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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, 1996
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.)
5311 NORTHFIELD ROAD, SUITE 320
CLEVELAND, OHIO 44146-1135
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:(216) 663-1668
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, $.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 12, 1996, the Registrant had outstanding 8,040,285 shares of Common
Stock, 305,140 shares of Series A Preferred Stock, 464,665 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 12, 1996 was $4,377,819 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 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 Annual Meeting of Stockholders to be held on September 4,
1996.
Except as otherwise indicated, the information contained in this Report is as
of March 31, 1996.
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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 region of Ohio and Pennsylvania. The Company's strategy focuses
primarily on its acquisition of proved undeveloped natural gas and oil
properties and on the turnkey 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 non-industry
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, 1996, the Company is serving as the managing general
partner of 23 Drilling Programs and has contracted to operate 657 wells, 365 of
which are operated for the Drilling Programs, 106 of which are operated for the
Company and various working interest owners and 186 of which are operated for
the Company's account. In connection with the drilling and development of the
wells it operates, North Coast currently owns approximately 185 miles of
natural gas gathering pipelines in various counties throughout eastern Ohio and
western Pennsylvania. These gas gathering systems currently transport gas from
576 wells operated by the Company. At March 31, 1996, the Company had
estimated net proved reserves of approximately 20,048,000 Mcf of natural gas
and 195,200 Bbls of oil.
The Company focuses its exploration and development activities in the
Appalachian Basin where wellhead prices for natural gas have, in recent years,
generally averaged higher than in the Gulf Coast and mid-continent regions of
the country due to the area's proximity to major commercial and industrial
markets.
The Company began operations in 1981 with the formation of its first
Drilling Program. In August 1987, the Company completed the acquisition of
Capital Oil & Gas, Inc. which was engaged in drilling and oilfield operations
in the Appalachian Basin, as part of its plan to expand and diversify its
operations. By January 30, 1990, the Company had acquired the assets and
properties of 21 Drilling Programs which it had sponsored, as well as the
assets and properties of its predecessor entity, through an exchange offer (the
"Exchange Offer") which resulted in the Company becoming a public company
subject to the Exchange Act. Since the consummation of the Exchange Offer, the
Company has continued the business and operations of its predecessor and now
serves as the managing general partner of 23 Drilling Programs whose operations
are continuing.
Since its formation, the Company has participated in drilling
operations in a number of areas, including Ohio, Pennsylvania, Louisiana,
Texas, Oklahoma and Colorado. During the last five years, however, North Coast
has concentrated its drilling activities in the Appalachian Basin of Ohio and
Pennsylvania and, for the foreseeable future, the Company anticipates
continuing to focus its activities in the Appalachian Basin. Since the
Exchange Offer, the Company has drilled 425 wells in the Appalachian Basin, all
but 7 of which were drilled in conjunction with the Drilling Programs.
Subsidiaries. On March 31, 1993, the Company reorganized three of its
four principal subsidiaries, consolidating the business activities of Capital
Oil & Gas, Inc., Trinity Oil & Gas, Inc., and North Coast Energy Programs into
North Coast Energy, Inc. The reorganization of its subsidiaries enabled the
Company to reduce certain duplications between its affiliates and increase the
overall efficiency of the Company's operations. As of the date of this report,
the Company's sole active subsidiary is NCE Securities, Inc., ("NCE
Securities") a member of
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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, thereby
reducing its risk through diversification. 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, gas-gathering,
and gas marketing and transportation services which are provided to the
Drilling Programs.
The Company's strategy focuses on increasing its natural gas and oil
reserves, as well as production, drilling and oil field service revenues, by
acquiring undeveloped oil and gas properties in the Appalachian Basin and
financing and conducting the drilling and development of these properties in
conjunction with the Drilling Programs.
While the Company is pursuing its strategy of increasing reserves
through drilling and development in conjunction with the Drilling Programs, it
continues to review potential acquisitions, including other gas and oil
companies or partnerships and producing properties.
Consistent with its efforts to increase reserve levels, from time to
time the Company also may participate in drilling and development activities in
other geographic regions of the US. The budget for these activities typically
has not exceeded $100,000 to $200,000 annually for any such non-Appalachian
project and the Company has no current plans to materially increase this
budget.
AREAS OF OPERATION
Appalachian Basin. 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 by a relatively low
recovery of reserves in place, lower rates of production and wells 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.
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The Company also maintains leasehold acreage in other portions of
Pennsylvania 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.
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.
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.
On December 1, 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 Clinton/Medina producing wells, 43 miles of gas
gathering lines and drilling locations.
The Company secured financing from its lender and from NAGIT (USA),
Inc. ("NAGIT"), a principal stockholder of the Company to purchase these oil
and gas interests. The Company has agreed to repay amounts owed to NAGIT from
the net proceeds of the purchased interests and to grant NAGIT an overriding
royalty interest in the acquired properties. Management of the Company
believes that the loan from NAGIT is on terms no less favorable than the
Company could receive from unrelated third parties.
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, 1996, North
Coast has sponsored 44 Drilling Programs to engage in oil and gas drilling and
development operations. Public Drilling Programs registered with the
Commission accounted for 7 of these programs, while 37 were sold through
private placements. The Company dissolved 21 of the 22 partnerships which were
included in the Exchange Offer and acquired the properties of such
partnerships. The Company currently is the managing general partner of 23
Drilling Programs whose operations are continuing.
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.
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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., a wholly-owned subsidiary of the Company, acts as placement
agent and enters into selling agreements with a number of broker-dealers to
assist it in selling the interests. In the last four calendar years NCE
Securities has entered into selling agreements with more than 35 such
broker-dealers who have sold substantially all of the interests in the Drilling
Programs formed during this period.
The Company has generally sponsored three Drilling Programs each
fiscal year. Typically, the first program is organized in August or September,
the second in November, and the third in late December. The schedule for
marketing and organizing the Drilling Programs is largely a function of selling
broker-dealer and potential investor interest. The Company monitors Drilling
Program subscriptions and generally establishes the closing date for a
particular program based upon the amount of subscriptions received, the
proposed drilling schedule and the Company's determination as to the desired
timing for a subsequent Drilling Program. Although the Company, previously has
elected to form three Drilling Programs each year, the actual number of
Drilling Programs, and consequently the amount of available drilling capital
and wells, will vary depending upon investor interest and other factors.
During fiscal 1996, the Company formed two drilling programs and anticipates
forming at least two drilling programs this fiscal year.
The Drilling Programs raised $8,366,000 during fiscal 1994 and
$8,406,000 during fiscal 1995 and $6,460,000 during fiscal 1996 from
non-industry investors. The Company believes that the decrease from fiscal
1995 to fiscal 1996 results primarily from the uncertainties related to natural
gas prices and the potential returns from drilling program investments by
prospective investors. North Coast intends to continue its effort to market
its Drilling Programs and increase the number of wells drilled. If it is
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
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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, 1996, the Company operated 657 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 576 wells as of March 31, 1996. 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,
1996.
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 alternate 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.
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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
$1.46 to $4.95 during fiscal 1996. As of March 31, 1996, approximately 75% of
the wells operated by the Company which produce gas to fulfill contractual
obligations were either committed for less than one year and/or contained
market sensitive pricing provisions. The variance of unit pricing during March
31, 1996, was from $1.31 to $5.05 per Mcf. On an overall basis, the Company
received an average price of $2.24 per Mcf for natural gas sold during fiscal
1996.
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 under 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. In the near
term, natural gas prices will likely continue to escalate until supply and
demand market factors reach equilibrium. It is likely that these market forces
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 $17.01 per barrel for its oil during
fiscal 1996; 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.
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
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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 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
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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, 1996, the Company had 59 employees, including 23 field
employees, 2 petroleum engineers, 3 geologists and 3 employees engaged in
land/lease acquisition. No employees are represented by a union and the
Company believes that it maintains good relations with its employees.
ITEM 2. PROPERTIES.
Oil and Gas Properties
In the following tables, "gross" refers to the total acres or wells in
which the Company has a working interest and "net" refers to gross acres or
wells multiplied by the Company's percentage working interests therein.
Royalty interests held by the Company will not affect the Company's working
interests (net wells) in its properties and will not be reflected in net wells.
Proved Reserves. The following table reflects the estimates of the
Company's Proved Reserves as of March 31, 1996.
RESERVES
Oil Reserves (Bbls):
Proved Developed 151,800
Proved Undeveloped 43,400
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Total 195,200
Gas Reserves (Mcf):
Proved Developed 16,303,000
Proved Undeveloped 3,745,000
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Total 20,048,000
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)
- --------- ------ ----- ------- ------- -------
1994 16,900 1,162,000 $15.35 $2.46 $2.60
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)
(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.
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11
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, 1996.
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
--- --- ----- --- --- -----
16 615 631 7.10 291.73 298.83
(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, 1996.
LEASEHOLD ACREAGE
Total Leasehold Acreage:
Gross Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68,700
Net Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34,900
Developed Acreage:
Gross Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37,400
Net Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,200
Proved Undeveloped Acreage:
Gross Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,300
Net Acres . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,200
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,
- ---------------------------
1994 1995 1996
---- ---- ----
Exploratory Wells (1)
Productive
Gross 0 0 0
Net 0 0 0
Dry
Gross 1 1 0
Net .250 .250 .000
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12
Development Wells (2)
Productive (4) (5)
Gross 72 71 52
Net 25.372 18.900 9.800
Dry
Gross 0 0 0
Net 0 0 0
Total Wells (3)
Productive
Gross 72 71 52
Net 25.372 18.900 9.800
Dry
Gross 1 1 0
Net .250 .250 .000
(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) Total Wells is the sum of the Exploratory and Development Wells
(4) The number of productive wells for fiscal 1995 includes 6 gross wells
(1.65 net wells) as productive development wells which are awaiting
pipeline connection or well completion operations at March 31, 1996.
(5) The number of productive wells for fiscal 1996 includes 21 gross wells
(3.97 net wells) as productive development wells which are awaiting
pipeline connection or well completion operations at March 31, 1996.
FACILITIES
The Company's headquarters in Cleveland, Ohio, are leased from a
stockholder and consist of approximately 4,650 square feet for which the
Company pays rental of $4,845 per month. The lease is currently month to
month. The Company owns the building from which it conducts its field
operations in Youngstown, Ohio, and also leases additional office space in
Youngstown, Ohio, from an unaffiliated third party. North Coast also maintains
an office located in Colorado Springs, Colorado which is leased from an
unaffiliated third party. The Company anticipates moving 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 will
allow the Company to relocate certain operations and its personnel from its
Cleveland and Youngstown offices. The Youngstown facility owned by the Company
will be converted to use for field operations and the office space that was
leased in Youngstown will not be renewed. The Company initially anticipated
constructing an office facility on land the Company owned in Streetsboro, Ohio,
however, the Company sold the land when the Twinsburg property was purchased.
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, 1996,
there were no matters submitted to a vote of security holders through the
solicitation of proxies or otherwise.
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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 1995
First Quarter . . . . . . . . . . . . . . . . . . $1 7/8 $2 1/8 $1 5/8 $1 7/8
Second Quarter . . . . . . . . . . . . . . . . . . 1 3/4 2 1 1/8 1 5/16
Third Quarter . . . . . . . . . . . . . . . . . . 1 9/16 1 3/4 1 1/4 1 1/2
Fourth Quarter . . . . . . . . . . . . . . . . . . 1 1/2 1 5/8 1 1 1/8
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
As of June 12, 1996, there were 8,040,285 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, 1996, the Company paid $649,864 in aggregate cash dividends, $185,199 on
its Series A Preferred Stock and $464,665 Series B Preferred Stock.
The Company has not paid any cash dividends on its Common Stock and is
restricted from paying such dividends 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 and expansion of its business,
other than funds required for the payment of dividends on the Preferred Stock.
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, 1992, 1993, 1994, 1995 and
1996.
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14
Years Ended March 31
(In thousands, except per share amounts)
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Revenues $10,426 $10,007 $12,834 $15,275 $10,860
Net Income (Loss) 171 241 652 295 (1,254)
Net Income (Loss) per Share(1) (.03) .00 .00 (.05) (.24)
Total Assets 10,105 12,732 15,796 21,136 20,243
Long-term Debt (less current portion) 2,932 1,696 3,626 6,197 8,955
(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 a substantial portion of its
revenues from turnkey drilling, well operations, gas gathering, transportation
and gas marketing services performed under contract with the Drilling Programs.
During the last three fiscal years the Drilling Programs received
$23,232,000 from the sale of partnership interests to non-industry investors.
This funding, together with the Company's contributions to the Drilling
Programs, has resulted in the addition of 226 Drilling Program wells from
fiscal year 1992 through fiscal year 1996.
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.
The Company's continued 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 drilling activity and acquisition of oil and gas properties
resulted in an increase in the Company's proved developed natural gas reserves
to 16,303,000 Mcf for fiscal 1996 from 15,788,000 Mcf for fiscal 1995 while
proved developed oil reserves decreased to 151,800 barrels from 178,600
barrels, respectively. The increase in future net revenues (undiscounted) from
$27,997,000 for fiscal 1995 to $33,772,000 for fiscal 1996 for the net proved
developed reserves was due to increased natural gas prices received at March
31, 1996 as compared to the natural gas price received at March 31, 1995. The
Company produced 1,166,000 Mcf of gas from proved developed reserves while
adding 2,076,000 Mcf through the drilling of new wells. During fiscal 1996,
the Company adopted a methodology of only recognizing 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
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15
which the Company fully expects to drill in the very near future. This
methodology, coupled with the determination that certain proved undeveloped
leasehold acreage no longer fit the Company's long-term development plans at
the current price or development cost, and was either released or
re-categorized to possible or probable reserves, resulted in a downward
revision of proved reserves by 3,299,000 Mcf. Although the Mcfs were revised
downward, the reduction in development costs for undeveloped acreage more than
offset the reduction in reserve value. Proved oil reserves decrease from
419,700 barrels at March 31, 1995 to 195,200 barrels at March 31, 1996 as
extensions and discoveries (including purchases) of 12,600 barrels were offset
by production of 14,100 barrels, sales of 17,100 barrels as contributions of
undeveloped acreage to Drilling Programs and downward revisions of proved
undeveloped leasehold acreage amounting to 205,900 barrels. The decrease in
proved oil reserves was primarily due to the determination that certain proved
undeveloped leasehold acreage no longer fit the Company's development plans at
the current price or development cost and was either re-categorized or
released. Changes in the Standardized Measure of 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 81% are proved developed and approximately
19% 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, 1994, 1995 and 1996. All items in
the table are calculated as a percentage of total revenues.
Revenues: 1994 1995 1996
---- ---- ----
Oil and gas production 24% 19% 26%
Drilling revenues 57 57 50
Well operating, transportation and other 13 18 15
Administrative, management and agency fees 5 5 8
Other 1 1 1
--- --- ---
Total Revenues 100% 100% 100%
--- --- ---
Expenses:
Oil and gas production expenses 4% 4% 7%
Drilling costs 46 47 38
Oil and gas operations 6 13 8
General and administrative expenses 24 19 26
Depreciation, depletion, amortization, impairment and other 12 11 30
Abandonment of oil and gas properties 1 1 1
Provision (credit) for income taxes 1 0 (6)
Other 1 3 7
--- --- ---
Total Expenses 95% 98% 111%
--- --- ---
Net Income (Loss) 5% 2% (11)%
=== === ===
The following discussion and analysis reviews the results of
operations and financial condition for the Company for the years ended March
31, 1994, 1995 and 1996. This review should be read in conjunction with the
Financial Statements and other financial data presented elsewhere herein.
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,
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16
gas prices increased substantially during the Company's fourth quarter due to
the generally colder weather conditions, resulting in increased demand.
Production also has been 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 1400 feet to 2300 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.
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.
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17
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 principal 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.
COMPARISON OF FISCAL 1995 TO FISCAL 1994
REVENUES
Oil and gas production revenues decreased $270,062 (9%) to $2,845,573
for fiscal 1995 as compared to $3,115,635 for the prior corresponding period.
Natural gas production was relatively constant between years with a slight
decrease in oil production. The decrease in revenue is primarily attributable
to an average decrease in gas prices of 9% and a decline in oil production from
the Company's Louisiana properties resulting from reworking of wells throughout
fiscal 1995. For fiscal 1995 the Company received an average price of $15.92
per barrel of oil and $2.25 per Mcf of natural gas compared to an average price
of $15.35 per barrel of oil and $2.46 per Mcf of natural gas received during
fiscal 1994.
Drilling revenues increased by $1,394,541 (19%) as a result of the
increased drilling activity. The Company utilizes the completed contract
method to recognize revenue on drilling contracts. Under this method, drilling
revenues are recognized on wells when they are deemed to be substantially
complete. For fiscal 1995 the Company recognized revenue on 74 wells as
compared to 61 wells in fiscal 1994. This increase in the number of wells
completed along with an increase in the Company's turnkey price resulted in
increased drilling revenues.
Well operating, transportation and other revenues for fiscal 1995
increased $1,153,201 (69%) as compared to fiscal 1994. The increase was
primarily due to increased gas sales made to third parties of $1,310,998 in
fiscal 1995 as compared to sales of $262,511 in fiscal 1994.
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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 $163,382 (25%) for fiscal 1995, as compared to
fiscal 1994, due to the additional Drilling Programs.
EXPENSES
Drilling costs in fiscal 1995 as compared to fiscal 1994 increased
$1,286,375 (22%) primarily due to the increased number of wells completed in
the recent period. The profit margin on drilling revenue decreased to 18% for
fiscal 1995 from 20% for fiscal 1994.
General and administrative expenses decreased $70,966 (2%) for fiscal
1995 as compared to fiscal 1994. A larger decrease was offset somewhat by
Management's decision to withdraw its Registration Statement on Form S-2
resulting in additional expense of approximately $117,000 in associated costs
in fiscal 1995. The Company retained certain capitalized costs incurred with
the Registration Statement at March 31, 1995.
Depreciation, depletion, amortization, impairment and other increased
$181,256 (12%) for fiscal 1995 as compared to fiscal 1994. This increase was
due to increased depreciation resulting from the Company's capital investment
for gas gathering lines for new wells, depreciation of Company vehicles and
amortization of costs associated with the Credit Facility. The Company
continues to capitalize certain costs associated with its Drilling Programs
resulting in an increased depreciable basis of its investment. Consequently,
depreciation, depletion, amortization, impairment and other has increased in
conjunction with increased Drilling Program activity in fiscal 1995.
Abandonment of oil and gas properties increased $74,125 (101%), due
primarily to a larger amount of the Company's Jurmonville acreage abandoned
during fiscal 1995 as compared to fiscal 1994.
Interest expense increased from $184,687 for fiscal 1994 to $529,161
for fiscal 1995. This increase is primarily associated with higher borrowings
under the Credit Facility in order to fund a portion of the Company's
additional investments in fiscal year 1995 Drilling Programs. At March 31,
1996, $6,050,003 was outstanding under the Company's Credit Facility, as
compared to $3,465,774 at March 31, 1995.
Net income for fiscal 1995 of $294,708 compares to $652,132 for fiscal
1994. The decrease in net income for fiscal 1995 resulted primarily from a
decrease in oil and gas production revenues attributable to the decrease in the
average price received for its gas. In addition, net income was decreased by
the increase in interest expense due to the Company's additional borrowings in
fiscal 1995 as compared to the prior year.
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 $17.01 and $15.92 per
barrel for fiscal 1996 and 1995, respectively, and $2.24 and $2.25 per Mcf for
natural gas for fiscal 1996 and 1995, 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 1995/1996 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
16
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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 negative $ 360,000 at March 31, 1996
compared to negative $482,000 at March 31, 1995. The increase of $ 122,000 in
working capital from March 31, 1995 reflects the Company's use of cash to
purchase property and equipment to meet its obligations to fund its investments
in the Drilling Programs. Also, the Company's current accounts receivable
related to Federal Income Taxes increased during the year ended March 31, 1996.
An amendment to the Credit Facility increased the Company's borrowing base to
$9,360,000 (after adjustment for outstanding letters of credit) at March 31,
1996. As of March 31, 1996, the Company had $7,560,000 outstanding under its
Credit Facility. North Coast's current ratio was .90 to 1.0 at March 31, 1996
and .90 to 1.0 at March 31, 1995.
The following table summarizes the Company's financial position at
March 31, 1995 and 1996:
(Amounts in Thousands) 1995 1996
---- ----
Amount % Amount %
------ --- ------ ---
Working capital $ (482) (3%) $ (360) (2%)
Property and equipment 16,387 100 16,737 100
Other 445 3 253 2
------- --- ------- ---
Total $16,350 100% $16,630 100%
======= === ======= ===
Long-term debt $ 6,197 38% $ 8,954 54%
Deferred income taxes 930 6 357 2
Stockholders' equity 9,223 56 7,319 44
------ --- ------- ---
Total $16,350 100% $16,630 100%
======= === ======= ===
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, 1994, 1995 and 1996:
(Amounts in Thousands) 1994 1995 1996
---- ---- ----
Dollars % Dollars % Dollars %
------- --- ------- --- ------- ---
Net cash provided by operating activities 3,318 73 2,428 40 1,049 27
Net cash used for investing activities (4,543) (100) (5,065) (83) (3,377) (87)
Net cash provided by financing activities 516 11 3,708 60 1,513 39
------ ---- ------ --- ------ ---
Increase (decrease) in cash and cash equivalents (709) (16) 1,071 17 (815) (21)
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(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 decreased approximately $ 1,379,000 for fiscal 1996 as
compared to fiscal 1995. This decrease is due to the reduced amount of funds
raised in Drilling Programs, resulting in reduced drilling activity and lower
profits.
Net cash used for investing activities decreased from $5,065,000 (83%
of cash sources) for fiscal 1995 to $3,377,000 (87% of cash sources) for fiscal
1996. The decrease of $1,688,000 was due to the Company's purchase of certain
oil and gas interests in fiscal 1995 in western Pennsylvania compared to small
individual purchases of working interests in fiscal 1996. In addition, the
Company's investment in tangible equipment and gas gathering lines for Drilling
Programs were reduced in fiscal 1996, compared to fiscal 1995, due to the
reduced number of wells drilled, the timing and amount of funds raised in
Drilling Programs and the reduced investment in tangibles resulting from
drilling shallower wells.
Net cash provided by financing activities decreased by $2,195,000 from
fiscal 1995 to fiscal 1996. This decrease reflects the sale of stock in fiscal
1995 without a corresponding sale of stock in fiscal 1996 coupled with a
decrease in overall borrowings between the comparable periods.
On September 20, 1993 the Company entered into an agreement with an
affiliate of its lender to provide a reducing revolving line of credit of up to
$10,000,000 (the "Credit Facility"). The Credit Facility (as amended for
borrowing base adjustments) provided the Company with available (future)
borrowings of $9,360,000 (after adjustment for outstanding letters of credit)
at March 31, 1996 based upon the Company's financial position and level of oil
and natural gas and pipeline-based reserves, with available borrowings reducing
$110,000 at the first of each month. Available borrowings also are subject to
reduction based upon the amount of outstanding letters of credit used to
support certain bonding requirements ($140,000 as of March 31, 1996). The
Credit Facility provides that availability is subject to adjustment based upon
the Company's semi-annual reserve study and is subject to certain covenants
(see Note 4 to the Company's March 31, 1996 financial statements). As of March
31, 1996, the Company had $7,560,000 outstanding under the Credit Facility. At
March 31, 1996 the Company was in violation of its stockholders' equity loan
covenant, although this violation has been waived by the lender. Amounts
borrowed under the Credit Facility bear interest at the lending bank's prime
rate plus 1-1/2%. Also, at March 31, 1996, the Company had approximately
$67,000 outstanding under a mortgage note payable. The mortgage note bears
interest at the rate of 8% and requires the Company to make monthly payments of
approximately $1,019 through July 2003. Also, subsequent to year end 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 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 secured $335,000 in
financing from NAGIT, a principal stockholder of the Company, relating to the
purchase of certain producing wells, gas gathering lines and drilling
locations. The amounts outstanding under the terms of the Company's financing
arrangements with NAGIT are subordinated to the prior payment and amounts
outstanding under the Company's Credit Facility, and bear an interest rate at
the prime rate designated by the Chemical Bank, N.A., plus 1% (9.25% at March
31, 1996). This agreement grants NAGIT an overriding royalty interest in the
acquired properties. Repayment of the loan is in cash based upon a percentage
of the net monthly revenues from the acquired properties.
Also, effective June 13, 1995, the Company entered into a Loan
Agreement with NAGIT with respect to a loan of $1,000,000. The unsecured loan
may be repaid in cash plus accrued interest (with approval of the Company's
senior lender) with the proceeds of a sale of equity securities 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
18
21
senior lender and bears interest at the rate of 8% per annum. As of March 31,
1996, the balance of the loan and accrued interest was $1,064,000. 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.
The oil and gas industry is intensely capital driven and
demands on the Company's capital resources may increase further during fiscal
1997. The potential increases may result from additional drilling and
completion obligations of the Company relating to its sponsorship of Drilling
Programs, further development of the Company drilling prospects, the
possibility of future joint ventures or other arrangements intended to assist
in increasing the Company's reserve base and production revenues and the
dividend obligations associated with the Company's Preferred stock.
Management of the Company believes that internally generated funds and
available borrowings under its Credit Facility will be sufficient to fund the
Company's anticipated capital expenditures as well as its working capital needs
through the end of the current fiscal year. During fiscal year 1996, the
Company adhered to its plan of increasing drilling margins by adjusting both
its percentage of ownership of the wells drilled by the Drilling Programs and
the depths of these wells. The improvement in drilling margins was a result of
reduced drilling and completion costs and increasing per well drilling
revenues. Although Management has taken the steps outlined above, due to the
amount of funds committed to current Drilling Programs and future projects, the
uncertainties associated with the amount of funds which may be raised from
investors in future Drilling Programs, and uncertainties associated with
turnkey drilling costs and future production revenues, it may be necessary for
the Company to secure additional sources of capital or financing for its future
projects and to fund its obligations. In the event that available borrowings
under the Credit Facility are not sufficient or if additional financing is
needed and cannot be obtained, the Company believes that it would be required
to change its growth oriented business strategy to conserve cash. 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 certain 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. SFAS No.
123 is required to be adopted for Financial Statements with fiscal years
beginning after December 15, 1995. The Company is currently reviewing the
Accounting Standard and has not yet determined the effect, if any, on its
Financial Statements.
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
NORTH COAST ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
F-1
23
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-24
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
24
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, 1995 and
1996, 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, 1996. 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, 1995 and 1996, and the results of their operations
and their cash flows for each of the three fiscal years in the period ended
March 31, 1996, 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.
Arthur Andersen LLP
Cleveland, Ohio,
May 31, 1996.
F-3
25
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
MARCH 31, 1995 AND 1996
ASSETS
1995 1996
------------ ------------
CURRENT ASSETS:
Cash and equivalents $ 2,366,660 $ 1,551,748
Accounts receivable-
Trade, net 1,592,321 1,339,601
Affiliates 59,243 97,993
Inventories 218,628 85,235
Deferred income taxes 59,000 41,000
Refundable income taxes - 115,000
Other, net 7,682 22,097
------------ ------------
Total current assets 4,303,534 3,252,674
------------ ------------
PROPERTY AND EQUIPMENT, at cost:
Land 122,699 122,699
Oil and gas properties (successful efforts) 21,051,552 23,769,853
Pipelines 3,187,714 3,696,277
Vehicles 384,241 427,920
Furniture and fixtures 362,288 453,718
Building and improvements 145,539 145,539
------------ ------------
25,254,033 28,616,006
Less- Accumulated depreciation, depletion, amortization and
impairment (8,867,435) (11,879,077)
------------ ------------
16,386,598 16,736,929
OTHER ASSETS, net 445,534 253,206
------------ ------------
$21,135,666 $20,242,809
============ ============
The accompanying notes are an integral part of these consolidated balance
sheets.
F-4
26
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
MARCH 31, 1995 AND 1996
LIABILITIES AND STOCKHOLDERS' EQUITY
1995 1996
-------------- -------------
CURRENT LIABILITIES:
Current portion of long-term debt $ 432,100 $ 213,060
Accounts payable 3,644,368 2,481,558
Accrued expenses 423,981 280,565
Billings in excess of costs on uncompleted contracts 284,880 637,347
------------- -------------
Total current liabilities 4,785,329 3,612,530
------------- -------------
LONG-TERM DEBT, net of current portion 6,197,450 8,954,574
DEFERRED INCOME TAXES, net 930,000 357,100
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Series A, 6% Noncumulative Convertible Preferred stock, par value
$.01 per share; 563,270 shares authorized; 309,460 and 305,200
issued and outstanding (aggregate liquidation value of $3,094,600
and $3,050,200, respectively) 3,095 3,052
Series B, Cumulative Convertible Preferred stock, par value $.01
per share; 625,000 shares authorized, 464,665 issued and
outstanding (aggregate liquidation value $4,646,650) 4,647 4,647
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; 8,030,352 and 8,040,148 issued and outstanding 80,304 80,402
Additional paid-in capital 12,083,024 12,082,969
Retained deficit (2,948,183) (4,852,465)
------------- -------------
Total stockholders' equity 9,222,887 7,318,605
------------- -------------
$21,135,666 $20,242,809
============= =============
The accompanying notes are an integral part of these consolidated balance
sheets.
F-5
27
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED MARCH 31, 1994, 1995 AND 1996
1994 1995 1996
------------ ------------ ------------
REVENUE:
Oil and gas production $ 3,115,635 $ 2,845,573 $ 2,848,610
Drilling revenues 7,407,065 8,801,606 5,490,364
Well operating, transportation and other 1,661,347 2,814,548 1,610,469
Administrative, management and agency fees 649,630 813,012 911,053
------------ ------------ ------------
12,833,677 15,274,739 10,860,496
------------ ------------ ------------
COSTS AND EXPENSES:
Oil and gas production expenses 547,926 560,755 796,530
Drilling costs 5,892,074 7,178,449 4,160,788
Oil and gas operations 828,804 1,942,547 881,025
General and administrative expenses 3,020,268 2,949,302 2,878,762
Depreciation, depletion, amortization,
impairment and other 1,529,382 1,710,638 3,298,359
Abandonment of oil and gas properties 73,252 147,377 60,506
------------ ------------ ------------
11,891,706 14,489,068 12,075,970
------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS 941,971 785,671 (1,215,474)
------------ ------------ ------------
OTHER INCOME:
Interest 35,678 90,720 63,063
Other 9,545 - 14,429
Gain on sale of property and equipment 20,125 - 18,295
------------ ------------ ------------
65,348 90,720 95,787
------------ ------------ ------------
OTHER EXPENSE:
Interest 184,687 529,161 772,731
Loss on sale of property and equipment - 3,522 -
------------ ------------ ------------
184,687 532,683 772,731
------------ ------------ ------------
INCOME (LOSS) BEFORE INCOME TAXES 822,632 343,708 (1,892,418)
PROVISION (CREDIT) FOR INCOME TAXES:
Current 274,000 82,000 (83,100)
Deferred (103,500) (33,000) (554,900)
------------ ------------ ------------
170,500 49,000 (638,000)
------------ ------------ ------------
NET INCOME (LOSS) $ 652,132 $ 294,708 $ (1,254,418)
============ ============= ============
NET LOSS APPLICABLE TO COMMON STOCK (after Preferred
stock dividends of $680,165, $654,111 and $649,864
in 1994, 1995 and 1996, respectively) $ (28,033) $ (359,403) $ (1,904,282)
============ ============= ============
NET LOSS PER SHARE (primary and fully diluted)
$0.00 $(0.05) $(0.24)
============ ============= ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
28
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED MARCH 31, 1994, 1995 AND 1996
Series A Series B
Preferred Stock Preferred Stock
--------------------- ---------------------
Shares Amount Shares Amount
---------- ------- --------- --------
BALANCE, MARCH 31, 1993 343,380 $3,434 479,200 $4,792
Net income - - - -
Issuance of Common stock - - - -
Shares converted (25,715) (257) (3,800) (38)
Stock distribution - - - -
Dividends on Series A Preferred stock ($.60 per
share) - - - -
Dividends on Series B Preferred stock ($1.00 per
share) - - - -
-------- ------ -------- ------
BALANCE, MARCH 31, 1994 317,665 3,177 475,400 4,754
Net income - - - -
Exercise of stock options - - - -
Issuance of Common stock - - - -
Shares converted (8,205) (82) (10,735) (107)
Dividends on Series A Preferred stock ($.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
======== ====== ======== ======
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
29
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED MARCH 31, 1994, 1995 AND 1996
Common Stock Additional Total
- ------------------------ Paid-In Retained Stockholders'
Shares Amount Capital Deficit Equity
- --------- ---------- ----------- ------------ ------------
5,330,375 $53,304 $ 8,537,919 $(1,012,088) $7,587,361
- - - 652,132 652,132
100,000 1,000 127,962 - 128,962
70,430 704 (409) - -
825,951 8,260 1,540,399 (1,548,659) -
- - - (203,365) (203,365)
- - - (476,800) (476,800)
- --------- ------- ----------- ----------- ----------
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
========= ======= =========== =========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-8
30
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED MARCH 31, 1994, 1995 AND 1996
1994 1995 1996
----------- ------------ -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 652,132 $ 294,708 $(1,254,418)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities-
Depreciation, depletion, amortization, impairment and other 1,529,382 1,710,638 3,298,359
Abandonment of oil and gas properties 73,252 147,377 60,506
Loss (gain) on sale of property and equipment (20,125) 3,522 (18,295)
Deferred income taxes (103,500) (33,000) (554,900)
Change in-
Accounts receivable (268,469) (404,481) 213,970
Inventories and other current assets 25,529 (187,258) 118,979
Refundable income taxes - - (115,000)
Other assets, net (18,924) (48,156) 88,129
Accounts payable 843,324 1,340,497 (997,350)
Accrued expenses 129,290 9,886 (143,417)
Billings in excess of costs on uncompleted contracts 475,628 (405,892) 352,467
----------- ------------ -----------
Total adjustments 2,665,387 2,133,133 2,303,448
----------- ------------ -----------
Net cash provided by operating activities 3,317,519 2,427,841 1,049,030
----------- ------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of property and equipment (4,557,595) (5,075,715) (3,389,274)
Proceeds on sale of property and equipment 15,000 10,620 12,253
----------- ------------ -----------
Net cash used for investing activities (4,542,595) (5,065,095) (3,377,021)
----------- ------------ -----------
The accompanying notes are an integral part of these consolidated financial
statements.
F-9
31
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED MARCH 31, 1994, 1995 AND 1996
1994 1995 1996
----------- ------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of accounts payable used to finance property and
equipment additions $ (74,878) $ (335,552) $ (236,422)
Borrowings under revolving credit facility 5,515,774 3,020,000 3,800,000
Borrowings under note payable to stockholder - 335,000 1,064,000
Repayment of borrowings under revolving credit facility (2,750,000) (435,771) (2,290,003)
Payments on long-term debt (1,499,339) (89,321) (127,278)
Cash paid for deferred financing (124,178) (25,973) (47,354)
Exercise of stock options - 22,500 -
Proceeds from issuance of Common stock 128,962 1,871,500 -
Distributions and dividends (680,165) (654,111) (649,864)
----------- ------------ -----------
Net cash provided by financing activities 516,176 3,708,272 1,513,079
----------- ------------ -----------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS (708,900) 1,071,018 (814,912)
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 2,004,542 1,295,642 2,366,660
----------- ------------ -----------
CASH AND EQUIVALENTS AT END OF YEAR $ 1,295,642 $ 2,366,660 $ 1,551,748
=========== ============ ===========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for-
Interest $ 184,000 $ 521,000 $ 716,000
Income taxes 120,000 155,000 30,000
SUPPLEMENTAL DISCLOSURES ON NONCASH INVESTING AND FINANCING
ACTIVITIES:
Long-term debt incurred for the purchase of property and
equipment $ 84,000 $ 111,000 $ 91,000
Accounts payable incurred for the purchase of property and
equipment 336,000 236,000 71,000
Accounts payable from interest on long-term debt - - 64,000
The accompanying notes are an integral part of these consolidated financial
statements.
F-10
32
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1994, 1995 AND 1996
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 25.0%
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
33
North Coast Energy 1991-2 Appalachian Drilling Program Limited
Partnership 25.0%
North Coast Energy 1991-3 Appalachian Drilling Program Limited
Partnership 25.0%
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%
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
34
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 3 to 7 years,
building and improvements using accelerated methods over 31 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.
G. Per Share Amounts
The computation of primary and fully diluted earnings per share for 1994, 1995
and 1996 does not assume the conversion of the 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.
F-13
35
The average number of outstanding shares used in computing both primary and
fully diluted loss per share was 6,195,091, 7,210,268 and 8,033,642 for the
years ended March 31, 1994, 1995 and 1996, 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.
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.
2. BILLINGS IN EXCESS OF COSTS ON UNCOMPLETED CONTRACTS:
Billings in excess of costs on uncompleted contracts consist of the following
at March 31:
1995 1996
-------- ----------
Billings on uncompleted contracts $687,850 $1,518,486
Costs incurred on uncompleted contracts 402,970 881,139
-------- ----------
$284,880 $ 637,347
======== ==========
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, 1994, 1995 and
1996, amounted to approximately $73,000, $80,000 and $82,000, respectively. In
1994, 1995 and 1996, rent expense of approximately $65,000 was incurred
pursuant to the lease of the Company's corporate headquarters from one of the
Company's principal stockholders.
F-14
36
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:
1995 1996
---------- ----------
Revolving credit notes payable--bank $6,050,003 $7,560,000
Notes payable to stockholder with interest at prime plus 1% and 8% 335,000 1,386,842
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 73,790 67,842
Various installment notes payable in aggregate monthly installments
(including interest) of $8,585 and $11,012 at March 31, 1995 and
1996, respectively, through 1999 170,757 152,950
---------- ----------
6,629,550 9,167,634
Less- Current portion 432,100 213,060
---------- ----------
$6,197,450 $8,954,574
========== ==========
The Company has an agreement with its lender to provide a reducing revolving
line of credit of up to $10,000,000. Available borrowings under this agreement
are computed based on a borrowing base determined semi-annually by the lender,
based upon the Company's financial position and level of oil and gas and
pipeline based reserves, and are further reduced based upon the amount of
outstanding letters of credit used to support certain bonding requirements
($140,000 at March 31, 1996). The borrowing base is reduced monthly by an
amount determined by the lender at the semi-annual borrowing base
determination. At March 31, 1996, the borrowing base was $9,360,000, and
required monthly reductions of $110,000 beginning in May 1996. Available
borrowings under the revolving line of credit were $1,800,000 at March 31,
1996, and may subsequently change based on the semi-annual 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 1998.
Amounts outstanding under the reducing revolving line of credit bear interest
at the lending bank's prime rate plus 1.5% or approximately 10.5% and 9.75% at
March 31, 1995 and 1996, respectively. The weighted average interest rate on
these borrowings was 9.6% and 10.4% for fiscal 1995 and 1996, 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 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,
1996.
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.
F-15
37
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. During fiscal
1996, the Company entered into an additional 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 1997 $ 213,060
Fiscal 1998 8,895,174
Fiscal 1999 14,115
Fiscal 2000 9,268
Fiscal 2001 10,127
Thereafter 25,890
----------
$9,167,634
==========
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 (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
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.
F-16
38
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 by two, and
the holders of the Series B will be entitled to elect such two additional
directors to the Board of Directors. Such voting right will terminate when all
such distributions accrued and in default have been paid in full or set apart
for payment, as defined.
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.
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, 1995 and 1996, 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 $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, 1996.
F-17
39
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 1994, 1995 and 1996 are summarized as follows:
Options Price
Outstanding Range
----------- -----------
March 31, 1993 357,581
Options granted 345,000 $1.52
Options canceled (57,787) $1.38-$2.17
-------
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
=======
Exercisable at March 31, 1996 499,831
=======
A summary of stock options outstanding at March 31, 1996 follows:
Options Option
Exercisable at March 31, 1996 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 69,000 $.98
March 19, 2003 5,750 $1.38
March 31, 2003 3,450 $1.55
-------
499,831
=======
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.
F-18
40
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 66,958 shares of common stock related to this plan since
inception.
F. Stock Distribution
In fiscal 1994, the Board of Directors of the Company declared a 15% common
stock distribution. In March 1994, 825,951 shares of common stock were issued
as a result of this distribution.
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:
1994 1995 1996
---------- --------- ---------
Provision based on the statutory rate $ 280,000 $ 125,000 $(643,000)
Tax effect of:
Adjustment from prior years 12,500 18,000 39,000
Statutory depletion (119,000) (108,000) (109,000)
Other - net (3,000) 14,000 75,000
---------- ---------- ---------
Total $ 170,500 $ 49,000 $(638,000)
========== ========== =========
The components of the net deferred tax liability as of March 31, 1995 and 1996
were as follows:
1995 1996
--------- ----------
DEFERRED TAX LIABILITIES:
Property and equipment $(551,000) $(364,000)
Partnership income difference (212,000) -
Other (167,000) (106,100)
--------- ----------
Total deferred tax liabilities (930,000) (470,100)
--------- ----------
DEFERRED TAX ASSETS:
Alternative minimum tax credit carryforwards 204,000 367,000
Other financial reserves 59,000 81,000
Partnership income difference - 73,000
Less- Valuation allowance (204,000) (367,000)
--------- ----------
Total deferred tax assets 59,000 154,000
--------- ----------
Net deferred tax liability $(871,000) $(316,100)
========= =========
F-19
41
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 $44,000 and $15,000 were accrued for the years
ended March 31, 1994 and 1996, respectively. No contribution was accrued for
the year ended March 31, 1995.
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,
1996, management estimates the commitment to fund such costs to be
approximately $916,000. The commitment is expected to be funded by September
30, 1996.
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 1994, 1995, and 1996 between 17% and 39% 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,
1995 and 1996 was attributable to these purchasers.
F-20
42
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.
CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES
March 31,
-------------------------------------------
1994 1995 1996
----------- ----------- ------------
Proved oil and gas properties $17,124,567 $21,051,552 $ 23,769,853
Accumulated depreciation, depletion, amortization
and impairment (6,819,740) (7,749,013) (10,392,335)
----------- ----------- ------------
Net capitalized costs $10,304,827 $13,302,539 $ 13,377,518
=========== =========== ============
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
Year Ended March 31,
-------------------------------------
1994 1995 1996
----------- ----------- ----------
Property acquisition costs $ 67,000 $ 71,000 $ 334,934
Exploration costs 224,639 370,106 216,595
Development costs 3,809,332 4,066,637 2,584,430
F-21
43
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
March 31,
----------------------------------------
1994 1995 1996
----------- ----------- ----------
Oil and gas production $ 3,115,635 $ 2,845,573 $2,848,610
Gain on sale of oil and gas properties 20,125 1,175 9,766
Production costs (547,926) (560,755) (796,530)
Exploration expenses (167,347) (222,729) (156,089)
Depreciation, depletion, amortization, impairment and other (1,240,916) (1,253,875) (2,550,431)
Abandonment of oil and gas properties (73,252) (147,377) (60,506)
----------- ----------- ----------
1,106,319 662,012 (705,180)
Provision (credit) for income taxes 250,000 117,000 (349,000)
----------- ----------- ----------
Results of operations for oil and gas producing activities
(excluding corporate overhead and financing costs) $ 856,319 $ 545,012 $ (356,180)
============ ============ ===========
Provision (credit) for income taxes was computed using the statutory tax rates
for the years ended March 31, 1994, 1995 and 1996 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.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Oil Gas
(BBLS) (MCF)
--------- ------------
Balance, March 31, 1993 58,000 39,024,000
Extensions, discoveries and other additions 554,100 25,758,000
Production (16,900) (1,162,000)
Revision of previous estimates 15,500 (15,322,000)
Sales of minerals in place (800) (2,092,000)
--------- ------------
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
========= ============
PROVED DEVELOPED RESERVES:
March 31, 1993 33,100 11,182,000
March 31, 1994 122,300 13,589,000
March 31, 1995 178,600 15,788,000
March 31, 1996 151,800 16,303,000
F-22
44
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
March 31,
---------------------------------------------
1994 1995 1996
------------ ----------- -----------
Future cash inflows from sales of oil and
gas $124,748,000 $54,022,000 $59,810,000
Future production and development costs
(62,331,000) (20,135,000) (19,992,000)
Future income tax expense (20,204,000) (10,571,000) (12,836,000)
------------ ----------- -----------
Future net cash flows 42,213,000 23,316,000 26,982,000
Effect of discounting future net cash
flows at 10% per annum (26,775,000) (11,681,000) (13,720,000)
------------ ----------- -----------
Standardized measure of discounted future
net cash flows $ 15,438,000 $11,635,000 $13,262,000
============ =========== ===========
CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
Year Ended March 31,
-------------------------------------------
1994 1995 1996
----------- ----------- -----------
Balance, beginning of year $12,944,000 $15,438,000 $11,635,000
Extensions, discoveries and other
additions 9,247,000 2,499,000 3,925,000
Sales of oil and gas, net of production
costs (2,568,000) (2,198,000) (2,052,000)
Net changes in prices and production
costs 1,990,000 (1,819,000) 3,019,000
Revisions of previous quantity estimates
(4,854,000) (5,731,000) (2,893,000)
Sales of minerals in place (657,000) (464,000) (158,000)
Net change in income taxes (1,612,000) 2,114,000 (1,034,000)
Accretion of discount 1,294,000 1,544,000 1,163,000
Other (346,000) 252,000 (343,000)
----------- ----------- -----------
Balance, end of year $15,438,000 $11,635,000 $13,262,000
=========== =========== ===========
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.
The estimated quantities of proved oil 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.
F-23
45
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:
During 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 October 1995, the Financial Accounting Standards Board issued SFAS No. 123,
"Accounting for Stock-Based Compensation" which permits either recording the
estimated 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. SFAS No. 123 is required to
be adopted for financial statements with fiscal years beginning after December
15, 1995. The Company is currently reviewing the accounting standard and has
not yet determined the effect, if any, on its financial statements.
F-24
46
Item 9. Disagreements on Accounting and Financial Disclosure.
Not Applicable.
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 Annual Meeting of Shareholders to be held on
September 4, 1996, 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 36, 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 42, 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 is a
member of the Ohio Oil and Gas Association and the Society of Petroleum
Engineers.
Thomas A. Hill, age 38, 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.
Robert M. Hoisek, age 44, is Executive Vice President, Sales and Marketing
for North Coast. From 1984 through 1986, Mr. Hoisek served as Director of
Marketing and, prior to rejoining North Coast in 1990, he served as a director
and officer of various oil and gas companies. Mr. Hoisek has been associated
with the oil and gas industry for fifteen years and is a member of the
Independent Petroleum Association of America and the American Gas Association.
*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 Annual Meeting of Shareholders to
by held on September 4, 1996, 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.
20
47
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item 12 is incorporated by reference to
the information set forth under the captions "Principal Shareholders" and
"Share Ownership of Directors and Officers" in the Company's definitive Proxy
Statement for the Annual Meeting of Shareholders to be held on September 4,
1996, 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 Annual Meeting of Shareholders
to be held on September 4, 1996, 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-24
(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
48
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly cased this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
NORTH COAST ENERGY, INC.
By /s/ Charles M. Lombardy Chief Executive Officer June 26, 1996
- --------------------------
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 26, 1996
- ------------------------- (principal executive officer)
Charles M. Lombardy, Jr.
/s/ Garry Regan Director June 26, 1996
- -------------------------
Garry Regan
/s/ Timothy Wagers Treasurer and Chief Financial Officer June 26, 1996
- ------------------------- (principal accounting and financial officer)
Timothy Wagers
/s/ Charles K. Ebinger Director June 26, 1996
- -------------------------
Charles K. Ebinger
/s/ W. Dale Wegrich Director June 26, 1996
- -------------------------
W. Dale Wegrich
/s/ George R. Begley Director June 26, 1996
- -------------------------
George Begley
/s/ Robert L. Bauman Director June 26, 1996
- -------------------------
Robert L. Bauman
22
49
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. (J)
10.1 Employment Agreement dated May 3, 1995 by and between Registrant and Charles M. Lombardy, Jr. (J)
10.2 Employment Agreement dated May 3, 1995 by and between Registrant and Garry Regan. (J)
10.3 1988 Stock Option Plan. (B)
10.4 Form of Profit Sharing Plan. (B)
10.5 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.
10.6 Amendment (dated as of July 15, 1988 but effective for all purposes as of (B)
October 4, 1989) to Option Agreement originally dated August 31, 1987 by and between
Registrant and Garry Regan.
10.7 Form of Indemnity Agreement between the Registrant and each of its Directors and (B)
executive officers.
10.8 North Coast Energy, Inc. Key Employees Stock Bonus Plan. (B)
10.9 Stock Option Agreement dated as of May 17, 1991 between Registrant and Timothy (C)
Wagers.
10.10 Stock Option Agreement dated as of May 17, 1991 between the Registrant and (C)
Thomas A. Hill.
10.11 Option Agreement dated February 22, 1994 by and between Registrant and (E)
Charles M. Lombardy, Jr.
50
Exhibit Sequential
Number Description of Documents Page
- ------- ------------------------ ----------
10.12 Option Agreement dated February 22, 1994 by and between Registrant and Garry Regan. (E)
10.13 Reducing Revolving Credit Agreement dated September 20, 1993 between Bank One (E)
Texas, N.A. and North Coast Energy, Inc.
10.14 First Amendment to Credit Agreement dated March 16, 1994 between Bank One Texas, (E)
N.A. and North Coast Energy, Inc.
10.15 Agreement dated January 6, 1995 between Bruce E. Brocker, Garry Regan, (F)
Charles M. Lombardy, Jr. and the Registrant.
10.16 Option Agreement dated June 2, 1994 by and between Registrant and Charles Ebinger. (G)
10.17 Option Agreement dated June 2, 1994 by and between Registrant and W. Dale Wegrich. (G)
10.18 Option Agreement dated October 11, 1994 by and between Registrant and (G)
Tony Kovacevich.
10.19 Employment Agreement dated October 11, 1994 by and between Registrant (G)
and Tony Kovacevich.
10.20 Share Purchase Agreement between NAGIT (USA) INC. and the Registrant dated (H)
September 29, 1994.
10.21 Stockholder's Agreement between Charles M. Lombardy, Jr., Garry Regan and (H)
NAGIT (USA) INC. dated as of September 29, 1994.
10.22 Loan and Participation Agreement by and between NAGIT (USA) INC. and the Company (I)
dated as of January 13, 1995.
10.23 Second Amendment to Credit Agreement by and between Bank One, Texas, N.A. (I)
and the Company dated January 13, 1995.
10.24 Loan Agreement by and between NAGIT (USA) INC. and the Company dated (J)
June 13, 1995.
10.25 8% Convertible Subordinated Note for $1,000,000 by and between NAGIT(USA) INC. (J)
and the Company dated June 13, 1995.
10.26 Warrant to purchase 200,000 shares of Common Stock of the Company. (J)
10.27 Warrant to purchase 300,000 shares of Common Stock of the Company. (J)
10.28 Third Amendment to Credit Agreement by and between Bank One, Texas, N.A. and (K)
the Company dated August 8, 1995.
10.29 Fourth Amendment to Credit Agreement by and between Bank One, Texas, N.A. and _
the Company dated March 31, 1996.
51
Exhibit Sequential
Number Description of Documents Page
- ------- ------------------------ ----------
10.30 Restated Employment Agreement dated May 3, 1995 by and between Registrant and _
Charles M. Lombardy, Jr.
10.31 Restated Employment Agreement dated May 3, 1995 by and between Registrant and _
Garry Regan.
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 Current Report on Form 8-K dated January 6, 1995.
(G) 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.
(H) Incorporated herein by reference to the appropriate exhibit to the
Schedule 13D dated September 29, 1994.
(I) 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.
(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, 1995.
(K) 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.
*Exhibit 27.1 furnished for Securities and Exchange Commission purposes only.