required or
is furnished in the financial statements or in the notes
thereto.
F-2
<PAGE> 23
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
North Coast Energy, Inc.:
We have audited the accompanying consolidated balance sheets of North Coast
Energy, Inc. (a Delaware corporation) and Subsidiaries as of March 31, 1997 and
1998, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three fiscal years in the period ended
March 31, 1998. 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 audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of North Coast Energy, Inc. and
Subsidiaries as of March 31, 1997 and 1998, and the results of their operations
and their cash flows for each of the three fiscal years in the period ended
March 31, 1998, in conformity with generally accepted accounting principles.
Arthur Andersen LLP
Cleveland, Ohio,
June 4, 1998.
F-3
<PAGE> 24
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED BALANCE SHEETS
---------------------------
MARCH 31, 1997 and 1998
-----------------------
ASSETS
------
<TABLE>
<CAPTION>
1997 1998
------------ ------------
<S> <C> <C>
CURRENT ASSETS:
Cash and equivalents $ 1,503,278 $ 1,578,984
Accounts receivable-
Trade, net 1,306,577 1,311,714
Affiliates 81,456 96,011
Inventories 200,971 189,223
Deferred income taxes 26,000 26,000
Refundable income taxes 50,000 38,000
Other, net 8,488 8,057
------------ ------------
Total current assets 3,176,770 3,247,989
------------ ------------
PROPERTY AND EQUIPMENT, at cost:
Land 93,437 93,437
Oil and gas properties (successful efforts) 24,290,505 25,754,748
Pipelines 4,158,204 4,380,772
Vehicles 348,825 420,026
Furniture and fixtures 501,049 508,417
Building and improvements 788,419 786,689
------------ ------------
30,180,439 31,944,089
Less- Accumulated depreciation, depletion, amortization
and impairment (12,279,402) (13,155,288)
------------ ------------
17,901,037 18,788,801
OTHER ASSETS, net 150,893 274,726
------------ ------------
$ 21,228,700 $ 22,311,516
============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated balance
sheets.
F-4
<PAGE> 25
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED BALANCE SHEETS
---------------------------
MARCH 31, 1997 and 1998
-----------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
<TABLE>
<CAPTION>
1997 1998
--------------- -------------
<S> <C> <C>
CURRENT LIABILITIES:
Current portion of long-term debt $ 108,900 $ 88,300
Accounts payable 1,952,863 1,824,740
Accrued expenses 320,255 250,073
Billings in excess of costs on uncompleted contracts 469,361 302,881
--------------- -------------
Total current liabilities 2,851,379 2,465,994
--------------- -------------
LONG-TERM DEBT, net of current portion 10,720,510 7,171,035
DEFERRED INCOME TAXES, net 347,200 335,200
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Series A, 6% Noncumulative Convertible Preferred stock,
par value $.01 per share; 563,270 shares authorized;
76,951 and 75,481 issued and outstanding (aggregate
liquidation value of $769,510 and $754,810,
respectively) 770 755
Series B, Cumulative Convertible Preferred stock, par
value $.01 per share; 625,000 shares authorized; 269,464
and 268,264 issued and outstanding (aggregate
liquidation value of $2,694,640 and $2,682,640,
respectively) 2,695 2,683
Undesignated Serial Preferred stock, par value $.01 per
share; 811,730 shares authorized; none issued and
outstanding - -
Common stock, par value $.01 per share; 40,000,000 shares
authorized; 10,753,895 and 16,612,931 issued and
outstanding 107,539 166,129
Additional paid-in capital 12,083,196 16,859,237
Retained deficit (4,884,589) (4,689,517)
------------- -------------
Total stockholders' equity 7,309,611 12,339,287
------------- -------------
$21,228,700 $22,311,516
============= =============
</TABLE>
The accompanying notes are an integral part of these consolidated balance
sheets.
F-5
<PAGE> 26
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998
<TABLE>
<CAPTION>
1996 1997 1998
-------------- --------------- -------------
<S> <C> <C> <C>
REVENUE:
Oil and gas production $ 2,848,610 $3,137,556 $3,013,929
Drilling revenues 5,490,364 3,783,630 2,988,371
Well operating, transportation and other 1,610,469 1,859,806 1,622,608
Administrative and agency fees 911,053 883,997 965,724
-------------- --------------- -------------
10,860,496 9,664,989 8,590,632
-------------- --------------- -------------
COSTS AND EXPENSES:
Oil and gas production expenses 796,530 777,163 840,346
Drilling costs 4,160,788 2,876,615 2,516,588
Oil and gas operations 881,025 976,943 652,672
General and administrative expenses 2,878,762 2,307,994 2,215,961
Depreciation, depletion, amortization, impairment and
other 3,298,359 1,385,570 1,242,200
Abandonment of oil and gas properties 60,506 73,528 88,947
-------------- --------------- -------------
12,075,970 8,397,813 7,556,714
-------------- --------------- -------------
INCOME (LOSS) FROM OPERATIONS (1,215,474) 1,267,176 1,033,918
-------------- --------------- -------------
OTHER INCOME:
Interest 63,063 47,491 62,263
Other 14,429 52,892 3,690
Gain on sale of property and equipment 18,295 - 1,609
-------------- --------------- -------------
95,787 100,383 67,562
-------------- --------------- -------------
OTHER EXPENSE:
Interest 772,731 1,055,409 839,342
Loss on sale of property and equipment - 20,400 -
-------------- --------------- -------------
772,731 1,075,809 839,342
-------------- --------------- -------------
INCOME (LOSS) BEFORE INCOME TAXES (1,892,418) 291,750 262,138
PROVISION (CREDIT) FOR INCOME TAXES:
Current (83,100) (5,100) 12,000
Deferred (554,900) 5,100 (12,000)
-------------- --------------- -------------
(638,000) - -
-------------- --------------- -------------
NET INCOME (LOSS) $ (1,254,418) $ 291,750 $ 262,138
============== =============== =============
NET LOSS APPLICABLE TO COMMON
STOCK (after Preferred stock dividends paid
or in arrears of $649,864, $458,606 and
$268,264 in 1996, 1997 and 1998,
respectively) $ (1,904,282) $ (166,856) $ (6,126)
============== =============== =============
NET LOSS PER SHARE (basic and diluted)
$(0.24) $(0.02) $(0.00)
============== =============== =============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE> 27
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998
-------------------------------------------------
<TABLE>
<CAPTION>
Series A Series B
Preferred Stock Preferred Stock
----------------------- ------------------------
Shares Amount Shares Amount
--------- ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, MARCH 31, 1995 309,460 $ 3,095 464,665 $ 4,647
Net loss - - - -
Shares converted (4,260) (43) - -
Dividends on Series A Preferred stock ($0.60 per
share) - - - -
Dividends on Series B Preferred stock ($1.00 per
share) - - - -
----------- ---------- ------------ ----------
BALANCE, MARCH 31, 1996 305,200 3,052 464,665 4,647
Net income - - - -
Shares converted (228,249) (2,282) (195,201) (1,952)
Dividends on Series A Preferred stock ($.30 per
share) - - - -
Dividends on Series B Preferred stock ($.50 per
share) - - - -
----------- ---------- ------------ ----------
BALANCE, MARCH 31, 1997 76,951 770 269,464 2,695
Net income - - - -
Shares converted (1,470) (15) (1,200) (12)
Dividends on Series B Preferred stock ($.25 per
share) - - - -
Issuance of common stock - - - -
Issuance of stock bonus common shares - - - -
----------- ---------- ------------ ----------
BALANCE, MARCH 31, 1998 75,481 $ 755 268,264 $ 2,683
=========== ========== ============ ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
<PAGE> 28
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998
-------------------------------------------------
<TABLE>
<CAPTION>
Common Stock Additional Total
------------------- Paid-In Retained Stockholders'
Shares Amount Capital Deficit Equity
------------- ----------- ---------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
8,030,352 $ 80,304 $12,083,024 $ (2,948,183) $ 9,222,887
- - - (1,254,418) (1,254,418)
9,796 98 (55) - -
- - - (185,199) (185,199)
- - - (464,665) (464,665)
------------- ----------- ---------------- --------------- --------------
8,040,148 80,402 12,082,969 (4,852,465) 7,318,605
- - - 291,750 291,750
2,713,747 27,137 227 - 23,130
- - - (91,542) (91,542)
- - - (232,332) (232,332)
------------- ----------- ---------------- --------------- --------------
10,753,895 107,539 12,083,196 (4,884,589) 7,309,611
- - - 262,138 262,138
16,616 166 56 - 195
- - - (67,066) (67,066)
5,825,720 58,257 4,765,716 - 4,823,973
16,700 167 10,269 - 10,436
------------- ----------- ---------------- --------------- --------------
16,612,931 $166,129 $ 16,859,237 $ (4,689,517) $12,339,287
============= =========== ================ =============== ==============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-8
<PAGE> 29
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998
-------------------------------------------------
<TABLE>
<CAPTION>
1996 1997 1998
-------------- --------------- --------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $(1,254,418) $ 291,750 $262,138
Adjustments to reconcile net income (loss) to net
cash provided by operating activities-
Depreciation, depletion, amortization,
impairment and other 3,298,359 1,385,570 1,242,200
Abandonment of oil and gas properties 60,506 73,528 88,947
Loss (gain) on sale of property and
equipment (18,295) 20,400 (1,609)
Deferred income taxes (554,900) 5,100 (12,000)
Change in-
Accounts receivable 213,970 49,561 (19,692)
Inventories and other current assets 118,979 (102,127) 12,179
Refundable income taxes (115,000) 65,000 12,000
Other assets, net 88,129 23,109 (109,154)
Accounts payable (997,350) (521,662) (62,667)
Accrued expenses (143,417) 39,690 (70,182)
Billings in excess of costs on
uncompleted contracts 352,467 (167,986) (166,480)
-------------- --------------- --------------
Total adjustments 2,303,448 870,183 913,542
-------------- --------------- --------------
Net cash provided by operating
activities 1,049,030 1,161,933 1,175,680
-------------- --------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of property and equipment (3,389,274) (2,025,561) (2,124,052)
Proceeds on sale of property and equipment 12,253 198,669 2,000
-------------- --------------- --------------
Net cash used for investing
activities (3,377,021) (1,826,892) (2,122,052)
-------------- --------------- --------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-9
<PAGE> 30
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998
<TABLE>
<CAPTION>
1996 1997 1998
--------------- --------------- --------------
<S> <C> <C> <C>
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of accounts payable used to finance
property and equipment additions $ (236,422) $ (70,964) $(87,161)
Borrowings under revolving credit facility 3,800,000 2,080,000 6,765,265
Borrowings (repayments) under note payable to
stockholder 1,064,000 84,883 (1,453,674)
Repayment of borrowings under revolving credit
facility (2,290,003) (1,000,000) (8,840,000)
Payments on long-term debt (127,278) (140,656) (106,698)
Cash paid for deferred financing (47,354) (12,900) (88,223)
Proceeds from issuance of long-term debt - - 65,031
Net proceeds from issuance of common stock - - 4,834,604
Distributions and dividends (649,864) (323,874) (67,066)
--------------- --------------- --------------
Net cash provided by financing
activities 1,513,079 616,489 1,022,078
--------------- --------------- --------------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS (814,912) (48,470) 75,706
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 2,366,660 1,551,748 1,503,278
--------------- --------------- --------------
CASH AND EQUIVALENTS AT END OF YEAR $ 1,551,748 $ 1,503,278 $ 1,578,984
=============== =============== ==============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for-
Interest $ 716,000 $ 1,032,000 $ 887,000
Income taxes 30,000 52,000 51,000
SUPPLEMENTAL DISCLOSURES ON NONCASH INVESTING AND FINANCING
ACTIVITIES:
Long-term debt incurred for the purchase of
property and equipment $ 91,000 $ 638,000 $ 65,000
Accounts payable incurred for the purchase of
property and equipment 71,000 87,000 22,000
Accounts payable from interest on long-term debt 64,000 85,000 44,000
Accounts payable incurred for deferred financing - - 88,000
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-10
<PAGE> 31
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
MARCH 31, 1996, 1997 AND 1998
-----------------------------
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. ORGANIZATION
North Coast Energy, Inc. (North Coast), a Delaware corporation, was formed in
August 1988 to engage in the exploration, development and production of oil and
gas, the acquisition of producing oil and gas properties, and the organization
and management of oil and gas partnerships.
B. PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of North Coast
Energy, Inc. and its wholly owned subsidiaries (collectively, the Company),
North Coast Operating Company (NCOC), and NCE Securities, Inc. (NCE Securities).
In addition, the Company's investments in oil and gas drilling partnerships,
which are accounted for under the proportional consolidation method, are
reflected in the accompanying financial statements. The Company's ownership of
revenues in these drilling partnerships is as follows:
Capital Drilling Fund 1986-1 Limited Partnership 13.2%
North Coast Energy/Capital 1987-1 Appalachian
Drilling Program Limited Partnership 40.4%
North Coast Energy/Capital 1987-2 Appalachian
Drilling Program Limited Partnership 38.9%
North Coast Energy/Capital 1988-1 Appalachian Drilling
Program Limited Partnership 35.1%
North Coast Energy/Capital 1988-2 Appalachian
Drilling Program Limited Partnership 41.7%
North Coast Energy/Capital 1989 Appalachian
Drilling Program Limited Partnership 31.6%
North Coast Energy 1990-1 Appalachian Drilling
Program Limited Partnership 29.4%
North Coast Energy 1990-2 Appalachian Drilling
Program Limited Partnership 28.9%
North Coast Energy 1990-3 Appalachian Drilling
Program Limited Partnership 25.0%
North Coast Energy 1991-1 Appalachian Drilling
Program Limited Partnership 28.4%
F-11
<PAGE> 32
North Coast Energy 1991-2 Appalachian Drilling
Program Limited Partnership 25.6%
North Coast Energy 1991-3 Appalachian Drilling
Program Limited Partnership 28.9%
North Coast Energy 1992-1 Appalachian Drilling
Program Limited Partnership 25.0%
North Coast Energy 1992-2 Appalachian Drilling
Program Limited Partnership 27.8%
North Coast Energy 1992-3 Appalachian Drilling
Program Limited Partnership 39.5%
North Coast Energy 1993-1 Appalachian Drilling
Program Limited Partnership 32.6%
North Coast Energy 1993-2 Appalachian Drilling
Program Limited Partnership 31.7%
North Coast Energy 1993-3 Appalachian Drilling
Program Limited Partnership 30.0%
North Coast Energy 1994-1 Appalachian Drilling
Program Limited Partnership 31.4%
North Coast Energy 1994-2 Appalachian Drilling
Program Limited Partnership 25.0%
North Coast Energy 1994-3 Appalachian Drilling
Program Limited Partnership 25.0%
North Coast Energy 1995-1 Appalachian Drilling
Program Limited Partnership 20.0%
North Coast Energy 1995-2 Appalachian Drilling
Program Limited Partnership 20.0%
North Coast Energy 1996-1 Appalachian Drilling
Program Limited Partnership 20.0%
North Coast Energy 1996-2 Appalachian Drilling
Program Limited Partnership 20.0%
North Coast Energy 1997-1 Appalachian
Drilling Program Limited Partnership 38.2%
North Coast Energy 1997-2 Appalachian
Drilling Program Limited Partnership 22.1%
All significant intercompany accounts and transactions have been eliminated.
F-12
<PAGE> 33
C. CASH EQUIVALENTS
Investments having an original maturity of 90 days or less that are readily
convertible into cash have been included in, and are a significant portion of,
the cash and equivalents balances.
D. PROPERTY AND EQUIPMENT
Property and equipment are stated at cost and are depreciated or depleted
principally on methods and at rates designed to amortize their costs over their
estimated useful lives (proved oil and gas properties using the
unit-of-production method based upon estimated proved developed oil and gas
reserves, pipelines using the straight-line method over 10 to 14 years,
vehicles, furniture and fixtures using accelerated methods over 5 to 7 years,
building and improvements using accelerated methods over 31.5 years).
E. OIL AND GAS INVESTMENTS AND PROPERTIES
The Company uses the successful efforts method of accounting for oil and gas
producing activities. Under successful efforts, costs to acquire mineral
interests in oil and gas properties, to drill and equip exploratory wells that
find proved reserves, and to drill and equip development wells are capitalized.
Costs to drill exploratory wells that do not find proved reserves, costs of
development wells on properties the Company has no further interest in,
geological and geophysical costs, and costs of carrying and retaining unproved
properties are expensed.
Unproved oil and gas properties that are significant are periodically assessed
for impairment of value and a loss is recognized at the time of impairment by
providing an impairment allowance.
Other unproved properties are expensed when surrendered or expired.
When a property is determined to contain proved reserves, the capitalized costs
of such properties are transferred from unproved properties to proved properties
and are amortized by the unit-of-production method based upon estimated proved
developed reserves. To the extent that capitalized costs of groups of proved
properties having similar characteristics exceed the estimated future net cash
flows, the excess capitalized costs are written down to such amounts. Impairment
is recorded on a drilling program or property specific basis, as applicable.
On sale or abandonment of an entire interest in an unproved property, gain or
loss is recognized, taking into consideration the amount of any recorded
impairment if the property had been assessed. If a partial interest in an
unproved property is sold, the amount received is treated as a reduction of the
cost of the interest retained.
F. REVENUE RECOGNITION
The Company recognizes revenue on drilling contracts using the completed
contract method of accounting for both financial reporting purposes and income
tax purposes. This method is used because the typical contract is completed in
three months or less and financial position and results of operations do not
vary significantly from those which would result from use of the
percentage-of-completion method.
Provisions for estimated losses on uncompleted contracts are made in the period
in which such losses are determined. Billings in excess of costs on uncompleted
contracts are classified as current liabilities.
F-13
<PAGE> 34
Oil and gas production revenue is recognized as income as it is extracted and
sold from the properties. Other revenue is recognized at the time it is earned
and the Company has a contractual right to such revenue.
G. PER SHARE AMOUNTS
The computation of basic and diluted earnings per share for 1996, 1997 and 1998
does not assume the conversion of the unconverted Series A and B Preferred stock
or the effect of warrants and stock options outstanding due to a calculated loss
(after dividends) being incurred in each period and the effect, therefore, being
anti-dilutive.
The average number of outstanding shares used in computing both basic and
diluted net loss per share was 8,033,642, 8,240,776 and 14,106,492, for the
years ended March 31, 1996, 1997 and 1998, respectively.
H. RISK FACTORS
The Company operates in an environment with many financial risks, including, but
not limited to, its limited history of profitable operations, the ability to
acquire additional economically recoverable oil and gas reserves, the continued
ability to market drilling programs, the inherent risks of the search for
development of and production of oil and gas, the ability to sell oil and gas at
prices which will provide attractive rates of return, and the highly competitive
nature of the industry and worldwide economic conditions. The Company's ability
to expand its reserve base, diversify its operations and continue its marketing
efforts for and investments in drilling programs is also dependent upon the
Company's ability to obtain the necessary capital through operating cash flow,
additional borrowings or additional equity funds.
In the event that available borrowings under the Credit Facility are not
sufficient or additional financing cannot be obtained, the Company would be
required to continue its current efforts to conserve cash resources. In order to
accomplish this objective, the Company believes that it would be necessary to
take various actions, including reducing the amount of capital raised in future
Drilling Programs, the introduction of additional cost cutting measures and the
possible sale of certain assets.
I. ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
J. FINANCIAL INSTRUMENTS
The Company's financial instruments include cash and equivalents, accounts
receivable, accounts payable and debt obligations. The book value of cash and
equivalents, accounts receivable and payable are considered to be representative
of fair value because of the short maturity of these instruments. The Company
believes that the carrying value of its borrowings under its bank credit
facility and other debt obligations approximates their fair value as they bear
interest at adjustable interest rates which change periodically to reflect
market conditions. The Company's accounts receivable are concentrated in the oil
and gas industry. The Company does not view such a concentration as an unusual
credit risk.
F-14
<PAGE> 35
2. BILLINGS IN EXCESS OF COSTS ON UNCOMPLETED CONTRACTS:
Billings in excess of costs on uncompleted contracts consist of the following at
March 31:
<TABLE>
<CAPTION>
1997 1998
-------- --------
<S> <C> <C>
Billings on uncompleted contracts $738,554 $335,920
Costs incurred on uncompleted contracts 269,193 33,039
---------- ---------
$469,361 $302,881
=========== ===========
</TABLE>
3. LEASE COMMITMENTS:
The Company leases real and personal property under operating leases. The most
significant obligations under these lease agreements were for annual building
rentals, which included standard maintenance and insurance. Total rental expense
under the operating leases for the years ended March 31, 1996, 1997 and 1998,
amounted to approximately $82,000, $43,000 and $6,000, respectively. In 1996 and
1997, rent expense of approximately $65,000, and $34,000, respectively, was
incurred pursuant to the lease of the Company's previous corporate headquarters
from one of the Company's principal stockholders.
The Company currently has no noncancelable operating leases which require future
minimum rental payments.
4. LONG-TERM DEBT:
Long-term debt consists of the following at March 31:
<TABLE>
<CAPTION>
1997 1998
---- ----
<S> <C> <C>
Revolving credit notes payable--bank $ 8,640,000 $6,565,265
Notes payable to stockholder with interest at prime
plus 1% and 8%, repaid in 1998 1,453,674 -
Mortgage note payable to a bank, secured by land
and a building, requiring monthly payments of
approximately $1,019 (including interest at 8%)
through July 2003 60,216 52,571
Mortgage note payable to a bank, secured by land
and a building, requiring monthly payments of
approximately $5,248 (including interest at
8.58%) through May 2001. Thereafter the balance
of the note will be amortized over a ten-year
period, at an interest rate to be renegotiated
every five years 524,033 507,404
Various installment notes payable in aggregate monthly
installments (including interest) of $6,860 at March 31,
1998, through 2003 151,487 134,095
--------------- --------------
10,829,410 7,259,335
Less- Current portion 108,900 88,300
--------------- --------------
$10,720,510 $7,171,035
=============== ==============
</TABLE>
F-15
<PAGE> 36
The Company has a $20,000,000 revolving credit agreement with its lender at
March 31, 1998. The Agreement provides for a borrowing base which is determined
semiannually by the lender based upon the Company's financial position, oil and
gas reserves, as well as outstanding letters of credit ($290,000 at March 31,
1998), as defined. At March 31, 1998, the Company's borrowing base was
$10,000,000 subject to reduction for the outstanding letters of credit.
Available borrowings under the facility at March 31, 1998 were $3,144,735 and
may subsequently change based upon the semiannual reserve study and borrowing
base determination. Subsequent to year end, the availability decreased and
borrowing base increased in conjunction with the Kelt Ohio Acquisition (Note
14).
The revolving line of credit is reviewed semi-annually and may be extended by an
amendment to the current facility or converted to a term loan on July 1, 1999.
Amounts outstanding under the reducing revolving line of credit bear interest at
the lending bank's prime rate plus 1% or LIBOR plus 2.75%, or approximately 10%
and 8.5% at March 31, 1997 and 1998, respectively. The weighted average interest
rate on these borrowings was 9.9% and 10.1% for fiscal 1997 and 1998,
respectively. The agreement requires the Company to pay a commitment fee of .5%
on the unused amount of the available borrowings. The agreement contains certain
restrictive covenants, including working capital, current ratio, tangible net
worth, and EBITDA calculations, as defined. The Company was in compliance with
all covenants and restrictions at March 31, 1998.
The revolving credit facility and the notes are collateralized by substantially
all of the Company's assets including receivables, inventory, equipment and a
first mortgage on certain of the Company's interests in oil and gas wells and
reserves.
Future maturities of long-term debt for the years ended March 31, are as
follows:
<TABLE>
<S> <C> <C>
Fiscal 1999 $ 88,300
Fiscal 2000 1,041,671
Fiscal 2001 1,371,413
Fiscal 2002 1,369,197
Fiscal 2003 1,368,345
Thereafter 2,020,409
-------------
$7,259,335
=============
</TABLE>
The carrying amount of the Company's long-term debt approximates fair value, as
primarily all of the Company's debt instruments carry adjustable interest rates
which change periodically to reflect market conditions.
5. STOCKHOLDERS' EQUITY:
In September, 1997, the Company sold 5,747,127 shares of its common stock for
$5,000,000 to NUON International (NUON), pursuant to the terms of a stock
purchase agreement (NUON Agreement). Under the terms of the NUON Agreement, and
subject to the satisfaction of certain conditions, as defined, NUON may purchase
an additional 5,747,127 shares of common stock by each of September 30, 1998 and
September 30, 1999. Proceeds from the sale of common stock were utilized to
repay notes payable to a stockholder, reduce the amount outstanding under the
revolving credit facility and for working capital purposes.
F-16
<PAGE> 37
A. PREFERRED STOCK
The Board of Directors of North Coast has designated 563,270 shares of the
2,000,000 shares of preferred stock authorized as Series A, 6% Convertible
Noncumulative Preferred stock (Series A Preferred stock) and 625,000 shares of
preferred stock as Series B, Cumulative Convertible Preferred stock (Series B
Preferred stock).
Stockholders of Series A Preferred stock are entitled to vote such shares on any
and all matters submitted to a vote of the stockholders of the Company based
upon the number of votes such stockholders would have if the Series A Preferred
stock been converted into shares of common stock of the Company. Holders of
shares of Series A Preferred stock are entitled to receive, when and if declared
by the Board of Directors, noncumulative cash dividends at an annual rate of
$.60 per share. Shares of Series A Preferred stock are senior to shares of
common stock with respect to such cash dividends and junior to shares of Series
B Preferred stock.
Series A Preferred stock is convertible, at the stockholder's option, into
shares of common stock at the conversion rate of 2.3 shares of common stock for
each share of Series A Preferred stock converted.
All of the outstanding shares of Series A Preferred stock shall, at the option
of North Coast, be converted into shares of common stock pursuant to an
effective registration statement, as defined.
In the case where North Coast issues warrants or rights to purchase shares of
common stock of the Company, each record holder of outstanding shares of Series
A Preferred stock will receive the kind and amount of such warrants or rights so
issued which such holder would have been entitled to upon such issuance had all
of the holders of shares of Series A Preferred stock been converted, as defined.
The Series A Preferred stock is redeemable at the option of North Coast at a
price of $10 per share. North Coast does not have any obligation to redeem the
Series A Preferred stock.
In the event of a voluntary or involuntary liquidation, dissolution or winding
up of North Coast, holders of the Series A Preferred stock are entitled to be
paid $10 per share out of the assets of North Coast but after payment of other
indebtedness of North Coast, after payment or distribution to the holders of
Series B Preferred stock, but prior to any distribution to holders of the common
stock.
Holders of shares of Series B Preferred stock are entitled to receive, when, as
and if declared by the Board of Directors cash dividends at an annual rate of
$1.00 per share, payable quarterly.
In the event of any liquidation, dissolution or winding up of the Company,
holders of shares of Series B Preferred stock are entitled to receive the
liquidation preference of $10 per share, plus an amount equal to any accrued and
unpaid dividends to the payment date, before any payment or distribution is made
to the holders of common stock and Series A Preferred stock, as defined. After
payment of the liquidation preference, the holders of such shares will not be
entitled to any further participation in any distribution of assets by the
Company.
Each outstanding share of Series B Preferred stock will be entitled to one vote,
excluding shares held by the Company or any entity controlled by the Company,
which shares shall have no voting rights.
F-17
<PAGE> 38
Whenever distributions on the Series B Preferred stock have not been paid, as
defined, the number of directors of the Company may be increased, and the
holders of the Series B will be entitled to elect such additional directors to
the Board of Directors, as defined. Such voting right will terminate when all
such distributions accrued and in default have been paid in full or set apart
for payment, as defined. The amount of dividends in arrears attributable to
Series B preferred is $335,330 as of March 31, 1998.
Effective December 18, 1995, the Series B Preferred stock was redeemable at the
option of the Company, at $10 per share plus any accrued and unpaid dividends,
as defined.
There is no mandatory redemption or sinking fund obligation with respect to the
Series B Preferred stock. In the event that the Company has failed to pay
accrued dividends on the Series B Preferred stock, it may not redeem any of the
outstanding shares of the Series B Preferred stock until all such accrued and
unpaid distributions have been paid in full.
The holders of Series B Preferred stock shall have the right, exercisable at
their option, to convert any or all of such shares into 6.47 shares of common
stock.
In fiscal 1997, the Company commenced a conversion offer to its preferred
shareholders (Series A and B) to convert their shares into common stock with
additional shares offered as an incentive. Following the termination of the
conversion offer in fiscal 1997, 223,159 shares of preferred Series A were
tendered and exchanged for 1,115,795 shares of common stock and 195,201 shares
of preferred Series B were tendered and exchanged for 1,561,608 shares of common
stock.
The following table presents unaudited, pro forma operating results as if the
stock conversion and the NUON common stock sale had occurred at the beginning of
each period presented.
<TABLE>
<CAPTION>
1997 1998
Pro Forma Pro Forma
-------------- ---------------
<S> <C> <C>
REVENUES $ 9,664,989 $ 8,590,632
NET INCOME 547,981 361,187
NET INCOME APPLICABLE TO COMMON
STOCK $ 254,709 $ 92,923
WEIGHTED AVERAGE SHARES OUTSTANDING 16,497,101 16,547,053
INCOME PER SHARE - BASIC AND DILUTED $ 0.02 $ 0.01
</TABLE>
The pro forma operating results have been prepared for comparative purposes
only. They do not purport to present actual operating results that would have
been achieved had the conversions and stock sale been made at the beginning of
each period presented or to necessarily be indicative of future results of
operations.
F-18
<PAGE> 39
B. COMMON STOCK WARRANTS
Warrants issued in connection with the Series B Preferred stock entitle the
holders thereof to purchase 1.15 shares of common stock with each warrant at a
price of $2.61 per share, as defined. The warrants issued in connection with the
Series B Preferred stock expired on December 18, 1997. There were 2,500,000
Series B warrants outstanding at March 31, 1996 and 1997, respectively.
The Company has granted a shareholder certain warrants to purchase 200,000
shares of common stock at $1.20 per share and 300,000 shares of common stock at
$1.00 per share, as defined. These warrants were exercisable on June 13, 1995
and expire on June 13, 2000 and 1998, respectively. The warrants may be redeemed
by the Company for $.10 per share at its option upon 30 days written notice.
In conjunction with the NUON Agreement, the Company issued NUON warrants to
purchase 134,000 shares of common stock for $.875 per share. The Company is
obligated to issue 134,000 warrants on each occasion NUON purchases an
additional 5,747,127 shares of common stock. These warrants expire in September,
2002.
C. SERIES B UNIT WARRANTS
In connection with the issuance of the Series B Preferred stock, the underwriter
of the issue received 50,000 warrants to purchase Series B Units at $12.00 per
unit. A Series B Unit consists of one share of Series B Preferred stock, and
five warrants to purchase 1.15 shares of common stock at $2.61 per share. These
warrants expired on December 18, 1997 and none of these warrants were exercised
as of March 31, 1998.
D. STOCK OPTIONS AND STOCK APPRECIATION RIGHTS
North Coast has a stock option plan (the Option Plan) to provide incentives to
stimulate interest in the development and financial success of the Company. The
Option Plan provides for the granting of stock options to purchase common stock
at an option price determined by North Coast's Compensation Committee (the
Committee). The Committee shall determine the expiration date but no option
shall be exercisable for a period of more than 10 years. The aggregate fair
market value of the common stock exercisable for the first time during any
calendar year shall not exceed $100,000. Options granted under the Option Plan
terminate upon the employee leaving the Company. The Company, from time to time,
may issue additional options outside the plan.
F-19
<PAGE> 40
Stock option transactions during 1996, 1997 and 1998 are summarized as follows:
<TABLE>
<CAPTION>
Options Range
Outstanding Range
------------ --------
<S> <C> <C>
March 31, 1995 553,369
Options granted 10,000 $.94
Options canceled (63,538) $.98-$2.17
-----------
March 31, 1996 499,831
Options exercised (100) $.78
Options granted 18,100 $.78
Options canceled (4,475) $.78-$1.38
-----------
March 31, 1997 513,356
Options exercised (250) $.78
Options canceled (206,368) $.78-$4.91
-----------
March 31, 1998 306,738
===========
</TABLE>
Subsequent to year end, the Company granted 100,000 options to a company
director at $.875 per share.
A summary of stock options outstanding and exercisable at March 31, 1998
follows:
<TABLE>
<CAPTION>
Options Option
Exercisable at March 31, 1998 through: Outstanding Price
-------------------------------------- ----------- ------
<S> <C> <C> <C> <C>
February 20, 1999 230,000 $1.52
January 18, 2000 17,500 $1.62
May 17, 2001 43,700 $.98
March 19, 2003 4,888 $1.38
September 4, 2006 10,650 $.78
-------
306,738
=======
</TABLE>
Stock appreciation rights may be awarded by the Committee at the time or
subsequent to the time of the granting of options. Stock appreciation rights
awarded shall provide that the option holder shall have the right to receive an
amount equal to 100% of the excess, if any, of the fair market value of the
shares of common stock covered by the option over the option price payable, as
defined.
The Company has adopted the disclosure-only provisions of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock Based Compensation."
Accordingly, no compensation cost has been recognized for the stock option
plans. Had compensation cost for the Company's two stock option plans been
determined based on the fair value at the grant date for awards in fiscal 1996,
1997 and 1998 consistent with the provisions of SFAS No. 123, the Company's net
loss per share would not change materially.
F-20
<PAGE> 41
E. STOCK BONUS PLAN
The Company has a Key Employees Stock Bonus Plan (the Bonus Plan) to provide key
employees, as defined, with greater incentive to serve and promote the interests
of the Company and its shareholders. The aggregate number of shares of common
stock which may be issued as bonuses shall be 230,000 shares of common stock, as
defined. The expenses of administering the Bonus Plan shall be borne by the
Company. The Bonus Plan will terminate on February 1, 2001. The Company has
issued 16,700 shares of common stock related to this plan during fiscal 1998 and
108,249 shares of common stock since inception.
6. INCOME TAXES:
The Company has adopted the Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" (SFAS 109). SFAS 109 is an asset and liability
approach that requires the recognition of deferred tax assets and liabilities
for the expected future tax consequences of events that have been recognized in
the Company's consolidated financial statements or tax returns.
Income taxes differed from the amount computed by applying the federal statutory
rates to pretax book income as follows:
<TABLE>
<CAPTION>
1996 1997 1998
---- ---- ----
<S> <C> <C> <C>
Provision based on the statutory rate $(643,000) $ 99,000 $89,000
Tax effect of:
Adjustment from prior years 39,000 28,000 12,000
Statutory depletion (109,000) (143,000) (132,000)
Other - net 75,000 16,000 31,000
------------- ------------- -------------
Total $(638,000) $ - $ -
============= ============= =============
</TABLE>
The components of the net deferred tax liability as of March 31, 1997 and 1998
were as follows:
<TABLE>
<CAPTION>
1997 1998
---- ----
<S> <C> <C>
DEFERRED TAX LIABILITIES:
Property and equipment $(350,000) $(389,000)
Other, net (56,000) (30,200)
------------ -------------
Total deferred tax liabilities (406,000) (419,200)
------------ -------------
DEFERRED TAX ASSETS:
Alternative minimum tax credit carryforwards 307,000 397,000
Net operating loss carryforwards - 640,000
Other financial reserves 65,000 30,000
Less- Valuation allowance (287,200) (957,000)
------------ -------------
Total deferred tax assets 84,800 110,000
------------ -------------
Net deferred tax liability $(321,200) $(309,200)
============ =============
</TABLE>
F-21
<PAGE> 42
The Company has certain alternative minimum tax credit carryforwards and net
operating loss carryforwards which may be available to offset future taxable
income. A valuation allowance has been recorded against these amounts due to
uncertainty as to the Company's ability to realize any future benefit.
7. PROFIT SHARING PLAN:
The Company has a profit sharing plan that provides retirement and death
benefits to participants and covers substantially all employees. Company
contributions are discretionary and are allocated to the participants' accounts
based upon their compensation and are subject to a graded vesting schedule which
allows 20% vesting after two years of vesting service with an additional 20%
vesting for each complete year of vesting service thereafter. Contributions of
approximately $20,000 and $30,000 were accrued or paid for the years ended March
31, 1997 and 1998, respectively.
North Coast provides no significant postretirement and/or postemployment
benefits other than the profit sharing plan discussed above.
8. OTHER COMMITMENTS AND CONTINGENCIES:
North Coast Energy, Inc., as general partner of several limited partnerships,
has committed to fund certain costs (primarily tangible well costs and
sales lines additions) of the partnerships as they are incurred. At March 31,
1998, management estimates the commitment to fund such costs to be approximately
$876,000. The commitment is expected to be funded by September 30, 1998.
The Company shares in unlimited liability to third parties with respect to the
operations of the partnerships it has sponsored and may be liable to limited
partners for losses attributable to breach of fiduciary obligations. In certain
partnerships, certain investors have participated as co-general partners in such
partnerships. To make such investments more acceptable to potential investors
(from a standpoint of risks to such investors) North Coast has agreed to
indemnify these investor-general partners from any partnership liability which
they may incur in excess of their contributions.
The Company has entered into employment contracts with certain of its officers
that provide for a minimum annual salary and incentives based on the Company's
sales and profitability. The commitment, including minimum incentives, amounts
to $430,000, $430,000 and $330,000, respectively, for the years ending March 31,
1996, 1997 and 1998 plus CPI adjustments. In addition, each employment contract
provides for: reimbursement of certain business expenses; life insurance ranging
from $500,000 to $1,000,000; disability benefits for a stated period of time as
defined, and termination benefits of between one and three years' salary.
9. INDUSTRY SEGMENTS AND MAJOR CUSTOMERS:
North Coast and its subsidiaries operate in a single industry segment, the
acquisition, exploration and development of oil and gas properties. North Coast
and its subsidiaries both originate and acquire prospects and drill or cause to
be drilled, such prospects through joint drilling arrangements with other
independent oil companies or through limited partnerships sponsored by the
Company.
The Company's revenue, other than revenue from oil and gas production, is
derived primarily from public and private program partnerships sponsored by the
Company. During 1996, 1997, and 1998 between 35% and 49% of the Company's oil
and gas production
F-22
<PAGE> 43
revenues were derived from two and/or three significant purchasers. A
significant portion of trade accounts receivable at March 31, 1997 and 1998 was
attributable to these purchasers.
10. RECEIVABLES FROM AFFILIATES:
Accounts receivable from affiliates consists primarily of receivables from the
partnerships managed by the Company and are for administrative fees charged to
the partnerships, and to reimburse the Company for amounts paid on behalf of the
partnerships.
11. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED):
The following supplemental unaudited oil and gas information is required by
Statement of Financial Accounting Standards (SFAS) No. 69, "Disclosures about
Oil and Gas Producing Activities."
The tables on the following pages set forth pertinent data with respect to the
Company's oil and gas properties, all of which are located within the United
States.
F-23
<PAGE> 44
CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
March 31,
--------------------------------------
1996 1997 1998
---- ---- ----
<S> <C> <C> <C>
Proved oil and gas properties $23,769,853 $ 24,290,505 $25,754,748
Accumulated depreciation, depletion, amortization
and impairment (10,392,335) (10,488,719) (10,892,238)
--------------- ---------------- ---------------
Net capitalized costs $13,377,518 $ 13,801,786 $14,862,510
=============== ================ ===============
</TABLE>
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
Year Ended March 31,
---------------------------------
1996 1997 1998
---- ---- ----
<S> <C> <C> <C>
Property acquisition costs $ 334,934 $ 124,384 $ 277,742
Exploration costs 216,595 121,809 194,503
Development costs 2,584,430 1,477,312 2,149,440
</TABLE>
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
March 31,
---------------------------------------------
1996 1997 1998
------------ ----------- ------------
<S> <C> <C> <C>
Oil and gas production $2,848,610 $ 3,137,556 $3,013,929
Gain (loss) on sale of oil and gas properties 9,766 (26,031) 1,700
Production costs (796,530) (777,163) (840,346)
Exploration expenses (156,089) (121,809) (194,503)
Depreciation, depletion, amortization, impairment and other (2,550,431) (695,877) (627,636)
Abandonment of oil and gas properties (60,506) (73,528) (88,947)
-------------- -------------- --------------
(705,180) 1,443,148 1,264,197
Provision (credit) for income taxes (349,000) 347,460 278,123
-------------- -------------- --------------
Results of operations for oil and gas producing activities (excluding
corporate overhead and financing costs) $ (356,180) $ 1,095,688 $ 986,074
============== ============== ==============
</TABLE>
Provision (credit) for income taxes was computed using the statutory tax rates
for the years ended March 31, 1996, 1997 and 1998 and reflects permanent
differences, including the Partnership's results of operations for oil and gas
producing activities that are reflected in the Company's consolidated income tax
provision (credit) for the periods.
F-24
<PAGE> 45
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
Oil Gas
(BBLS) (MCF)
-------- -----------
<S> <C> <C>
Balance, March 31, 1995 419,700 20,234,000
Extensions, discoveries and other additions 12,600 4,899,000
Production (14,100) (1,166,000)
Revision of previous estimates (205,900) (3,299,000)
Sales of minerals in place (17,100) (620,000)
------------ --------------
Balance, March 31, 1996 195,200 20,048,000
Extensions, discoveries and other additions - 2,267,000
Production (16,200) (1,153,000)
Revision of previous estimates (58,800) (3,121,000)
Sales of minerals in place - (1,082,000)
------------ --------------
Balance, March 31, 1997 120,200 16,959,000
Extensions, discoveries and other additions 3,000 1,333,000
Production (13,900) (1,116,000)
Revision of previous estimates 26,400 1,153,000
Sales of minerals in place - (527,000)
------------ --------------
Balance, March 31, 1998 135,700 17,802,000
============ ==============
Oil Gas
(BBLS) (MCF)
-------- -----------
PROVED DEVELOPED RESERVES:
March 31, 1995 178,600 15,788,000
March 31, 1996 151,800 16,303,000
March 31, 1997 120,200 14,472,000
March 31, 1998 126,700 15,087,000
</TABLE>
F-25
<PAGE> 46
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
<TABLE>
<CAPTION>
March 31,
---------------------------------------------------
1996 1997 1998
---------------- ---------------- ---------------
<S> <C> <C> <C>
Future cash inflows from sales of oil and
gas $59,810,000 $44,379,000 $46,349,000
Future production and development costs (19,992,000) (15,442,000) (15,175,000)
Future income tax expense (12,836,000) (8,145,000) (8,959,000)
---------------- ---------------- ---------------
Future net cash flows 26,982,000 20,792,000 22,215,000
Effect of discounting future net cash flows
at 10% per annum (13,720,000) (10,447,000) (11,557,000)
---------------- ---------------- ---------------
Standardized measure of discounted future
net cash flows $13,262,000 $10,345,000 $10,658,000
================ ================ ===============
</TABLE>
CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
<TABLE>
<CAPTION>
Year Ended March 31,
--------------------------------------------------
1996 1997 1998
--------------- --------------- ----------------
<S> <C> <C> <C>
Balance, beginning of year $11,635,000 $13,262,000 $10,345,000
Extensions, discoveries and other additions 3,925,000 1,301,000 728,000
Sales of oil and gas, net of production
costs (2,052,000) (2,355,000) (2,173,000)
Net changes in prices and production costs 3,019,000 (3,567,000) 26,000
Revisions of previous quantity estimates (2,893,000) (1,477,000) 1,122,000
Sales of minerals in place (158,000) (859,000) (259,000)
Net change in income taxes (1,034,000) 2,257,000 (246,000)
Accretion of discount 1,163,000 1,326,000 1,035,000
Other (343,000) 457,000 80,000
--------------- --------------- ----------------
Balance, end of year $13,262,000 $10,345,000 $10,658,000
=============== =============== ================
</TABLE>
Under the guidelines of SFAS No. 69, estimated future cash flows are determined
based on year-end prices for crude oil, current allowable prices applicable to
expected natural gas production, estimated production of proved crude oil and
natural gas reserves, estimated future production and development costs of
reserves based on current economic conditions, and the estimated future income
tax expenses, based on year-end statutory tax rates (with consideration of true
tax rates already legislated) to be incurred on pretax net cash flows less the
tax basis of the properties involved. Such cash flows are then discounted using
a 10% rate.
F-26
<PAGE> 47
The estimated quantities of proved oil and gas reserves and standardized measure
of discounted future net cash flows include reserves from proved undeveloped
acreage. The proved undeveloped acreage is included at the working interest
which the Company estimates to retain in the properties, and the standardized
measure was calculated using prices and operating costs and development costs
expected in the area of interest. The quantities for fiscal 1997 and 1998 were
reviewed by an independent petroleum engineering firm.
The methodology and assumptions used in calculating the standardized measure are
those required by SFAS No. 69. It is not intended to be representative of the
fair market value of the Company's proved reserves. The valuation of revenues
and costs do not necessarily reflect the amounts to be received or expended by
the Company. In addition to the valuations used, numerous other factors are
considered in evaluating known and prospective oil and gas reserves.
12. RELATED PARTY TRANSACTIONS:
During fiscal 1997, the Company paid finder's fees to two employees in the
amount of $75,000 each. During fiscal 1998, the Company purchased wells and a
pipeline from a shareholder for $62,000 and purchased 28 wells from an employee
for $339,000.
13. ACCOUNTING STANDARDS:
In fiscal 1996, the Company adopted the provisions of SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets." Although the Company in the past has
routinely reviewed its oil and gas properties for impairment, the Company
changed its method of assessing the impairment of the capitalized costs of oil
and gas properties, to a drilling program or property specific basis as
applicable, to comply with the new standard. As a result of adoption, the
Company incurred impairment expense of approximately $1,562,000, on a pretax
basis, for the year ended March 31, 1996. The impairment expense is included in
the depreciation, depletion, amortization, impairment and other caption in the
accompanying consolidated financial statements.
In February 1997, the Financial Accounting Standards Board issued SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information" which may
require the Company to report certain information about operating segments
including product, services and geographical areas. SFAS No. 131 is required to
be adopted for financial statements with fiscal years beginning after December
15, 1997. The Company has not determined the impact, if any, of this standard.
14. SUBSEQUENT EVENT:
In May 1998, the Company acquired oil and gas properties from Kelt Ohio (the
"Kelt Ohio Acquisition") for a purchase price of approximately $16 million. The
acquisition was accounted for as a purchase. The acquired assets include
approximately 900 natural gas and oil wells, brine disposal facilities, drilling
and service rigs, and natural gas compressors and gas gathering systems.
The Company funded the acquisition primarily with borrowings under its revolving
credit facility which was amended in May 1998 to increase the borrowing base to
$25 million, as defined.
The accompanying unaudited pro forma financial information gives effect to the
Kelt Ohio Acquisition and the related financing in May 1998 for approximately
$16 million. The unaudited pro forma operating results were prepared as if the
Kelt Ohio Acquisition had
F-27
<PAGE> 48
occurred on April 1, 1997. The accompanying unaudited pro forma balance sheet
information of the Company as of March 31, 1998 has been prepared as if the
transaction had occurred as of that date.
<TABLE>
<CAPTION>
Year Ended
March 31, 1998
Pro Forma
(unaudited)
------------------
<S> <C>
REVENUES:
Oil and gas production $ 7,169,392
Drilling revenues 2,988,371
Well operating transportation and other 2,088,115
Administrative and agency fees 965,724
------------
13,211,602
------------
COSTS AND EXPENSES:
Oil and gas production expenses 3,120,954
Drilling costs 2,516,588
Oil and gas operations 652,672
General and administrative expenses 2,339,511
Depreciation, depletion, amortization,
impairment and other 2,141,389
Abandonment of oil and gas properties 88,947
------------
10,860,061
------------
INCOME FROM OPERATIONS 2,351,541
OTHER INCOME:
Interest 62,263
Other 3,690
Gain on sale of property and equipment 1,609
------------
67,562
------------
OTHER EXPENSES:
Interest 2,448,092
------------
2,448,092
------------
NET LOSS $ (28,989)
============
NET LOSS, applicable to common stock (after
preferred stock dividends paid or in
arrears of $268,264 in 1998) $ (297,253)
============
BASIC AND DILUTED EARNINGS, per common share
$(0.02)
============
WEIGHTED AVERAGE SHARES, outstanding 14,106,492
============
</TABLE>
F-28
<PAGE> 49
Balance Sheet Data (at March 31, 1998 unaudited):
Cash and equivalents $ 1,578,984
Total assets $39,811,516
Long-term debt $23,671,035
Stockholders' equity $12,339,287
The pro forma operating results do not purport to present actual operating
results that would have been achieved had the acquisition and financing been
made at the beginning of the period presented or to necessarily be indicative of
future results of operations.
F-29
<PAGE> 50
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item 10 as to the Directors of the Company
is incorporated herein by reference to the information set forth under the
caption "Information Concerning Nominees for Directors" in the Company's
definitive Proxy Statement for the 1998 Annual Meeting of Stockholders, since
such Proxy Statement will be filed with the Securities and Exchange Commission
not later than 120 days after the end of the Company's fiscal year pursuant to
Regulation 14A. Information required by this Item 10 as to the Executive
Officers of the Company is included in Part I of this Annual Report on Form
10-K.
Executive Officers of the Registrant*
Timothy Wagers, age 38, joined North Coast in 1983 and currently is
Treasurer and Chief Financial Officer. Mr. Wagers is also responsible for
overseeing the accounting for partnership distributions, oil and gas production
and tax reporting, and for monitoring well costs. He received a Bachelor of
Science in Accounting from the University of Akron. From 1982 through 1983, Mr.
Wagers was employed by Hausser + Taylor, independent certified public
accountants, as a staff accountant auditing various entities including oil and
gas partnerships. Mr. Wagers is a certified public accountant, a member of the
Ohio Society of Certified Public Accountants, the Ohio Petroleum Accountants
Society, and the American Institute of Certified Public Accountants.
Thomas A. Hill, age 40, was elected Secretary and General Counsel
of North Coast Energy in August 1987. Mr. Hill joined Capital Oil &
Gas, Inc. in 1984, before its acquisition by North Coast. He graduated
from Hiram College with a Bachelor of Arts degree in History and
Political Science and from George Washington University National Law
Center with a Juris Doctor degree. Mr. Hill is a member of the Mahoning
County Bar Association and Eastern Mineral Law Foundation.
*The description of the Company's executive officers called for in this item
is included herein pursuant to instruction 3 to Section (b) of Item 401 of
Regulation S-K.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item 11 is incorporated by reference to
the information set forth under the caption "Executive Compensation" in the
Company's definitive Proxy Statement for the 1998 Annual Meeting of
Stockholders, since such Proxy Statement will be filed with the Securities and
Exchange Commission not later than 120 days after the end of the Company's
fiscal year pursuant to Regulation 14A.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item 12 is incorporated by reference to
the information set forth under the captions "Principal Shareholders" and "Share
Ownership of Directors and Officers" in the Company's definitive Proxy Statement
for the 1998 Annual Meeting of Stockholders, since such Proxy Statement will be
filed with the Securities and Exchange Commission not later than 120 days after
the end of the Company's fiscal year pursuant to Regulation 14A.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this Item 13 is incorporated by reference to
the information set forth under the caption "Transactions with Management" in
the Company's definitive Proxy Statement for the 1998 Annual Meeting
19
<PAGE> 51
of Stockholders, since such Proxy Statement will be filed with the Securities
and Exchange Commission not later than 120 days after the end of the Company's
fiscal year pursuant to Regulation 14A.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K.
(a) (1) Financial Statements
The following Consolidated Financial Statements of the Registrant and its
subsidiaries are included in Part II, Item 8:
Page(s)
Report of Independent Public Accountants F-3
Consolidated balance sheets F-4 - F-5
Consolidated statements of operations F-6
Consolidated statements of stockholders' equity F-7 - F-8
Consolidated statements of cash flows F-9 - F-10
Notes to consolidated financial statements F-11 - F-29
(a) (2) Financial Statements Schedules
All schedules for which provision is made in the applicable accounting
regulation of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable, and therefore have been omitted.
(a) (3) Exhibits
Reference is made to the Exhibit Index.
(b) Reports on Form 8-K:
The Company's current report on Form 8-K dated June 12, 1998.
20
<PAGE> 52
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly cased this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
NORTH COAST ENERGY, INC.
By /s/ Charles M. Lombardy Chief Executive Officer June 26, 1998
- -----------------------------
Charles M. Lombardy, Jr.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
- --------- ----- ----
<S> <C> <C>
/s/ Charles M. Lombardy Chief Executive Officer and Director June 26, 1998
- --------------------------- (principal executive officer)
Charles M. Lombardy, Jr.
/s/ Garry Regan Chairman of the Board; June 26, 1998
- -------------------------- President and Director
Garry Regan
/s/ Timothy Wagers Treasurer and Chief Financial Officer June 26, 1998
- ------------------------- (principal accounting and financial officer)
Timothy Wagers
/s/ Saul Siegel Chief Operating Officer and Director June 26, 1998
- ------------------------
Saul Siegel
/s/ Leo J.M.J. Blomen Director June 26, 1998
- ------------------------
Leo J.M.J. Blomen
/s/ Jos J.M. Smits Director June 26, 1998
- ------------------------
Jos J.M. Smits
/s/ Ralph L. Bradley Director June 26, 1998
- ------------------------
Ralph L. Bradley
Director June 26, 1998
- ------------------------
John H. Pinkerton
/s/ C. Rand Michaels Director June 26, 1998
- ------------------------
C. Rand Michaels
/s/ Steven L. Grose Director June 26, 1998
- ------------------------
Steven L. Grose
</TABLE>
21
<PAGE> 53
Exhibit Index
-------------
<TABLE>
<CAPTION>
Exhibit Sequential
Number Description of Documents Page
- ------ ------------------------ ----------
<S> <C> <C>
4.1 Certificate of Incorporation of the Registrant dated August
30, 1988. (B)
4.2 Certificate of Stock Designation of the Registrant filed
September 12, 1988. (B)
4.3 Certificate of Stock Designation of the Registrant filed
September 14, 1989. (B)
4.4 Certificate of Correction filed March 22, 1991. (C)
4.5 Certificate of Amendment to Certificate of Incorporation filed
November 4, 1992. (A)
4.6 Certificate of Stock Designation filed December 29, 1992. (D)
4.7 Certificate of Amendment to Certificate of Incorporation filed
August 29, 1994. (G)
10.1 1988 Stock Option Plan. (B)
10.2 Form of Profit Sharing Plan. (B)
10.3 Form of Indemnity Agreement between the Registrant and each of
its Directors and executive officers. (B)
10.4 North Coast Energy, Inc. Key Employees Stock Bonus Plan. (B)
10.5 Stock Option Agreement dated as of May 17, 1991 between
Registrant and Timothy Wagers. (C)
10.6 Stock Option Agreement dated as of May 17, 1991 between the
Registrant and Thomas A. Hill. (C)
10.7 Option Agreement dated February 22, 1994 by and between
Registrant and Charles M. Lombardy, Jr. (E)
10.8 Option Agreement dated February 22, 1994 by and between
Registrant and Garry Regan. (E)
10.9 Warrant to purchase 200,000 shares of Common Stock of the
Company. (G)
10.10 Warrant to purchase 300,000 shares of Common Stock of the
Company. (G)
10.11 Restated Employment Agreement dated May 3, 1995 by and between
Registrant and Charles M. Lombardy, Jr. (H)
10.12 Restated Employment Agreement dated May 3, 1995 by and between
Registrant and Garry Regan. (H)
10.13 Open End Mortgage and Promissory Note by and between Bank One,
Akron, N.A. and the Company dated April 30, 1996. (I)
</TABLE>
22
<PAGE> 54
<TABLE>
<CAPTION>
Exhibit Sequential
Number Description of Documents Page
- ------- ------------------------ ------------
<S> <C> <C>
10.14 Purchase and Sale Agreement dated April 8, 1998 between Kelt
Ohio, Inc., and North Coast Energy, Inc. (J)
10.15 Ratification and Amendment to Purchase and Sale Agreement
dated May 12, 1998 between Kelt Ohio, Inc., and North Coast
Energy, Inc. (J)
10.16 First Amendment to Credit Agreement and Promissory Note dated
May 29, 1998 between ING (U.S.) Capital Corporation and North
Coast Energy, Inc. (J)
11.1 Statement regarding computation of per share earnings. _
21.1 List of Subsidiaries. (E)
23.1 Consent of Arthur Andersen LLP. _
27.1 Financial Data Schedule *
</TABLE>
- -------------------------
(A) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Registration Statement on Form S-2 (Reg. No. 33-54288).
(B) Incorporated herein by reference to the appropriate exhibits to the
Company's Registration Statement on Form S-1 (File No. 33-24656).
(C) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the fiscal year ended March
31, 1991.
(D) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the fiscal year ended March
31, 1993.
(E) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the fiscal year ended March
31, 1994.
(F) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on form 10-Q for the fiscal quarter ended
September 30, 1994.
(G) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the fiscal year ended March
31, 1995.
(H) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Annual Report on Form 10-K for the fiscal year ended March
31, 1996.
(I) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Quarterly Report on Form 10-Q for the fiscal quarter ended
September 30, 1996.
(J) Incorporated herein by reference to the appropriate exhibit to the
Registrant's Report on Form 8-K dated June 12, 1998.
*Exhibit 27.1 furnished for Securities and Exchange Commission purposes
only.
23
<PAGE> 1
Exhibit 11.1
<TABLE>
<CAPTION>
Computation of Basic and Diluted Earnings Per Common Share
EARNINGS
3/31/96 3/31/97 3/31/98
------- ------- -------
<S> <C> <C> <C>
Net Income (Loss) $(1,254,418) $ 291,750 $ 262,138
Series A Preferred Stock Dividends (185,199) (91,542) 0
Series B Preferred Stock Dividends (464,655) (232,332) (67,066)
Series B Preferred Stock Dividends in arrears 0 (134,732) (201,198)
----------- --------- ------------
Pro Forma Loss Applicable to Common Stock $(1,904,272) $ (166,856) $(6,126)
- -----------------------------------------------------------------------------------------------------------
SHARES
Weighted Average Common Shares for the
period ended 8,033,642 8,240,776 14,106,492
Additional Shares Assuming Conversion of:
Employee Options Exercised 0 0 0
------------ ---------- ------------
Pro Forma Shares for Basic Earnings
Per Common Share 8,033,642 8,240,776 14,106,492
------------ ---------- ------------
Additional Shares Assuming Conversion of:
Preferred Stock 0 0 0
------------ ---------- ------------
Pro Forma Shares for Diluted Earnings
Per Common Share 8,033,642 8,240,776 14,106,492
============ ========== ==========
- -----------------------------------------------------------------------------------------------------------
Basic Earnings Per Common Share $( .24) $( .02) $( .00)
Diluted Earnings Per Share *$( .24) *$( .02) *$( .00)
- -----------------------------------------------------------------------------------------------------------
</TABLE>
* Common Stock Equivalents Have an Anti-Dilutive Effect on
Earnings Per Share and are Excluded From This Exhibit.
<PAGE> 1
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
North Coast Energy, Inc.:
As independent public accountants, we hereby consent to the incorporation of our
report included in this Form 10-K, into the Company's previously filed
Registration Statement on File No. 33-40341.
Arthur Andersen LLP
Cleveland, Ohio,
June 26, 1998.
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000839950
<NAME> NORTH COAST ENERGY, INC.
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> MAR-31-1998
<PERIOD-START> APR-01-1997
<PERIOD-END> MAR-31-1998
<CASH> 1,578,984
<SECURITIES> 0
<RECEIVABLES> 1,407,725
<ALLOWANCES> 0
<INVENTORY> 189,223
<CURRENT-ASSETS> 3,247,989
<PP&E> 31,944,089
<DEPRECIATION> 13,155,288
<TOTAL-ASSETS> 22,311,516
<CURRENT-LIABILITIES> 2,465,994
<BONDS> 0
0
3,438
<COMMON> 166,129
<OTHER-SE> 12,169,720
<TOTAL-LIABILITY-AND-EQUITY> 22,311,516
<SALES> 8,590,632
<TOTAL-REVENUES> 8,590,632
<CGS> 7,556,714
<TOTAL-COSTS> 7,556,714
<OTHER-EXPENSES> (67,562)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 839,342
<INCOME-PRETAX> 262,138
<INCOME-TAX> 0
<INCOME-CONTINUING> 262,138
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 262,138
<EPS-PRIMARY> (0.00)
<EPS-DILUTED> (0.00)
</TABLE>
