NORTH COAST ENERGY INC / DE/ - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K

[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

COMMISSION FILE NUMBER 0-18691
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NORTH COAST ENERGY, INC.
(Exact name of Registrant as specified in its charter)

DELAWARE 34-1594000
(State of incorporation) (I.R.S. Employer Identification No.)

1993 CASE PARKWAY 44087-2343
TWINSBURG, OHIO (Zip Code)
(Address of principal executive offices)

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.

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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

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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

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(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.

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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

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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.
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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

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
=======

- ---------------

(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

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.

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.

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

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

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)

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.

- ---------------

(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.

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.

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.

- ---------------

(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.

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.

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)

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.

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.

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.

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:

- ---------------

(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:

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 Te