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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, 1997
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:(216) 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 19, 1997, the Registrant had outstanding 10,667,521 shares of Common
Stock, 76,106 shares of Series A Preferred Stock, 268,264 shares of Series B
Preferred Stock, Warrants to purchase 3,375,000 shares of Common Stock and
Representative Warrants to purchase 50,000 units, each consisting of one share
of Series B Preferred Stock and five warrants to purchase 1.15 shares of Common
Stock.
The aggregate market value of Common Stock held by non-affiliates of the
Registrant at June 19, 1997 was $4,844,201 which value has been computed on
the basis of $.875 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 1997 Annual Meeting of Stockholders.
Except as otherwise indicated, the information contained in this Report is as of
March 31, 1997.
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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, 1997, the Company serves as the managing general
partner of 25 Drilling Programs and operates 654 wells, 368 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
185 miles of natural gas gathering pipelines which transport gas from 578
Company operated wells. At March 31, 1997, the Company had estimated net proved
reserves of approximately 17 Bcf of natural gas and 120,000 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") which
resulted in the Company becoming public and traded on NASDAQ. Subsequently, the
Company has continued its original business strategy and now serves as the
managing general partner of 25 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
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conjunction with the Drilling Programs, it continues to review potential
acquisitions, including other gas and oil companies or partnerships and
producing properties.
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 which generally 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
thickness' and at depths ranging generally from 2,800 to 7,500 feet.
Substantially all of the wells which 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 which 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.
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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 include the entire working interest in 163 producing
wells, 43 miles of gas gathering lines and drilling locations.
The Company intends to continue to review potential acquisitions of oil
and gas properties, but has no commitment with respect to any material
acquisition.
DRILLING PROGRAMS
From the Company's inception in 1981 through March 31, 1997, North
Coast has sponsored 46 Drilling Programs to engage in oil and gas drilling and
development operations. Public Drilling Programs accounted for 7 of these
programs, while 39 were sold through private placements. Twenty-one of the
twenty-two partnerships were dissolved as a result of the Exchange Offer and,
therefore, the Company currently is managing 25 Drilling Programs.
To date, 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 be responsible 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 entitled to
indemnification by each program to the extent of the assets of the Drilling
Programs under certain circumstances. Since the partnership interests in the
Drilling Programs constitute securities, the Company is also 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 total intangible drilling and development costs to
be incurred for all of 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%. The Company may elect to acquire a smaller or larger percentage
in future Drilling Programs.
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 $8.4 million during fiscal 1995
and $6.5 million during fiscal 1996 and $3.0 million during fiscal 1997 from
investors. The Company believes that the decrease from fiscal 1995 to fiscal
1996 was primarily due to the uncertainties related to natural gas prices and
the decrease from fiscal 1996 to fiscal 1997 was primarily related to the
uncertainties related to the purchase of approximately 47% of the Company's
voting stock outstanding on September 4, 1996 by Lomak Petroleum, Inc.
("Lomak"). North Coast intends to continue its efforts to market its Drilling
Programs and increase the number of wells drilled. If it is
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unsuccessful in obtaining capital through future Drilling Programs, the Company
would anticipate seeking access to other sources of capital and, if unavailable,
altering its business plan.
DRILLING SERVICES
The Company enters into turnkey drilling contracts with the Drilling
Programs to drill wells. From time to time the Company also performs a limited
amount of drilling and other services for unaffiliated third parties. Pursuant
to these drilling contracts, the Company is responsible for the drilling and
development of the wells. Since the Company does not own any drilling rigs or
other drilling equipment, 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, 1997, the Company operated 654 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 is paid for such services on a per well, monthly fee basis.
The Company 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 which it
operates, the Company has constructed and owns approximately 185 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 578 wells as of March 31, 1997. Since early calendar 1992, the
Company has increased 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, 1997.
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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 which may extend several years. 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 authority, 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 length 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 $1.87 to
$4.50 per Mcf during fiscal 1997. As of March 31, 1997, 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 more 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 $2.70 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 1996/1997 was from $1.87 to $4.50 per Mcf.
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 (weaken), 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. More recently, regional natural gas shortages occurred,
fueling the uncertainty of future pricing. 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 which is offered to all producers. The Company
received an average price of $20.65 per barrel for its oil during fiscal 1997;
however, during the last several years prices paid for crude oil have fluctuated
substantially. 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.
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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.
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 a number 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 $500,000 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
Energy, Inc. is not an
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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.
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 in excess of 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, 1997, the Company had 38 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
which 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 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, the cost
of the locating and drilling oil and gas wells in the Appalachian Basin area,
the amount of funds raised in the fiscal 1998 Drilling Programs, and the ability
to locate productive oil and gas prospects for development by the Company.
ITEM 2. PROPERTIES.
Oil and Gas Properties
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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, 1997.
RESERVES
Oil Reserves (Bbls):
Proved Developed 120,200
Proved Undeveloped 0
-------
Total 120,200
Gas Reserves (Mcf):
Proved Developed 14,472,000
Proved Undeveloped 2,487,000
----------
Total 16,959,000
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PRODUCTION. The following table summarizes the net oil and gas
production (on a rounded basis), average sales prices, and average production
(lifting) costs per equivalent unit of production for the periods indicated.
PRODUCTION
Production Sales Price Average Lifting
Years Ended Oil Gas Cost per Equiv.
March 31: (Bbls) (Mcf) Per Bbl Per Mcf Bbl (1)
- --------- ------ ----- ------- ------- -------
1995 14,400 1,161,000 $15.92 $2.25 $2.70
1996 14,100 1,166,000 $17.01 $2.24 $3.82 (2)
1997 16,200 1,153,000 $20.65 $2.43 $3.73
(1) For calculation of average lifting cost per equivalent barrel 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.
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, 1997. Wells
are classified as gas or oil according to their predominant product stream.
PRODUCTIVE WELLS
Gross Wells (1) Net Wells
Oil Gas Total Oil Gas Total
--- --- ----- --- --- -----
23 667 690 9.69 334.45 344.14
(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, 1997.
LEASEHOLD ACREAGE
Total Leasehold Acreage:
Gross Acres 66,000
Net Acres 33,400
Developed Acreage:
Gross Acres 38,500
Net Acres 19,600
Proved Undeveloped Acreage:
Gross Acres 1,200
Net Acres 600
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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.
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,
- ---------------------------
1995 1996 1997
---- ---- ----
Exploratory Wells (1)
Productive
Gross 0 0 0
Net 0 0 0
Dry
Gross 1 0 0
Net .25 .00 .00
Development Wells (2)
Productive (3)
Gross 71 52 20
Net 18.90 9.80 3.88
Dry
Gross 0 0 0
Net 0 0 0
Total Wells (4)
Productive
Gross 71 52 20
Net 18.90 9.80 3.88
Dry
Gross 1 0 0
Net .25 .00 .00
(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 1997 includes 10 gross and net
wells as productive development wells which are awaiting pipeline
connection or well completion operations at March 31, 1997.
(4) Total Wells is the sum of the Exploratory and Development Wells.
FACILITIES
On September 17, 1996, the Company moved its corporate headquarters to
a 12,000 square foot building it acquired on May 8, 1996 in Twinsburg, Ohio. The
office facility is in a centralized location which allowed the Company to
relocate certain operations and its personnel from its Cleveland and Youngstown
offices. The
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Youngstown facility owned by the Company was converted to use for field
operations. North Coast also maintains an office located in Colorado Springs,
Colorado which is leased from an unaffiliated third party.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
During the fourth quarter of the fiscal year ended March 31, 1997,
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 table 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)
High Low
---- ---
Bid Ask Bid Ask
--- --- --- ---
FISCAL 1996
First Quarter.............................................$1 1/4 $1 7/16 $1/2 $7/8
Second Quarter............................................ 1 3/8 1 1/2 9/16 7/8
Third Quarter............................................. 1 3/8 1 1/2 7/8 1 1/16
Fourth Quarter............................................ 1 1 3/8 1/2 3/4
FISCAL 1997
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
As of June 19, 1997, there were approximately 10,667,521 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 (convertible to
5.75 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,
1997, the Company paid $323,874 in aggregate cash dividends, $91,542 on its
Series A Preferred
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Stock and $232,332 on its Series B Preferred Stock. The Company has dividends in
arrears on its Series B Preferred Stock of $134,732 at March 31, 1997.
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.
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, 1993, 1994, 1995, 1996 and
1997.
Years Ended March 31
(In thousands, except per share amounts)
1993 1994 1995 1996 1997
---- ---- ---- ---- ----
Revenues $10,007 $12,834 $15,275 $10,860 $9,665
Net Income (Loss) 241 652 295 (1,254) 292
Net Income (Loss) per Share(1) .00 .00 (.05) (.24) (.02)
Total Assets 12,732 15,796 21,136 20,243 21,229
Long-term Debt (less current portion) 1,696 3,626 6,197 8,955 10,721
(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 over $81,000,000 from the sale
of partnership interests which has resulted in the formation of 46 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
interest percentage in future Drilling Programs.
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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 decreased to 14.5
Bcf for fiscal 1997 from 16.3 Bcf for fiscal 1996 while proved developed oil
reserves decreased to 120,200 barrels from 151,800 barrels, respectively. The
decrease in proved developed natural gas reserves was primarily due to reduced
drilling and lower product prices received on March 31, 1997, the date utilized
for the reserve evaluation. The proved reserves (developed and undeveloped)
decreased to 17 Bcf for fiscal 1997 from 20 Bcf for fiscal 1996 due primarily to
the revision of proved undeveloped acreage that did not fit the development plan
of the Company. Proved oil reserves (developed and undeveloped) decreased to
120,200 barrels at March 31, 1997 from 195,200 barrels at March 31, 1996 due
primarily to a downward revisions of 58,800 barrels and the production of 16,200
barrels for fiscal 1997. This decrease was primarily due to the determination
that certain proved undeveloped leasehold acreage no longer fits the Company's
development plans with the current economics and was either re-categorized or
released. 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 86% are proved developed and approximately
14% 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, 1995, 1996 and 1997. All items in
the table are calculated as a percentage of total revenues.
Revenues: 1995 1996 1997
---- ----- ----
Oil and gas production 19% 26% 32%
Drilling revenues 57 50 39
Well operating, transportation and other 18 15 19
Administrative, management and agency fees 5 8 9
Other 1 1 1
--- --- ----
Total Revenues 100% 100% 100%
---- ---- ----
Expenses:
Oil and gas production expenses 4% 7% 8%
Drilling costs 47 38 29
Oil and gas operations 13 8 10
General and administrative expenses 19 26 24
Depreciation, depletion, amortization, impairment and other 11 30 14
Abandonment of oil and gas properties 1 1 1
Provision (credit) for income taxes 0 (6) 0
Other 3 7 11
--- ---- --
Total Expenses 98% 111% 97%
--- ---- --
Net Income (Loss) 2% (11)% 3%
=== ===== ====
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The following discussion and analysis reviews the results of operations
and financial condition for the Company for the years ended March 31, 1995, 1996
and 1997. This review should be read in conjunction with the Financial
Statements and other financial data presented elsewhere herein.
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.
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 decreaseof $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, now a principal
stockholder of the Company. The Company has 5 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. Also, 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
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a corresponding impairment for 1997. Also, 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, as 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.
COMPARISON OF FISCAL 1996 TO FISCAL 1995
REVENUES
Oil and gas production revenues remained relatively constant between
fiscal 1996 and fiscal 1995. Production revenues were effected by relatively low
gas prices during the Company's first three quarters, although, gas prices
increased substantially during the Company's fourth quarter due to the generally
colder weather conditions, resulting in increased demand. Production was also
adversely affected by the continued rework on the Company's Gulf Coast
properties, but increased oil production and gas production from the Company's
acquisition and drilling of Appalachian wells offset the Gulf Coast production
decline. For fiscal 1996, the Company received an average price of $17.01 per
barrel of oil and $2.24 per Mcf of natural gas compared to an average price of
$15.92 per barrel of oil and $2.25 per Mcf of natural gas received during fiscal
1995.
Drilling revenues decreased by $3,311,242 (38%) for fiscal 1996
compared to fiscal 1995 primarily due to the decrease in the amount of funds
raised from Drilling Programs as well as the timing of the formation of the
1995-1 Drilling Program, the commencement and completion of drilling activities
and the number of wells recognized in revenue and the type of wells drilled.
Drilling revenues were recognized on 45 wells for fiscal 1996 compared to 74
wells for fiscal 1995. At March 31, 1996, the Company had 14 additional wells as
yet not recognized in revenues as compared to 7 wells at March 31, 1995. The
Company's shallow wells range in depth from 1,400 feet to 2,300 feet, for which
the Company generally charges a lower turnkey drilling contract price compared
to deeper gas wells ranging from 3700 feet to 6400 feet. During fiscal 1996 the
Company formed two Drilling Programs and raised investor funds of $6,460,000 as
compared to three Drilling Programs with investor funds of $8,406,000 during
fiscal 1995. The first Drilling Program of fiscal 1996 was formed forty-five
days later than the first Drilling Program of fiscal 1995, thereby delaying the
number of wells completed and the recognition of revenue for the fiscal year.
Well operating, transportation and other revenues for fiscal 1996
decreased $1,204,079 (43%) compared to fiscal 1995 primarily due to a $1,175,898
decline in unaffiliated third party gas sales. The Company reduced the number of
low margin third party gas transactions in favor of focusing its gas marketing
department on its proprietary gas sales during the period of low natural gas
prices. Although the Company actively pursues these sales, the amount of third
party gas sales may vary materially from year to year.
Revenue from administrative, management and agency fees, which are
based on a percentage of the total investor capital raised in all of the
Drilling Programs, increased by $98,041 (12%) for fiscal 1996, as compared to
fiscal 1995, due to the formation of the Drilling Programs in fiscal 1996
coupled with the ongoing administrative fees accrued from the fiscal 1995
Drilling Programs.
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EXPENSES
Oil and gas production expenses increased $235,775 (42%) for fiscal
1996 compared to fiscal 1995. This increase was primarily due to costs
associated with reworking two wells in the Gulf Coast area and costs associated
with the production enhancement program on the 163 wells the Company acquired in
December 1994. The Company was successful in reworking one Gulf Coast area well
while the results of the second well will not be known until the first or second
quarter of fiscal 1997.
Drilling costs for fiscal 1996 compared to fiscal 1995 decreased
$3,017,661 (42%) due to the decrease in the number of wells completed between
comparable periods. However, the profit margin on drilling revenues increased
from 18% for fiscal 1995 to 24% for fiscal 1996. The increase in the drilling
profit margin is due to lower drilling costs associated with the average depth
of the Company's Upper Devonian and Clinton/Medina wells and improved cost
controls for wells currently recognized in revenue compared to the prior period.
The Company's Upper Devonian and Clinton/Medina wells averaged 4,200 feet in
depth for fiscal 1996 compared to an average of 5,400 feet in depth for fiscal
1995. The Company also reduced its interest in the fiscal 1996 Drilling programs
to 20%, as compared to 25% in the fiscal 1995 Drilling Programs, and increased
the turnkey drilling price the Company receives thereby effecting the Company's
profit margin.
Oil and gas operations expense decreased $1,061,522 (55%) in fiscal
1996 compared to fiscal 1995. This decrease was primarily due to the decrease in
unaffiliated third party gas purchases related to third party gas sales as
discussed above.
Depreciation, depletion, amortization, impairment and other increased
$1,587,721 (93%) in fiscal 1996 compared to fiscal 1995. This increase was
primarily due to the Company's 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". The Company
routinely reviews its long-lived assets for impairment, although SFAS No. 121
required a different grouping of assets which caused an impairment for the
period. At March 31, 1996 the Company's impairment of oil and gas properties and
leases due to the accounting change was $1,561,776. The Statement of Financial
Accounting Standards (SFAS) No. 121 requires the cumulative effect of the
accounting change to be reported in net income in the year of adoption.
Abandonment of oil and gas properties decreased $86,871 (59%) in fiscal
1996 compared to fiscal 1995. During fiscal 1996, the Company abandoned a deep
zone in two wells associated with its drilling on acreage acquired in the
purchase of 163 wells in western Pennsylvania. The Company, in conjunction with
its Drilling Programs, at March 31, 1996 has completed one of the wells in a
shallower formation and anticipates the completion of the second well in the
first fiscal quarter of 1997.
Interest expense increased to $772,731 in fiscal 1996 from $529,161 in
fiscal 1995. This increase was associated with the Company's additional
borrowings on its reducing revolving credit facility, the placement of a private
debt financing with NAGIT (USA), a former shareholder of the Company, and an
increase in the prime interest rate. At March 31, 1996, $7,560,000 was
outstanding under the Company's Credit Facility, as compared to $6,050,003 at
March 31, 1995.
Net operating loss of $1,215,474 for fiscal 1996 compares to net
operating income of $785,671 for fiscal 1995. The increase in the operating loss
was due primarily to the increase in depreciation, depletion, amortization,
impairment and other which resulted from the accounting change promulgated by
the Financial Accounting Standard Board causing an impairment of oil and gas
properties and leases of $1,561,776. Without the affect of the impairment of oil
and gas properties the Company's fiscal 1996 net operating loss would have been
a net operating income of $346,302. Net income of $294,708 for fiscal 1995
decreased during fiscal 1996 to a net loss of $1,254,418 due primarily to the
impairment of the Company's oil and gas properties and leases coupled with the
lower net drilling income recognized and high interest expense.
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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 $20.65 and $17.01 per
barrel for fiscal 1997 and 1996, respectively, and $2.43 and $2.24 per Mcf for
natural gas for fiscal 1997 and 1996, respectively. The general market for
natural gas in the Appalachian Basin has remained weak for a longer period than
the Company previously anticipated, however, gas prices have increased
approximately 30% in the Company's last quarter of fiscal 1996 due to the colder
Appalachian area weather. The reasons for the continued weak natural gas prices
and recent increases in the gas prices can be attributed to supply and demand
fluctuations caused by the weather sensitive nature of the industry. Although it
is anticipated that there will be a decline in gas prices during the summer
months compared to the winter of 1996/1997 the demand for gas by storage
facilities may continue to keep gas prices above last year's low prices. 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 $ 325,000 at March 31, 1997 compared
to negative $360,000 at March 31, 1996. The increase of $ 685,000 in working
capital from March 31, 1996 reflects the Company's increase in cash flow from
operating activities, the reduced cash outflow for the purchase of tangible
equipment and additional borrowings during the fiscal year. The Company was able
to utilize equipment on previously uneconomic wells by abandoning those wells
and installing the equipment on new productive wells to meet its obligations to
the partnerships formed in fiscal 1997. As of March 31, 1997, the Company had
$8,640,000 outstanding under its Credit Facility. North Coast's current ratio
was 1.11 to 1.0 at March 31, 1997 and .90 to 1.0 at March 31, 1996.
The following table summarizes the Company's financial position at
March 31, 1996 and 1997:
(Amounts in Thousands) 1996 1997
---- ----
Amount % Amount %
------ - ------ -
Working capital $ (360) (2%) $ 325 2
Property and equipment 16,737 100 17,901 97
Other 253 2 151 1
-------- ---- -------- ----
Total $16,630 100% $18,377 100%
======= ==== ======= ====
Long-term debt $ 8,954 54% $10,720 58
Deferred income taxes 357 2 347 2
Stockholders' equity 7,319 44 7,310 40
------- -- -------- ---
Total $16,630 100% $18,377 100%
======= ==== ======= ====
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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, 1995, 1996 and 1997:
(Amounts in Thousands) 1995 1996 1997
---- ---- ----
Dollars % Dollars % Dollars %
------- - ------- - ------- -
Net cash provided by operating activities $2,428 40% $1,049 27% $1,162 48%
Net cash used for investing activities (5,065) (83) (3,377) (87) (1,827) (76)
Net cash provided by financing activities 3,708 60 1,513 39 616 26
------ --- ------ --- ------ ---
Increase (decrease) in cash and cash equivalents $1,071 17% $ (815) (21)% (49) (2)%
====== === ======= ===== ==== ====
(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 increased approximately $113,000 for fiscal 1997 as
compared to fiscal 1996. This increase is due to increased oil and gas
production, well operating, and compression revenues coupled with reduced
general and administrative expenses.
Net cash used for investing activities decreased from $3,377,000 (87%
of cash sources) for fiscal 1996 to $1,827,000 (75% of cash sources) for fiscal
1997. The decrease of $1,550,000 was due to the amount of funds raised in
Drilling Programs and the subsequent number of wells drilled, coupled with the
Company's ability to utilize equipment on previously uneconomic wells by
abandoning those wells and installing the equipment on new productive wells to
meet its obligations to the fiscal 1997 Drilling Programs.
Net cash provided by financing activities decreased by $897,000 from
fiscal 1996 to fiscal 1997. This decrease reflects the Company's reduced need
for borrowing due to the reduction in employee staff and the elimination of its
Preferred Stock dividends.
The Company has a $20,000,000 revolving credit agreement with its
lender. 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 ($140,000 at March 31,
1997), as defined. At March 31, 1997, the Company's borrowing base was
$10,200,000 subject to monthly reductions of $110,000 beginning in May 1997.
Available borrowings under the facility at March 31, 1997 were $1,420,000 any
may subsequently change based upon the semiannual reserve study and borrowing
base determination (see Note 4 to the Company's March 31, 1997 financial
statements). Also, the amendment of December 2, 1996 provides that the payment
of dividends with respect to the capital stock of the Company is prohibited. As
of March 31, 1997, the Company had $8,640,000 outstanding under the Credit
Facility. At March 31, 1997 the Company was in violation of its debt coverage
ratio, although, this violation was waived by the lender. Amounts borrowed under
the Credit Facility bear interest at the lending bank's prime rate plus 1 1/2%.
The revolving line of credit can be renewed annually or converted to a term loan
at the Company's option prior to its expiration in fiscal 1999. Also, at March
31, 1997, the Company had approximately $60,216 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
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July 2003. The Company purchased a building for its headquarters and entered
into a mortgage note on May 13, 1996 for $540,000 over 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, 1997 was $524,033.
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.
In addition to bank financing, the Company has two loans with Lomak.
The first loan of $335,000 ($304,791 outstanding on March 31, 1997) bears an
interest rate at the prime rate designated by the Chemical Bank, N.A., plus 1%
(9.25% at March 31, 1997). The amounts outstanding under the terms of the
Company's financing arrangement are subordinated to the prior payment and
amounts outstanding under the Company's Credit Facility. Repayment of the loan
is in cash, based upon a percentage of the net monthly revenues received from
certain previously acquired properties.
The second loan in the amount of $1,000,000 is unsecured and may be
repaid in cash plus accrued interest (with approval of the Company's senior
lender) with the proceeds of a sale of equity or may be converted into shares of
Common Stock at the rate of $1.00 per share. The loan is subordinate to the
Company's Credit Facility with its senior lender and bears interest at the rate
of 8% per annum. As of March 31, 1997, the balance of the loan and accrued
interest was $1,148,883. In connection with entering into the Loan Agreement,
the Company issued a warrant to purchase 200,000 shares of Common Stock at $1.20
per share and a warrant to purchase 300,000 shares of Common Stock at $1.00 per
share. The warrants may be redeemed by the Company for $.10 per share at its
option upon 30 days written notice.
On or about September 4, 1996 Lomak, a publicly traded oil and gas
company, purchased approximately 47% of the voting stock of the Company (as of
June 19, 1997 Lomak owns 37% of the voting stock of the Company) from two of the
Company's largest stockholders, NAGIT, USA (NAGIT) and Bruce E. Brocker. At the
Company's annual meeting of stockholders, Lomak presented proxies representing
the shares acquired from these shareholders and indicated its intention to
nominate and elect two directors in the class whose terms were scheduled to
expire at that meeting. Due to concerns about the validity of such proxies, the
annual meeting was adjourned to a later date. Litigation among the Company,
Lomak and Mr. Brocker then ensued until November 1996 when the parties reached a
settlement with respect to that litigation.
Revenues derived from the Company's Drilling Programs provide an
important source of the Company's cash flow. Due to uncertainties among
potential Drilling Program investors arising out of Lomak's acquisition of a
substantial ownership interest in the Company and the other matters described
above, the Company's ability to market its Drilling Programs has been adversely
affected. With the reduction of the Drilling Program activity and the need to
conserve cash, the Company's ability to utilize equipment it owns on
non-productive wells and increase profitably through the Drilling Programs was
adversely affected. Demands on the Company's capital resources have increased
due to reduced cash flow associated with lower levels of investor interest in
its Drilling Programs and increased costs associated with litigation and
evaluating the Company's strategic alternatives. This has necessitated actions
by the Company to alter its growth oriented business plan in order to conserve
cash. On October 21, 1996, the Company initiated layoffs of 21% of its staff
coupled with a temporary reduction or deferment in wages to many of its
remaining employees. Also, the Company suspended its dividends on its Series A
Non-cumulative and Series B Cumulative Preferred Stock in an effort to conserve
cash resources. The Company subsequently made an offer to all holders of the
Company's Preferred Stock offering additional shares of the Company's Common
Stock as an enticement for conversion of the Preferred Stock to Common Stock.
Management of the Company believes that the funds anticipated to be
raised in the Drilling Programs together with anticipated general economic
conditions and various sources of available capital, including current available
borrowings under the Credit Facility, will be sufficient to fund the Company's
operations and meet debt service requirements through fiscal 1998.
18
21
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. Management of the Company believes that
measures of this type would have a material adverse effect on the Company.
ACCOUNTING STANDARDS
In October 1995, the Financial Accounting Standards Board issued SFAS
No. 123, "Accounting for Stock-Based Compensation" which permits either
recording the estimation value of stock-based compensation over the applicable
vesting period or disclosing the unrecorded cost and the related effect on
earnings per share in the notes to Consolidated Financial Statements. The
Company has adopted the disclosure-only provision of SFAS No. 123. Accordingly,
no compensation costs have been recognized for stock-based compensation (see
Footnote 5 of the Company's Consolidated Financial Statements).
In February 1997, the Financial Accounting Standards Board issued SFAS No. 128,
"Earnings Per Share" which will revise the calculation methods and disclosures
regarding earnings per share. SFAS No. 128 is required to be adopted for
financial statements with fiscal years ending after December 31, 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.
19
22
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 1997 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 37, 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.
Anthony R. Kovacevich, age 43, joined North Coast in October 1994 as Senior
Vice President of Exploration and Production. Mr. Kovacevich graduated from
Marietta College with a BS degree in Petroleum Engineering and has over 19 years
of oil and gas experience, with over 14 years in the Appalachian Basin. Prior to
joining North Coast, from November 1984 to October 1994, Mr. Kovacevich was Vice
President of Exploration and Production with Resource America, Inc., a publicly
held oil and gas company conducting operations in the Appalachian Basin, and had
overall responsibility for drilling, production, exploration, land department
and gas marketing activities. Mr. Kovacevich began his career as a production
engineer with Marathon Oil. Mr. Kovacevich is a member of the Ohio Oil and Gas
Association and the Society of Petroleum Engineers.
Thomas A. Hill, age 39, was elected Secretary and General Counsel of North
Coast Energy in August, 1987. Mr. Hill joined Capital Oil & Gas, Inc. in 1984,
prior to 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 1997 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
20
23
Proxy Statement for the 1997 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 1997 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.
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 income 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-26
(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: None.
21
24
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 27, 1997
- --------------------------
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.
Signature Title Date
- --------- ----- ----
/s/ Charles M. Lombardy Chief Executive Officer and Director June 27, 1997
- ------------------------- (principal executive officer)
Charles M. Lombardy, Jr.
/s/ Garry Regan Chairman of the Board; June 27, 1997
- ------------------------- President and Director
Garry Regan
/s/ Timothy Wagers Treasurer and Chief Financial Officer June 27, 1997
- ------------------------- (principal accounting and financial officer)
Timothy Wagers
/s/ Charles K. Ebinger Director June 27, 1997
- -------------------------
Charles K. Ebinger
/s/ W. Dale Wegrich Director June 27, 1997
- -------------------------
W. Dale Wegrich
Director
- -------------------------
George Begley
/s/ Robert L. Bauman Director June 27, 1997
- -------------------------
Robert L. Bauman
Director
- ------------------------
John H. Pinkerton
/s/ C. Rand Michaels Director June 27, 1997
- -------------------------
C. Rand Michaels
/s/ Steven L. Grose Director June 27, 1997
- ------------------------
Steven L. Grose
22
25
Exhibit Index
-------------
Exhibit Sequential
Number Description of Documents Page
- ------ ------------------------ ----------
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. (H)
10.1 1988 Stock Option Plan. (B)
10.2 Form of Profit Sharing Plan. (B)
10.3 Amendment (dated as of July 15, 1988 but effective for all purposes as of October 4, (B)
1989) to Option Agreement originally dated August 31, 1987 by and between Registrant
and Charles M. Lombardy, Jr.
10.4 Amendment (dated as of July 15, 1988 but effective for all (B)
purposes as of October 4, 1989) to Option Agreement originally
dated August 31, 1987 by and between Registrant and Garry Regan.
10.5 Form of Indemnity Agreement between the Registrant and each of its Directors and (B)
executive officers.
10.6 North Coast Energy, Inc. Key Employees Stock Bonus Plan. (B)
10.7 Stock Option Agreement dated as of May 17, 1991 between Registrant and Timothy (C)
Wagers.
10.8 Stock Option Agreement dated as of May 17, 1991 between the Registrant and (C)
Thomas A. Hill.
10.9 Option Agreement dated February 22, 1994 by and between Registrant and (E)
Charles M. Lombardy, Jr.
23
26
Exhibit Sequential
Number Description of Documents Page
- ------ ------------------------ ----------
10.10 Option Agreement dated February 22, 1994 by and between Registrant and Garry Regan. (E)
10.11 Reducing Revolving Credit Agreement dated September 20, 1993 between Bank One (E)
Texas, N.A. and North Coast Energy, Inc.
10.12 First Amendment to Credit Agreement dated March 16, 1994 between Bank One Texas, (E)
N.A. and North Coast Energy, Inc.
10.13 Option Agreement dated June 2, 1994 by and between Registrant and Charles Ebinger. (F)
10.14 Option Agreement dated June 2, 1994 by and between Registrant and W. Dale Wegrich. (F)
10.15 Option Agreement dated October 11, 1994 by and between Registrant and (F)
Tony Kovacevich.
10.16 Employment Agreement dated October 11, 1994 by and between Registrant (F)
and Tony Kovacevich.
10.17 Loan and Participation Agreement by and between NAGIT (USA) INC. and the Company (G)
dated as of January 13, 1995.
10.18 Second Amendment to Credit Agreement by and between Bank One, Texas, N.A. (G)
and the Company dated January 13, 1995.
10.19 Loan Agreement by and between NAGIT (USA) INC. and the Company dated (H)
June 13, 1995.
10.20 8% Convertible Subordinated Note for $1,000,000 by and between NAGIT(USA) INC. (H)
and the Company dated June 13, 1995.
10.21 Warrant to purchase 200,000 shares of Common Stock of the Company. (H)
10.22 Warrant to purchase 300,000 shares of Common Stock of the Company. (H)
10.23 Third Amendment to Credit Agreement by and between Bank One, Texas, N.A. and (I)
the Company dated August 8, 1995.
10.24 Fourth Amendment to Credit Agreement by and between Bank One, Texas, N.A. and (J)
the Company dated March 31, 1996.
10.25 Restated Employment Agreement dated May 3, 1995 by and between Registrant and (J)
Charles M. Lombardy, Jr.
10.26 Restated Employment Agreement dated May 3, 1995 by and between Registrant and (J)
Garry Regan.
10.27 Fifth Amendment to Credit Agreement by and between Bank One, Texas, N.A. and the (K)
Company dated August 30, 1996.
10.28 Open End Mortgage and Promissory Note by and between Bank One, Akron, N.A. and (K)
the Company dated April 30, 1996.
24
27
Exhibit Sequential
Number Description of Documents Page
- ------ ------------------------ ----------
10.29 Sixth Amendment to Credit Agreement by and between Bank One, Texas, N.A. and the (L)
Company dated December 2, 1996.
10.30 Option Agreement dated March 13, 1996 by and between Registrant and George R. -
Begley.
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 *
- -------------------------
(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 Quarterly Report on Form 10-Q for the fiscal
quarter ended December 31, 1994.
(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, 1995.
(I) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Quarterly Report on Form 10-Q for the fiscal
quarter ended June 30, 1995.
(J) 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.
(K) 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.
25
28
(L) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Quarterly Report on Form 10-Q for the fiscal
quarter ended December 31, 1996.
*Exhibit 27.1 furnished for Securities and Exchange Commission purposes only.
26
29
NORTH COAST ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
F-1
30
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-26
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
31
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, 1996 and
1997, 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, 1997. 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, 1996 and 1997, and the results of their operations
and their cash flows for each of the three fiscal years in the period ended
March 31, 1997, in conformity with generally accepted accounting principles.
As explained in Note 12 to the consolidated financial statements, in fiscal
1996, the Company changed its method of assessing the impairment of the
capitalized costs of oil and gas properties and other long-lived assets.
/s/ Arthur Andersen LLP
Cleveland, Ohio,
June 4, 1997.
F-3
32
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED BALANCE SHEETS
---------------------------
MARCH 31, 1996 and 1997
-----------------------
ASSETS
------
1996 1997
------------ ------------
CURRENT ASSETS:
Cash and equivalents $ 1,551,748 $ 1,503,278
Accounts receivable-
Trade, net 1,339,601 1,306,577
Affiliates 97,993 81,456
Inventories 85,235 200,971
Deferred income taxes 41,000 26,000
Refundable income taxes 115,000 50,000
Other, net 22,097 8,488
------------ ------------
Total current assets 3,252,674 3,176,770
------------ ------------
PROPERTY AND EQUIPMENT, at cost:
Land 122,699 93,437
Oil and gas properties (successful efforts) 23,769,853 24,290,505
Pipelines 3,696,277 4,158,204
Vehicles 427,920 348,825
Furniture and fixtures 453,718 501,049
Building and improvements 145,539 788,419
------------ ------------
28,616,006 30,180,439
Less- Accumulated depreciation, depletion, amortization
and impairment (11,879,077) (12,279,402)
------------ ------------
16,736,929 17,901,037
OTHER ASSETS, net 253,206 150,893
------------ ------------
$ 20,242,809 $ 21,228,700
============ ============
The accompanying notes are an integral part of these
consolidated balance sheets.
F-4
33
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED BALANCE SHEETS
---------------------------
MARCH 31, 1996 and 1997
-----------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
1996 1997
------------ ------------
CURRENT LIABILITIES:
Current portion of long-term debt $ 213,060 $ 108,900
Accounts payable 2,481,558 1,952,863
Accrued expenses 280,565 320,255
Billings in excess of costs on uncompleted contracts 637,347 469,361
------------ ------------
Total current liabilities 3,612,530 2,851,379
------------ ------------
LONG-TERM DEBT, net of current portion 8,954,574 10,720,510
DEFERRED INCOME TAXES, net 357,100 347,200
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Series A, 6% Noncumulative Convertible Preferred
stock, par value $.01 per share; 563,270 shares
authorized; 305,200 and 76,951 issued and
outstanding (aggregate liquidation value of
$3,052,000 and $769,510, respectively) 3,052 770
Series B, Cumulative Convertible Preferred stock, par
value $.01 per share; 625,000 shares authorized; 464,665
and 269,464 issued and outstanding (aggregate
liquidation value of $4,646,650 and $2,694,640,
respectively) 4,647 2,695
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; 8,040,148 and 10,753,895 issued
and outstanding 80,402 107,539
Additional paid-in capital 12,082,969 12,083,196
Retained deficit (4,852,465) (4,884,589)
------------ ------------
Total stockholders' equity 7,318,605 7,309,611
------------ ------------
$ 20,242,809 $ 21,228,700
============ ============
The accompanying notes are an integral part of these
consolidated balance sheets.
F-5
34
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF OPERATIONS
-------------------------------------
FOR THE YEARS ENDED MARCH 31, 1995, 1996 AND 1997
-------------------------------------------------
1995 1996 1997
------------ ------------ ------------
REVENUE:
Oil and gas production $ 2,845,573 $ 2,848,610 $ 3,137,556
Drilling revenues 8,801,606 5,490,364 3,783,630
Well operating, transportation and other 2,814,548 1,610,469 1,859,806
Administrative, management and agency fees 813,012 911,053 883,997
------------ ------------ ------------
15,274,739 10,860,496 9,664,989
------------ ------------ ------------
COSTS AND EXPENSES:
Oil and gas production expenses 560,755 796,530 777,163
Drilling costs 7,178,449 4,160,788 2,876,615
Oil and gas operations 1,942,547 881,025 976,943
General and administrative expenses 2,949,302 2,878,762 2,307,994
Depreciation, depletion, amortization, impairment and
other 1,710,638 3,298,359 1,385,570
Abandonment of oil and gas properties 147,377 60,506 73,528
------------ ------------ ------------
14,489,068 12,075,970 8,397,813
------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS 785,671 (1,215,474) 1,267,176
------------ ------------ ------------
OTHER INCOME:
Interest 90,720 63,063 47,491
Other - 14,429 52,892
Gain on sale of property and equipment - 18,295 -
------------ ------------ ------------
90,720 95,787 100,383
------------ ------------ ------------
OTHER EXPENSE:
Interest 529,161 772,731 1,055,409
Loss on sale of property and equipment 3,522 - 20,400
------------ ------------ ------------
532,683 772,731 1,075,809
------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES 343,708 (1,892,418) 291,750
PROVISION (CREDIT) FOR INCOME TAXES:
Current 82,000 (83,100) (5,100)
Deferred (33,000) (554,900) 5,100
------------ ------------ ------------
49,000 (638,000) -
------------ ------------ ------------
NET INCOME (LOSS) $ 294,708 $ (1,254,418) $ 291,750
============ ============ ============
NET LOSS APPLICABLE TO COMMON
STOCK (after Preferred stock dividends paid
or in arrears of $654,111, $649,864 and
$458,606 in 1995, 1996 and 1997, respectively) $ (359,403) $ (1,904,282) $ (166,856)
============ ============ ============
NET LOSS PER SHARE (primary and fully diluted)
$ (0.05) $ (0.24) $ (.02)
============ ============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
35
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------
FOR THE YEARS ENDED MARCH 31, 1995, 1996 AND 1997
-------------------------------------------------
Series A Series B
Preferred Stock Preferred Stock
----------------------- ------------------------
Shares Amount Shares Amount
-------- -------- -------- --------
BALANCE, MARCH 31, 1994 317,665 $ 3,177 475,400 $ 4,754
Net income - - - -
Exercise of stock options - - - -
Issuance of Common stock - - - -
Shares converted (8,205) (82) (10,735) (107)
Dividends on Series A Preferred stock ($.60 per
share) - - - -
Dividends on Series B Preferred stock ($1.00 per
share) - - - -
-------- -------- -------- --------
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
======== ======== ======== ========
The accompanying notes are an integral part of these
consolidated financial statements.
F-7
36
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------
FOR THE YEARS ENDED MARCH 31, 1995, 1996 AND 1997
-------------------------------------------------
Common Stock Additional Total
------------------------ Paid-In Retained Stockholders'
Shares Amount Capital Deficit Equity
------ ------ ------- ------- ------
6,326,756 $ 63,268 $ 10,205,871 $ (2,588,780) $ 7,688,290
- - - 294,708 294,708
23,000 230 22,270 - 22,500
1,600,000 16,000 1,855,500 - 1,871,500
80,596 806 (617) - -
- - - (188,571) (188,571)
- - - (465,540) (465,540)
- -------------- ----------- ---------------- --------------- ---------------
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
============== =========== ================ =============== ===============
The accompanying notes are an integral part of these
consolidated financial statements.
F-8
37
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
FOR THE YEARS ENDED MARCH 31, 1995, 1996 AND 1997
-------------------------------------------------
1995 1996 1997
----------- ----------- -----------
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income (loss) $ 294,708 $(1,254,418) $ 291,750
Adjustments to reconcile net income (loss) to net
cash provided by operating activities-
Depreciation, depletion, amortization,
impairment and other 1,710,638 3,298,359 1,385,570
Abandonment of oil and gas properties 147,377 60,506 73,528
Loss (gain) on sale of property and
equipment 3,522 (18,295) 20,400
Deferred income taxes (33,000) (554,900) 5,100
Change in-
Accounts receivable (404,481) 213,970 49,561
Inventories and other current assets (187,258) 118,979 (102,127)
Refundable income taxes - (115,000) 65,000
Other assets, net (48,156) 88,129 23,109
Accounts payable 1,340,497 (997,350) (521,662)
Accrued expenses 9,886 (143,417) 39,690
Billings in excess of costs on
uncompleted contracts (405,892) 352,467 (167,986)
----------- ----------- -----------
Total adjustments 2,133,133 2,303,448 870,183
----------- ----------- -----------
Net cash provided by operating
activities 2,427,841 1,049,030 1,161,933
----------- ----------- -----------
CASH FLOWS FROM INVESTING
ACTIVITIES:
Purchases of property and equipment (5,075,715) (3,389,274) (2,025,561)
Proceeds on sale of property and equipment 10,620 12,253 198,669
----------- ----------- -----------
Net cash used for investing
activities (5,065,095) (3,377,021) (1,826,892)
----------- ----------- -----------
The accompanying notes are an integral part of these
consolidated financial statements.
F-9
38
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
FOR THE YEARS ENDED MARCH 31, 1995, 1996 AND 1997
-------------------------------------------------
1995 1996 1997
----------- ----------- -----------
CASH FLOWS FROM FINANCING
ACTIVITIES:
Payments of accounts payable used to finance
property and equipment additions $ (335,552) $ (236,422) $ (70,964)
Borrowings under revolving credit facility 3,020,000 3,800,000 2,080,000
Borrowings under note payable to stockholder 335,000 1,064,000 84,883
Repayment of borrowings under revolving credit
facility (435,771) (2,290,003) (1,000,000)
Payments on long-term debt (89,321) (127,278) (140,656)
Cash paid for deferred financing (25,973) (47,354) (12,900)
Exercise of stock options 22,500 - -
Proceeds from issuance of common stock 1,871,500 - -
Distributions and dividends (654,111) (649,864) (323,874)
----------- ----------- -----------
Net cash provided by financing
activities 3,708,272 1,513,079 616,489
----------- ----------- -----------
INCREASE (DECREASE) IN CASH AND
EQUIVALENTS 1,071,018 (814,912) (48,470)
CASH AND EQUIVALENTS AT BEGINNING
OF YEAR 1,295,642 2,366,660 1,551,748
----------- ----------- -----------
CASH AND EQUIVALENTS AT END OF YEAR $ 2,366,660 $ 1,551,748 $ 1,503,278
=========== =========== ===========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for-
Interest $ 521,000 $ 716,000 $ 1,032,000
Income taxes 155,000 30,000 52,000
SUPPLEMENTAL DISCLOSURES ON NONCASH INVESTING AND
FINANCING ACTIVITIES:
Long-term debt incurred for the purchase of
property and equipment $ 111,000 $ 91,000 $ 638,000
Accounts payable incurred for the purchase of
property and equipment 236,000 71,000 87,000
Accounts payable from interest on long-term debt - 64,000 85,000
The accompanying notes are an integral part of these
consolidated financial statements.
F-10
39
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
-----------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
MARCH 31, 1995, 1996 AND 1997
-----------------------------
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 33.7%
North Coast Energy/Capital 1987-2 Appalachian
Drilling Program Limited Partnership 27.0%
North Coast Energy/Capital 1988-1 Appalachian
Drilling Program Limited Partnership 25.5%
North Coast Energy/Capital 1988-2 Appalachian
Drilling Program Limited Partnership 34.8%
North Coast Energy/Capital 1989 Appalachian
Drilling Program Limited Partnership 30.0%
North Coast Energy 1990-1 Appalachian
Drilling Program Limited Partnership 26.0%
North Coast Energy 1990-2 Appalachian
Drilling Program Limited Partnership 25.7%
North Coast Energy 1990-3 Appalachian
Drilling Program Limited Partnership 25.0%
North Coast Energy 1991-1 Appalachian
Drilling Program Limited Partnership 26.5%
F-11
40
North Coast Energy 1991-2 Appalachian
Drilling Program Limited Partnership 25.0%
North Coast Energy 1991-3 Appalachian
Drilling Program Limited Partnership 25.3%
North Coast Energy 1992-1 Appalachian
Drilling Program Limited Partnership 25.0%
North Coast Energy 1992-2 Appalachian
Drilling Program Limited Partnership 25.0%
North Coast Energy 1992-3 Appalachian
Drilling Program Limited Partnership 39.5%
North Coast Energy 1993-1 Appalachian
Drilling Program Limited Partnership 30.3%
North Coast Energy 1993-2 Appalachian
Drilling Program Limited Partnership 31.0%
North Coast Energy 1993-3 Appalachian
Drilling Program Limited Partnership 30.0%
North Coast Energy 1994-1 Appalachian
Drilling Program Limited Partnership 30.0%
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%
All significant intercompany accounts and transactions have been eliminated.
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.
F-12
41
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.
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.
F-13
42
G. Per Share Amounts
-----------------
The computation of primary and fully diluted earnings per share for 1995, 1996
and 1997 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 primary and
fully diluted loss per share was 7,210,268, 8,033,642 and 8,240,776 for the
years ended March 31, 1995, 1996 and 1997, 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
43
2. BILLINGS IN EXCESS OF COSTS ON UNCOMPLETED CONTRACTS:
-----------------------------------------------------
Billings in excess of costs on uncompleted contracts consist of the following at
March 31:
1996 1997
------------ -----------
Billings on uncompleted contracts $1,518,486 $738,554
Costs incurred on uncompleted
contracts 881,139 269,193
------------ -----------
$ 637,347 $469,361
============ ===========
3. LEASE COMMITMENTS:
------------------
The Company leases real and personal property under operating leases. The most
significant obligations under these lease agreements are for annual building
rentals, which include standard maintenance and insurance. Total rental expense
under the operating leases for the years ended March 31, 1995, 1996 and 1997,
amounted to approximately $80,000, $82,000 and $43,000, respectively. In 1995,
1996 and 1997, rent expense of approximately $65,000, $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:
1996 1997
----------- -----------
Revolving credit notes payable--bank $ 7,560,000 $ 8,640,000
Notes payable to stockholder with interest at
prime plus 1% and 8% 1,386,842 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 67,842 60,216
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
Various installment notes payable in aggregate monthly
installments (including interest) of $9,042 at March 31,
1997, through 1999 152,950 151,487
----------- -----------
9,167,634 10,829,410
Less- Current portion 213,060 108,900
----------- -----------
$ 8,954,574 $10,720,510
=========== ===========
F-15
44
The Company has a $20,000,000 revolving credit agreement with its lender. 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 ($140,000 at March 31, 1997), as defined.
At March 31, 1997, the Company's borrowing base was $10,200,000 subject to
monthly reductions of $110,000 beginning in May 1997. Available borrowings under
the facility at March 31, 1997 were $1,420,000 and may subsequently change based
upon the semiannual reserve study and borrowing base determination.
The revolving line of credit can be renewed annually or converted to a term loan
at the Company's option prior to its expiration in fiscal 1999.
Amounts outstanding under the reducing revolving line of credit bear interest at
the lending bank's prime rate plus 1.5% or approximately 9.75% and 10% at March
31, 1996 and 1997, respectively. The weighted average interest rate on these
borrowings was 10.4% and 9.9% for fiscal 1996 and 1997, respectively. The
agreement requires the Company to pay a commitment fee of .5% on the unused
amount of the available borrowings and closing costs of 1% on any increase in
borrowing availability. The agreement contains certain restrictive covenants,
including minimum working capital, minimum stockholders' equity, restrictions on
the payment of dividends, as defined, and a minimum debt coverage ratio, as
defined. The Company was in compliance with or had received waivers with respect
to all covenants and restrictions at March 31, 1997.
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.
The Company has two notes payable to a stockholder. One note is payable out of
future operating revenues, as defined. The note is subordinated to the
borrowings under the revolving credit notes payable - bank. The Company also
entered into an second note payable with the same stockholder for $1,000,000.
This note can be repaid in either shares of common stock or proceeds of a public
offering, as defined. This note is also subordinated to the borrowings under the
revolving credit notes payable - bank.
Future maturities of long-term debt for the years ended March 31, are as
follows:
Fiscal 1998 $ 108,900
Fiscal 1999 9,865,430
Fiscal 2000 44,852
Fiscal 2001 73,528
Fiscal 2002 83,158
Thereafter 653,542
-----------
$10,829,410
===========
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:
--------------------
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
F-16
45
(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.
Whenever distributions on the Series B Preferred stock have not been paid, as
defined, the number of directors of the Company will 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
F-17
46
or set apart for payment, as defined. The amount of dividends in arrears
attributable to Series B preferred is $134,732 as of March 31, 1997.
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 5.75 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 had occurred at the beginning of each period presented.
1996 1997
Pro Forma Pro Forma
--------------- ---------------
REVENUES $10,860,496 $ 9,664,989
NET (LOSS) INCOME (1,349,418) 291,750
NET LOSS APPLICABLE TO COMMON
STOCK $(1,571,722) $ (1,522)
WEIGHTED AVERAGE SHARES
OUTSTANDING 10,739,918 10,749,974
LOSS PER SHARE $ (0.15) $ (0.00)
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 been made at the beginning of each period
presented or to necessarily be indicative of future results of operations.
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 expire on December 18, 1997. There are 2,500,000 Series
B warrants outstanding at March 31, 1996 and 1997, respectively.
The Company has entered into a loan agreement with an existing stockholder (Note
4). In conjunction therewith, the Company granted the stockholder certain
warrants to purchase 200,000 shares of common stock at $1.20 per share and
300,000 shares of common stock at
F-18
47
$1.00 per share, as defined. These warrants are 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.
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. None
of these warrants were exercised as of March 31, 1997.
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.
Stock option transactions during 1995, 1996 and 1997 are summarized as follows:
Options Price
Outstanding Range
------------ -----------
March 31, 1994 644,794
Options exercised (23,000) $.99
Options granted 57,500 $1.50-$1.88
Options canceled (125,925) $.98-$1.52
-----------
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
Exercisable at March 31, 1997 513,356
===========
F-19
48
A summary of stock options outstanding at March 31, 1997 follows:
Options Option
Exercisable at March 31, 1997 through: Outstanding Price
-------------------------------------- ----------- -----
August 31, 1997 124,131 $4.91
February 20, 1999 230,000 $1.52
May 31, 1999 20,000 $1.88
October 10, 1999 20,000 $1.50
January 18, 2000 17,500 $1.62
March 12, 2001 10,000 $.94
May 17, 2001 66,700 $.98
March 19, 2003 5,175 $1.38
March 31, 2003 3,450 $1.55
September 4, 2006 16,400 $.78
-------
513,356
=======
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
and 1997 consistent with the provisions of SFAS No. 123, the Company's net loss
per share would not change materially.
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 91,549 shares of common stock related to this plan 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:
F-20
49
1995 1996 1997
------------- ------------- -------------
Provision based on the statutory rate $ 125,000 $(643,000) $ 99,000
Tax effect of:
Adjustment from prior years 18,000 39,000 28,000
Statutory depletion (108,000) (109,000) (143,000)
Other - net 14,000 75,000 16,000
------------- ------------- -------------
Total $ 49,000 $(638,000) $ -
============= ============= =============
The components of the net deferred tax liability as of March 31, 1996 and 1997
were as follows:
1996 1997
------------ -------------
DEFERRED TAX LIABILITIES:
Property and equipment $(364,000) $(350,000)
Other , net (33,100) (56,000)`
------------ -------------
Total deferred tax liabilities (397,100) (406,000)
------------ -------------
DEFERRED TAX ASSETS:
Alternative minimum tax credit carryforwards 367,000 307,000
Other financial reserves 81,000 65,000
Less- Valuation allowance (367,000) (287,200)
------------ -------------
Total deferred tax assets 81,000 84,800
------------ -------------
Net deferred tax liability $(316,100) $(321,200)
============ =============
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 $15,000 and $20,000 were accrued or paid for the years ended March
31, 1996 and 1997, 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
saleslines additions) of the partnerships as they are incurred. At March 31,
1997, management estimates the commitment to fund such costs to be approximately
$415,998. The commitment is expected to be funded by September 30, 1997.
F-21
50
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.
Effective December 31, 1994, the Chairman of the Board of the Company resigned.
In connection therewith, an existing employment contract was terminated and a
consulting and noncompete agreement was entered into. The consulting and
noncompete agreement provides for the payment of fees of $165,000 per year, and
certain benefits and expenses, as defined, for a three-year period.
The Company has entered into employment contracts with three 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 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 1995, 1996, and 1997 between 28% and 43% of the Company's oil
and gas production revenues were derived from two and/or three significant
purchasers. A significant portion of trade accounts receivable at March 31, 1996
and 1997 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.
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51
CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES
March 31,
--------------------------------------------------
1995 1996 1997
--------------- ---------------- ----------------
Proved oil and gas properties $21,051,552 $ 23,769,853 $ 24,290,505
Accumulated depreciation, depletion, amortization
and impairment (7,749,013) (10,392,335) (10,488,719)
--------------- ---------------- ----------------
Net capitalized costs $13,302,539 $ 13,377,518 $ 13,801,786
=============== ================ ================
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
Year Ended March 31,
--------------------------------------
1995 1996 1997
----------- ---------- ----------
Property acquisition costs $ 71,000 $ 334,934 $ 124,384
Exploration costs 370,106 216,595 121,809
Development costs 4,066,637 2,584,430 1,477,312
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
March 31,
---------------------------------------------
1995 1996 1997
-------------- -------------- --------------
Oil and gas production $ 2,845,573 $2,848,610 $ 3,137,556
Gain (loss) on sale of oil and gas properties 1,175 9,766 (26,031)
Production costs (560,755) (796,530) (777,163)
Exploration expenses (222,729) (156,089) (121,809)
Depreciation, depletion, amortization, impairment and other (1,253,875) (2,550,431) (695,877)
Abandonment of oil and gas properties (147,377) (60,506) (73,528)
-------------- -------------- --------------
662,012 (705,180) 1,443,148
Provision (credit) for income taxes 117,000 (349,000) 347,460
-------------- -------------- --------------
Results of operations for oil and gas producing activities (excluding
corporate overhead and financing costs) $ 545,012 $ (356,180) $ 1,095,688
============== ============== ==============
Provision (credit) for income taxes was computed using the statutory tax rates
for the years ended March 31, 1995, 1996 and 1997 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.
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52
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Oil Gas
(BBLS) (MCF)
------------ --------------
Balance, March 31, 1994 609,900 46,206,000
Extensions, discoveries and other additions 157,900 3,548,000
Production (14,400) (1,161,000)
Revision of previous estimates (291,600) (26,619,000)
Sales of minerals in place (42,100) (1,740,000)
------------ --------------
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
============ ==============
Oil Gas
(BBLS) (MCF)
------------ --------------
PROVED DEVELOPED RESERVES:
March 31, 1994 122,300 13,589,000
March 31, 1995 178,600 15,788,000
March 31, 1996 151,800 16,303,000
March 31, 1997 120,200 14,472,000
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53
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
March 31,
---------------------------------------------------
1995 1996 1997
---------------- ---------------- ---------------
Future cash inflows from sales of oil and
gas $54,022,000 $59,810,000 $44,379,000
Future production and development
costs (20,135,000) (19,992,000) (15,442,000)
Future income tax expense (10,571,000) (12,836,000) (8,145,000)
---------------- ---------------- ---------------
Future net cash flows 23,316,000 26,982,000 20,792,000
Effect of discounting future net cash flows
at 10% per annum (11,681,000) (13,720,000) (10,447,000)
---------------- ---------------- ---------------
Standardized measure of discounted future
net cash flows $11,635,000 $13,262,000 $10,345,000
================ ================ ===============
CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
Year Ended March 31,
-------------------------------------------------
1995 1996 1997
--------------- --------------- ---------------
Balance, beginning of year $15,438,000 $11,635,000 $13,262,000
Extensions, discoveries and other
additions 2,499,000 3,925,000 1,301,000
Sales of oil and gas, net of production
costs (2,198,000) (2,052,000) (2,355,000)
Net changes in prices and production
costs (1,819,000) 3,019,000 (3,567,000)
Revisions of previous quantity
estimates (5,731,000) (2,893,000) (1,477,000)
Sales of minerals in place (464,000) (158,000) (859,000)
Net change in income taxes 2,114,000 (1,034,000) 2,257,000
Accretion of discount 1,544,000 1,163,000 1,326,000
Other 252,000 (343,000) 457,000
--------------- --------------- ---------------
Balance, end of year $11,635,000 $13,262,000 $10,345,000
=============== =============== ===============
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.
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54
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 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. 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. 128,
"Earnings Per Share" which will revise the calculation methods and disclosures
regarding earnings per share. SFAS No. 128 is required to be adopted for
financial statements with fiscal years ending after December 31, 1997. The
Company has not determined the impact, if any, of this standard.
F-26