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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
FORM 10-K
<Table>
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
</Table>
COMMISSION FILE NUMBER 0-18691
---------------------
NORTH COAST ENERGY, INC.
(Exact name of Registrant as specified in its charter)
<Table>
DELAWARE 34-1594000
(State of incorporation) (I.R.S. Employer Identification No.)
1993 CASE PARKWAY 44087-2343
TWINSBURG, OHIO (Zip Code)
(Address of principal executive offices)
</Table>
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(330) 425-2330
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
COMMON STOCK, $0.01 PAR VALUE
(Title of class)
SERIES A 6% CONVERTIBLE NON-CUMULATIVE PREFERRED STOCK, $0.01 PAR VALUE
(Title of class)
SERIES B CUMULATIVE CONVERTIBLE PREFERRED STOCK, $0.01 PAR VALUE
(Title of class)
WARRANTS TO PURCHASE COMMON STOCK, $0.01 PAR VALUE
(Title of class)
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 February 28, 2003, the Registrant had outstanding 15,251,679 shares of
Common Stock, 72,336 shares of Series A Preferred Stock, and no shares of Series
B Preferred Stock.
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No. [X]
The aggregate market value of Common Stock held by non-affiliates of the
Registrant at February 28, 2003, was $12,960,941 which value was computed on the
basis of $6.33 per share of Common Stock, the mean between the closing bid and
ask price as reported for that day on the Nasdaq Stock Market.
DOCUMENTS OR PARTS THEREOF INCORPORATED BY REFERENCE
Part of Form 10-K
Part III (Items 11, 12, and 13)
Document Incorporated by Reference
Registrant's definitive proxy statement filed under Regulation 14A promulgated
by the Securities and Exchange Commission under the Securities Exchange Act of
1934, which definitive proxy statement is to be filed within 120 days after the
end of Registrant's fiscal year ended December 31, 2002, is incorporated by
reference in Part III hereof.
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PART I
ITEM 1. BUSINESS
OVERVIEW
North Coast Energy, Inc., ("NCE"), is an independent energy company engaged
in the exploration, development and production of natural gas and oil in the
Appalachian Basin of the United States. The Company began operations in 1981.
As of December 31, 2002, the Company owned interests in 4,138 wells, and
operated 3,869 of these wells. In connection with producing natural gas from the
wells it operates, the Company currently owns and operates 1,523 miles of
natural gas gathering systems with access to the commercial and industrial gas
markets of the northeastern United States. At December 31, 2002, the Company had
estimated net proved reserves of approximately 174 Bcf (billion cubic feet) of
natural gas and 1.3 million barrels of oil. The estimated future net cash flows
from these reserves had a present value (discounted at 10 percent) before income
taxes of approximately $243 million at December 31, 2002. Daily net production
as of December 31, 2002 was approximately 25 MMcf (million cubic feet of natural
gas) and 257 barrels of oil. At that date, the Company held leases on 415,515
gross (320,736 net) acres, including 230,270 gross (172,232 net) undeveloped
acres.
The Company has grown principally through the acquisition of producing
natural gas properties and related gas gathering facilities and the exploration
and development of its leasehold acreage. We have a consistent track record of
reserve replacement and growth through both drilling and acquisitions. In 2002,
the Company drilled 115 wells at a direct cost of $20.7 million, adding 19.2
Bcfe (billion cubic feet of natural gas equivalent) at an average cost of $1.08
per Mcfe (thousand cubic feet of natural gas equivalent). All of the wells
drilled by the Company in 2002 were commercially productive. In addition, we
acquired producing properties having 7.7 Bcfe of proved developed reserves at an
average cost of $0.45 per Mcfe.
Our proved reserves totaled 182 Bcfe at December 31, 2002, of which 96% was
natural gas. This proved reserve level is the Company's highest ever, and
represents an 18% increase over the prior year-end. The increase is due to our
successful drilling programs in 2001 and 2002, aided by strong year-end
commodity prices.
In 2002, net income was $9.8 million, or $0.64 per share and was the
highest annual level of earnings that we have ever achieved. Cash flow of $23.8
million, or $1.56 per share, was also a record, and represented a 16% increase
over last year. The strong commodity prices experienced in 2002 combined with
increased oil and gas production and strategic hedging of natural gas prices
were the main factors in this year's financial success. At December 31, 2002,
the Company had approximately 72% of its expected production in 2003 from proved
developed producing reserves hedged through fixed-price contracts and financial
collars at an average price of $3.65 per Mcf at the collar floor price and $4.52
at the collar ceiling price.
SIGNIFICANT EVENTS
ON AUGUST 2, 2001, THE COMPANY CHANGED ITS FISCAL YEAR END FROM MARCH 31 TO
A CALENDAR YEAR END OF DECEMBER 31. AS A RESULT, THE OPERATIONAL AND FINANCIAL
INFORMATION PRESENTED IN THIS REPORT WILL REFLECT THE FISCAL YEARS ENDED
DECEMBER 31, 2002 AND MARCH 31, 2001 AS WELL AS THE NINE-MONTH PERIOD ENDED
DECEMBER 31, 2001. FOR COMPARATIVE PURPOSES THE UNAUDITED TWELVE MONTHS ENDED
DECEMBER 31, 2001 AND NINE MONTHS ENDED DECEMBER 31, 2000 ARE ALSO PRESENTED.
The Company stopped offering drilling investment programs at the end of
2001 -- electing to focus its resources on growing its exploration and
production business. We do not plan to offer investment programs to outside
investors in the future.
In August 2002, the Company offered to buy all of the outstanding interests
in 17 of its prior drilling programs. A majority of the interests in 14 of the
partnerships voted in favor of selling the partnerships' assets to the Company.
We acquired the assets of these 14 partnerships; the partnerships were
terminated; and the proceeds of the sale were distributed to the remaining
investors.
1
AREA OF OPERATIONS
The Appalachian Basin is located in close proximity to major natural gas
markets in the northeastern United States. This proximity to a substantial
number of large commercial and industrial gas markets, coupled with the
relatively stable nature of the Basin's production and the availability of
transportation facilities has resulted in generally higher wellhead prices for
Appalachian Basin natural gas than those prices available in the Gulf Coast and
Mid-continent regions of the United States. The 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. Although the
Basin has sedimentary formations indicating the potential for deposits of gas
and oil reserves to depths of 30,000 feet or more, most production in the 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 long-lived reserves that produce for more than 20 years. Drilling success
rates of the Company and other operators drilling to these formations
historically have exceeded 90%.
Long production life and high drilling success rates in these shallow
formations has resulted in a highly fragmented, extensively drilled, low
technology operating environment in the Basin. As a result, there has been
limited testing or development of productive and potentially productive
formations at deeper depths in the Basin. The Company believes that significant
exploration and development opportunities exist in these deeper, less developed
formations for those operators with the capital, technical expertise and ability
to assemble the large acreage positions needed to justify the use of advanced
exploration and production technologies. In 2002, we drilled six wells to the
Knox series of formations, four of which were commercially productive. While two
wells were nonproductive in the Knox formations, they were completed as
producing wells in the Trenton/Black River formation. In 2003, we plan to drill
14 gross wells to this deeper more prolific formation.
BUSINESS STRATEGY
The Company's business strategy is to increase stockholder value by
increasing production, operating margins and cash flow through the exploration
and development of our existing and acquired acreage base; by making strategic
acquisitions that either enhance operating results and/or are beneficial to the
Company's future strategic positioning; by improving profit margins through
operational and technological efficiencies; and through the further expansion of
the Company's gas gathering systems. The key elements of the Company's business
strategy are as follows:
- Maintain a Balanced Drilling Program. The Company intends to focus its
exploration and development activities on a well-balanced portfolio of
development drilling in the shallow blanket formations of the Basin and
development and exploratory drilling in the deeper more prolific
formations in the Basin. This broad portfolio approach allows the Company
to optimize economic returns and minimize certain of the geological risks
associated with gas and oil development and exploration.
- Make Strategic Acquisitions That Enhance Operating and Financial
Results. The Company uses a highly disciplined approach to acquisition
analysis that requires each acquisition to be accretive to the Company's
long-term operational and financial performance. Approval to proceed with
an acquisition requires input and approval from all key areas of the
Company. These areas include field operations, exploration and
production, finance, legal, land management and environmental compliance.
- Improve Profit Margins. The Company intends to become one of the most
efficient operators in the Basin. To accomplish this goal, we intend to
improve our profit margins on the production from existing and acquired
properties through advanced production techniques, operating
efficiencies, mechanical improvements and the use of enhanced recovery
methods.
- Expand its Natural Gas Gathering Systems. The Company currently owns and
operates approximately 1,523 miles of gas gathering lines in Ohio,
Pennsylvania, West Virginia and Kentucky. All of these lines connect or
have the ability to connect to various intrastate and interstate natural
gas transmission and distribution systems. The interconnections with
these pipelines give the Company access to numerous natural gas markets,
including existing and proposed electric power generating facilities. We
intend to
2
continue to expand our gas gathering systems to further enhance
production capacity and improve the rate of return on our exploration and
development operations.
- Risk Management. The Company manages its exposure to natural gas price
volatility by selling a portion of its future gas production under
fixed-price contracts with varying expiration dates, using financial
hedging instruments to realize a target price for a portion of its future
gas production and by monitoring technical and fundamental information to
determine when to use various financial hedging techniques. We believe
that over the next decade those companies that master the ability to
manage the volatility of natural gas prices will be successful - given
the fundamental shift in the price of this commodity that appears to have
taken place.
ACQUISITIONS
The Company's acquisition strategy focuses on natural gas properties and
entities that can provide:
- Enhanced cash flow,
- Additional drilling and development opportunities,
- Synergies with the Company's existing properties,
- Enhancement potential of current operations, and/or
- Economies of scale and cost efficiencies.
In the three calendar years ended December 31, 2002, the Company acquired
approximately 11 Bcfe of proved developed reserves at an average cost of $0.51
per Mcfe. In addition during that period, the Company acquired various gas
gathering systems and numerous drilling locations.
GAS AND OIL OPERATIONS AND PRODUCTION
Operations. The Company operates 93% of the wells in which it holds
working interests. It seeks to maximize the value of its properties through
operating efficiencies, operating cost reductions and equipment improvements.
We currently maintain production field offices in Ohio, West Virginia and
Kentucky. Through these offices, management, technical professionals and field
personnel continuously review our properties to identify actions which could
reduce operating costs and improve production.
Production. The following table summarizes the net gas and oil production
and the average sales prices and average production (operating) expenses per
equivalent unit of production for the years ended December 31, 2001 and 2002,
the nine months ended December 31, 2001 and for the fiscal year ended March 31,
2001.
PRODUCTION
<Table>
<Caption>
PRODUCTION SALES PRICE AVERAGE
FISCAL YEAR OR ----------------------- ----------------- OPERATING COST
PERIOD ENDED OIL (MBBLS) GAS (BCF) PER BBL PER MCF PER MCFE (1)
- -------------- ----------- --------- ------- ------- --------------
March 31, 2001........................... 96 7.8 $28.28 $3.40 $1.08
December 31, 2001 (2).................... 82 6.4 20.75 3.31 .93
December 31, 2001........................ 98 8.4 21.57 3.43 1.01
December 31, 2002........................ 104 9.6 22.63 3.64 0.84
</Table>
- ---------------
(1) For calculation of average operating cost (including production taxes) per
Mcfe, the standard ratio of 6:1 for natural gas to oil was used.
(2) Nine months ended December 31, 2001.
3
EXPLORATION AND DEVELOPMENT
The exploration and development activities we conduct have primarily
involved exploring and developing our existing acreage and acquiring proved
undeveloped gas and oil properties and exploring and developing these
properties.
The Company's historical drilling operations in the Basin have principally
involved drilling to the Clinton/ Medina sandstone formation. This formation is
a gas and oil bearing sandstone, which underlies a large portion of eastern Ohio
and western Pennsylvania in varying thicknesses and at depths ranging generally
from 2,800 to 7,500 feet. Substantially all of the wells that the Company has
drilled to this formation have depths ranging between 3,500 and 6,700 feet.
In 1993, the Company began a seismic data program that led to the inception
of exploratory and development drilling to formations below the Clinton/Medina
Sandstone on a portion of its Ohio leasehold acreage. This exploratory drilling
has focused on the Knox Group, a sequence of sandstone and dolomite formations
that includes the Rose Run, Beekmantown and Trempealeau productive zones, at
depths ranging from 2,500 to 8,000 feet.
In the Company's area of interest, the Knox formations are found
approximately 2,000 feet below the Clinton formation at depths between 5,000 and
7,000 feet. To date, the Company's exploration of the Knox formations has
resulted in 12 commercially productive wells of the 17 wells drilled. Indicative
of the more prolific nature of the deeper formations in the basin, productive
Knox wells represented only 0.3% of the Company's producing wells, while
accounting for 13% of the Company's gas and oil production in 2002.
The Company's exploration and development strategy is to develop a balanced
portfolio of drilling prospects that includes lower risk wells with a high
probability of success and higher risk wells with greater economic potential.
The Company maintains substantial leasehold acreage in portions of Ohio,
Pennsylvania and West Virginia with the potential for production from the
deeper, less developed formations in the Appalachian Basin.
We continually evaluate undeveloped prospects originated by our technical
staff as well as prospects generated by other independent geologists and gas and
oil companies. If the review of a prospect indicates that it may be geologically
and economically attractive, we will attempt to lease the mineral rights
encompassing the prospect's acreage. Typically, we will acquire the entire
working interest in a lease by 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.
In the twelve months ended December 31, 2002, the Company drilled 115 gross
(100.8 net) wells in its four state operating area at a direct cost of
approximately $20.7 million for the net wells. In 2003, the Company expects to
spend approximately $17 million to drill 100 gross (90 net) development and
exploratory wells. The Company believes that its diversified portfolio approach
to its drilling activities results in more consistent and predictable economic
results than might be experienced with a less diversified or higher risk
drilling profile.
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,
4
nor should it be assumed that there is necessarily any correlation between the
number of productive wells drilled and the gas and oil reserves generated.
DRILLING ACTIVITIES
<Table>
<Caption>
FISCAL YEAR ENDED FISCAL YEAR ENDED NINE MONTHS ENDED FISCAL YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- ----------------- -----------------
Exploratory Wells(1)
Productive
Gross................. 8 7 7 5
Net................... 6.1 6.5 6.5 4.3
Dry
Gross................. 0 0 0 0
Net................... 0 0 0 0
Development Wells(2)
Productive(3)
Gross................. 107 77 57 46
Net................... 94.7 51.3 49.3 13.2
Dry
Gross................. 0 0 0 0
Net................... 0 0 0 0
Total Wells
Productive
Gross................. 115 84 64 51
Net................... 100.8 57.8 55.8 17.4
Dry
Gross................. 0 0 0 0
Net................... 0 0 0 0
</Table>
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(1) Exploratory Wells are those wells drilled outside the confines of a known
productive reservoir area.
(2) Development Wells are those wells drilled within the confines of a known
productive reservoir.
(3) The number of productive wells for the year ended December 31, 2002 includes
20 gross (20 net) wells that were waiting for pipeline connection or well
completion operations at December 31, 2002.
DRILLING PROGRAMS
From the Company's inception in 1981 through 2001, we sponsored investment
programs to engage in gas and oil drilling and development operations on behalf
of outside investors. The Company stopped offering these investment programs in
2002 and does not intend to offer such programs in the future. We are currently
managing the assets of nine remaining investment programs.
OIL FIELD SERVICE OPERATIONS
As of December 31, 2002, NCE operated 3,869 wells located in Ohio,
Pennsylvania, West Virginia and Kentucky. As operator of these wells, the
Company is responsible for the maintenance and verification of all production
records, contracting for gas and oil 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 services for
producing wells. The Company may, however, subcontract certain field operations
that require third party services. The Company receives a monthly operating fee
for each producing well it operates for third parties and is reimbursed for most
third party costs associated with operating and producing these wells. Each
working interest owner in a well pays the Company its share of the operating fee
based upon its aggregate interest in the well.
5
GAS GATHERING ACTIVITIES
In connection with the drilling and completion of the natural gas wells
that we operate, the Company has acquired, constructed and owns approximately
1,523 miles of gas gathering systems throughout Ohio, Pennsylvania, West
Virginia and Kentucky. These gathering lines carry natural gas from the wellhead
to various gas transmission systems for sale to utilities, the Company's
industrial customers and to natural gas marketers purchasing gas for resale to
others. The Company intends to continue to acquire and construct gathering
systems and to establish compressor facilities in order to expand its existing
and future potential markets.
For its gas gathering services, the Company collects certain allowances
from public utilities, end users or other natural gas purchasers, including
natural gas marketers. Gathering fees and allowances in 2002 averaged
approximately $0.19 per Mcf.
MARKETS
Our ability to market gas and oil depends, to an extent, on factors beyond
our control. The potential effects of governmental regulation and market factors
including alternative domestic and imported energy sources, available pipeline
capacity, and general market conditions are not entirely predictable.
Natural Gas. Natural gas is generally sold pursuant to individually
negotiated gas purchase contracts, which vary in length from spot market sales
of a single day to term agreements that may extend for a year or more. The
Company's natural gas customers include utilities, natural gas marketing
companies, and a variety of commercial and industrial end users. 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 varies daily
-- reflecting changing market conditions.
The deliverability and price of natural gas are subject to both
governmental regulation and the forces of supply and demand. During the past
several years, regional natural gas surpluses and shortages have occurred
resulting in wide fluctuations in the prices paid to producers.
The contract duration for each of the Company's gas purchase agreements
varies widely. Additionally, several of our contracts provide for prices to be
set monthly based on published NYMEX (New York Mercantile Exchange) or
Appalachian price indices. The Columbia Gas Transmission Corp. and Dominion
Transmission Inc. Appalachia Index prices, which create a basis for spot sale
prices in the Mid-Atlantic and Northeast regions of the United States, ranged
from $2.17 to $4.41 per MMBtu during 2002. (One MMBtu represents one million
British Thermal Units. One MMBtu is approximately equal to one Mcf.) At December
31, 2002, approximately 13% of the Company's natural gas contracts were
fixed-price contracts with industrial end-users. The prices received from these
contracts range between $3.36 and $6.20 per Mcf. The remainder of fixed-price
contracts was with utilities and natural gas marketers. The prices received from
these contracts range between $2.42 and $4.30 per Mcf. In 2002, the Company
received an average price of $3.64 per Mcf. In 2002, one customer purchased 20%
of the gas produced by the Company.
Due to the high volatility of natural gas prices over the last three years,
the Company has adopted a price hedging strategy of converting, where possible,
fixed-price contracts to short-term market sensitive contracts. Where
successful, this allows the Company to financially hedge the converted volumes.
For 2003, the Company has approximately 18% of its production committed to
fixed-price contracts at an average price of $3.74 per Mcf. The Company has also
put costless collars on approximately 54% of its expected 2003 production from
proved developed producing reserves, with a weighted average floor and ceiling
of $3.61 and $4.77 per Mcf, respectively. The Company also has costless collars
on 39% of its 2004 proved developed reserves with a weighted average floor price
of $3.72 per Mcf and a weighted average ceiling price of $5.38 per Mcf. Costless
collars are financial hedging instruments that the Company uses to limit the
impact of price decreases, (the "floor price"), in turn placing an upward limit
on the potential benefit of price increases (the "ceiling price").
During the past several years, periodic overabundances or short-term
shortages of natural gas deliverability and promulgation of state and federal
regulations pertaining to the sale, transportation, and marketing of natural gas
have resulted in high volatility of natural gas prices. Recent trends have also
shown that there may be an imbalance between supply and demand as evidenced by
the increase in natural gas futures prices during 2002.
6
Crude Oil. Oil produced from the Company's properties is generally sold at
the prevailing field price to one or more unaffiliated purchasers in the area.
Generally, purchase contracts for the sale of oil are cancelable on 30 days
notice. The price paid by these purchasers is generally an established, or
"posted," price that is offered to all producers. The Company received an
average price of $22.63 per barrel for its oil in 2002; however, during the last
several years prices paid for crude oil have fluctuated substantially. The price
posted for purchase contracts for the sale of Pennsylvania-grade crude oil at
December 31, 2002 was $27.50, compared to $16.25 at December 31, 2001. Future
oil prices are difficult to predict due to the impact of worldwide economic and
political events. Oil production comprised approximately 6% of our total gas and
oil production calculated on a Mcfe basis in 2002. Therefore, an increase or
decrease in oil prices will have a minimal impact on revenues when compared to
the effect of the price of natural gas. To the extent that the price that the
Company receives for its crude oil increases or decreases from current levels,
revenues from oil production will be affected accordingly.
COMPETITION
The gas and oil industry is highly competitive. Competition is particularly
intense with respect to the acquisition of producing properties and the sale of
gas and oil production. There is competition among gas and oil producers as well
as with other industries in supplying energy and fuel to end-users.
The Company's competitors in gas and oil exploration, development and
production include numerous independent gas and oil companies, individual
proprietors, natural gas pipelines and their affiliates. Many of these
competitors possess and employ financial and personnel resources substantially
in excess of those of the Company. The ability of the Company to increase its
production and add to its reserves in the future will depend on the availability
of capital, the ability to exploit its current lease holdings and the ability to
identify and acquire suitable producing properties and undeveloped prospects for
future exploration and development.
REGULATION
Exploration and Production. The exploration, production and sale of
natural gas and oil are subject to various local, state and federal laws and
regulations. These laws and regulations govern a wide range of matters,
including the drilling and spacing of wells, allowable rates of production,
restoration of surface areas, plugging and abandonment of wells and requirements
for the operation of wells. Such regulations may adversely affect the rate at
which the Company's wells produce gas and oil. In addition, legislation and new
regulations concerning gas and oil exploration and production operations are
constantly being reviewed and proposed. Most of the states in which the Company
owns and operates properties have laws and regulations governing several of the
matters enumerated above. Compliance with the laws and regulations affecting the
gas and oil industry generally increases our cost of doing business and
consequently affects our profitability.
Environmental Matters. Discharging oil, gas or other pollutants into the
air, soil or water may give rise to liabilities and may require the Company to
incur costs to remedy the discharge. Natural gas, oil or other pollutants
(including brine) may be discharged in many ways, including from a well or
drilling equipment at a drill site, leakage from 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). Compliance
with these 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 our capital
expenditures or earnings.
We do not believe that our environmental risks are materially different
from those of comparable companies in the gas and oil industry. We believe our
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 increases 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
7
environmental risks generally are not fully insurable. The amount of such
coverage is currently not less than $1 million and is provided on a "claims
made" basis.
Marketing and Transportation. The Federal Energy Regulatory Commission
(the "FERC") regulates the interstate transportation and sale for resale of
natural gas 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"), eliminated all gas price regulation effective January 1, 1993.
In 1992 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 the Company is not an interstate pipeline, we believe the
changes brought about by Order 636 have increased natural gas price competition
in the marketplace.
Various rules, regulations and orders, as well as statutory provisions may
also 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 the operating hazards
and risks normally incident to drilling for and producing gas and oil, such as
encountering unusual formations and pressures, blowouts, environmental
pollution, and personal injury. We will maintain such insurance coverage as we
believe 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 inventory
such as crude oil stored in tanks. Our insurance policies also have standard
exclusions. Losses can occur from an uninsurable risk or in amounts in excess of
existing insurance coverage. The occurrence of an event which is not insured or
not fully insured, could have an adverse impact on the Company's revenues and
earnings.
EMPLOYEES
At February 28, 2003, the Company had 150 full-time employees, including
105 field employees, 3 petroleum engineers, 3 geologists, 1 geoscientist, 6
accountants, 2 landmen, 1 attorney, and 2 gas marketers. No employees are
represented by a union, and the Company believes that it maintains good
relations with its employees.
KEY EMPLOYEES
In addition to the officers and directors listed in Item No. 10, the
following personnel are key to the Company's operations.
TONY L. ANDERSON currently serves as Operations Manager for the Company's
Southern Appalachian Business Unit. He is responsible for coordinating some of
the Company's engineering functions as well as being responsible for the
business unit's producing operations. He started his career in 1984 when he was
hired by KemGas, a wholly-owned subsidiary of Kaiser Aluminum. Mr. Anderson
served as Production/Reservoir Engineer for Presidio Oil. He has 18 years of
experience in the gas and oil industry. He received a BS degree in Petroleum
Engineering from Marietta College and is a Professional Registered Engineer.
EDWARD J. ANDREWS joined the Company in January 2003 as Senior Exploration
Geoscientist. From 1992 to 2002 he served as Senior Staff Geophysicist for
Belden & Blake Corporation and from 1983 to 1992 as Senior Geophysicist for
Standard Oil Company and British Petroleum Company. He has 27 years of energy
industry experience. Mr. Andrews holds a BS degree in Geology and an MS degree
in Geophysics from Bowling Green State University. He is a member of the Society
of Exploration Geophysicists and the Ohio Oil and Gas Association.
8
DAVID L. COX has served as Manager of Geology since March 2002. He has been
employed as a Petroleum Geologist since 1980, previously working for Belden &
Blake Corporation, Presidio Oil, and Kaiser Energy. He is a Certified Petroleum
Geologist with the American Association of Petroleum Geologists, where he has
been a member since 1983. Mr. Cox holds a BS degree in Geology from West
Virginia University and has served two terms as President of the Appalachian
Geological Society.
ROBERT A. CRISSINGER serves as the District Manager for the Company's
Northern Appalachian Business Unit, encompassing drilling and production
operations in northern Ohio and Pennsylvania. He holds a BS degree in petroleum
engineering from Marietta College. Mr. Crissinger has 25 years of engineering
experience and 30 years of diversified gas and oil industry experience that
includes working for a major integrated gas and oil company and large and small
independent gas and oil companies. Mr. Crissinger is a member of the Society of
Petroleum Engineers, the Ohio Oil and Gas Association, and the Oil and Gas
Association of New York.
CHARLES P. FABER joined the Company in May 2001 as Director of Corporate
Development. He previously served as Vice President of Corporate Development for
Belden & Blake Corporation from 1993 to April 2001 and as Senior Vice President
of Capital Markets for that company from 1988 to 1993. Mr. Faber was employed as
Senior Vice President of Marketing for Heritage Asset Management from 1986 to
1988. From 1983 to 1986, he served as President and Chief Executive Officer of
Samson Properties Incorporated, a gas and oil investment management company
headquartered in Tulsa, Oklahoma. Mr. Faber holds a BBA degree in Marketing and
an MBA in Finance from the University of Wisconsin where he graduated with
honors. He is a member of the Independent Petroleum Association of America, the
Ohio Oil and Gas Association and the National Investor Relations Institute.
ROBERT R. GESSNER, JR. was appointed to the position of Corporate
Controller in 2001. He joined the Company as Director of Corporate Development
in May 2000. From April 1988 through April 2000, Mr. Gessner was employed by
Belden & Blake Corporation, an Appalachian-based gas and oil company, where he
was involved in all phases of operational accounting and financial reporting.
From 1979 to 1988, he served as Senior Accountant for the M.A. Hanna Company.
Mr. Gessner received a BBA degree in Accounting from Cleveland State University.
He is a Certified Public Accountant and a member of the Ohio Society of
Certified Public Accountants.
PAUL W. POOLE, SR. is District Manager for the Company's Southern
Appalachian Business Unit. He joined the Company as Land Manager in March, 2000
when the Company acquired NCEE. He was previously employed by Belden and Blake
Corporation as Land Manager and Corporate Land Due Diligence Team Leader for all
acquisitions. He was a charter employee of Kaiser Energy and has 31 years
experience in the gas and oil industry having served as Assistant General
Manager with Kaiser Energy and Eastern Division Land Manager with Presidio Oil
Company. He holds an AA Degree in Business Administration and is a member of the
American Association of Petroleum Landmen ("AAPL") and the Michael Benedum
Chapter of the AAPL.
JOHN M. SINGER has served as Director of Gas Marketing since December 2001.
Prior to joining the Company, Mr. Singer was responsible for acquiring and
marketing natural gas with Columbia Energy Services, Inc. from 1996 to 2000 and
with Enron North America from 2000 to 2001. From 1993 to 1996 he was employed by
Belden & Blake Corporation in its Gas Marketing Division. Mr. Singer holds an
Associate Degree in Applied Business from Stark State College of Technology and
is a Certified Public Accountant (inactive). He is a member of the Ohio Oil and
Gas Association ("OOGA"), the Independent Oil and Gas Association of West
Virginia ("IOGA-WVA") and the Kentucky Oil and Gas Association. He serves on the
Natural Gas Committee for OOGA and the Commerce Committee for IOGA-WV.
9
ITEM 2. PROPERTIES
Proved Reserves. The following table reflects the Company's estimates of
proved gas and oil reserves as of December 31, 2002. These estimates were
reviewed and agreed to by Schlumberger Data and Consulting Services.
RESERVES
<Table>
Oil Reserves (MBbls)
Proved Developed.......................................... 1,204
Proved Undeveloped........................................ 115
-------
Total.................................................. 1,319
=======
Gas Reserves (MMcf)
Proved Developed.......................................... 150,979
Proved Undeveloped........................................ 22,693
-------
Total.................................................. 173,672
=======
MMcf Equivalent(1)
Proved Developed.......................................... 158,203
Proved Undeveloped........................................ 23,383
-------
Total.................................................. 181,586
=======
</Table>
- ---------------
(1) Oil was converted to Mcfe in the standard ratio of one Bbl equals six Mcf.
See Note 15 to the Consolidated Financial Statements for more detailed
information regarding the Company's gas and oil reserves. The following table
sets forth the estimated future net cash flows from the proved reserves of the
Company as of December 31, 2002 determined in accordance with the rules and
regulations of the U.S. Securities and Exchange Commission.
ESTIMATED FUTURE NET CASH FLOWS (BEFORE INCOME TAXES)
ATTRIBUTABLE TO ESTIMATED PRODUCTION DURING
<Table>
<Caption>
(IN THOUSANDS)
2003........................................................ $ 33,484
2004........................................................ 36,763
2005........................................................ 35,702
2006 and thereafter......................................... 557,857
--------
$663,806
========
</Table>
Estimated future net cash flows represent estimated future gross revenues
from the production and sale of proved reserves, net of estimated production
costs, including production taxes, ad valorem taxes, operating costs,
development costs and additional capital investment. Estimated future net cash
flows were calculated on the basis of prices and costs estimated to be in effect
at December 31, 2002 without escalation, except where changes in prices were
fixed and readily determinable under existing contracts.
The following table sets forth the weighted average prices for gas and oil
utilized in determining the Company's reserves.
<Table>
<Caption>
YEAR ENDED NINE-MONTHS ENDED FISCAL YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- -----------------
Gas (per Mcf)....................... $5.02 $3.13 $5.01
Oil (per Bbl)....................... 27.00 17.25 23.25
Per Mcfe............................ 5.00 3.12 4.95
</Table>
10
Gas and Oil Properties. In the following tables, "gross" refers to the
total wells or acres in which the Company has a working interest and "net"
refers to gross wells or acres multiplied by the Company's percentage working
interest in them.
Productive Wells. The following table shows the number of gross and net
productive gas and oil wells operated by the Company as of December 31, 2002.
Wells are classified as gas or oil according to their predominant product
stream.
<Table>
<Caption>
GAS WELLS OIL WELLS TOTAL WELLS
------------- ----------- -------------
STATE GROSS NET GROSS NET GROSS NET
- ----- ----- ----- ----- --- ----- -----
Ohio...................................... 1,315 980 0 0 1,315 980
Pennsylvania.............................. 573 456 28 10 601 466
West Virginia............................. 1,457 1,240 364 361 1,821 1,601
Kentucky.................................. 132 127 0 0 132 127
----- ----- --- --- ----- -----
Totals............................... 3,477 2,803 392 371 3,869 3,174
===== ===== === === ===== =====
</Table>
Acreage. The following table shows the Company's developed and undeveloped
leasehold acreage on both a gross and net basis as of December 31, 2002. The
amount included in proved undeveloped acreage recognizes only the acreage
directly offsetting locations to wells that have indicated commercial production
in the objective formation and that the Company expects to drill in the near
future.
LEASEHOLD ACREAGE
<Table>
Total Leasehold Acreage
Gross Acres............................................... 415,515
Net Acres................................................. 320,736
Developed Acreage
Gross Acres............................................... 175,045
Net Acres................................................. 140,752
Proved Undeveloped Acreage
Gross Acres............................................... 10,200
Net Acres................................................. 7,752
Unproved Acreage
Gross Acres............................................... 230,270
Net Acres................................................. 172,232
</Table>
The Company owns a 12,000 square foot building, its corporate headquarters,
in Twinsburg, Ohio. As part of the acquisition of Peake Energy, Inc. in 2000
(now, North Coast Energy Eastern, Inc.) the Company acquired 11,280 square feet
of office and operational facilities near Ravenswood, West Virginia. The Company
also owns or leases operating facilities in Youngstown and Cambridge, Ohio, and
Maben and Clarksburg, West Virginia. It also leases a small operating facility
in Shrewsbury, Kentucky.
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 three months ended December 31, 2002, there were no matters
submitted to a vote of security holders through the solicitation of proxies or
otherwise.
11
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's Common Stock is traded on the NASDAQ SmallCap Market under
the symbol "NCEB." The following table sets forth the high and low bid and ask
prices for the Company's Common Stock for the periods indicated.
COMMON STOCK
(amounts rounded to the third decimal)
<Table>
<Caption>
HIGH LOW
--------------- ---------------
BID ASK BID ASK
------ ------ ------ ------
YEAR ENDED
DECEMBER 31, 2001
First Quarter...................................... $4.624 $4.750 $3.625 $3.813
Second Quarter..................................... 5.250 5.250 3.500 3.580
Third Quarter...................................... 4.460 4.500 3.070 3.170
Fourth Quarter..................................... 3.760 3.900 3.050 3.130
YEAR ENDED
DECEMBER 31, 2002
First Quarter...................................... $3.980 $4.000 $3.250 $3.300
Second Quarter..................................... 4.300 4.500 3.130 3.190
Third Quarter...................................... 3.480 3.590 2.310 3.130
Fourth Quarter..................................... 4.150 4.240 2.740 2.860
</Table>
As of February 28, 2003, there were 15,251,679 shares of Common Stock
outstanding, which were held by approximately 1,300 holders of record. Of the
total 15,251,679 outstanding shares of the Company's Common Stock, 13,048,277
are held by a subsidiary of n.v. NUON ("NUON"), a limited liability company
organized under the law of The Netherlands.
Holders of Series A Preferred Stock may be entitled to receive semi-annual
non-cumulative cash dividends at an annual rate of $.60 per share when and if
declared by the Board of Directors. Such dividends are payable on June 1 and
December 1 of each year. The Series A Preferred Stock is convertible to 0.46
shares of Common Stock. All of the outstanding shares of Series B Preferred
Stock were redeemed on March 31, 2002. The redemption price for each outstanding
Series B Preferred share was $10.00. For the three months ended March 31, 2002,
the Company paid $58,165 in aggregate cash dividends on its Series B Preferred
Stock.
The Company has never paid any cash dividends on its Common Stock and is
currently restricted from paying cash dividends on its Common Stock under the
terms of its credit facility. The Company currently intends to retain future
earnings in order to provide funds for use in the operation of its business.
12
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data for the Company for
the years ended December 31, 2002 and 2001, the nine months ended December 31,
2001, and for each of the three fiscal years ended March 31, 2001, 2000, and
1999.
<Table>
<Caption>
YEARS ENDED
--------------------------------------------------------------------
NINE MONTHS
DEC. 31, DEC. 31, ENDED MAR. 31, MAR. 31, MAR. 31,
2002 2001 DEC. 31, 2001 2001 2000 1999
-------- -------- ------------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
Revenues................. $46,263 $49,173 $32,121 $45,535 $15,640 $12,982
Net Income............... 9,752 8,779 5,348 6,759 1,312 870
Net Income per share
(1).................... 0.64 0.56 0.34 0.46 0.21 0.16
Total Assets............. 151,851 144,790 144,790 135,353 123,618 43,573
Long Term Debt........... 67,000 67,000 67,000 67,167 90,122 21,494
Stockholders' equity..... 64,737 59,379 59,379 53,952 23,392 17,943
</Table>
- ---------------
(1) Net Income per share has been restated to reflect stock dividends and all
per share amounts have been restated to give retroactive effect to the
reverse stock split effective June 7, 1999.
The following table sets forth summary unaudited financial information on a
quarterly basis for the four quarters ended December 31, 2002 and 2001.
<Table>
<Caption>
CALENDAR YEAR 2002,
QUARTER ENDED
---------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
PRODUCTION
Oil production (MBbls)......................... 28 22 27 27
Gas production (MMcf).......................... 2,230 2,280 2,425 2,694
Total production (MMcfe)....................... 2,396 2,413 2,585 2,858
AVERAGE PRICES
Oil (per Bbl).................................. $17.68 $22.47 $25.80 $24.69
Gas (per Mcf).................................. 3.54 3.58 3.51 3.90
Average price per Mcfe......................... 3.50 3.59 3.56 3.91
AVERAGE COSTS (per Mcfe)
Production expense (including production
taxes)...................................... 0.80 0.84 0.87 0.84
Depreciation, depletion & amortization......... 0.88 0.87 0.87 0.90
General and administrative expense............. 0.38 0.44 0.37 0.44
GROSS OPERATING MARGIN (per Mcfe)................ 2.70 2.75 2.69 3.07
</Table>
<Table>
<Caption>
CALENDAR YEAR 2002,
QUARTER ENDED
-------------------------------------------
MARCH 31, JUNE 30, SEPT. 30, DEC. 31,
--------- -------- --------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues...................................... $12,149 $10,374 $10,843 $12,897
Net Income.................................... 2,460 2,109 2,302 2,881
Net Income per share.......................... 0.16 0.14 0.15 0.19
Total Assets.................................. 142,685 144,902 149,572 151,851
Long Term Debt................................ 67,000 67,000 67,000 67,000
</Table>
13
<Table>
<Caption>
CALENDAR YEAR 2001,
QUARTER ENDED
---------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
PRODUCTION
Oil production (MBbls)......................... 16 25 27 30
Gas production (MMcf).......................... 1,992 1,957 2,267 2,180
Total production (MMcfe)....................... 2,090 2,108 2,426 2,362
AVERAGE PRICES
Oil (per Bbl).................................. $25.69 $23.18 $21.70 $17.88
Gas (per Mcf).................................. 3.84 3.59 3.25 3.10
Average price per Mcfe......................... 3.86 3.61 3.27 3.09
AVERAGE COSTS (per Mcfe)
Production expense (including production
taxes)...................................... 1.30 1.04 0.92 0.82
Depreciation, depletion & amortization......... 0.68 0.91 0.90 0.95
General and administrative expense............. 0.55 0.46 0.37 0.36
GROSS OPERATING MARGIN (per Mcfe)................ 2.56 2.57 2.35 2.27
</Table>
<Table>
<Caption>
CALENDAR YEAR 2001,
QUARTER ENDED
-------------------------------------------
MARCH 31, JUNE 30, SEPT. 30, DEC. 31,
--------- -------- --------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues...................................... $17,052 $11,213 $10,345 $10,563
Net Income.................................... 3,431 1,533 1,889 1,926
Net Income per share.......................... 0.22 0.10 0.12 0.12
Total Assets.................................. 135,353 136,777 136,870 144,790
Long Term Debt................................ 67,167 67,144 67,000 67,000
</Table>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
NCE is engaged in the acquisition and enhancement of developed natural gas
and oil producing properties and the exploration, development and efficient
production of undeveloped natural gas and oil properties owned in whole or in
part by the Company. NCE derives its revenues from its own gas and oil
production, well operations, gas gathering, transportation and gas marketing
services it provides for third parties who own interests in wells operated by
NCE.
NCE recognizes as proved undeveloped reserves only the potential gas and
oil which can reasonably be expected to be recovered from drillable locations
which it owned (or to which it had rights) at fiscal year end which are directly
offsetting locations to wells that have indicated commercial production in the
objective formation and which NCE fully expects to drill in the near future.
Changes in the Standardized Measure of Discounted Future Net Cash Flows are set
forth in Note 15 of the Company's financial statements. The additions to proved
reserves 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 at December 31, 2002, approximately 87% are proved developed and
approximately 13% are proved undeveloped based upon equivalent unit Mcfs. Proved
undeveloped acreage requires considerable capital expenditures to develop.
Management 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.
In 2001, NCE changed its fiscal year end from March 31 to December 31. The
income statement for the year ended December 31, 2001 is unaudited and is
presented for comparison purposes only. The income statement for
14
the nine months ended December 31, 2000 is unaudited and is presented for
comparison only with the nine month period ended December 31, 2001.
<Table>
<Caption>
FISCAL YEARS ENDED NINE MONTHS ENDED
DECEMBER 31, DECEMBER 31,
------------------- ------------------
2002 2001 2001 2000
-------- ------- ------- -------
PRODUCTION
Oil production (MBbls)....................... 104 98 82 80
Gas Production (MMcf)........................ 9,629 8,396 6,400 5,800
Total production (MMcfe)..................... 10,251 8,986 6,900 6,300
AVERAGE PRICES
Oil (per Bbl)................................ $ 22.63 $21.57 $20.75 $28.82
Gas (per Mcf)................................ 3.64 3.43 3.31 3.26
Average price per Mcfe....................... 3.65 3.44 3.31 3.39
AVERAGE COSTS (per Mcfe)
Production expense (including production
taxes).................................... 0.84 1.01 0.93 1.01
Depreciation, depletion & amortization....... 0.88 0.86 0.92 1.05
General and administrative expense........... 0.41 0.43 0.40 0.30
GROSS OPERATING MARGIN (per Mcfe).............. 2.81 2.43 2.38 2.38
</Table>
The following table is a review of the results of operations of the Company
for the fiscal year ended December 31, 2002 and the twelve months ended December
31, 2001, and nine months ended December 31, 2001 and 2002. All items in the
table are calculated as a percentage of total revenues.
<Table>
<Caption>
FISCAL YEAR ENDED YEAR ENDED NINE-MONTHS ENDED NINE-MONTHS ENDED
DEC. 31, DEC. 31, DEC. 31, DEC. 31,
2002 2001 2001 2000
----------------- ---------- ----------------- -----------------
Revenues:
Oil and gas production........ 81% 63% 71% 75%
Drilling...................... 4% 14% 6% 2%
Well operating, gathering and
other...................... 15% 23% 23% 23%
--- --- --- ---
Total Revenues.................. 100% 100% 100% 100%
Expenses:
Oil and gas production........ 19% 19% 20% 22%
Drilling costs................ 4% 11% 6% 5%
Well operating, gathering and
other...................... 8% 10% 9% 10%
Exploration................... 3% 2% 4% 2%
General and administrative.... 9% 8% 8% 7%
Depreciation, depletion and
amortization............... 19% 16% 20% 23%
Interest (Net)................ 6% 8% 9% 16%
Income taxes.................. 11% 8% 8% 3%
--- --- --- ---
Total Expenses.................. 79% 82% 84% 88%
--- --- --- ---
Net Income...................... 21% 18% 16% 12%
=== === === ===
Net Income Applicable to Common
Stock (1)..................... 21% 17% 16% 11%
=== === === ===
</Table>
- ---------------
(1) Dividends were paid or accrued on the Series B cumulative preferred stock in
the amount of $58,165 and $232,864 for fiscal years ended December 31, 2002
and the twelve months ended December 31, 2001 and $174,647 for the
nine-month periods ended December 31, 2001 and 2000. These amounts did not
include the
15
payment of $326,010 of dividends in arrears paid in December 2001. All
Series B Preferred stock was retired in March 2002.
The following discussion and analysis reviews the Company's results of
operations and financial condition for the years ended December 31, 2002 and
2001 and for the nine months ended December 31, 2001 and 2000. This review
should be read in conjunction with the Financial Statements and other financial
data presented elsewhere herein.
COMPARISON OF THE YEAR ENDED DECEMBER 31, 2002 TO THE YEAR ENDED DECEMBER 31,
2001 (UNAUDITED).
In August 2001, the Company changed its fiscal year from March 31 to
December 31. As a result, the Company's fiscal period ended December 31, 2001
contained nine months. The following unaudited financial data is presented for
comparison purposes only.
The following statement of income shows the results of operations for the year
ended December 31, 2002 and the comparable year ended December 31, 2001.
Information presented below and in the following discussion which relates to the
year ended December 31, 2001 was derived from unaudited financial information.
<Table>
<Caption>
YEARS ENDED
---------------------------
DECEMBER 31, DECEMBER 31,
2002 2001
------------ ------------
(UNAUDITED)
Revenue
Oil and gas production................................... $37,414,188 $30,919,439
Drilling revenues........................................ 2,082,351 6,833,847
Well operating, gathering and other...................... 6,766,608 11,419,760
----------- -----------
Total revenues........................................... 46,263,147 49,173,046
Costs and expenses
Oil and gas production expense........................... 8,583,185 9,108,606
Drilling costs........................................... 1,752,456 5,434,471
Well operating, gathering and other...................... 3,488,709 4,818,960
Exploration costs........................................ 1,572,638 1,156,126
General and administrative............................... 4,168,323 3,870,021
Depreciation, depletion and amortization................. 9,022,370 7,743,227
----------- -----------
Total costs and expenses................................. 28,587,681 32,131,411
----------- -----------
Income from operations..................................... 17,675,466 17,041,635
Interest Expense, Net
Interest income.......................................... 371,807 739,609
Interest expense......................................... 3,146,609 4,755,612
----------- -----------
2,774,802 4,016,003
----------- -----------
Income before provision for income taxes................... 14,900,664 13,025,632
Provision for income taxes................................. 5,148,332 4,246,376
----------- -----------
Net income................................................. $ 9,752,332 $ 8,779,256
=========== ===========
Net income applicable to common stock...................... $ 9,694,167 $ 8,546,395
=========== ===========
Net income per share....................................... $ 0.64 $ 0.56
=========== ===========
</Table>
16
REVENUES
Oil and gas production increased from 9.0 Bcfe in the year ended December
31, 2001 to 10.3 Bcfe in the year ended December 31, 2002. Increased production
resulted primarily from the Company's successful corporate drilling activities
and the acquisition of partnership and third party interests. Oil and gas
production revenues increased $6.5 million (21%) to $37.4 million for the year
ended December 31, 2002 compared to $30.9 million for the year ended December
31, 2001. The increase in oil and gas revenues is attributed to higher volumes
resulting from the acquisition of partnership and third party interests, the
Company's successful corporate drilling program and higher prices received for
natural gas produced in 2002 compared to 2001.
The Company sold 9.6 Bcf of gas and 104,000 barrels of oil in the year
ended December 31, 2002, compared to 8.4 Bcf and 98,000 barrels in the year
ended December 31, 2001. The Company received an average price of $3.64 per Mcf
and $22.63 per barrel of oil in the year ended December 31, 2002 compared to
$3.43 per Mcf and $21.57 per barrel, respectively, in the year ended December
31, 2001.
Drilling revenues decreased $4.8 million to $2.1 million for the year ended
December 31, 2002 compared to $6.8 million in the year ended December 31, 2001
reflecting the Company's withdrawal from the drilling fund business. NCE does
not intend to raise drilling funds from third party investors in 2003 or beyond.
Drilling revenue was recognized on 14 wells in the year ended December 31, 2002
compared to 47 wells for the year ended December 31, 2001.
Well operating, gathering and other revenues decreased $4.6 million to $6.8
million for the year ended December 31, 2002 compared to $11.4 million for the
year ended December 31, 2001. The decrease resulted primarily from a reduction
in wells operated for third parties, a reduction in gas transportation and gas
sold for third parties, all of which resulted from the acquisition of third
party and partnership interests.
EXPENSES
Oil and gas production expenses decreased $0.5 million to $8.6 million in
spite of a slightly larger number of wells operated and greater production
volumes. The Company's average operating cost per Mcfe was $0.84 in the year
ended December 31, 2002 compared to $1.01 in the year ended December 31, 2001.
Drilling costs for 2002 decreased $ 3.7 million to $1.8 million as a result
of the decreased number of drilling fund wells drilled and completed in the year
ended December 31, 2002 compared to the year ended December 31, 2001 reflecting
the Company's withdrawal from the drilling fund business.
Well operating, gathering and other expenses decreased $1.3 million to $3.5
million in the year ended December 31, 2002 from $4.8 million in the year ended
December 31, 2001. Exploration costs increased $0.4 million to $1.6 million in
the year ended December 31, 2002 compared to $1.2 million in the year ended
December 31, 2001 reflecting the increased number of exploratory wells drilled
in 2002 ( 8 ) compared to 2001 ( 7 ) and increased seismic surveys.
General and administrative expense increased $0.3 million to $4.2 million
from $3.9 million in the year ended December 31, 2001 as a result of reduced
administrative fees charged to partnerships which offset G&A. General and
administrative expenses were 9% of oil and gas production revenue in the year
ended December 31, 2002 and 8% for the year ended December 31, 2001 mainly due
to reduced drilling and other revenues.
Depreciation, depletion and amortization increased $1.3 million to $9.0
million in the year ended December 31, 2002 compared to $7.7 million in the year
ended December 31, 2001 primarily as a result of higher volumes of natural gas
produced in 2002.
Income from operations for the year ended December 31, 2002 increased $0.7
million (4%) to $17.7 million from $17.0 million for the year ended December 31,
2001. The increase in income from operations was primarily due to a combination
of the items discussed above.
Net interest expense decreased $1.2 million to $2.8 million from $4.0
million primarily reflecting the lower LIBOR based interest rates in the year
ended December 31, 2002.
17
The Company's higher level of income required a larger provision for
deferred taxes in the year ended December 31, 2002 compared to the year ended
December 31, 2001.
The Company's net income increased $1.0 million (11%) to $9.8 million for
the year ended December 31, 2002, from $8.8 million for the year ended December
31, 2001, as a result of the items discussed above.
Income available to common stockholders increased $1.2 million to $9.7 in
the year ended December 31, 2002 from $8.5 million in the prior year primarily
due to the items discussed above and the reduction of dividends resulting from
the redemption of the Series B Preferred shares in March of 2002.
COMPARISON OF NINE MONTHS ENDED DECEMBER 31, 2001 TO THE NINE MONTHS ENDED
DECEMBER 31, 2000 (UNAUDITED).
In August 2001, the Company changed its fiscal year end from March 31 to
December 31. As a result, the Company's fiscal period ended December 31, 2001
consists of the nine months from April 1, 2001 through December 31, 2001.
The following statement of income shows the results of operations for the
nine months ended December 31, 2001 and the comparable nine-month period ended
December 31, 2000. Information in the following discussion, which relates to the
nine-month period ended December 31, 2000, was derived from unaudited financial
information.
<Table>
<Caption>
NINE-MONTH PERIOD ENDED
---------------------------
DECEMBER 31, DECEMBER 31,
2001 2000
------------ ------------
(UNAUDITED)
REVENUE
Oil and gas production................................... $22,851,489 $21,331,537
Drilling revenues........................................ 1,795,047 671,840
Well operating, gathering and other...................... 7,474,679 6,479,815
----------- -----------
32,121,215 28,483,192
COSTS AND EXPENSES
Oil and gas production expenses.......................... 6,399,658 6,362,711
Drilling costs........................................... 1,990,415 1,314,666
Well operating, gathering and other...................... 3,213,867 2,915,999
Exploration expenses..................................... 847,303 476,362
General and administrative expenses...................... 2,725,611 1,866,653
Depreciation, depletion, amortization, impairment and
other................................................. 6,330,099 6,619,745
----------- -----------
21,506,953 19,556,136
----------- -----------
INCOME FROM OPERATIONS..................................... 10,614,262 8,927,056
INTEREST EXPENSE, NET
Interest income.......................................... 420,226 404,982
Interest expense......................................... 3,190,118 5,054,658
----------- -----------
2,769,892 4,649,676
----------- -----------
INCOME BEFORE PROVISION FOR INCOME TAXES................... 7,844,370 4,277,380
PROVISION FOR INCOME TAXES................................. 2,496,376 950,000
----------- -----------
NET INCOME................................................. $ 5,347,994 $ 3,327,380
=========== ===========
NET INCOME APPLICABLE TO COMMON STOCK (after dividends on
Cumulative Preferred Stock of $174,647 for the nine
months ended December 31, 2001 and 2000)................. $ 5,173,347 $ 3,152,733
NET INCOME PER SHARE (basic and diluted)................... $ 0.34 $ 0.22
=========== ===========
</Table>
18
REVENUES
Oil and gas production increased from 6.3 Bcfe in the nine-month period
ended December 31, 2000 to 6.9 Bcfe in the nine-month period ended December 31,
2001. Increased production resulted primarily from the Company's successful
drilling and development activities. Oil and gas production revenues increased
$1.5 million (7.1%) to $22.8 million for the nine-month period ended December
31, 2001 compared to $21.3 million for the nine-month period ended December 31,
2000. The increase in oil and gas revenues is attributed to higher volumes
resulting from the Company's successful drilling program partially offset by
slightly lower prices.
The Company sold 6.4 Bcf of gas and 82,000 barrels of oil in the nine
months ended December 31, 2001, compared to 5.8 Bcf and 80,000 barrels in the
nine months ended December 31, 2000. The Company received an average price of
$3.31 per Mcf and $20.75 per barrel of oil in the nine-month period ended
December 31, 2001 compared to $3.26 per Mcf and $28.82 per barrel, respectively,
in the nine-month period ended December 31, 2000.
Drilling revenues increased $1.1 million to $1.8 million for the nine-month
period ended December 31, 2001 compared to $0.7 million in the nine-month period
ended December 31, 2000 due to the increase in the number of wells completed in
connection with the Company's 2001 drilling fund. Revenue was recognized on 13
wells in the nine-month period ended December 31, 2001 compared to 4 wells for
the nine-month period ended December 31, 2000.
Well operating, gathering and other revenues increased $1.0 million to $7.5
million for the nine-month period ended December 31, 2001 compared to $6.5
million for the nine-month period ended December 31, 2000. The increases
resulted primarily from increased volumes of gas transported through facilities
owned by the Company and an increase in wells operated for third parties
partially offset by a reduction in third party gas sold.
EXPENSES
Oil and gas production expenses were essentially flat at $6.4 million in
spite of a slightly higher number of wells operated and greater production
volumes. The Company's average operating cost per Mcfe was $0.93 in the
nine-month period ended December 31, 2001 compared to $1.01 in the nine-month
period ended December 31, 2000.
Drilling costs for the 2001 period increased $ 0.7 million to $2.0 million
as a result of the increased number of drilling fund wells drilled and completed
in the nine-month period ended December 31, 2001 compared to the nine-month
period ended December 31, 2000.
Well operating, gathering and other expenses increased $0.3 million to $3.2
million in the nine-month period ended December 31, 2001 from $2.9 million in
the nine-month period ended December 31, 2000. The slight increase in costs
resulted from increased repair and maintenance on the Company's gathering
systems in 2001.
Exploration costs increased $0.4 million to $0.8 million in 2001. The
increased spending reflects the Company's increased focus on exploration and
drilling for its own account.
General and administrative expense increased $0.8 million to $2.7 million
from $1.9 million in the nine-month period ended December 31, 2001 as a result
of reduced administrative fees charged to partnerships and bad debt expense
associated with the bankruptcy filing of Enron North America Corp. General and
administrative expenses were 8% of revenue in the nine-month period ended
December 31, 2001 and 7% for the nine-month period ended December 31, 2000.
Depreciation, depletion and amortization decreased $0.3 million to $6.3
million in the nine-month period ended December 31, 2001 compared to $6.6
million in the nine-month period ended December 31, 2000 primarily as a result
of lower estimated reserve volumes used to calculate depreciation, depletion and
amortization in the 2000 period.
Income from operations for the nine months ended December 31, 2001
increased $1.7 million (19%) to $10.6 million from $8.9 million for the
nine-month period ended December 31, 2000. The increase in income
19
from operations was primarily due to higher production and drilling revenues
partially offset by higher drilling and maintenance costs.
Net interest expense decreased $1.8 million to $2.8 million from $4.6
million primarily reflecting the conversion of $24 million of debt to common
stock by NUON in the nine-month period ended December 31, 2001.
The Company's higher level of income required a larger provision for
deferred taxes in the nine-month period ended December 31, 2001 compared to the
nine-month period ended December 31, 2000.
The Company's net income increased $2.0 million (61%) to $5.3 million for
the nine-month period ended December 31, 2001, from $3.3 million for the
nine-month period ended December 31, 2000, as a result of the items discussed
above.
INFLATION AND CHANGES IN PRICES
Inflation affects the Company's operating expenses as well as interest
rates, which may have an effect on the Company's profitability. Oil and gas
prices have not followed inflation and have fluctuated widely during recent
years as a result of other forces such as OPEC, economic factors, demand for and
supply of natural gas in the United States and within the Company's regional
area of operation. Oil prices during the year ended December 31, 2002 have
increased as a result of terrorism, the threat of war in the Middle East and the
national oil strike in Venezuela. Natural gas prices have also increased during
the year ended December 31, 2002 due to higher energy consumption during the
summer of 2002, a much colder winter in 2002/2003 and to some extent a slight
recovery in economic growth in the United States. As a result of these market
forces, the Company received an average price of $22.63 per barrel of oil for
the year ended December 31, 2002 compared to $21.57 for the year ended December
31, 2001. The Company received an average price of $3.64 per Mcf for its natural
gas in the year ended December 31, 2002 compared to $3.43 for 2001.
The Company cannot predict the duration of the current condition of gas and
oil markets and prices, because of the forces noted above, as well as other
variables, may change.
Currently, NCE sells natural gas under fixed and variable price contracts
on the spot market and uses financial hedging instruments to realize a fixed
price on a portion of its production sold under variable contracts. The Company
has entered into certain price hedging agreements to take advantage of current
market conditions by hedging a greater portion of its production for periods of
a year or longer at prices substantially higher than were received in recent
years.
The following table reflects the natural gas volumes and the weighted
average prices under financial hedges and fixed-price contracts at December 31,
2002. One MMBtu is approximately equal to one Mcf.
FINANCIAL HEDGES (COLLARS)
<Table>
<Caption>
ESTIMATED REALIZABLE PRICE FIXED PRICE CONTRACTS NYMEX
---------------------------- ---------------------- AT 12/31/2002
QUARTER ENDING MMBTU FLOOR CAP MMBTU EST. PRICE PER MMBTU
- -------------- ---------- ------ ------ -------- ----------- -------------
March 31, 2003............. 1,200,000 $3.07 $4.07 887,000 $3.40 $4.82
June 30, 2003.............. 1,660,000 3.39 4.48 404,000 3.53 4.46
September 30, 2003......... 1,670,000 3.39 4.48 276,000 3.52 4.44
December 31, 2003.......... 1,670,000 3.39 4.48 175,000 3.31 4.58
March 31, 2004............. 905,000 3.42 4.95 104,000 3.16 4.67
June 30, 2004.............. 910,000 3.43 4.96 92,000 3.06 4.10
September 30, 2004......... 920,000 3.43 4.96 89,000 3.03 4.04
December 31, 2004.......... 920,000 3.43 4.96 72,000 2.87 4.20
</Table>
20
During 2001, the Company entered into interest rate swap agreements that
effectively convert a portion of its variable-rate long-term debt to fixed-rate
debt for periods of up to two years, thus reducing the impact of interest-rate
changes on future income. The following contracts were outstanding at December
31, 2002.
<Table>
<Caption>
LIBOR
RATE NCE EFFECTIVE
TERM NOTIONAL AMOUNT FIXED FIXED RATE
---- --------------- ----- -------------
1. January 1, 2002 to December 31, 2003......... $20,000,000 4.2% 6.1%
2. January 1, 2001 to December 31, 2003......... $20,000,000 3.5% 5.4%
</Table>
The mark-to-market amount associated with the two interest rate swap
agreements was $974,318 at December 31, 2002.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity and capital resources are closely related to and
dependent on the current prices realized principally for natural gas and to a
lesser extent, oil.
The Company's working capital was $10.8 million at December 31, 2002,
compared to $16.4 million at December 31, 2001. The decrease of $5.6 million in
working capital reflects the cash spent during 2002 on the Company's drilling
program as well as the redemption of Series B Preferred for $2,327,000. As of
December 31, 2002, the Company had $57.0 million outstanding under its Credit
Facility (which has a borrowing base of $80 million) and $10.0 million in
subordinated borrowings from NUON due in 2015.
The following table summarizes the Company's financial position at December
31, 2002 and 2001.
<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2001
------------------ ------------------
AMOUNT % AMOUNT %
---------- ----- ---------- -----
(DOLLAR AMOUNTS IN THOUSANDS)
Working capital..................................... $ 10,819 8 $ 16,444 12
Property and equipment.............................. 129,256 91 113,248 86
Other............................................... 1,329 1 2,735 2
-------- --- -------- ---
Total............................................. $141,404 100 $132,427 100
======== === ======== ===
Long-term debt...................................... $ 67,000 47 $ 67,000 51
Deferred income taxes and other liability........... 9,667 7 6,048 4
Stockholders' equity................................ 64,737 46 59,379 45
-------- --- -------- ---
Total............................................. $141,404 100 $132,427 100
======== === ======== ===
</Table>
The Company's gas and oil exploration and development activities
historically have been financed through internally generated funds and bank
financing.
The following table summarizes the Company's Statements of Cash Flows for
the years ended December 31, 2002 and 2001.
<Table>
<Caption>
YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31,
2002 2001
------------ ------------
(UNAUDITED)
Net cash provided by operating activities................... $ 19,089 $ 26,812
Net cash used in investing activities....................... (24,029) (17,995)
Net cash used in financing activities....................... (2,385) (4,972)
-------- --------
(Decrease) increase in cash and cash equivalents............ $ (7,325) $ 3,845
======== ========
</Table>
As the above table indicates, the Company's cash provided by operating
activities was $19.1 million for the year ended December 31, 2002 compared to
$26.8 million for the year ended December 31, 2001. The decrease was mainly due
to changes in operating assets and liabilities.
21
Net cash used for investing activities was $24.0 million for the year ended
December 31, 2002, compared to $18.0 million for the year ended December 31,
2001. The increase in the year ended December 31, 2002 resulted from the
Company's expanded 2002 drilling program.
Net cash used in financing activities was $2.4 million for the year ended
December 31, 2002. The cash was used during this period to pay dividends and to
redeem the Company's Series B Preferred stock. Cash used in financing activities
in the year ended December 31, 2001 resulted from payments made on long-term
debt during 2001.
The Company has a five year, $125 million Credit Agreement (the "Credit
Agreement") which expires in September 2005 with a group of four banks, with
Union Bank of California acting as agent bank. The Credit Agreement provides for
a borrowing base (presently $80.0 million) that is determined semiannually by
the lenders based on the Company's financial position, gas and oil reserves and
certain other factors. The agreement provides for a 3/8% commitment fee on
amounts not borrowed up to the borrowing base and allows for a sub-limit of $15
million for the issuance of letters of credit. The agreement restricts the
Company from incurring additional debt or liens, prohibits dividends and
distributions (except for the outstanding preferred A shares), and requires the
Company to maintain positive working capital and certain minimum interest and
fixed charge coverages.
The amounts borrowed under its Credit Agreement are secured by the
Company's receivables, inventory, equipment and a first mortgage on certain of
the Company's interests in gas and oil wells and reserves.
During calendar 2003, the Company expects to spend approximately $20.5
million on drilling and lease acquisition and seismic and $0.7 million on other
capital expenditures. These capital expenditures will be financed from cash on
hand, cash flow generated during the year and, if needed, from available
borrowings.
CRITICAL ACCOUNTING POLICIES
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 Energy Eastern, Inc.
("NCEE", formerly Peake Energy, Inc.), 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. All significant intercompany accounts and transactions
have been eliminated.
Inventories -- Inventories consist of material, pipe and supplies valued at
the lower of cost or market.
Cash Equivalents -- Investments having an original maturity of 90 days or
less that are readily convertible into cash have been included in, the cash and
cash equivalents balances. Included in cash and cash equivalents is $9,224,145
of investments in a short-term bond fund.
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, gathering systems using the straight-line method over 10 to 25
years, vehicles, furniture and fixtures using various methods over 3 to 15 years
and building and improvements using various methods over 7 -- 31.5 years).
Oil and Gas Investments and Properties -- The Company uses the successful
efforts method of accounting for its 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 developmental wells are capitalized.
Costs to drill exploratory wells that do not find proved reserves, costs of
developmental wells on properties the Company has no further interest in,
geological and geophysical costs, and costs of carrying and retaining unproved
properties are expensed.
22
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 on a group (pool) basis with proved properties
having similar characteristics, by the unit-of-production method based upon
estimated proved developed reserves. To the extent that capitalized costs of
each pool of proved properties exceed estimated future net cash flow from such
pool, the excess capitalized costs are written down to the present value of such
amount. Estimated future net cash flows are determined based primarily upon the
estimated future proved reserves related to the Company's current proved
properties.
The Company follows Statement of Financial Accounting Standards ("SFAS")
No. 144 which requires a review for impairment whenever circumstances indicate
that the carrying amount of an asset may not be recoverable. Impairment is
recorded as impaired properties are identified.
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 a partial interest in an unproved property is sold, the amount
received is treated as a reduction of the cost of the interest retained. The
carrying cost of unproved properties is approximately $3,310,000 at December 31,
2002.
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. 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
from the properties and sold. Well operating, gathering and other revenues
include operating fees charged to outside working interest owners in NCE
operated wells, gathering fees (including transportation allowances and
compression fees), third party gas sales associated with purchased natural gas
and other miscellaneous revenues. Such revenue is recognized at the time it is
earned and the Company has a contractual right to receive payment.
Administrative fees received from NCE organized and managed oil and gas
partnerships are treated as a reduction of the Company's general and
administrative expenses.
Per Share Amounts -- For the year ended December 31, 2002, the nine month
period ended December 31, 2001, and the fiscal year ended March 31, 2001, the
conversion of Series A stock had the effect of increasing average outstanding
shares by 33,251, 33,624 and 33,624 shares, respectively. Assumed exercise of
dilutive stock options had the effect of adding 108, 3,705 and 3,645 shares to
the average outstanding shares for the year ended December 31, 2002, the nine
months ended December 31, 2001, and the year ended March 31, 2001, respectively.
The assumed conversion of the Series B Preferred Stock increased outstanding
shares by 76,321 shares and increased net income by approximately $58,000 for
the year ended March 31, 2001. The effect of warrants was anti-dilutive in all
periods.
The average number of outstanding shares used in computing basic and
diluted net income per share was 15,208,216 and 15,241,948, 15,208,031 and
15,245,360 and 14,306,011 and 14,419,601 for the year ended December 31, 2002,
the nine-month period ending December 31, 2001, and the fiscal year ended March
31, 2001, respectively.
Risk Factors -- The Company operates in an environment with many financial
risks including, but not limited to, the ability to acquire additional
economically recoverable oil and gas reserves, 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, the volatility and
seasonality of oil and gas production and prices and the highly competitive
nature of the industry as well as worldwide economic conditions.
Accounting Estimates -- The preparation of financial statements in
conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that
23
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. Significant
estimates used in calculating the Company's depletion, depreciation and
amortization which could be subject to significant near term revision include
estimated oil and gas reserves. The Company's reserve estimates could vary
significantly depending on various factors, including Company and industry
volatility of oil and natural gas prices.
Financial Instruments -- The Company's financial instruments include cash
and equivalents, accounts receivable, accounts payable, debt obligations and
derivatives. The book value of cash and equivalents, accounts receivable and
accounts 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 and credit
losses have historically been within management's estimate. Derivatives are used
as cash flow hedges and are marked to market through other comprehensive income.
NEW ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations". SFAS No. 141 requires the purchase method of accounting for
business combinations initiated after June 30, 2001 and eliminates the
pooling-of-interest method and further clarifies the criteria to recognize
intangible assets separately from goodwill. In June 2001, FASB issued SFAS No.
142, "Goodwill and Other Intangible Assets". Under SFAS No. 142, goodwill and
intangible assets deemed to have indefinite lives will no longer be amortized
but will be subject to periodic impairments tests. Other intangible assets will
continue to be amortized over their useful lives. SFAS No. 142 is effective for
fiscal years beginning after December 15, 2001.
In June 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" which is effective the first quarter of fiscal year 2003. SFAS 143
addresses financial accounting and reporting for obligations associated with the
retirement of long-lived assets and the associated asset retirement cost.
In August 2001, FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-lived Assets", which is effective the first quarter of fiscal
year 2002. SFAS No. 144 modifies and expands the financial accounting and
reporting for the impairment or disposal of long-lived assets other than
goodwill. The Company does not believe that these four SFAS will have any
significant impact on its financial position and results of operations.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No.
4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections."
SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of
Debt," SFAS 44, "Accounting for Intangible Assets of Motor Carriers" and SFAS
64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" and
amends SFAS 13, "Accounting of Leases". Statement 145 also makes technical
corrections to other existing pronouncements. SFAS 4 required gains and losses
from extinguishment of debt to be classified as an extraordinary item, net of
the related income tax effect. As a result of the rescission of SFAS 4, the
criteria for extraordinary items in APB Opinion No. 30, "Reporting the Results
Of Operations, Reporting the Effects of Disposal of Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions," now
will be used to classify those gains and losses. SFAS 145 was effective with the
quarter ending September 30, 2002, for the Company's financial position, results
of operations and cash flows.
In December, 2002, the FASB issued SFAS No. 148, Accounting for Stock
Based, Compensation-Transition and Disclosure (SFAS 148) that amends SFAS No.
123, Accounting for Stock-Based Compensation, to provide alternative methods of
transition to Statement 123's fair value method of accounting for stock-based
employee compensation. SFAS 148 also amends the disclosure provisions of SFAS
123 and APB Opinion No. 28, Interim Financial Reporting, to require disclosure
in the summary of significant accounting policies of the effects of an entity's
accounting policy with respect to stock-based employee compensation on reported
net income and
24
earnings per share in annual and interim financial statements. The Statement
does not amend SFAS 123 to require companies to account for employee stock
options using the fair value method. The Statement is effective for fiscal years
beginning after December 15, 2002. The Company is currently evaluating the
effects of SFAS 148, but does not expect that the adoption of SFAS 148 would
have a material effect on the Company's results of operations.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated
with Exit or Disposal Activities." SFAS 146 will be effective for the Company
for disposal activities initiated after December 31, 2002. The adoption of this
standard is not expected to have a material effect on the Company's financial
position, results of operations or cash flows.
OTHER INFORMATION
Consistent with Section 10A (i) (2) of the Securities Exchange Act of 1934,
as added by Section 202 of the Sarbanes-Oxley Act of 2002, we are responsible
for listing the non-audit services, approved in the fourth quarter of fiscal
year 2002 by our Audit Committee, to be performed by Hausser + Taylor LLP, our
external auditor. Non-audit services are defined in the law as services other
than those provided by connection with an audit or a review of our financial
statements. The non-audit service approved by our Audit Committee in the fourth
quarter of fiscal year 2002, listed below, is considered to be other services
and has been approved in accordance with a pre-approval from our Audit
Committee.
During the fiscal year covered by this filing, our Audit Committee approved
the recurring engagement of Hausser + Taylor LLP for non-audit service
consisting of tax compliance and tax consultations.
FORWARD LOOKING INFORMATION
The forward looking statements regarding future operations and financial
performance contained in this report involve risks and uncertainties that
include, but are not limited to the supply of and market demand for natural gas
and oil, levels of natural gas and oil production and cost of operations,
results of the Company's drilling, availability of capital to the Company,
uncertainties associated with reserve estimates, environmental risks and other
factors included in the Company's filings with the SEC. Actual results may
differ materially from forward-looking information included in this report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to commodity price, interest rate and credit risks.
The Company's primary interest rate risk exposure results from floating rate
debt including debt under the Company's revolving Credit Facility and the
Subordinated Promissory Note between the Company and NUON. However, the Company
has entered into contracts to fix the rate on $20 million of the bank debt at
4.6% for one year and an additional $20 million at 5.4% for two years. As a
result, at December 31, 2002, $17 million of the Company's total long-term debt
consisted of floating rate debt. In February 2003 the Company extended the term
of both swaps to December 31, 2004. As a result, swap number 1 will have a rate
of 3.2% from April 1, 2003 until it expires on December 31, 2004 and swap number
2 will have a rate of 3% from January 1, 2003 until it expires on December 31,
2004.
The Company's ability to collect for sales of natural gas and oil to its
customers is dependent on the payment ability of the Company's customer base.
The Company monitors the creditworthiness of its customers and, from time to
time, will demand adequate assurances of performance if the creditworthiness of
its customers is in question. If such assurances are not given to the Company,
an alternative purchaser may be sought. In recent months, a number of energy
marketing and trading companies have discontinued their marketing and trading
operations, which has significantly reduced the number of potential purchasers
for the Company's natural gas production. This reduction in potential customers
has reduced market liquidity and, in some cases, made it difficult for the
Company to identify creditworthy customers. The Company will continue to monitor
its customer base and to pursue alternative customers.
The Company sells approximately $1,000,000 per month of natural gas to a
major customer. In the event of a default in payment by the customer, the
Company may not be able to collect amounts due from the customer or customer's
affiliate and would need to identify an alternative purchaser for a significant
amount of natural gas.
25
The Company presently believes that the customer or its affiliate currently has
the ability to meet all payment obligations to the Company.
The Company is exposed to commodity price risks related to natural gas and
oil. The Company's financial results can be significantly impacted by changes in
commodity prices. The Company uses fixed-price contracts and a series of
financial hedges (costless collars) to reduce the exposure to changes in natural
gas prices for a portion of its net production. The contracts and financial
hedges are for various terms and prices and are detailed in Note 10 of this
report and summarized below:
<Table>
<Caption>
COSTLESS COLLARS FIXED-PRICE CONTRACTS
------------------------------------ -------------------------
AVERAGE PRICE
-----------------
YEAR MMBTU %(1) FLOOR CEILING MMBTU % (1) PRICE
- ---- --------- ---- ------- ------- --------- ----- -----
2003 6,200,000 54% $3.33 $4.40 1,742,000 18% $3.45
2004 3,655,000 39% 3.43 4.96 357,000 5% 3.04
</Table>
- ---------------
(1) Percent of production expected from wells with proved producing reserves at
December 31, 2002.
The Company is exposed to credit risks from its customers and
counterparties in derivative transactions. The Company has credit approval
policies that establish credit limits for its customers. The limits are closely
monitored, as are collection terms for accounts receivable. The Company
generally does not require collateral from its customers and counterparties.
Historically, losses from bad debts have been within management's expectations.
The information included in and referred to in this Item is considered to
constitute "forward looking statements" for purposes of the statutory safe
harbor provided in Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. See
"Management's discussion and Analysis of Financial Condition and Results of
operations - Forward Looking Information" in Item 7 of this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
(See Page 32 and Item 6)
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable.
26
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers and directors of the Company as of March 24, 2003 were as
follows:
<Table>
<Caption>
NAME AGE POSITION
- ---- --- --------
Omer Yonel.......................... 39 President, Chief Executive Officer and Director
Dale E. Stitt....................... 57 Chief Financial Officer
Dean A. Swift....................... 50 General Counsel and Secretary
Lawrence J. Risley.................. 52 Vice President for Exploration and Production
Pieter Jobsis....................... 49 Chairman of the Board and Director
Cok van der Horst................... 57 Director
Ron L. Langenkamp................... 57 Director
Joe K. Ward......................... 63 Director
Joop G. Drechsel.................... 48 Director
Garry Regan......................... 52 Director
</Table>
OMER YONEL is President, Chief Executive Officer and a Director. He joined
the Company in 1999. In 1998, he served as Business Development Manager, North
America, for nv NUON. During 1997 and 1998 he was a Project Manager for Schelde
Engineering & Contractors bv. From 1989 to 1997 he held various Project
Engineering, Sales and other management positions with ABB Lummus Global bv. Mr.
Yonel holds a BS degree in Engineering and MS degree in Engineering Economics
from Delft University of Technology in The Netherlands. He is also a graduate of
the Advanced Management Program at The Wharton School, University of
Pennsylvania. He is a member of the Ohio Oil and Gas Association and the
Cleveland Engineering Society.
DALE E. STITT has served as Chief Financial Officer since January 2001. He
is a Certified Public Accountant, and was previously employed by Ernst & Young
LLP from June 1967 to December 2000, serving most recently as an audit partner.
Mr. Stitt has extensive experience in the gas and oil industry, where he has
specialized in mergers and acquisitions, transaction financing and the public
offering of securities. He holds a Bachelor of Science degree in Accounting from
Miami University, and attended the Executive Program at the J.L. Kellogg
Graduate School of Management at Northwestern University. Mr. Stitt is a member
of the American Institute of Certified Public Accountants, the Ohio Society of
Certified Public Accountants, the Independent Petroleum Association of America,
the Ohio Oil and Gas Association, the Ohio Petroleum Producers Accountants
Society and the Miami University Business Advisory Council.
DEAN A. SWIFT was appointed General Counsel and Secretary of the Company in
July 2001. From 1999 to 2001, he was a partner in TriMillennium Ventures LLC and
engaged in the private practice of law. From 1989 to 1999 he served as Vice
President, Assistant General Counsel and Assistant Secretary of Belden & Blake
Corporation, and from 1981 to 1989 he served as Assistant General Counsel and
Assistant Secretary of that company. From 1978 to 1981 he was associated with
the law firm of Hahn, Loeser and Parks in Cleveland, Ohio. Mr. Swift received a
BA degree graduating summa cum laude from the University of the South. He holds
a JD degree from the University of Virginia. He is a member of the Stark County,
Ohio, Ohio State and American Bar Associations and the Ohio Gas and Oil
Association.
LAWRENCE J. RISLEY was appointed Vice President for Exploration and
Production in December 2002. From June 2002 to December 2002 he served as the
Company's Director of Operations. Prior to joining NCE, Mr. Risley was employed
for 23 years by Texaco, Inc., with 16 of those years in an exploration and
production asset development role in the Texas Gulf Coast and East Texas
regions. Most recently he was employed as a Technology Project Manager for
Exploration Technology. He also served Texaco as Team Leader in the Engineering
and Construction Management Group, Senior Resource Manager of the Exploration
and Production Technology Department and Asset Manager of the Texas Gulf Coast
Business Unit. Mr. Risley holds BS and MA degrees in Geology from the State
University of New York at Oneonta. He is a member of the American Association of
Petroleum Geologists, the Houston Geological Society, the Ohio Oil and Gas
Association and the
27
Independent Oil and Gas Association of West Virginia. He is also a past member
of the Board of Directors of the Petroleum Technology Transfer Council.
PIETER JOBSIS was elected Director in March 2003 and currently serves as
Chairman of the Board of Directors. Mr. Jobsis has been Executive Vice President
of Nuon Energy & Water Investments since June 2002. Mr. Jobsis is an experienced
financial executive with internationally operating companies in the energy and
publishing industry. Nuon Energy and Water Investments is a division of n.v.
Nuon, which holds Nuon's strategic investments in water (amongst others in The
Netherlands, US and UK) and in energy outside Europe (US and Asia). Mr. Jobsis
is responsible for the value enhancement of the portfolio of strategic
investments. Prior to joining Nuon in late 2001, Mr. Jobsis worked for Reed
Elsevier, the Anglo Ducth publisher of scientific, legal, business and education
information for professionals worldwide. At Reed Elsevier Mr. Jobsis was
Director of Corporate Finance from 1999 to 2001 and from 1996 to 1999 Mr. Jobsis
was CFO of the Science division, with its main operations in The Netherlands, UK
and US. From 1980 to 1996 Mr. Jobsis worked with Royal Dutch/ Shell in various
finance functions in exploration and production, refining, marketing and
chemicals companies in The Netherlands, Dutch Antilles and Thailand. Mr. Jobsis
holds master degrees from the University of Groningen (Netherlands) in business
and economics.
COK VAN DER HORST was appointed to the Board of Directors in October 1999.
Mr. van der Horst is currently Advisor to the Management Board of nv NUON. He
previously served as the Director, NUON East and North Holland, where he was the
Chief Financial Officer between 1993 and 1999, and was also in charge of
technical affairs, information technology, personnel and activities in the
national energy market. He has recently assumed responsibilities in the area of
regulatory affairs, mergers, acquisitions and divestments for the parent
company, nv NUON. Prior to joining NUON in January of 1993, Mr. van der Horst
was chairman of the board of PEB, the energy distribution company of the
province of Friesland (a regional government in The Netherlands). At PEB he was
responsible for financial and economic policy. Mr. van der Horst holds a
Master's degree in business administration from Erasmus University in Rotterdam.
He serves on the Audit Committee of the Board of Directors.
RON L. LANGENKAMP is currently advisor to the Executive Board of NUON;
before this assignment he was Managing Director of NUON's Energy Trade and
Wholesale division. Mr. Langenkamp most recently served for two years as an
external consultant to Reliant Energy, Inc. and supervised all European
commercial activities in his role as Acting Chief Commercial Officer. From 1994
to 1997 Mr. Langenkamp served in various capacities, including President, of
Norstar, a natural gas retail sales partnership between Orange and Rockland
Utilities, Inc. and Shell Oil Company. From 1977 to 1994 Mr. Langenkamp held
various management positions in the energy industry including the office of
President of Cabot Transmission Company and as President of Chippewa Gas
Corporation. Mr. Langenkamp received his B.A. degree from Sam Houston State
University and a Master's degree from the University of Texas at Austin. He
serves on the Company's Stock Option and Compensation Committee.
JOE K. WARD was elected Director in March 2003. Mr. Ward is a Certified
Public Accountant with over forty years experience as a financial advisor to a
wide range of businesses and industries. He is currently providing financial
advice to, and managing the accounting and financial reporting functions of
several privately-owned businesses. From 1962 through 1991, he was employed by
Ernst & Young LLP, serving as Partner from 1975 through 1991. Mr. Ward has
extensive experience in commercial banking and the oil and gas industry. He
holds a Bachelor of Science from The Ohio State University.
JOOP G. DRECHSEL is currently CEO of BCD Holdings N.V., a company holding
leading positions in the travel industry and the financial services market in
the United States and Europe. He is also a member of the Board of Directors of
ENECO Energy and Versatel Telecom International N.V., both located in the
Netherlands, and holds numerous advisory positions in both the energy and the
telecommunications industries. Previously he served as Vice Chairman of KPN
N.V., a large Dutch telecommunications company, and also served as President of
KPN International N.V. He was one of the founders of KPN-Qwest, a joint venture
between KPN and Qwest-U.S. West. Prior to joining KPN, Mr. Drechsel worked for
Royal Dutch Shell in a number of management positions in Australia, Taiwan and
the United Kingdom. He also worked for Royal Dutch KPN as a Senior Vice
President for Business Development. Mr. Drechsel holds a Master's degree in
economics from Erasmus
28
University in Rotterdam and has studied in the MBA program at the University of
Michigan. He currently chairs the Company's Audit Committee.
GARRY REGAN participated in the organization of North Coast Energy's
predecessor in 1981, and has served as an executive officer and Director. He
served as President from August 1988 through April 2001. He is currently
President of Nornew, Inc., a privately-held independent exploration and
production company that he joined in 2001. Mr. Regan holds a B.S. degree from
Ohio State University and a Masters degree from Indiana University. He is a
member of the Independent Petroleum Association of America, the Ohio Oil and Gas
Association and the Independent Oil & Gas Association of New York.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item 11 is incorporated by reference to
the information set forth under the caption "Compensation of Directors and
Executive Officers" in the Company's definitive Proxy Statement for the 2003
Annual Meeting of Stockholders, since such Proxy Statement is to be filed with
the Securities and Exchange Commission not later than 120 days after the end of
the Company's fiscal year ended December 31, 2002, pursuant to Regulation 14A.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item 12 is incorporated by reference to
the information set forth under the caption "Share Ownership of Principal
Holders and Management" in the Company's definitive Proxy Statement for the 2003
Annual Meeting of Stockholders, which definitive Proxy Statement is to be filed
with the Securities and Exchange Commission not later than 120 days after the
end of the Company's fiscal year ended December 31, 2002, 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 "Certain Transactions" in the
Company's definitive Proxy Statement for the 2003 Annual Meeting of
Stockholders, which definitive Proxy Statement is to be filed with the
Securities and Exchange Commission not later than 120 days after the end of the
Company's fiscal year ended December 31, 2002, pursuant to Regulation 14A.
ITEM 14. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures. The Company's Chief
Executive Officer and Chief Financial Officer, after evaluating the
effectiveness of the Company's disclosure controls and procedures (as defined in
Exchange Act Rule 13a-14) as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date") have concluded that as of the
Evaluation Date, the Company's disclosure controls and procedures were effective
in ensuring that information required to be disclosed by the Company in the
reports it files or submits under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the Commission's
rules and forms.
Changes in internal controls. There were no significant changes in the Company's
internal controls or in other factors that could significantly affect these
controls subsequent to the Evaluation Date.
29
PART IV
ITEM 15. 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:
<Table>
<Caption>
PAGE(S)
-------
Auditor's Report on the Financial Statements................ 33
Consolidated balance sheets................................. 34-35
Consolidated statements of income........................... 36
Consolidated statements of stockholders' equity............. 37
Consolidated statements of cash flows....................... 38
Notes to consolidated financial statements.................. 39-55
</Table>
(a)(2) Financial Statements Schedules
(a)(3) Exhibits
Reference is made to the Exhibit Index.
30
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
NORTH COAST ENERGY, INC.
By /s/ OMER YONEL
------------------------------------
Omer Yonel
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ OMER YONEL President, Chief Executive March 21, 2003
------------------------------------------------ Officer
Omer Yonel and Director (principal
executive officer)
/s/ DALE E. STITT Chief Financial Officer and March 21, 2003
------------------------------------------------ Secretary (principal accounting
Dale E. Stitt and financial officer)
/s/ G. PIETER JOBSIS Chairman of the Board and March 26, 2003
------------------------------------------------ Director
G. Pieter Jobsis
/s/ COK VAN DER HORST Director March 21, 2003
------------------------------------------------
Cok van der Horst
Director
------------------------------------------------
Ron L. Langenkamp
/s/ JOE K. WARD Director March 21, 2003
------------------------------------------------
Joe K. Ward
/s/ JOOP G. DRECHSEL Director March 24, 2003
------------------------------------------------
Joop G. Drechsel
/s/ GARRY REGAN Director March 24, 2003
------------------------------------------------
Garry Regan
</Table>
31
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
2002 CONSOLIDATED FINANCIAL REPORT
CONTENTS
<Table>
<Caption>
PAGE(S)
-------
AUDITOR'S REPORT ON THE FINANCIAL STATEMENTS................ 33
FINANCIAL STATEMENTS
Consolidated balance sheets............................... 34-35
Consolidated statements of income......................... 36
Consolidated statements of stockholders' equity........... 37
Consolidated statements of cash flows..................... 38
Notes to consolidated financial statements................ 39-55
</Table>
32
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
North Coast Energy, Inc.
Cleveland, Ohio
We have audited the accompanying consolidated balance sheets of North Coast
Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2002
and 2001, and the related consolidated statements of income, stockholders'
equity and cash flows for the year ended December 31, 2002, the nine month
period ended December 31, 2001 and the year ended March 31, 2001. 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 auditing standards generally
accepted in the United States of America. 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 consolidated financial position of North Coast
Energy, Inc. and subsidiaries as of December 31, 2002 and 2001, and the
consolidated results of their operations and their cash flows for the year ended
December 31, 2002, the nine month period ended December 31, 2001 and the year
ended March 31, 2001, in conformity with accounting principles generally
accepted in the United States of America.
HAUSSER + TAYLOR LLP
Cleveland, Ohio
February 13, 2003
33
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
DECEMBER 31, DECEMBER 31,
2002 2001
------------ ------------
ASSETS
CURRENT ASSETS
Cash and equivalents...................................... $ 14,711,205 $ 22,035,924
Accounts receivable -- trade.............................. 5,796,537 6,006,622
Inventories............................................... 353,722 290,481
Prepaid expenses.......................................... 404,726 474,411
------------ ------------
Total current assets................................... 21,266,190 28,807,438
PROPERTY AND EQUIPMENT, at cost
Land...................................................... 222,822 222,822
Oil and gas properties (successful efforts)............... 143,952,276 121,195,745
Gathering systems......................................... 17,137,184 16,411,433
Vehicles.................................................. 2,288,388 2,249,507
Furniture and fixtures.................................... 991,438 748,974
Buildings and improvements................................ 1,877,667 1,862,382
------------ ------------
166,469,775 142,690,863
Less accumulated depreciation, depletion and
amortization........................................... 37,213,430 29,442,909
------------ ------------
129,256,345 113,247,954
OTHER ASSETS, net........................................... 1,328,595 2,734,966
------------ ------------
TOTAL ASSETS................................................ $151,851,130 $144,790,358
============ ============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
34
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
DECEMBER 31, DECEMBER 31,
2002 2001
------------ ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable.......................................... $ 3,369,632 $ 3,395,272
Accrued expenses.......................................... 7,077,717 6,906,337
Billings in excess of costs on uncompleted contracts...... -- 2,062,094
------------ ------------
Total current liabilities............................ 10,447,349 12,363,703
LONG-TERM DEBT
Affiliates................................................ 10,000,000 10,000,000
Non-affiliates............................................ 57,000,000 57,000,000
------------ ------------
67,000,000 67,000,000
ACCRUED PLUGGING LIABILITY.................................. 208,456 367,394
DEFERRED INCOME TAXES....................................... 9,458,421 5,680,027
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Series A, 6% Noncumulative Convertible Preferred stock,
par value $.01 per share; 563,270 shares authorized;
72,336 and 73,096 shares issued and outstanding (aggregate
liquidation value of $723,360 and $730,960)............... 723 731
Series B, Cumulative Convertible Preferred stock, par
value $.01 per share; 625,000 shares authorized; 0 and
232,864 shares outstanding................................ -- 2,329
Undesignated Serial Preferred stock, par value $.01 per
share; 811,730 shares authorized; none issued and
outstanding............................................... -- --
Common stock, par value $.01 per share; 60,000,000 shares
authorized; 15,208,634 and 15,208,031 shares issued and
outstanding............................................... 152,086 152,080
Additional paid-in capital.................................. 47,889,111 50,213,422
Retained earnings........................................... 18,125,209 8,431,042
Accumulated other comprehensive (loss) income............... (1,430,225) 579,630
------------ ------------
Total stockholders' equity............................. 64,736,904 59,379,234
------------ ------------
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY.................... $151,851,130 $144,790,358
============ ============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
35
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<Table>
<Caption>
NINE-MONTH
YEAR ENDED PERIOD ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, MARCH 31,
2002 2001 2001
------------ ------------ -----------
REVENUE
Oil and gas production.............................. $37,414,188 $22,851,489 $29,399,487
Drilling revenues................................... 2,082,351 1,795,047 5,710,640
Well operating, gathering and other................. 6,766,608 7,474,679 10,425,066
----------- ----------- -----------
46,263,147 32,121,215 45,535,193
COSTS AND EXPENSES
Oil and gas production expenses..................... 8,583,185 6,399,658 9,071,659
Drilling costs...................................... 1,752,456 1,990,415 4,758,722
Well operating, gathering and other................. 3,488,709 3,213,867 4,530,463
Exploration expense................................. 1,572,638 847,303 775,814
General and administrative expenses................. 4,168,323 2,725,611 3,011,233
Depreciation, depletion and amortization............ 9,022,370 6,330,099 8,032,873
----------- ----------- -----------
28,587,681 21,506,953 30,180,764
----------- ----------- -----------
INCOME FROM OPERATIONS................................ 17,675,466 10,614,262 15,354,429
INTEREST EXPENSE, NET
Interest income..................................... 371,807 420,226 724,367
Interest expense.................................... 3,146,609 3,190,118 6,620,152
----------- ----------- -----------
2,774,802 2,769,892 5,895,785
----------- ----------- -----------
INCOME BEFORE PROVISION FOR INCOME TAXES.............. 14,900,664 7,844,370 9,458,644
PROVISION FOR INCOME TAXES............................ 5,148,332 2,496,376 2,700,000
----------- ----------- -----------
NET INCOME............................................ $ 9,752,332 $ 5,347,994 $ 6,758,644
=========== =========== ===========
NET INCOME APPLICABLE TO COMMON STOCK (after dividends
on cumulative Preferred Stock of $58,165, $174,647
and $232,864, respectively)......................... $ 9,694,167 $ 5,173,347 $ 6,525,780
=========== =========== ===========
NET INCOME PER SHARE (basic and diluted).............. $ 0.64 $ 0.34 $ 0.46
=========== =========== ===========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
36
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<Table>
<Caption>
SERIES A SERIES B
PREFERRED STOCK PREFERRED STOCK COMMON STOCK ADDITIONAL
--------------- ------------------ --------------------- PAID-IN
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT CAPITAL
------ ------ -------- ------- ---------- -------- -----------
BALANCE, MARCH 31, 2000........................ 73,096 $731 232,864 $ 2,329 5,599,706 $ 55,997 $26,274,574
Net Income................................... -- -- -- -- -- -- --
Dividends on Series B Preferred stock
$(1.00 per share).......................... -- -- -- -- -- -- --
Issuance of Common stock..................... -- -- -- -- 9,608,325 96,083 23,938,848
------ ---- -------- ------- ---------- -------- -----------
BALANCE, MARCH 31, 2001........................ 73,096 731 232,864 2,329 15,208,031 152,080 50,213,422
Net Income................................... -- -- -- -- -- -- --
Derivative mark-to-market, net of taxes...... -- -- -- -- -- -- --
Comprehensive income.........................
Dividends on Series B Preferred stock ($.75
per share plus dividends in arrears of
$1.40 per share)........................... -- -- -- -- -- -- --
------ ---- -------- ------- ---------- -------- -----------
BALANCE, DECEMBER 31, 2001..................... 73,096 731 232,864 2,329 15,208,031 152,080 50,213,422
Net Income................................... -- -- -- -- -- -- --
Derivative mark-to-market, net of taxes...... -- -- -- -- -- -- --
Compehensive income..........................
Shares converted and other transactions...... (760) (8) (200) (2) 603 6 4
Dividends on Series B Preferred stock ($.25
per share)................................. -- -- -- -- -- -- --
Redemption of series B Preferred Stock....... -- -- (232,664) (2,327) -- -- (2,324,315)
------ ---- -------- ------- ---------- -------- -----------
BALANCE, DECEMBER 31, 2002..................... 72,336 $723 -- -- 15,208,634 $152,086 $47,889,111
====== ==== ======== ======= ========== ======== ===========
<Caption>
ACCUMULATED
RETAINED OTHER TOTAL
EARNINGS COMPREHENSIVE STOCKHOLDERS'
(DEFICIT) INCOME (LOSS) EQUITY
----------- ------------- -------------
BALANCE, MARCH 31, 2000........................ $(2,942,075) -- $23,391,556
Net Income................................... 6,758,644 -- 6,758,644
Dividends on Series B Preferred stock
$(1.00 per share).......................... (232,864) -- (232,864)
Issuance of Common stock..................... -- -- 24,034,931
----------- ----------- -----------
BALANCE, MARCH 31, 2001........................ 3,583,705 -- 53,952,267
Net Income................................... 5,347,994 -- 5,347,994
Derivative mark-to-market, net of taxes...... -- 579,630 579,630
-----------
Comprehensive income......................... 5,927,624
Dividends on Series B Preferred stock ($.75
per share plus dividends in arrears of
$1.40 per share)........................... (500,657) -- (500,657)
----------- ----------- -----------
BALANCE, DECEMBER 31, 2001..................... 8,431,042 579,630 59,379,234
Net Income................................... 9,752,332 -- 9,752,332
Derivative mark-to-market, net of taxes...... -- (2,009,855) (2,009,855)
-----------
Compehensive income.......................... 7,742,477
Shares converted and other transactions...... -- -- --
Dividends on Series B Preferred stock ($.25
per share)................................. (58,165) -- (58,165)
Redemption of series B Preferred Stock....... -- -- (2,326,642)
----------- ----------- -----------
BALANCE, DECEMBER 31, 2002..................... $18,125,209 $(1,430,225) $64,736,904
=========== =========== ===========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
37
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
NINE-MONTH
YEAR ENDED PERIOD ENDED 2000
DECEMBER 31, DECEMBER 31, DECEMBER 31,
2002 2001 YEAR ENDED
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income........................................ $ 9,752,332 $ 5,347,994 $ 6,758,644
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization..... 9,022,370 6,330,099 8,032,873
(Gain) loss on sale of property and
equipment................................. (398) (28,541) 26,743
Deferred income taxes........................ 5,090,000 2,496,376 2,700,000
Stock bonus.................................. -- -- 34,931
Change in:
Accounts receivable....................... (597,365) 2,647,297 (438,202)
Inventories and other current assets...... 6,444 (158,034) 279,424
Other assets, net......................... 292,575 16,138 197,783
Accounts payable and accrued expenses..... (2,414,741) 712,644 3,687,979
Billings in excess of costs on uncompleted
contracts............................... (2,062,094) 1,184,813 309,225
------------ ------------ ------------
Total adjustments....................... 9,336,791 13,200,792 14,830,756
------------ ------------ ------------
Net cash provided by operating
activities......................... 19,089,123 18,548,786 21,589,400
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment............... (24,083,729) (13,801,713) (7,136,990)
Proceeds on sale of property and equipment........ 54,694 224,720 34,535
------------ ------------ ------------
Net cash used by investing
activities......................... (24,029,035) (13,576,993) (7,102,455)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under long-term credit facilities...... -- -- 63,000,000
Repayment of long term debt -- affiliates......... -- -- (38,500,000)
Repayment of long term debt....................... -- (724,026) (26,022,755)
Redemption of Preferred B stock................... (2,326,642) -- --
Cash paid for deferred financing fees............. -- -- (649,198)
Dividends......................................... (58,165) (500,657) (232,864)
------------ ------------ ------------
Net cash used by financing
activities......................... (2,384,807) (1,224,683) (2,404,817)
------------ ------------ ------------
(DECREASE) INCREASE IN CASH AND EQUIVALENTS......... (7,324,719) 3,747,110 12,082,128
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD......... 22,035,924 18,288,814 6,206,686
------------ ------------ ------------
CASH AND EQUIVALENTS AT END OF PERIOD............... $ 14,711,205 $ 22,035,924 $ 18,288,814
============ ============ ============
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest....................................... $ 3,218,081 $ 3,556,283 $ 5,943,446
Income taxes................................... -- 222,969 --
Supplemental disclosures of noncash investing and
financing activities:
Note payable -- affiliate exchanged for common
stock.......................................... $ -- $ -- $ 24,000,000
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.
38
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization - North Coast Energy, Inc. ("NCE"), a Delaware corporation, was
formed in August 1988 to engage in the exploration, development and
production of oil and gas and the acquisition of producing oil and gas
properties.
B. Change in Year-End - The Company changed its year-end from March 31 to
December 31 effective December 31, 2001. The nine-month period ended December
31, 2001 is not indicative of a full year of operations (see Note 13).
C. 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 Energy Eastern, Inc. ("NCEE",
formerly Peake Energy, Inc.), 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. All significant intercompany accounts and transactions
have been eliminated.
D. Inventories - Inventories consist of material, pipe and supplies valued at
the lower of cost or market.
E. Cash Equivalents - Investments having an original maturity of 90 days or less
that are readily convertible into cash have been included in the cash and
equivalents balances. Included in cash and cash equivalents is $9,224,145 of
investments in a short-term bond fund.
F. 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, gathering systems using the straight-line
method over 10 to 25 years, vehicles, furniture and fixtures using various
methods over 3 to 15 years and building and improvements using various
methods over 7-31.5 years).
G. Oil and Gas Investments and Properties - The Company uses the successful
efforts method of accounting for its 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 developmental wells are capitalized.
Costs to drill exploratory wells that do not find proved reserves, costs of
developmental 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 on a group (pool) basis with proved properties
having similar characteristics, by the unit-of-production method based upon
estimated proved developed reserves. To the extent that capitalized costs of
each pool of proved properties exceed the estimated future net cash flow from
such pool, the excess capitalized costs are written down to the present value
of such amount. Estimated future net cash flows are determined based
primarily upon the estimate future proved reserves related to the Company's
current proved properties.
39
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company follows Statement of Financial Accounting Standards ("SFAS") No.
144 which requires a review for impairment whenever circumstances indicate
that the carrying amount of an asset may not be recoverable. Impairment is
recorded as impaired properties are identified.
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 a partial interest in an unproved property is sold, the amount
received is treated as a reduction of the cost of the interest retained. The
carrying cost of unproved properties is approximately $3,310,000 at December
31, 2002.
H. 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. 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
from the properties and sold. Well operating, gathering and other revenues
include operating fees charged to outside working interest owners in NCE
operated wells, gathering fees (including transportation allowances and
compression fees), third party gas sales associated with purchased natural
gas and other miscellaneous revenues. Such revenue is recognized at the time
it is earned and the Company has a contractual right to receive payment.
Administrative fees received from NCE organized and managed oil and gas
partnerships are treated as a reduction of the Company's general and
administrative expenses.
I. Per Share Amounts - For the year ended December 31, 2002, the nine month
period ended December 31, 2001, and the fiscal year ended March 31, 2001, the
conversion of Series A stock had the effect of increasing average outstanding
shares by 33,251, 33,624 and 33,624 shares, respectively. Assumed exercise of
dilutive stock options had the effect of adding 108, 3,705 and 3,645 shares
to the average outstanding shares for the year ended December 31, 2002, the
nine months ended December 31, 2001, and the year ended March 31, 2001,
respectively. The assumed conversion of the Series B Preferred Stock
increased outstanding shares by 76,321 shares and increased net income by
approximately $58,000 for the year ended March 31, 2001. The effect of
warrants were anti-dilutive in all periods.
The average number of outstanding shares used in computing basic and diluted
net income per share was 15,208,216 and 15,241,948, 15,208,031 and 15,245,360
and 14,306,011 and 14,419,601 for the year ended December 31, 2002, the
nine-month period ending December 31, 2001, and the fiscal year ended March
31, 2001, respectively.
J. Risk Factors - The Company operates in an environment with many financial
risks including, but not limited to, the ability to acquire additional
economically recoverable oil and gas reserves, 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, the
volatility and seasonality of oil and gas production and prices and the
highly competitive nature of the industry as well as worldwide economic
conditions.
K. Accounting Estimates - The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
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. Significant
estimates used in calculating the Company's depletion, depreciation and
amortization which could be subject to significant near term revision include
estimated oil and gas reserves. The Company's reserve estimates could vary
significantly depending on various factors, including Company and industry
volatility of oil and natural gas prices.
40
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
L. Financial Instruments - The Company's financial instruments include cash and
equivalents, accounts receivable, accounts payable, debt obligations and
derivatives. The book value of cash and equivalents, accounts receivable and
accounts 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 and credit losses have historically been within management's
estimate. Derivatives are used as cash flow hedges and are marked to market
through other comprehensive income.
NOTE 2. ACQUISITIONS
During 2002, the Company acquired interests in proved oil and gas
properties and related equipment for $3,710,000. Such interests included the
assets of 3 companies and 14 oil and gas partnerships that had been organized
and sponsored by the Company. The pro form effect of the acquisitions is not
material and therefore has not been presented.
NOTE 3. DETAILS OF CURRENT LIABILITIES
Accrued expenses consist of the following:
<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------- -----------------
Production Taxes.................................... $1,689,351 $1,355,924
Drilling Costs...................................... 826,185 3,414,318
Compensation........................................ 1,268,716 625,330
Other Expenses...................................... 1,023,267 1,510,765
Mark to Market...................................... 2,270,198 --
---------- ----------
$7,077,717 $6,906,337
========== ==========
</Table>
Billings in excess of costs on uncompleted contracts consist of the
following:
<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------- -----------------
Billings on uncompleted contracts................... $-- $2,062,094
Costs incurred on uncompleted contracts............. -- --
-- ----------
$-- $2,062,094
== ==========
</Table>
At December 31, 2001, fourteen wells, were in the process of being
completed.
NOTE 4. LONG-TERM DEBT
Long-term debt consists of the following:
<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------- -----------------
NUON Non-Negotiable Subordinated Promissory Note due
February 28, 2015................................. $10,000,000 $10,000,000
Notes payable -- bank............................... 57,000,000 57,000,000
----------- -----------
$67,000,000 $67,000,000
=========== ===========
</Table>
The Non-Negotiable Subordinated Promissory Note bears interest at the
six-month LIBOR plus 2.3% or 4.1% and 4.2% at December 31, 2002 and December 31,
2001, respectively. The weighted average interest rate
41
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
was 4.5%, 4.9% and 9.0% for the year ended December 31, 2002, the nine-month
period ended December 31, 2001, and the fiscal year ended March 31, 2001,
respectively. The note is subordinated to the Company's senior debt. NUON has
the right to secure the indebtedness by a lien on NCEE's assets, subject to the
rights of the senior lender.
The Company has a five-year, $125,000,000 credit agreement with a group of
four banks with Union Bank of California acting as agent bank. The credit
agreement provides for a borrowing base (presently $80,000,000 of which
$57,000,000 is drawn upon) that is determined semiannually by the lenders based
on the Company's financial position, oil and gas reserves and certain other
factors. The agreement provides for a 3/8% commitment fee on amounts not
borrowed up to the borrowing base and allows for a sub-limit of $15,000,000 for
the issuance of letters of credit. At December 31, 2002 and 2001, amounts
outstanding under bank credit agreements bear interest at LIBOR plus 1.875%, or
approximately 3.3% and 3.8%, respectively. The weighted average interest rate on
bank borrowings was 4.7%, 4.7% and 8.7% for the year ended December 31, 2002,
the nine-month period ended December 31, 2001, and the fiscal year ended March
31, 2001, respectively. Amounts borrowed 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. At December 31, 2002, the
Company's credit agreement restricts the Company from incurring additional debt
or liens, prohibits certain dividends and distributions, and requires the
Company to maintain positive working capital and minimum interest and fixed
charge coverage. The Company was in compliance with all covenants and
restrictions at December 31, 2002.
Future maturities of long-term debt at December 31, 2002 are as follows:
<Table>
2005........................................................ $57,000,000
Thereafter.................................................. 10,000,000
-----------
$67,000,000
===========
</Table>
NOTE 5. STOCKHOLDERS' EQUITY
A. Sale of Common Stock
In September 1997, the Company sold 1,149,426 shares of its common stock for
$5 million to NUON, pursuant to the terms of a stock purchase agreement
("Agreement") by and between the Company and NUON dated August 1, 1997. In
September 1999 and 1998, NUON exercised its option under the Agreement to
purchase an additional 1,042,125 and 1,149,425 shares, respectively, of
common stock at $4.35 per share. In September 1999, NUON purchased an
additional 107,301 shares from the Company's former Chief Executive Officer.
Additionally, in May 2000, NUON received 9,600,000 shares from conversion of
its $24 million convertible promissory note. NUON, which owned 86% of the
Company's common shares at December 31, 2002, has no further contractual
rights or options to purchase shares.
B. Preferred Stock
The Board of Directors of NCE has designated 563,270 shares of the 2,000,000
shares of preferred stock authorized as Series A, 6% Noncumulative
Convertible 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 had been converted into shares of common stock of the
Company. Holders of shares of Series A Preferred stock are entitled to
receive, when and if declared by the Board of Directors, noncumulative cash
dividends at an annual rate of $.60 per share. Shares of Series A Preferred
stock are
42
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 .46 shares of common stock
for each share of Series A Preferred stock converted.
All of, but not less than all, the outstanding shares of Series A Preferred
stock shall, at the option of NCE, be converted into fully paid and
nonassessable shares of common stock at the conversion price, upon the
consummation of the sale of shares of common stock of NCE pursuant to an
effective registration statement under the Securities Act of 1933, as
amended; provided that such sale yields gross proceeds to the Corporation of
not less than $5,000,000 and is made at a public offering price per share of
not less than 1.5 times the conversion price in effect on such date.
In the case where NCE 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 NCE at a price of
$10 per share. NCE does not have any obligation to redeem the Series A
Preferred stock.
In the event of a voluntary or involuntary liquidation, dissolution or
winding up of NCE, holders of the Series A Preferred stock are entitled to be
paid $10 per share out of the assets of NCE but after payment of other
indebtedness of NCE, 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 were entitled to receive, when
and if declared by the Board of Directors, cash dividends at an annual rate
of $1.00 per share, payable quarterly.
During the nine month period ended December 31, 2001, the Company paid the
normal quarterly dividends and all dividends that were in arrears. The
holders of Series B Preferred Stock had the right, exercisable at their
option, to convert any and all of such shares into 1.15 shares of common
stock.
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. In March
2002, the Series B Preferred Stock was redeemed at $10 per share plus the
accrued and unpaid dividends of $0.25 per share, as defined. The Company does
not expect to reissue any Series B Preferred Stock.
C. Common Stock Warrants
In each of fiscal 2000, 1999 and 1998, the Company issued warrants to
purchase 26,800 shares of common stock for $4.375 per share in conjunction
with the NUON Agreement. These warrants (half of which were issued to a
former director and officer) expire between September 2002 and September
2004.
Effective April 1999, in connection with the signing of a separation
agreement, the Company's then Chief Executive Officer received a ten-year
warrant to purchase 60,000 shares of the Company's common stock at $5.00 per
share.
D. Stock Options and Stock Appreciation Rights
On December 13, 1999, the stockholders of the Company approved the adoption
of the North Coast Energy, Inc. 1999 Employee Stock Option Plan ("the Option
Plan"). The Option Plan provides 400,000 shares of common stock reserved for
the exercise of options granted under the plan. The Option Plan provides for
the granting of stock options to purchase common stock at an option price
determined by North Coast's Stock Option and Compensation Committee ("the
Committee"). Options granted under the plan have been at or above the fair
market value of the stock at the date of grant. The Committee determines the
expiration date but
43
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 cannot exceed $100,000. Options granted under
the Option Plan terminate upon, or within 90 days of the employee leaving the
Company. The Company, from time to time, may issue additional options outside
the plan.
Stock option transactions during for the year ended December 31, 2002, the
nine-month period ending December 31, 2001 and the year ending March 31, 2001
are summarized as follows:
<Table>
<Caption>
OPTIONS PRICE
OUTSTANDING RANGE
----------- -------------
March 31, 2000............................................. 62,135 $3.90 - $6.88
Options granted.......................................... 60,000 $3.47 - $3.99
Options cancelled........................................ --
-------
March 31, 2001............................................. 122,135 $3.47 - $6.88
Options granted.......................................... 60,000 $3.70 - $4.38
Options cancelled........................................ 23,384 $3.90 - $6.88
-------
December 31, 2001.......................................... 158,751 $3.47 - $6.88
Options Granted.......................................... 117,650 $3.36 - $3.51
Options Cancelled........................................ --
-------
December 31, 2002.......................................... 276,401 $3.36 - $6.88
=======
</Table>
In January 2002, the Company granted 30,000 options to an independent Director
at $3.36 per share. Those options vested 10,000 upon grant and 10,000 each on
January 31, 2003 and 2004. In March 2002, the Company granted 34,050 options
to an officer at $3.51 per share. All 34,050 options were vested upon grant.
In addition, the Company granted 53,600 options to two officers and two key
employees at $3.51 per share. One-third of those shares were vested upon grant
and one-third will vest on each of March 28, 2003 and 2004.
<Table>
<Caption>
OPTIONS OPTION
EXERCISABLE AT DECEMBER 31, 2002 THROUGH OUTSTANDING PRICE
- ---------------------------------------- ----------- ------------
March 19, 2003.............................................. 58 $ 6.88
April 1, 2003............................................... 6,667 $ 4.38
April 1, 2004............................................... 6,666 $ 4.38
April 1, 2005............................................... 13,334 $ 4.38
April 1, and May 7, 2006.................................... 29,166 $3.99 - 4.38
September 4, 2006........................................... 360 $ 3.91
January 31 through May 7, 2007.............................. 50,367 $3.36 - 4.38
October 18, 2009............................................ 5,000 $ 4.38
October 5, 2010............................................. 30,000 $ 3.47
October 6, 2011............................................. 35,000 $ 3.70
March 28, 2012.............................................. 34,050 $ 3.51
-------
210,668 $3.36 - 6.88
Non-vested Options.......................................... 65,733 $3.36 - 3.99
-------
Total Options............................................... 276,401 $3.36 - 6.88
=======
</Table>
44
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In the nine months ended December 31, 2001, the Company granted options for
35,000 shares to an officer of the Company at $3.70 per share, all of which
vested upon grant, and 25,000 options to a key employee at $4.38, which vests
one-half on each of May 7, 2001 and 2002.
In the year ended March 31, 2001, the Company granted 30,000 options to a
Director of the Company at $3.99 per share with one-third of those shares
vesting on April 1, 2001 and one-third vesting each year thereafter. The
Company also granted 30,000 options to an executive officer at $3.47 per share
all of which vested upon grant.
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. No stock appreciation rights have been awarded under the plan.
The Company has adopted the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock Based Compensation." Accordingly, no compensation cost
has been recognized for the stock option plans. Had compensation cost for the
Company's stock option plan been determined based on the fair value at the
grant date for awards, compensation expense would have increased by
approximately $163,900 in the year ended December 31, 2002 and the Company's
basic and net income per share would have decreased by $.01. The fair value of
options granted during 2002 was approximately $205,900, which was determined
using the Black-Scholes option pricing model, assuming no dividend yield, and
weighted average: risk-free interest rate of 4.6%; volatility of 52%; and
expected life of 5 years. Options granted prior to 2002 were not material
enough to significantly impact the Company's previous years' net income per
share.
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 stockholders. The aggregate
number of shares of common stock, which may be issued as bonuses, shall be
400,000 shares of common stock. The expenses of administering the Bonus Plan
are borne by the Company. The Bonus Plan, as amended, terminates on February
1, 2011. The Company has issued 25,120 shares of common stock under the Bonus
Plan since inception.
NOTE 6. INCOME TAXES
The Company accounts for income taxes under SFAS 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. The provision for income taxes
consisted of the following:
<Table>
<Caption>
YEAR ENDED NINE-MONTHS ENDED FISCAL YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- -----------------
Current provision................... $ 58,332 $ 96,376 $ --
Deferred provision.................. 5,090,000 2,400,000 2,700,000
---------- ---------- ----------
Total............................. $5,148,332 $2,496,376 $2,700,000
========== ========== ==========
</Table>
45
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income taxes differed from the amount computed by applying the federal statutory
rates to pretax book income as follows:
<Table>
<Caption>
YEAR ENDED NINE-MONTHS ENDED FISCAL YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- -----------------
AMOUNT % AMOUNT % AMOUNT %
---------- ---- ---------- ---- ---------- ----
Provision based on the
statutory rate............. $5,066,000 34.0 $2,667,000 34.0 $3,216,000 34.0
Tax effect of:
Statutory
Depletion.................. (210,000) (1.4) (335,000) (4.2) (442,000) (4.7)
State income tax and
other................... 292,332 2.0 164,376 2.0 (74,000) (0.8)
---------- ---- ---------- ---- ---------- ----
Total................... $5,148,332 34.6 $2,496,376 31.8 $2,700,000 28.5
========== ==== ========== ==== ========== ====
</Table>
The components of the net deferred tax liability as of December 31, 2002 and
2001 were as follows:
<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------- -----------------
DEFERRED TAX LIABILITIES
Property and equipment............................ $(16,203,421) $(9,009,580)
Derivative mark to market......................... -- (340,420)
------------ -----------
Total deferred tax liabilities.................... (16,203,421) (9,350,000)
DEFERRED TAX ASSETS
Alternative minimum tax credit carryforwards...... 524,000 524,000
Net operating loss carryforwards.................. 3,500,000 1,650,000
Statutory depletion carryforward.................. 1,300,000 1,110,000
Mark to market liability.......................... 840,000 --
Other temporary differences....................... 581,000 417,000
------------ -----------
Total deferred tax assets.................... 6,745,000 3,701,000
------------ -----------
Net deferred tax liability................... $ (9,458,421) $(5,649,000)
============ ===========
Current asset....................................... $ -- $ 31,027
Long-term liability................................. (9,458,421) (5,680,027)
------------ -----------
Net deferred tax liability................... $ (9,458,421) $(5,649,000)
============ ===========
</Table>
As of December 31, 2002, the Company had operating loss, percentage
depletion and alternative minimum tax credit carryforwards of approximately
$9,500,000 $3,600,000 and $524,000, respectively. The operating loss
carryforwards begin to expire in 2019. The percentage depletion and alternative
minimum tax carryforwards can be carried forward indefinitely. Realization of
these items is subject to certain limitations and is contingent upon future
earnings. Additionally, a portion of the carryforwards may be subject to
limitations imposed by Internal Revenue Code Section 382, which could further
restrict the Company's utilization and realization of such carryforwards.
NOTE 7. RETIREMENT SAVINGS TRUST AND PLAN
The Company has a Retirement Savings Trust and Plan (the "Plan") that
covers all employees that meet the eligibility requirements of the Plan. During
2002, the Plan provided that the Company could make (i) profit sharing
contributions and (ii) contributions to match fifty percent (50%) of employee
pre-tax contributions with
46
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
matching contributions on the first five percent (5%) of an employee's
compensation contributed to the plan. The Plan was restated as of April 1, 2002
to comply with certain changes in law and to adopt a plan year ending December
31 of each year.
The Plan was also restated as of January 1, 2003 to make certain changes in
the Plan and to comply with certain changes in law. The Plan now provides for
immediate vesting of all profit sharing contributions and all matching
contributions. Also, effective January 1, 2003, the Plan provides that instead
of making profit sharing contributions the Company may make a non-elective
contribution equal to three percent (3%) of each eligible employee's
compensation. The Company must determine annually whether or not to make this
contribution, which is designated under the Plan as an "ADP Test Safe Harbor
Contribution", which satisfies the requirements of Internal Revenue Code Section
401(k)(12) and regulations issued thereunder. During 2003, the Company will make
a non-elective contribution of three percent (3%) of each eligible employee's
compensation.
Profit sharing contributions were $75,000 and $120,000 for the plan years
ended March 31, 2002 and March 31, 2001, respectively. Matching contributions
were $68,312 and $48,354 for the plan years ended March 31, 2002 and March 31,
2001, respectively. Effective April 1, 2002, the Plan was amended to adopt a
plan year ending December 31 of each year. Contributions in the twelve months
ended December 31, 2002 were $90,906.
NOTE 8. COMMITMENTS AND CONTINGENCIES
The Company has unlimited liability to third parties with respect to the
operations of the remaining partnerships 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), NCE has agreed to indemnify
these investor-general partners from any partnership liability, which they may
incur in excess of their contributions.
NOTE 9. INDUSTRY SEGMENTS AND MAJOR CUSTOMERS
NCE and its subsidiaries operate in a single industry segment, the
acquisition, exploration and development of oil and gas properties primarily in
the Appalachian Basin. NCE 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 and gas companies.
The Company's revenue is derived from oil & gas related activities in the
Appalachian Basin. Gas production revenues represented 94%, 93% and 91% of total
oil and gas production revenues for the year ended December 31, 2002, the
nine-month period ended December 31, 2001 and the fiscal year ended March 31,
2001, respectively. During the year ended December 31, 2002, one customer
purchased 20% of the gas produced by the Company. During the nine-month period
ended December 31, 2001, two customers purchased 21% and 13% of the gas produced
by the Company. During the fiscal year ended March 31, 2001, two customers
purchased 21% and 14% of the gas produced by the Company. A significant portion
of trade accounts receivable at December 31, 2002 and 2001 was attributable to
these purchasers.
NOTE 10. FINANCIAL INSTRUMENTS
Derivative Financial Instruments: The Company only uses derivatives for
hedging purposes. The following is a summary of the Company's risk management
strategies and the effect of these strategies on the Company's consolidated
financial statements.
Cash Flow Hedging Strategy: The Company is exposed to commodity price
risks related to natural gas and oil. The Company's financial results can be
significantly impacted by changes in commodity prices. To lessen its exposure to
commodity price risk, NCE expects to continue to sell natural gas under fixed
price contracts, on the
47
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
spot market and to use financial hedging instruments to realize a fixed-price on
a portion of its production. As a result of oil and gas hedging activities, oil
and gas sales were increased by approximately $539,000 and $840,000 for the year
ended December 31, 2002 and nine months ended December 31, 2001, respectively
and decreased $3.9 million for the fiscal year ended March 31, 2001. The
following table reflects the natural gas volumes and the weighted average prices
under financial hedges and fixed-price contracts at December 31, 2002:
FINANCIAL HEDGES (COLLARS)
<Table>
<Caption>
ESTIMATED REALIZABLE PRICE FIXED PRICE CONTRACTS NYMEX
---------------------------- ---------------------- AT 12/31/2002
QUARTER ENDING MMBTU FLOOR CAP MMBTU EST. PRICE PER MMBTU
- -------------- ---------- ------ ------ -------- ----------- -------------
March 31, 2003..................... 1,200,000 $3.07 $4.07 887,000 $3.40 $4.82
June 30, 2003...................... 1,660,000 3.39 4.48 404,000 3.53 4.46
September 30, 2003................. 1,670,000 3.39 4.48 276,000 3.52 4.44
December 31, 2003.................. 1,670,000 3.39 4.48 175,000 3.31 4.58
March 31, 2004..................... 905,000 3.42 4.95 104,000 3.16 4.67
June 30, 2004...................... 910,000 3.43 4.96 92,000 3.06 4.10
September 30, 2004................. 920,000 3.43 4.96 89,000 3.03 4.04
December 31, 2004.................. 920,000 3.43 4.96 72,000 2.87 4.20
</Table>
Interest Rate Swap: During 2001, the Company entered into interest rate
swap agreements that effectively convert a portion of its
variable-rate-long-term-debt to fixed rate debt for periods of up to two years,
thus reducing the impact of interest rate changes on future income. As a result
of the swap agreement interest expense was increased by approximately $500,000
in 2002. The amount was immaterial in 2001. At December 31, 2002, the following
contracts were outstanding:
<Table>
<Caption>
LIBOR
RATE NCE EFFECTIVE FIXED
TERM NOTIONAL AMOUNT FIXED RATE
---- --------------- ----- -------------------
1. January 1, 2003 to December 31, 2003.... $20,000,000 4.2% 6.1%
2. January 1, 2001 to December 31, 2003.... $20,000,000 3.5% 5.4%
</Table>
The mark-to-market liability associated with the two interest rate swap
contracts was $974,318 at December 31, 2002.
In February 2003 the Company extended the term of both swaps to December
31, 2004. As a result, swap number 1 will have a rate of 3.2% from April 1, 2003
until it expires on December 31, 2004 and swap number 2 will have a rate of 3%
from January 1, 2003 until it expires on December 31, 2004.
The Company qualifies for special hedge accounting treatment under SFAS
133, whereby the fair value of the hedge is recorded in the balance sheet as
either an asset or liability and changes in fair value are recognized in other
comprehensive income until settled, when the resulting gains and losses are
recorded in earnings. Any hedge ineffectiveness is charged to earnings. The
Company believes that any ineffectiveness in its hedges is immaterial. The
effect on earnings and other comprehensive income as a result of SFAS 133 will
vary from period to period and will be dependent upon prevailing oil and gas
prices, the volatility of forward prices for such commodities, the volumes of
production the Company hedges and the time periods covered by such hedges. As a
result of the adoption of SFAS 133, the Company recorded a liability associated
with its natural gas hedges based on gas prices in effect at April 1, 2001 of
$3,200,000, with offsetting charges to deferred taxes of $1,100,000 and other
comprehensive income of $2,100,000.
The change was accounted for as a cumulative effect of a change in
accounting principle. During the nine months ended December 31, 2001, natural
gas prices decreased and one hedge instrument expired. Consequently,
48
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the liability at December 31, 2001 was eliminated along with the related
deferred tax asset and a mark-to-market asset of $920,050 and a deferred tax
liability of $340,420 were recorded. Accumulated other comprehensive income at
December 31, 2001 was $579,630 and total comprehensive income for the nine
months ended December 31, 2001 was $5,927,624. During 2002 natural gas prices
increased resulting in a mark to market liability and a deferred tax asset of
$1,295,880 and $479,476 respectively, at December 31, 2002. As a result,
accumulated other comprehensive income was a loss of $1,430,225 (interest rate
swap $ 613,821 and costless collar $816,404) and total comprehensive income was
$7,742,477 for the year ended December 31, 2002.
Concentrations of credit risk: Financial instruments that potentially
subject the Company to significant concentrations of credit risk consist
principally of cash and cash equivalents, trade accounts receivable, and
derivatives.
The Company maintains cash and cash equivalents with a large financial
institution, which has an investment grade rating on its debt. This financial
institution operates throughout the country and the Company's policy is to
review the institution's credit worthiness periodically.
Concentrations of credit risk with respect to trade accounts receivable are
limited due to the large number of diverse entities comprising the Company's
customer base. The Company does not require collateral for trade accounts
receivable, and, therefore, the Company could record losses if these customers
fail to pay. The Company believes that established reserves for nonpayment of
$620,000 and $528,000 at December 31, 2002 and 2001, respectively, are adequate.
The Company is exposed to credit risk in the event of non-performance by
counterparties to derivative instruments. The Company limits this exposure by
using counterparties with high credit ratings and monitors those ratings
periodically.
The carrying amounts and fair values of the Company's financial instruments
are as follows:
<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2001
------------------------- -------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
----------- ----------- ----------- -----------
Cash and cash equivalents........ $14,711,205 $14,711,205 $22,035,924 $22,035,924
Accounts receivable.............. 5,796,537 5,796,537 6,006,622 6,006,622
Account payable.................. 3,369,632 3,369,632 3,395,272 3,395,272
Long-term debt................... 67,000,000 67,000,000 67,000,000 67,000,000
Natural gas collars (liability)
asset.......................... (1,295,880) (1,295,880) 920,050 920,050
Interest rate swaps (liability)
asset.......................... (974,318) (974,318) -- --
</Table>
NOTE 11. RELATED PARTY TRANSACTIONS
Accounts receivable from affiliates amounted to $72,385 and $985,559 at
December 31, 2002 and 2001 respectively, consist 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. In the year ended December 31, 2002, the nine months ended
December 31, 2001, and the fiscal year ended March 31, 2001, the Company
acquired limited partnership interests in oil and gas drilling programs that it
had sponsored at a cost of approximately $1,517,000, $1,250,000 and $676,000,
respectively.
NOTE 12. ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations". SFAS No. 141 requires the purchase method of accounting for
business combinations initiated after June 30, 2001 and eliminates the
polling-of-interest method and further clarifies the criteria to recognize
intangible assets separately from goodwill. In
49
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
June 2001, FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets".
Under SFAS No. 142, goodwill and intangible assets deemed to have indefinite
lives will no longer be amortized but will be subject to periodic impairment
tests. Other intangible assets will continue to be amortized over their useful
lives. SFAS No. 142 is effective for fiscal years beginning after December 15,
2001.
In June 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" which is effective the first quarter of fiscal year 2003. SFAS 143
addresses financial accounting and reporting for obligations associated with the
retirement of long-lived assets and the associated asset retirement cost.
In August 2001, FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-lived Assets", which is effective the first quarter of fiscal
year 2002. SFAS No. 144 modifies and expands the financial accounting and
reporting for the impairment or disposal of long-lived assets other than
goodwill. The Company does not believe that these four SFAS will have any
significant impact on its financial position and results of operations.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No.
4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections."
SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of
Debt," SFAS 44, "Accounting for Intangible Assets of Motor Carriers" and SFAS
64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" and
amends SFAS 13, "Accounting of Leases". Statement 145 also makes technical
corrections to other existing pronouncements. SFAS 4 required gains and losses
from extinguishment of debt to be classified as an extraordinary item, net of
the related income tax effect.
As a result of the rescission of SFAS 4, the criteria for extraordinary
items in APB Opinion No. 30, "Reporting the Results Of Operations, Reporting the
Effects of Disposal of Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions," now will be used to classify
those gains and losses. SFAS 145 was effective for the quarter ending September
30, 2002, for the Company's financial position, results of operations and cash
flows.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated
with Exit or Disposal Activities." SFAS 146 will be effective for the Company
for disposal activities initiated after December 31, 2002. The adoption of this
standard is not expected to have a material effect on the Company's financial
position, results of operations or cash flows.
In December 31, 2002, the FASB issued SFAS No. 148, Accounting for
Stock-Based, Compensation - Transition and Disclosure (SFAS 148) that amends
SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative
methods of transition to Statement 123's fair value method of accounting for
stock-based employee compensation. SFAS 148 also amends the disclosure
provisions of SFAS 123 and APB Opinion No. 28, Interim Financial Reporting, to
require disclosure in the summary of significant accounting policies of the
effects of an entity's accounting policy with respect to stock-based employee
compensation on reported net income and earnings per share in annual and interim
financial statements. The Statement does not amend SFAS 123 to require companies
to account for employee stock options using the fair value method. The Statement
is effective for fiscal years beginning after December 15, 2002. The Company is
currently evaluating the effects of SFAS 148, but does not expect that the
adoption of SFAS 148 would have a material effect on the Company's results of
operations.
NOTE 13. TRANSITION REPORTING
In August 2001, the Company elected to change its year end from March 31 to
December 31. As a result, the Company's transition period was the nine months
ended December 31, 2001.
The following table of consolidated financial data provides a year-to-year
comparison of the results of operations for the years ended December 31, 2002
and 2001. The 2001 amounts are unaudited and reflect all
50
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
adjustments, which are, in the opinion of management, necessary to a fair
statement of the results for the period. All adjustments made were of a normal
recurring nature.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
--------------------------
2002 2001
----------- -----------
(UNAUDITED)
REVENUE
Oil and gas production.................................... $37,414,188 $30,919,493
Drilling revenues......................................... 2,082,351 6,833,847
Well operating, gathering, and other...................... 6,766,608 11,419,760
----------- -----------
46,263,147 49,173,046
COSTS AND EXPENSES
Oil and gas production expenses........................... 8,583,185 9,108,606
Drilling costs............................................ 1,752,456 5,434,471
Well operating, gathering, and other...................... 3,488,709 4,818,960
Exploration expense....................................... 1,572,638 1,156,126
General and administrative expenses....................... 4,168,323 3,870,021
Depreciation, depletion and amortization.................. 9,022,370 7,743,227
----------- -----------
28,587,681 32,131,411
----------- -----------
INCOME FROM OPERATIONS...................................... 17,675,466 17,041,635
INTEREST EXPENSE, NET
Interest income........................................... 371,807 739,609
Interest expense.......................................... 3,146,609 4,755,612
----------- -----------
2,774,802 4,016,003
----------- -----------
INCOME BEFORE PROVISION FOR INCOME TAXES.................... 14,900,664 13,025,632
PROVISION FOR INCOME TAXES.................................. 5,148,332 4,246,376
----------- -----------
NET INCOME.................................................. $ 9,752,332 $ 8,779,256
=========== ===========
NET INCOME APPLICABLE TO COMMON STOCK
(after dividends on cumulative Preferred Stock
of $58,165, and $232,861, respectively)................... $ 9,694,167 $ 8,546,395
=========== ===========
NET INCOME PER SHARE
(basic and diluted)....................................... $ 0.64 $ 0.56
=========== ===========
</Table>
51
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 14. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES
CAPITALIZED COSTS RELATING TO OIL AND GAS
PRODUCING ACTIVITIES
<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- --------------
Proved oil and gas properties................. $140,098,372 $121,195,745 $108,466,905
Accumulated depreciation, depletion and
amortization................................ (30,626,693) (24,069,473) (19,681,628)
------------ ------------ ------------
Net capitalized costs......................... $109,471,679 $ 97,126,272 $ 88,785,277
============ ============ ============
</Table>
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<Table>
<Caption>
YEAR ENDED NINE-MONTHS ENDED YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- --------------
Property acquisition costs.................... $3,454,000 $1,259,000 $ 937,592
Exploration costs............................. 2,725,000 1,351,000 775,814
Development costs............................. 20,696,000 7,800,000 5,151,732
</Table>
Property acquisition costs include purchases of proved and unproved oil and
gas properties acquired in business acquisitions.
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
<Table>
<Caption>
YEAR ENDED NINE-MONTHS ENDED FISCAL YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- -----------------
Oil and gas production...................... $37,414,188 $22,851,489 $29,399,487
Loss on sale of oil and gas properties...... -- -- (26,734)
Production costs............................ (8,583,185) (6,399,658) (9,071,659)
Exploration expenses........................ (1,572,638) (847,303) (775,814)
Depreciation, depletion and amortization.... (6,486,110) (4,387,845) (5,249,058)
----------- ----------- -----------
20,772,255 11,216,683 14,276,222
Provision for income taxes.................. 7,154,012 3,508,000 4,450,000
----------- ----------- -----------
Results of operations for oil and gas
producing activities (excluding corporate
overhead and financing costs)............. $13,618,243 $ 7,708,683 $ 9,826,222
=========== =========== ===========
</Table>
Provision for income taxes was computed using the statutory tax rates and
reflects permanent differences, including statutory depletion and the
Partnership's results of operations for oil and gas producing activities that
are reflected in the Company's consolidated income tax provision for the
periods.
52
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 15. ESTIMATED QUANTITIES AND STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS OF PROVED OIL AND GAS RESERVES (UNAUDITED)
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
continental United States.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
<Table>
<Caption>
OIL GAS
(BBLS) (MCF)
--------- -----------
Balance, March 31, 2000..................................... 1,021,400 124,868,000
Extensions and discoveries................................ -- 8,629,000
Purchase of reserves in place............................. 5,600 1,298,000
Production................................................ (96,200) (7,835,000)
Revisions of previous estimates........................... 275,800 16,436,000
--------- -----------
Balance, March 31, 2001..................................... 1,206,600 143,396,000
Extensions and discoveries................................ 100,900 12,730,000
Purchase of reserves in place............................. 8,800 1,857,000
Production................................................ (82,000) (6,404,000)
Revisions of previous estimates........................... 8,000 (4,801,000)
Sales of reserves in place................................ (300) (18,000)
--------- -----------
Balance, December 31, 2001.................................. 1,242,000 146,760,000
Extensions and discoveries................................ 88,000 18,709,000
Purchase of reserves in place............................. 30,000 7,561,000
Production................................................ (104,000) (9,629,000)
Revisions of previous estimates........................... 65,000 10,395,000
Sale of reserves in place................................. (2,000) (124,000)
--------- -----------
Balance, December 31, 2002.................................. 1,319,000 173,672,000
========= ===========
PROVED DEVELOPED RESERVES
March 31, 2000............................................ 924,000 109,174,000
March 31, 2001............................................ 1,119,000 124,444,000
December 31, 2001......................................... 1,132,000 126,385,000
December 31, 2002......................................... 1,204,000 150,979,000
</Table>
53
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
<Table>
<Caption>
YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- --------------
Future cash inflows from sales of oil and gas
(including transportation allowances)....... $907,537,000 $481,414,000 $746,302,000
Future production costs....................... (220,342,000) (159,398,000) (205,754,000)
Future development costs...................... (23,389,000) (19,755,000) (19,492,000)
Future income tax expense..................... (199,142,000) (90,319,000) (155,951,000)
------------ ------------ ------------
Future net cash flows......................... 464,664,000 211,942,000 365,105,000
Effect of discounting future net cash flows at
10% per annum............................... (294,738,000) (133,520,000) (236,774,000)
------------ ------------ ------------
Standardized measure of discounted future net
cash flows.................................. $169,926,000 $ 78,422,000 $128,331,000
============ ============ ============
</Table>
CHANGES IN THE STANDARDIZED MEASURE OF
DISCOUNTED FUTURE NET CASH FLOWS
<Table>
<Caption>
YEAR ENDED NINE-MONTHS ENDED YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 MARCH 31, 2001
----------------- ----------------- --------------
Balance, beginning of period................. $ 78,422,000 $128,331,000 $ 68,320,000
Extensions and discoveries................... 43,911,000 6,207,000 18,292,000
Purchase of reserves in place................ 8,033,000 1,145,000 724,000
Sales of oil and gas, net of production
costs...................................... (28,831,000) (16,452,000) (20,328,000)
Net changes in prices and production costs... 80,239,000 (77,911,000) 62,374,000
Net changes in development costs............. (3,635,000) (263,000) (6,075,000)
Revisions of previous quantity estimates..... 13,977,000 (3,876,000) 20,725,000
Sales of reserves in place................... (75,000) (16,000) --
Net change in income taxes................... (39,711,000) 21,400,000 (25,709,000)
Accretion of discount........................ 11,154,000 18,284,000 9,712,000
Other........................................ 6,442,000 1,573,000 296,000
------------ ------------ ------------
Balance, end of period....................... $169,926,000 $ 78,422,000 $128,331,000
============ ============ ============
</Table>
Under the guidelines of SFAS No. 69, estimated future cash flows are
determined based on period-end prices for crude oil, current allowable prices
applicable to expected natural gas production (including transportation
allowances), 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 to present value using
a 10% year end rate.
The estimated quantities of proved oil and gas reserves and standardized
measure of discounted future net cash flows include reserves from proved
undeveloped acreage. The proved undeveloped acreage includes only the acreage
directly offsetting locations to wells that have indicated commercial production
in the objective formation and which NCE expects to drill in the near future
using prices, operating costs and development costs expected in the area of
interest. The reserve quantities were reviewed by an independent petroleum
engineering firm.
54
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 does 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.
55
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION OF DOCUMENTS PAGE
- ------- ------------------------ ----------
3.1 Certificate of Incorporation of the Registrant dated August
30, 1988. (B)
3.2 Certificate of Stock Designation of the Registrant filed
September 12, 1988. (B)
3.3 Certificate of Stock Designation of the Registrant filed
September 14, 1989. (B)
3.4 Certificate of Correction filed March 22, 1991. (C)
3.5 Certificate of Amendment to Certificate of Incorporation
filed November 4, 1992. (A)
3.6 Certificate of Stock Designation filed December 29, 1992. (D)
3.7 Certificate of Amendment to Certificate of Incorporation
filed August 29, 1994. (G)
3.8 Certificate of Amendment of Certificate of Incorporation
filed December 16, 1998. (J)
3.9 Certificate of Correction filed November 15, 1999. (M)
10.1 1988 Stock Option Plan. (B)
10.2 Form of Profit Sharing Plan. (B)
10.3 Form of Indemnity Agreement between the Registrant and each
of its Directors and executive officers. (B)
10.4 North Coast Energy, Inc. Key Employees Stock Bonus Plan. (B)
10.5 Stock Option Agreement dated as of May 17, 1991 between
Registrant and Timothy Wagers. (C)
10.6 Stock Option Agreement dated as of May 17, 1991 between the
Registrant and Thomas A. Hill. (C)
10.7 Option Agreement dated February 22, 1994 by and between
Registrant and Charles M. Lombardy, Jr. (E)
10.8 Option Agreement dated February 22, 1994 by and between
Registrant and Garry Regan. (E)
10.9 Warrant to purchase 200,000 shares of Common Stock of the
Company. (G)
10.10 Warrant to purchase 300,000 shares of Common Stock of the
Company. (G)
10.11 Restated Employment Agreement dated May 3, 1995 by and
between Registrant and Charles M. Lombardy, Jr. (H)
10.12 Restated Employment Agreement dated May 3, 1995 by and
between Registrant and Garry Regan. (H)
10.13 Open End Mortgage and Promissory Note by and between ING
Capital and the Company dated February 9, 1998. (K)
10.14 Purchase and Sale Agreement dated April 8, 1998 between Kelt
Ohio, Inc., and North Coast Energy, Inc. (I)
10.15 Ratification and Amendment to Purchase and Sale Agreement
dated May 12, 1998 between Kelt Ohio, Inc., and North Coast
Energy, Inc. (I)
10.16 First Amendment to Credit Agreement and Promissory Note
dated May 29, 1998 between ING (U.S.) Capital Corporation
and North Coast Energy, Inc. (I)
10.17 Second Amendment to Credit Agreement and Promissory Note
dated September 2, 1998 between ING (U.S.) Capital
Corporation and North Coast Energy, Inc. (K)
10.18 Warrants to purchase 300,000 shares (pre-split) of Common
Stock of the Company. (K)
10.19 Separation Agreement dated April 30, 1999 by and among North
Coast Energy, Inc., NUON International Projects, bv, Charles
M. Lombardy, Jr., and Betty M. Lombardy. (K)
10.20 Third Amendment to Credit Agreement and Promissory Note
dated June 23, 1999 between ING (U.S.) Capital Corporation
and North Coast Energy, Inc. (K)
10.21 North Coast Energy, Inc. 1999 Employee Stock Option Plan (M)
10.22 Stock Purchase Agreement between Belden & Blake Corporation
and North Coast Energy, Inc. dated March 17, 2000. (L)
</Table>
56
<Table>
<Caption>
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION OF DOCUMENTS PAGE
- ------- ------------------------ ----------
10.23 Non-Negotiable Subordinated Promissory Note in the amount of
$48,500,000 between North Coast Energy, Inc. as maker and
NUON International Projects, bv as holder, dated March 17,
2000. (L)
10.24 Non-Negotiable Subordinated Convertible Promissory Note in
the amount of $24,000,000 (L)
between North Coast Energy, Inc. as maker and NUON
International Projects, bv as holder dated March 17, 2000.
10.25 Fourth Amendment to Credit Agreement and Promissory Noted
dated March 17, 2000 between ING (U.S.) Capital LLC, as
Agent, and North Coast Energy, Inc., as Borrower. (M)
10.26 Amendment to North Coast Energy, Inc. Employees' Profit
Sharing Plan, effective April 1, 2000. (M)
10.27 $125 million Credit Agreement dated September 26, 2000
between North Coast Energy, (N)
Inc. as Borrower, Union Bank of California, NA, as Agent,
Bank One, Texas, NA, as Syndication Agent, and certain
financial institutions, as Lenders.
10.28 First Amendment to Credit Agreement dated March 27, 2001
between North Coast Energy, Inc., as Borrower, Union Bank of
California, NA, as Agent, and certain other financial
institutions, as Lenders. (O)
10.29 North Coast Energy, Inc. 2000 Employee Stock Bonus Plan,
effective February 1, 2001. (O)
10.30 Second Amendment to Credit Agreement dated August 13, 2001
between North Coast Energy, Inc., as Borrower, Union Bank of
California, NA, as Agent, and certain other financial
institutions, as Lenders. (P)
10.31 Third Amendment to Credit Agreement dated December 31, 2002
between North Coast Energy, Inc., as Borrower, Union Bank of
California, N.A., as agent, and certain other financial
institutions, as Lenders --
21.1 List of Subsidiaries. (M)
23.1 Consent of Hausser + Taylor LLP. --
(A) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Registration Statement on Form S-2 (Reg.
No. 33-54288).
(B) Incorporated herein by reference to the appropriate exhibits
to the Company's Registration Statement on Form S-1 (File
No. 33-24656).
(C) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Annual Report on Form 10-K for the
fiscal year ended March 31, 1991.
(D) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Annual Report on Form 10-K for the
fiscal year ended March 31, 1993.
(E) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Annual Report on Form 10-K for the
fiscal year ended March 31, 1994.
(F) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Quarterly Report on form 10-Q for the
fiscal quarter ended September 30, 1994.
(G) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Annual Report on Form 10-K for the
fiscal year ended March 31, 1995.
(H) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Annual Report on Form 10-K for the
fiscal year ended March 31, 1996.
(I) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Report on Form 8-K dated June 12, 1998.
(J) Incorporated herein by reference to the appropriate exhibits
to the Company's Registration Statement on Form S-1 (File
No. 33-71855).
(K) 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, 1999.
(L) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Report on Form 8-K dated March 22, 2000.
</Table>
57
<Table>
<Caption>
EXHIBIT SEQUENTIAL
NUMBER DESCRIPTION OF DOCUMENTS PAGE
- ------- ------------------------ ----------
(M) 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, 2000.
(N) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2000.
(O) 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, 2001.
(P) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2001.
(Q) Incorporated herein by reference to the appropriate exhibit
to the Registrant's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001.
</Table>
58
CERTIFICATIONS*
I Omer Yonel, certify that:
1. I have reviewed this annual report on Form 10-K of North Coast Energy;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent
functions):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
<Table>
Date: March 21, 2003 Signed: /s/ OMER YONEL
--------------------------------------------------------
Title: President, Chief Executive Officer and
Director
</Table>
59
CERTIFICATIONS*
I Dale E. Stitt, certify that:
1. I have reviewed this annual report on Form 10-K of North Coast Energy,
Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
<Table>
Date: March 21, 2003 Signed: /s/ DALE E. STITT
--------------------------------------------------------
Title: Chief Financial Officer and Principal
Accounting Officer
</Table>
60