<PAGE>

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

                                   FORM 10-K

<Table>
<C>          <S>
    [ ]      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
             SECURITIES EXCHANGE ACT OF 1934



                                   OR



    [X]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
             SECURITIES EXCHANGE ACT OF 1934



             FOR THE TRANSITION PERIOD FROM MARCH 31, 2001 TO
             DECEMBER 31, 2001.
</Table>

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

<Table>
<S>                                         <C>
                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, 2002, the Registrant had outstanding 15,208,031 shares
of Common Stock, 73,096 shares of Series A Preferred Stock, and 232,864 shares
of Series B Preferred Stock. All shares reflect the 1 for 5 reverse Common Stock
split effective June 7, 1999.

     The aggregate market value of Common Stock held by non-affiliates of the
Registrant at February 28, 2002, was $7,256,773 which value was computed on the
basis of $3.36 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 10, 11, 12, and 13)

                       Document Incorporated by Reference

Portions of the Registrant's definitive Proxy Statement to be used in connection
                 with its 2002 Annual Meeting of Stockholders.
Except as otherwise indicated, the information contained in this Report is as of
                               December 31, 2001.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                                     PART I

ITEM 1.  BUSINESS

GENERAL

     North Coast Energy, Inc., ("NCE" or the "Company") is a Delaware
corporation. The Company conducts operations in the United States in one
reportable segment, which is oil and gas exploration and production. NCE is an
independent natural gas and oil company engaged in exploration, development and
production activities in the Appalachian Basin. The Company's business strategy
focuses primarily on the acquisition of proved developed and undeveloped
properties and on the enhancement and development of such properties. As used in
this Annual Report on Form 10-K, the terms "Company" and "NCE" mean North Coast
Energy, Inc., its subsidiaries and predecessors, unless the context otherwise
requires. The Company currently has three wholly owned subsidiaries, NCE
Securities, Inc. ("NCE Securities"), North Coast Operating Company ("NCOC"), and
North Coast Energy Eastern, Inc. ("NCE Eastern"), two of which are considered
active (NCE Securities and NCE Eastern). All references herein to the Company
are to North Coast Energy, Inc., its subsidiaries and predecessor entities.

     The Company began operations in 1981. In 1997, NUON International Projects
bv ("NUON") and the Company formed a strategic alliance that has resulted in
NUON acquiring a majority ownership position (86%) in the Company as of May
2000. NUON has also provided significant financial resources that have enabled
the Company to acquire additional oil and gas producing assets, increase its
daily production and reserves, improve its efficiency as an operator and
substantially improve its financial structure.

     As of December 31, 2001, NCE owned interests in 4,080 wells, operating
3,800 of these wells. In connection with the drilling and development of the
wells it operates, NCE currently owns and operates approximately 1,446 miles of
natural gas gathering systems with access to the commercial and industrial gas
markets of the northeastern United States. At December 31, 2001, the Company had
estimated net proved reserves of approximately 147 Bcf (billion cubic feet) of
natural gas and 1.2 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 $112 million at December 31, 2001. Daily net production
as of December 31, 2001 was approximately 22 MMcf (million cubic feet of natural
gas) and 272 barrels of oil. At that date, the Company held leases on 388,705
gross (298,874 net) acres, including 208,264 gross (155,046 net) undeveloped
acres.

     The Company has grown principally through the acquisition of producing
properties and related gas gathering facilities and the exploration and
development of its leasehold acreage. In the three calendar years ended December
31, 2001, the Company has acquired producing properties with 80 Bcfe (billion
cubic feet of natural gas equivalent) of proved developed reserves at an average
cost of $ .74 per Mcfe (thousand cubic fee of natural gas equivalent).

SIGNIFICANT EVENTS

     On August 2, 2001, the Company chose to change its fiscal year end from
March 31, the year used in its most recent filing with the Securities and
Exchange Commission; to a fiscal year end of December 31. As a result, this Form
10-K covers the transition period of the nine months ended December 31, 2001.

SUBSEQUENT EVENTS

     On February 15, 2002, the Company served notice of its intent to redeem all
of the 232,864 outstanding shares of its Series B Cumulative Convertible
Preferred Stock. The redemption date is March 31, 2002. The redemption price for
each outstanding Preferred B share is $10.00. The Series B Preferred Stock paid
quarterly cumulative cash dividends at an annual rate of $1.00 per share.

     Holders of the Preferred B Shares may elect to convert their shares into
common shares of the Company at a conversion rate of 1.15 shares of common stock
for each Preferred B Share.

                                        2
<PAGE>

AREA OF OPERATIONS

     The Appalachian Basin (the "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 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 to 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 may 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.

BUSINESS STRATEGY

     The Company's business strategy is to increase shareholder value by
increasing production, operating margins and cash flow by making strategic
acquisitions that are either accretive to operating results and/or beneficial to
the Company's future strategic positioning; through the exploration and
development of the Company's existing and acquired acreage base; 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:

     - MAKE STRATEGIC ACQUISITIONS ACCRETIVE TO 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.

     - 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 oil and gas development and exploration.

     - IMPROVE PROFIT MARGINS. The Company intends to become one of the most
       efficient operators in the Basin. To accomplish this goal, the Company
       intends to improve its 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 1,446 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. The
       Company intends to continue to expand its gas gathering systems to
       further improve the rate of return on its exploration and development
       operations.

                                        3
<PAGE>

     - 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. NCE believes
       that over the next decade those companies that master the ability to
       manage the volatility of natural gas prices will be successful - given
       the anticipated fundamental shift in the price of this commodity.

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, 2001, the Company acquired
working interests in approximately 3,300 producing wells with 80 Bcfe of proved
developed reserves at an average cost of $ .74 per Mcfe. In addition during such
period, the Company acquired various gas-gathering systems and numerous
additional drilling locations. The Company has also acquired additional
interests in wells operated for its Drilling Programs by purchasing investors'
oil and gas interests for cash.

OIL AND GAS OPERATIONS AND PRODUCTION

     Operations.  The Company operates substantially all 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.

     The Company currently maintains production field offices in Ohio, West
Virginia and Kentucky. Through these offices, the Company continuously reviews
its properties to identify actions which could reduce operating costs and
improve production.

     Production.  The following table summarizes the net oil and gas production
for the average sales prices and average production (operating) expenses per
equivalent unit of production for the nine months ended December 31, 2001 and
for fiscal years ended March 31, 2001 and March 31, 2000.

                                   PRODUCTION

<Table>
<Caption>
                                         PRODUCTION            SALES PRICE          AVERAGE
         FISCAL YEAR OR            ----------------------   ------------------   OPERATING COST
          PERIOD ENDED             OIL (BBLS)   GAS (BCF)   PER BBL   PER MCF     PER MCFE (1)
         --------------            ----------   ---------   -------   --------   --------------
<S>                                <C>          <C>         <C>       <C>        <C>
March 31, 2000...................    31,000        3.0      $20.08     $2.58         $1.14
March 31, 2001...................    96,200        7.8      $28.28     $3.40         $1.08
December 31, 2001................    82,000        6.4      $20.75     $3.31         $0.93
</Table>

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

(1) For calculation of average operating cost per Mcfe, the standard ratio of
    6:1 for gas to oil was used.

EXPLORATION AND DEVELOPMENT

     Exploration and development activities conducted by the Company have
primarily involved the acquisition of proved undeveloped oil and gas properties
and the drilling and development of such properties.

                                        4
<PAGE>

     The Company's strategy focuses on increasing its natural gas and oil
reserves, as well as production, drilling and oilfield service revenues, by
acquiring undeveloped oil and gas properties in the Basin and financing and
conducting the drilling and development of these properties by the Company or in
conjunction with the Drilling Programs.

     The Company's historical drilling operations in the Basin have principally
involved drilling to the Clinton/Medina sandstone formation. This formation is
an oil and gas 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 1998, the Company began a seismic data program that led to the inception
of exploratory drilling to formations below the Clinton/Medina Sandstone on a
portion of its Ohio leasehold acreage. This exploratory drilling has focused on
the Knox unconformity, 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 14 exploratory wells drilled
to the Knox formations on seismic data.

     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.

     NCE continually evaluates undeveloped prospects originated by its staff or
other independent geologists as well as other gas and oil companies. If the
review of a prospect indicates that it may be geologically and economically
attractive, the Company will attempt to lease the mineral rights the prospect's
acreage encompasses.

     Typically, the Company 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 nine months ended December 31, 2001, the Company drilled 64 gross
(55.8 net) wells in its four state operating area at a direct cost of
approximately $7.8 million for the net wells. The result of this drilling
activity is shown in the table on page 6. In 2002, the Company expects to spend
approximately $18 million to drill 121 gross (109 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, nor should it be assumed that there is necessarily any correlation
between the number of productive wells drilled and the oil and gas reserves
generated.

                                        5
<PAGE>

     All wells were drilled by March 31 of their respective fiscal years and by
December 31 for the nine months ended December 31, 2001 and are reflected in the
Drilling Activities table. Wells in which the Company owns only a royalty
interest are not reflected in the table below.

                              DRILLING ACTIVITIES

<Table>
<Caption>
                                                                            FISCAL YEAR
                                                   NINE MONTHS ENDED      ENDED MARCH 31,
                                                   -----------------      ----------------
                                                   DECEMBER 31, 2001      2001       2000
                                                   -----------------      -----      -----
<S>                                                <C>                    <C>        <C>
Exploratory Wells (1)
  Productive
     Gross.......................................           7                5          1
     Net.........................................         6.5              4.3          1
  Dry
     Gross.......................................           0                0          0
     Net.........................................           0                0          0
Development Wells (2)
  Productive (3)
     Gross.......................................          57               46         34
     Net.........................................        49.3             13.2        8.2
  Dry
     Gross.......................................           0                0          0
     Net.........................................           0                0          0
Total Wells (4)
  Productive
     Gross.......................................          64               51         35
     Net.........................................        55.8             17.4        9.2
  Dry
     Gross.......................................           0                0          0
     Net.........................................           0                0          0
</Table>

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

(1) Exploratory Wells are those wells drilled outside the confines of a known
    productive reservoir area.

(2) Development Wells are those wells drilled within the confines of a known
    productive reservoir.

(3) The number of productive wells for the nine months ended December 31, 2001
    includes 10 gross and 10 net wells that are awaiting pipeline connection or
    well completion operations at December 31, 2001.

(4) Total Wells is the sum of the Exploratory and Development Wells.

DRILLING PROGRAMS

     From the Company's inception in 1981 through December 31, 2001, NCE has
raised approximately $100 million and has sponsored 53 Drilling Programs to
engage in oil and gas drilling and development operations. Each Drilling Program
has been conducted as a separate limited partnership with the Company serving as
managing general partner of each. Thirty of the Company's prior Drilling
Programs have been dissolved as a result of the acquisition of interests by the
Company. Currently, NCE serves as the managing general partner of 23 Drilling
Programs.

     The Company acts as operator and general contractor for drilling and
production operations, undertaking to drill and complete Drilling Program wells
and to serve as operator for producing wells. At December 31, 2001, the Company
operated 460 wells for the Drilling Programs.

DRILLING SERVICES

     NCE derives revenue and net income from the drilling services it provides
to the Drilling Programs. NCE enters into turnkey (fixed price) contracts with
the Drilling Programs to drill Program wells. Pursuant to these drilling
contracts, the Company is responsible for the drilling and completion of the
wells. The Company

                                        6
<PAGE>

manages and supervises all necessary drilling and related service and equipment
operations on these wells and contracts a number of third party services
including contract drilling, fracturing, logging and pipeline construction,
which are performed by subcontractors who specialize in those operations. Since
NCE contracts with the Drilling Programs on a turnkey basis, the Company is
subject to the risk that prices incurred in the actual drilling and completion
operations could exceed its contract price.

OIL FIELD SERVICE OPERATIONS

     As of December 31, 2001, NCE operated 3,800 wells located in Ohio,
Pennsylvania, West Virginia and Kentucky. As an operator of producing wells, the
Company is responsible for the maintenance and verification of all production
records, contracting for oil and gas sales, distribution of production proceeds
and information, and compliance with various state and federal regulations.
Generally, the Company provides the routine day-to-day production operations for
producing wells. The Company may, however, subcontract certain oil 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 unaffiliated third party
costs associated with operations and production of the 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.

GAS GATHERING ACTIVITIES

     In connection with the drilling and completion of the wells that it
operates, NCE has acquired, constructed and owns approximately 1,446 miles of
gas gathering systems in various counties 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 its acquisition and construction of
gathering systems and the establishment of compressor facilities in order to
expand its existing and future potential markets.

     For such 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 transportation allowances averaged
approximately $0.34 per Mcf (thousand cubic feet) of natural gas for the nine
months ending December 31, 2001.

MARKETS

     The ability of the Company to market oil and gas depends to an extent, on
factors beyond its control. The potential effects of governmental regulation and
market factors including alternative domestic and imported energy sources,
available pipeline capacity, and general market conditions are not entirely
predictable.

     Natural Gas.  Natural gas is generally sold pursuant to individually
negotiated gas purchase contracts, which vary in length from spot market sales
of a single day to term agreements that may extend several years. 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 may vary 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 the Company's contracts provide for
prices to be set monthly based on published NYMEX (New York Mercantile Exchange)
or Appalachian price indices. The Columbia Gas Transmission Corporation (TCO)
and Dominion Southpoint Index prices, which create a basis for spot sale prices
in the Mid-Atlantic and northeastern regions of the United States, ranged from
$2.03 to $5.67 per MMBtu during the nine months
                                        7
<PAGE>

ending December 31, 2001. (MMBtu represents one million British Thermal Units.
One MMBtu is approximately equal to one Mcf.) At December 31, 2001,
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 $6.29 per Mcf. The remainder of the Company's natural
gas fixed-price contracts are with utilities and natural gas marketers. The
prices received from these contracts range between $2.50 and $5.00 per Mcf. For
the nine months ending December 31, 2001, the Company received an average price
of $3.31 per Mcf.

     During the nine months ending December 31, 2001, two customers purchased
21% and 13% of the gas produced by the Company, respectively.

     Due to the seasonality of supply and demand, prices paid by purchasers for
natural gas will continue to fluctuate. The Company has pursued a strategy of
varying the length and pricing provisions of its gas purchase contracts in order
to maintain flexibility to react to those fluctuating prices. Due to current
market conditions, the duration of recently renegotiated fixed price contracts
have been extended to from one to three years in length. In order to reduce the
volatility of natural gas prices, the Company has fixed approximately 52% of its
production for the calendar year 2002 at an average price of $3.45 per Mcf. The
Company has also put costless collars on 26% of its expected 2002 production
with a weighted average floor and a cap of $3.57 and $4.47 per Mcf,
respectively. Costless collars are financial hedging instruments which the
Company uses to limit the impact of price decreases, the "floor price", in turn
capping the potential benefit of price increases, the "ceiling price".

     During the past several years, an overabundance of natural gas supplies and
promulgation of state and federal regulations pertaining to the sale,
transportation, and marketing of natural gas resulted in increasing competition
and declining prices. Also, recent trends have shown that there may be an
imbalance between supply and demand as evidenced by increased natural gas
futures prices during 2000. During 2001 prices trended lower from the all time
highs of December 2000. However, the Company believes that the upward trend in
prices may resume spurred by increased demand in the residential and commercial
sectors, construction of gas-fired electric generation and declining domestic
production.

     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 $20.75 per barrel for its oil for the nine months ended
December 31, 2001; 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, 2001 was $16.25. Future
oil prices are difficult to predict due to the impact of worldwide economic
trends, coupled with supply and demand variables, and such non-economic factors
as the impact of political considerations on OPEC pricing policies and the
possibility of supply interruptions. Oil production comprised approximately 7%
of NCE's total oil and gas production calculated on a Mcfe basis for the nine
months ended December 31, 2001. 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
oil and gas production. There is competition among oil and gas producers as well
as with other industries in supplying energy and fuel to end-users.

     The Company's competitors in oil and gas exploration, development and
production include numerous independent oil and gas 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

                                        8
<PAGE>

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. Such laws and regulations govern a wide range of matters, including
the drilling and spacing of wells, allowable rates of production, restoration of
surface areas, plugging and abandonment of wells and requirements for the
operation of wells. Such regulations may adversely affect the rate at which the
Company's wells produce gas and oil. In addition, legislation and new
regulations concerning gas and oil exploration and production operations are
constantly being reviewed and proposed. Most of the states in which the Company
owns and operates properties have laws and regulations governing several of the
matters enumerated above. Compliance with the laws and regulations affecting the
gas and oil industry generally increases the Company's cost of doing business
and consequently affects its profitability.

     Environmental Matters.  The discharge of oil, gas or other pollutants into
the air, soil or water may give rise to liabilities to the government and third
parties and may require the Company to incur costs to remedy the discharge.
Natural gas, oil or other pollutants (including 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),
failure to notify the proper authorities of a discharge, and other noncompliance
with those laws. Compliance with such laws and regulations may increase the cost
of gas and oil exploration, development and production although the Company does
not currently anticipate that compliance will have a material adverse effect on
capital expenditures or earnings of the Company.

     The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry. The
Company believes its present activities substantially comply, in all material
respects, with existing environmental laws and regulations. Nevertheless, no
assurance can be given that environmental laws will not, in the future, result
in a curtailment of production or material increase in the cost of production,
development or exploration or otherwise adversely affect the Company's
operations and financial condition. Although the Company maintains liability
insurance coverage for certain liabilities from pollution, such environmental
risks generally are not fully insurable. The amount of such coverage is
currently not less than $1 million and is provided on a "claims made" basis.

     Marketing and Transportation.  The interstate transportation and sale for
resale of natural gas is regulated by the Federal Energy Regulatory Commission
(the "FERC") under the Natural Gas Act of 1938 ("NGA"). The wellhead price of
natural gas is also regulated by FERC under the authority of the Natural Gas
Policy Act of 1978 ("NGPA"). The Natural Gas Wellhead Decontrol Act of 1989 (the
"Decontrol Act"), which was enacted on July 26, 1989, eliminated all gas price
regulation effective January 1, 1993.

     In 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 NCE is not an interstate pipeline, the Company believes 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
affect the price of natural gas production and the transportation and marketing
of natural gas.

                                        9
<PAGE>

OPERATING HAZARDS AND UNINSURED RISKS

     The Company's gas and oil operations are subject to all operating hazards
and risks normally incident to drilling for and producing gas and oil, such as
encountering unusual formations and pressures, blowouts, environmental
pollution, and personal injury. The Company will maintain such insurance
coverage, as it believes to be appropriate, taking into account the size of the
Company and its proposed operations. The Company currently does not maintain
insurance coverage for physical loss or damage to equipment located on the wells
or for inventory such as crude oil stored in tanks. The Company's insurance
policies also have standard exclusions. Losses can occur from an uninsurable
risk or in amounts more than existing insurance coverage. The occurrence of an
event, which is not insured or not fully insured, could have an adverse impact
on the Company's revenues and earnings.

     As managing general partner of the Drilling Programs, NCE is subject to
full liability for the obligations of the Drilling Programs. It is indemnified,
however, by each Program under certain circumstances, to the extent of the
Program's assets. The partnership interests in the Drilling Programs constitute
securities and the Company is subject to potential liability for failure to
comply with applicable federal and state securities laws and regulations.

EMPLOYEES

     At December 31, 2001, the Company had 139 full-time employees, including
105 field employees, 2 petroleum engineers, 2 geologists, 6 accountants, 2 land
men, 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.

ITEM 2.  PROPERTIES

     Proved Reserves.  The following table reflects the estimates of the
Company's proved reserves as of December 31, 2001.

                                    RESERVES

<Table>
<S>                                                            <C>
Oil Reserves (MBbls)
  Proved Developed..........................................     1,132
  Proved Undeveloped........................................       110
                                                               -------
     Total..................................................     1,242
                                                               =======
Gas Reserves (MMcf)
  Proved Developed..........................................   126,385
  Proved Undeveloped........................................    20,375
                                                               -------
     Total..................................................   146,760
                                                               =======
MMcf Equivalent (1)
  Proved Developed..........................................   133,177
  Proved Undeveloped........................................    21,035
                                                               -------
     Total..................................................   154,212
                                                               =======
</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 oil and gas reserves. The following table
sets forth the estimated future net cash flows from the proved reserves of the
Company as of December 31, 2001 determined in accordance with the rules and
regulations of the Securities and Exchange Commission.

                                        10
<PAGE>

             ESTIMATED FUTURE NET CASH FLOWS (BEFORE INCOME TAXES)
                  ATTRIBUTABLE TO ESTIMATED PRODUCTION DURING

<Table>
<Caption>
                                                                    (IN
                                                                 THOUSANDS)
<S>                                                            <C>
2002........................................................      $ 10,501
2003........................................................        16,904
2004........................................................        18,504
2005 and thereafter.........................................      $256,352
</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, 2001 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 oil and gas
utilized in determining the Company's reserves.

<Table>
<Caption>
                                                                      FISCAL YEAR ENDED
                                              NINE MONTHS ENDED   -------------------------
                                              DECEMBER 31, 2001   MARCH, 2001   MARCH, 2000
                                              -----------------   -----------   -----------
<S>                                           <C>                 <C>           <C>
Gas (per Mcf)...............................         3.13             5.01          2.80
Oil (per Bbl)...............................        17.25            23.25         22.69
Per Mcfe....................................         3.12             4.95          2.84
</Table>

     Oil and Gas Properties.  In the following tables, "gross" refers to the
total acres or wells in which the Company has a working interest and "net"
refers to gross acres or wells multiplied by the Company's percentage working
interests therein. Royalty interests held by the Company will not be reflected
in net wells.

     Productive Wells.  The following table sets forth the number of gross and
net productive oil and gas wells of the Company as of December 31, 2001. 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
-----                                       -----   -----   -----   ---   -----   -----
<S>                                         <C>     <C>     <C>     <C>   <C>     <C>
Ohio......................................  1,343     989      0      0   1,343     989
Pennsylvania..............................    515     299     28     10     543     309
West Virginia.............................  1,431   1,209    364    361   1,795   1,570
Kentucky..................................    119     114      0      0     119     114
                                            -----   -----    ---    ---   -----   -----
TOTALS....................................  3,408   2,611    392    371   3,800   2,982
                                            =====   =====    ===    ===   =====   =====
</Table>

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

(1) Gross wells include 100 wells in which the Company owns a royalty interest.

                                        11
<PAGE>

     Acreage.  The following table sets forth the Company's developed and
undeveloped leasehold acreage on both a gross and net basis, as of December 31,
2001. 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>
<S>                                                            <C>
Total Leasehold Acreage
  Gross Acres...............................................   388,705
  Net Acres.................................................   298,874
Developed Acreage
  Gross Acres...............................................   170,621
  Net Acres.................................................   136,328
Proved Undeveloped Acreage
  Gross Acres...............................................     9,820
  Net Acres.................................................     7,500
Undeveloped Acreage
  Gross Acres...............................................   208,264
  Net Acres.................................................   155,046
</Table>

FACILITIES

     NCE owns a 12,000 square foot building, its corporate headquarters, in
Twinsburg, Ohio. As part of the NCE Eastern acquisition NCE 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 materials 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, 2001, there were no matters
submitted to a vote of security holders through the solicitation of proxies or
otherwise.

                                        12
<PAGE>

                                    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 tables sets forth the high and low bid and ask
prices for the Common Stock for the periods indicated.

                                  COMMON STOCK
                     (amounts rounded to the third decimal)

<Table>
<Caption>
                                                          HIGH               LOW
                                                     ---------------   ---------------
                                                      BID      ASK      BID      ASK
                                                     ------   ------   ------   ------
<S>                                                  <C>      <C>      <C>      <C>
FISCAL YEAR ENDED
  MARCH 31, 2001
  First Quarter....................................  $4.375   $5.188   $2.250   $2.438
  Second Quarter...................................   4.438    4.500    2.813    3.125
  Third Quarter....................................   4.875    5.125    3.000    3.750
  Fourth Quarter...................................   4.624    4.750    3.625    3.813
NINE MONTHS ENDED
  DECEMBER 31, 2001
  First Quarter....................................  $5.250   $5.250   $3.500   $3.580
  Second Quarter...................................   4.460    4.500    3.070    3.170
  Third Quarter....................................   3.760    3.900    3.050    3.130
</Table>

     As of February 28, 2002, there were 15,208,031 shares of Common Stock
outstanding, which were held by approximately 1,467 holders of record. On June
7, 1999, a 1 for 5 reverse stock split became effective thereby reducing the
number of shares of outstanding Common Stock from 22,784,070 to 4,556,814. Of
the total 15,208,031 outstanding shares of the Company's Common Stock, 9,600,000
were issued on May 4, 2000, to NUON in compliance with NUON's election to
convert a $24 million Non-Negotiable Subordinated Convertible Promissory Note
from debt to equity. The Note had been entered into between the Company and NUON
on March 17, 2000, and represented a portion of the financing that had been
provided by NUON in conjunction with the purchase of the stock of NCE Eastern.

     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 was convertible to 2.3
shares of Common Stock prior to the reverse stock split and is convertible to
0.46 shares of Common Stock after the reverse stock split. The holders of Series
B Preferred Stock are entitled to receive quarterly cumulative cash dividends at
an annual rate of $1.00 per share. The Series B Preferred Stock was convertible
to 6.56 shares of Common Stock prior to the reverse stock split and is
convertible to 1.15 shares of Common Stock after the stock split. For the nine
months ended December 31, 2001, the Company paid $500,657 in aggregate cash
dividends on its Series B Preferred Stock, including $326,010 of dividends in
arrears.

     On February 15, 2002, the Company served notice of its intent to redeem all
of the 232,864 outstanding shares of its Series B Preferred Stock. The
redemption date is March 31, 2002. The redemption price for each outstanding
Preferred B share is $10.00.

     The Company has never paid any cash dividends on its Common Stock and is
currently restricted from paying cash dividends on any of 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.

                                        13
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

     The following table sets forth-selected financial data for the Company for
the nine months ended December 31, 2001 and 2000 and for each of the four fiscal
years in the periods ended March 31, 2001, 2000, 1999 and 1998.

<Table>
<Caption>
                                   NINE MONTHS ENDED               FISCAL YEARS ENDED
                                  -------------------   -----------------------------------------
                                  DEC. 31,   DEC. 31,   MAR. 31,   MAR. 31,   MAR. 31,   MAR. 31,
                                    2001       2000       2001       2000       1999       1998
                                  --------   --------   --------   --------   --------   --------
                                             (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                               <C>        <C>        <C>        <C>        <C>        <C>
Revenues........................  $ 32,121   $ 28,483   $ 45,535   $ 15,640   $12,982    $ 7,625
Net Income......................     5,348      3,327      6,759      1,312       870        262
Net Income per share (1)........      0.34       0.22       0.46       0.21      0.16       0.00
Total Assets....................   144,790    136,799    135,353    123,618    43,573     22,312
Long Term Debt (less current
  portion)......................    67,000     70,635     67,167     90,122    21,494      7,171
Stockholders' equity............    59,379     50,565     53,952     23,392    17,943     12,339
</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 three quarters ended December 31, 2001 and for the
fiscal year ended March 31, 2001.

<Table>
<Caption>
                                                        NINE MONTHS ENDED DECEMBER 31, 2001
                                                                   QUARTER ENDED
                                                       -------------------------------------
                                                        JUNE 30,     SEPT. 30,     DEC. 31,
                                                          2001         2001          2001
                                                       ----------   -----------   ----------
                                                                  (IN THOUSANDS,
                                                             EXCEPT PER SHARE AMOUNTS)
<S>                                                    <C>          <C>           <C>
Revenues.............................................   $ 11,213      $ 10,345     $ 10,563
Net Income...........................................      1,533         1,889        1,926
Net Income per share (1).............................       0.10          0.12         0.12
Total Assets.........................................    136,777       136,870      144,790
Long Term Debt (less current portion)................     67,144        67,000       67,000
</Table>

<Table>
<Caption>
                                                  FISCAL YEAR ENDED MARCH 31, 2001
                                                           QUARTER ENDED
                                             ------------------------------------------
                                             JUNE 30,   SEPT. 30,   DEC. 31,   MAR. 31,
                                               2000       2000        2000       2001
                                             --------   ---------   --------   --------
                                              (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                          <C>        <C>         <C>        <C>
Revenues...................................  $  8,096   $ 10,006    $  9,304   $ 18,129
Net Income (Loss)..........................       406      1,013       1,909      3,431
Net Income (Loss) per share (1)............      0.03       0.06        0.12       0.22
Total Assets...............................   129,460    127,297     136,799    135,353
Long Term Debt (less current portion)......    67,493     70,564      70,635     67,167
</Table>

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

(1) Net Income (Loss) 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.

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 production of
undeveloped natural gas and oil properties.

                                        14
<PAGE>

NCE derives its revenues from its own oil and gas production, turnkey drilling,
well operations, gas gathering, transportation and gas marketing services it
provides for third parties.

     NCE recognizes as proved undeveloped reserves only the potential oil and
gas 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, 2001, approximately 86% are proved developed and
approximately 14% are proved undeveloped based upon equivalent unit Mcfs. Proved
undeveloped acreage requires considerable capital expenditures to develop.
Management 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 August 2001, NCE elected to change its fiscal year from March 31 to
December 31. The current period's income statement is for the nine months ended
December 31, 2001. The unaudited statement of income for the nine months ended
December 31, 2000 is presented for comparison purposes only.

     The following table is a review of the results of operations of the Company
for the fiscal years ended March 31, 2001 and 2000 and for the nine months ended
December 31, 2001 and December 31, 2000. All items in the table are calculated
as a percentage of total revenues.

<Table>
<Caption>
                                                      NINE MONTHS ENDED           FISCAL YEAR ENDED
                                                          DEC. 31,                    MAR. 31,
                                                  -------------------------   -------------------------
                                                     2001          2000          2001          2000
                                                  -----------   -----------   -----------   -----------
                                                                       (UNAUDITED)
<S>                                               <C>           <C>           <C>           <C>
Revenues:
  Oil and gas production........................       71%           75%           65%           53%
  Drilling......................................        6%            2%           12%           28%
  Well operating, gathering and other...........       23%           23%           23%           19%
                                                      ---           ---           ---           ---
Total Revenues..................................      100%          100%          100%          100%
Expenses:
  Oil and gas production........................       20%           22%           20%           23%
  Drilling costs................................        6%            5%           10%           22%
  Well operating, gathering and other...........       13%           12%           12%           10%
  General and administrative....................        8%            7%            6%           10%
  Depreciation, depletion and amortization......       20%           23%           18%           15%
  Interest (Net)................................        9%           16%           13%           12%
  Income taxes..................................        8%            3%            6%            0%
                                                      ---           ---           ---           ---
Total Expenses..................................       84%           88%           85%           92%
Net Income......................................       16%           12%           15%            8%
                                                      ===           ===           ===           ===
Net Income Applicable to Common Stock (1).......       16%           11%           14%            7%
                                                      ===           ===           ===           ===
</Table>

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

(1) Dividends were paid or accrued on the Series B cumulative preferred stock in
    the amount of $232,864 and $232,864 for fiscal years ended March 31, 2001
    and 2000 and $174,647 for the nine-month periods ended December 31, 2001 and
    2000. These amounts did not include the payment of $326,010 of dividends in
    arrears in December 2001.

                                        15
<PAGE>

     The following discussion and analysis reviews the results of operations and
financial condition for the Company for the nine months ended December 31, 2001
and 2000 and the fiscal years ended March 31, 2001 and 2000. This review should
be read in conjunction with the Financial Statements and other financial data
presented elsewhere herein.

COMPARISON OF NINE MONTHS ENDED DECEMBER 31, 2001 TO THE NINE MONTHS ENDED
DECEMBER 31, 2000 (UNAUDITED)

     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 MONTHS ENDED
                                                                     DECEMBER 31,
                                                              ---------------------------
                                                                  2001           2000
                                                              ------------   ------------
                                                                             (UNAUDITED)
<S>                                                           <C>            <C>
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.......................    4,061,170      3,392,361
  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
OTHER INCOME (EXPENSE)
  Interest Income...........................................      420,226        399,267
  Other.....................................................           --          5,715
  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)...................  $ 5,173,347    $ 3,152,733
                                                              ===========    ===========
NET INCOME PER SHARE (basic and diluted)....................  $      0.34    $      0.22
                                                              ===========    ===========
</Table>

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
corporate 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

                                        16
<PAGE>

attributed to higher volumes resulting from the Company's successful corporate
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 Program. 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 larger 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 Program 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 $0.7 million to $4.1
million in the nine-month period ended December 31, 2001 from $3.4 million in
the nine-month period ended December 31, 2000. The increased costs resulted from
increased repair and maintenance on the Company's gathering system.

     General and administrative expense increased $0.9 million to $2.7 million
from $1.9 million in the nine-month period ended December 31, 2000 as a result
of reduced administrative fees charged to partnerships and bad debt expense
associated with the bankruptcy filing of Enron North America Corp. (see Item 7A,
Quantitative and Qualitative Disclosures about market risk). 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, 2001.

     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 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 lower LIBOR based interest rates 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.

                                        17
<PAGE>

     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.

COMPARISON OF FISCAL 2001 TO FISCAL 2000

     During the fiscal year ended March 31, 2001, NCE successfully integrated
NCE Eastern, which was acquired in March 2000, and successfully executed
drilling and development activities that resulted in significant increases in
its operations, proved reserves and financial results. Average wells operated
increased from approximately 1,700 in 2000 to approximately 3,800 in 2001 as a
result of the NCE Eastern acquisition. NCE's proved developed natural gas
reserves increased to 124.4 Bcf for fiscal 2001 from 109.2 Bcf for fiscal 2000
and proved developed oil reserves increased to 1,119,000 Bbls from 924,000 Bbls.
The increase in proved reserves at the fiscal year-end resulted from a
successful exploration and development program and the extension of well lives
due to higher prices for natural gas at March 31, 2001 compared to March 31,
2000. The proved gas reserves (developed and undeveloped) increased to 143.4 Bcf
for fiscal 2001 from 124.9 Bcf for fiscal 2000. The increase in proved gas
reserves was due to the increases mentioned previously for the proved developed
reserves. Proved oil reserves (developed and undeveloped) increased to 1,206,600
Bbls for fiscal 2001 from 1,201,400 Bbls for fiscal 2000.

REVENUES

     The Company sold 7.8 Bcf of gas and 96,000 barrels of oil in the fiscal
year ended March 31, 2001, compared to 3.0 Bcf and 31,000 barrels in the fiscal
year ended March 31, 2000. The acquisition of assets from Environmental
Exploration Corporation was completed in October of 1999 and the acquisition of
Peake Energy, Inc. was completed in March of 2000. The Company's operating
results for the year ended March 31, 2001, increased substantially due to the
inclusion of both acquisitions for the entire year 2001. Increased production
also resulted from the Company's drilling and development activities. Oil and
gas production revenues increased $21.2 million (258%) to $29.4 million for
fiscal 2001 compared to $8.2 million for fiscal 2000. The increase in oil and
gas revenues is attributed to higher volumes resulting from the above
acquisitions and higher prices received for oil and gas sold.

     The Company received an average price of $3.40 per Mcf (thousand cubic
feet) of gas and $28.28 per barrel of oil in fiscal 2001 compared to $2.58 per
Mcf and $20.08 per barrel in fiscal 2000.

     Drilling revenues increased $1.3 million to $5.7 million for fiscal 2001
compared to $4.4 million in fiscal 2000 due to the increase in the number of
wells completed in fiscal 2001 in connection with the Company's 2000 Drilling
Program. Revenue was recognized on 34 wells in fiscal 2001 compared to 26 wells
for fiscal year 2000.

     Well operating, gathering and other revenues increased $7.4 million to
$10.4 million for fiscal 2001 compared to $3.0 million for fiscal 2000. The
increases result primarily from increased volumes of gas transported through
facilities owned by the Company and an increase in wells operated for third
parties.

EXPENSES

     Oil and gas production expense increased $5.5 million to $9.1 million for
fiscal 2001 from $3.6 million for fiscal 2000 primarily as a result of the wells
acquired and operated during the fiscal year. The Company's average operating
cost per Mcfe was $1.08 in fiscal 2001 compared to $1.14 in fiscal 2000.

     Drilling costs for fiscal 2001 increased $1.3 million (38%) as a result of
the increased number of Drilling Program wells drilled and completed in fiscal
2001 compared to fiscal 2000. The Company maintained a 17% profit margin for
wells drilled in fiscal 2001 compared to 21% in fiscal 2000.

     Well operating, gathering and other expenses increased $3.7 million (237%)
to $5.3 million in fiscal 2001 from $1.6 million in fiscal 2000. The increased
costs resulted from the increase in the number of wells operated by the Company
through its acquisitions and drilling activities.

                                        18
<PAGE>

     General and administrative expense increased $1.5 million (102%) to $3.0
million from $1.5 million in fiscal 2000 as a result of costs associated with
the Company's business process reengineering efforts, the implementation of a
new software system including training and conversion expenses and additional
general and administrative expenses associated with the Company's recent
acquisitions. General and administrative expenses were 6% of revenue in fiscal
2001 compared to 10% in fiscal 2000.

     Depreciation, depletion and amortization, increased $5.6 million to $8.0
million in fiscal 2001 compared to $2.4 million in fiscal 2000 primarily as a
result of higher volumes resulting from the acquisitions discussed earlier.

     Income from operations for fiscal 2001 increased $12.3 million (388%) to
$15.4 million from $3.1 million for fiscal 2000. The increase in income from
operations was primarily due to higher production resulting from the recent
acquisitions and the Company's drilling activity and higher prices paid for
natural gas and oil coupled with increased drilling revenues, well operating,
transportation and other revenues.

     Net interest expense increased $4.1 million to $5.9 million from $1.8
million primarily reflecting the increase in the average outstanding borrowings
resulting from financing recent acquisitions.

     The Company's higher level of income required a provision for deferred
taxes in fiscal 2001 where as no provision was required in fiscal 2000.

     The Company's net income increased $5.5 million (415%) to $6.8 million for
the fiscal year ended March 31, 2001, from $1.3 million for the fiscal year
ended March 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 nine-month period ended December 31,
2001 have decreased as a result of reduced industrial demand and reduced air and
over-land travel combined with an increase in the available supply of crude oil
to world markets. Natural gas prices have also decreased during the nine-month
period ended December 31, 2001 due to higher storage supplies, mild winter
2001/2002 weather and reduced industrial demand resulting from the slowdown in
economic growth in the United States. As a result of these market forces, the
Company received an average price of $20.75 per barrel of oil for the nine-month
period ended December 31, 2001 compared to $28.28 for the fiscal year ended
March 31, 2001. The Company received an average price of $3.31 per Mcf for its
natural gas in the nine-month period ended December 31, 2001, compared to $3.40
for fiscal 2001.

     The Company cannot predict the duration of the current condition of oil and
gas markets and price, as those forces noted above, as well as other variables,
may change.

     Currently, NCE sells natural gas under fixed price contracts, on the spot
market and uses financial hedging instruments to realize a fixed price on a
portion of its production. The Company has positioned itself to take advantage
of current market conditions by fixing a greater portion of its gas to contracts
of a year or longer at prices substantially higher than were received in recent
years.

                                        19
<PAGE>

     The following table reflects the natural gas volumes and the weighted
average prices under financial hedges and fixed price contracts at December 31,
2001.

<Table>
<Caption>
                                         FINANCIAL HEDGES (COLLARS)         FIXED PRICE CONTRACTS
                                      --------------------------------   ----------------------------
                                                         ESTIMATED
                                                     REALIZABLE PRICE                 ESTIMATED
                                             NYMEX   -----------------                REALIZABLE
QUARTER ENDING                        MMCF   PRICE    FLOOR      CAP     MMCF           PRICE
--------------                        ----   -----   -------   -------   -----   --------------------
<S>                                   <C>    <C>     <C>       <C>       <C>     <C>
March 31, 2002......................  743    $2.56    $3.75     $4.82    1,315          $3.59
June 30, 2002.......................  391    2.62      3.54      4.97    1,113           3.45
September 30, 2002..................  391    2.76      3.54      4.53    1,031           3.38
December 31, 2002...................  586    3.02      3.39      4.72      818           3.32
March 31, 2003......................  977    3.25      3.44      4.97      700           3.32
June 30, 2003.......................  684    3.04      3.54      4.97      396           3.30
September 30, 2003..................  684    3.13      3.54      4.97      342           3.17
December 31, 2003...................  684    3.32      3.54      4.97      329           3.07
March 31, 2004......................   --      --        --        --      247           3.05
</Table>

     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, 2001.

<Table>
<Caption>
                                                                   LIBOR
                                                      NOTIONAL     RATE    NCE EFFECTIVE
                       TERM                            AMOUNT      FIXED    FIXED RATE
--------------------------------------------------   -----------   -----   -------------
<S>                                                  <C>           <C>     <C>
January 1, 2002 to December 31, 2002..............   $20,000,000    2.7%        4.6%
January 1, 2002 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 not material at December 31, 2001.

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 $16.4 million at December 31, 2001,
compared to $16.1 million at March 31, 2001. The increase of $0.3 million in
working capital reflects the working capital generated by operations during the
nine-month period ended December 31, 2001. As of December 31, 2001, the Company
had $57.0 million outstanding under its Credit Facility and $10.0 million in
borrowings from NUON.

     The following table summarizes the Company's financial position at December
31, 2001, and March 31, 2001.

<Table>
<Caption>
                                                      DECEMBER 31, 2001    MARCH 31, 2001
                                                      ------------------   --------------
                                                        AMOUNT       %      AMOUNT     %
                                                      ----------   -----   --------   ---
                                                         (DOLLAR AMOUNTS IN THOUSANDS)
<S>                                                   <C>          <C>     <C>        <C>
Working capital.....................................   $ 16,444      12    $ 16,075    13
Property and equipment..............................    113,248      86     105,243    84
Other...............................................      2,735       2       3,506     3
                                                       --------     ---    --------   ---
  Total.............................................   $132,427     100    $124,824   100
                                                       ========     ===    ========   ===
Long-term debt......................................   $ 67,000      51    $ 67,167    54
Deferred income taxes and other liability...........      6,048       4       3,705     3
Stockholders' equity................................     59,379      45      53,952    43
                                                       --------     ---    --------   ---
  Total.............................................   $132,427     100    $124,824   100
                                                       ========     ===    ========   ===
</Table>

     The Company's oil and gas exploration and development activities of NCE
historically have been financed through internally generated funds, through the
Drilling Programs and from bank financing.

                                        20
<PAGE>

     The following table summarizes the Company's Statements of Cash Flows for
the nine months ended December 31, 2001 and 2000 and the fiscal years ended
March 31, 2001 and 2000.

<Table>
<Caption>
                                                 NINE MONTHS ENDED      FISCAL YEARS ENDED
                                               ----------------------   ------------------
                                               DEC. 31,    DEC. 31,     MAR. 31   MAR. 31
                                                 2001        2000        2001       2000
                                               --------   -----------   -------   --------
                                                          (UNAUDITED)
<S>                                            <C>        <C>           <C>       <C>
Net cash provided by operating activities....  $ 18,549     $13,326     $21,589   $  3,901
Net cash used in investing activities........   (13,577)     (2,684)     (7,102)   (75,443)
Net cash (used in) provided by financing
  activities.................................    (1,225)      1,341      (2,405)    75,792
Increase in cash and cash equivalent.........  $  3,747     $11,983     $12,082   $  4,250
                                               ========     =======     =======   ========
</Table>

     As the above table indicates, the Company's cash provided by operating
activities was $18.5 million for the nine-month period ended December 31, 2001
compared to $13.3 million for the nine-month period ended December 31, 2000. The
increase was mainly due to increased production of gas and oil resulting from
the Company's 2001 corporate drilling program, higher drilling revenues and
lower operating costs.

     Net cash used for investing activities was $13.6 million for the nine-month
period ended December 31, 2001, compared to $2.7 million for the nine-month
period ended December 31, 2000. The increase in the nine-month period ended
December 31, 2001 resulted from the Company's expanded 2001 corporate drilling
program.

     Net cash used in financing activities was $1.2 million for the nine-month
period ended December 31, 2001. The cash was used during this period to pay down
various loans and mortgages and to pay current dividends and dividends in
arrears on the Company's Series B Preferred stock. Cash provided by financing
activities in the nine-month period ended December 31, 2000 resulted from the
refinancing of the Company's long-term debt in September 2000.

     On September 26, 2000, the Company entered into a five year, $125 million
Credit Agreement (the "Credit Agreement") with a group of four banks with Union
Bank of California acting as agent bank. The new Credit Agreement replaced the
Company's previous credit agreement with ING (US) Capital Corporation. The
Credit Agreement provides for a borrowing base that is determined semiannually
by the lenders based on the Company's financial position, oil and gas reserves
and certain other factors (presently $65.0 million). 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
and B 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 oil and gas wells and reserves.

     During calendar 2002, the Company expects to spend approximately $20.5
million on drilling and lease acquisition and $0.7 million on other capital
expenditures. In addition, the company intends to redeem its outstanding
Preferred B Shares for $2.3 million in March 2002 and offer to repurchase
limited partners interests in partnerships it manages for up to $7 million.
These capital expenditures will be financed from cash on hand, free cash flow
generated during the year and, if needed, from available borrowings.

ACCOUNTING STANDARDS

     On April 1, 2001, the Company adopted Financial Accounting Standards Board
("FASB") Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (as amended).
SFAS 133 establishes accounting and reporting standards for hedging activities
and derivative instruments, including certain derivative instruments embedded in
other contracts.

     The Company qualifies for special hedge accounting treatment under SFAS
133, whereby the fair value of the hedge is recorded on 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
                                        21
<PAGE>

earnings. Any hedge ineffectiveness is charged to earnings. The Company believes
that its hedges are effective and any ineffectiveness 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
and interest rates, the volatility of forward prices for such commodities and
forward interest rates, the volumes of production the Company hedges and the
amount loan interest hedged 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. During the nine-month period ended December
31, 2001, natural gas prices decreased and the Company entered into additional
hedging transactions. As a result, the liability at April 1, 2001 was eliminated
and at December 31, 2001, the Company had recorded a hedge asset of $920,050
offset by deferred taxes of $340,420 and accumulated other comprehensive income
of $579,630. The result of hedge accounting during the nine-month period ended
December 31, 2001 was other comprehensive income of $579,630 and total
comprehensive income of $5,927,624.

     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 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.

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, 2001 $17 million of the Company's total long-term debt
consisted of floating rate debt. If interest rates were to increase 100 basis
points (1%) from December 31, 2001, and assuming no changes in floating rate
long-term debt from the December 31, 2001, levels, the additional annual expense
would be approximately $270,000 on a pre-tax basis. Subsequent to December 31,
2001, the Company entered into a hedge transaction to fix the rate on $20
million of debt at 6.0% for Calendar 2003.
                                        22
<PAGE>

     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 and 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 a previous
portion of Item 7 of this report and summarized below:

<Table>
<Caption>
                                                COSTLESS COLLARS           FIXED PRICE CONTRACTS
                                         -------------------------------   ---------------------
                                                          AVERAGE PRICE
                                                         ---------------
                 YEAR                    MMCF    % (1)   FLOOR   CEILING   MMCF    % (1)   PRICE
                 ----                    -----   -----   -----   -------   -----   -----   -----
<S>                                      <C>     <C>     <C>     <C>       <C>     <C>     <C>
2002...................................  2,111    26%    $3.57    $4.77    3,910    48%    $3.41
2003...................................  3,029    42%     3.51     4.97    1,499    21%     3.23
</Table>

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

(1) Percent of production expected from wells with proved producing reserves at
    December 31, 2001.

     The Company is exposed to credit risks from its customers and counter
parties 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 counter parties.
Historically, losses from bad debts have been minimal.

     On March 21, 2000, the Company entered into a contract with Enron North
America Corp. (Enron) to supply approximately 100,000 MMBTU of natural gas per
month through March 31, 2003 at a fixed price. The Company also made spot market
sales to Enron of approximately 20,000 MMBTU per month at current market rates.
On November 30, 2001, the Company suspended deliveries of natural gas to Enron.

     Effective May 1, 2000, the Company entered into a commodity swap covering
approximately 150,000 MMBTU per month of natural gas through December 31, 2001.
The terms of the swap provided that the Company would receive $3.05 per MMBTU
for the natural gas under contract and would pay Enron market price.

     On December 2, 2001, Enron filed a voluntary bankruptcy petition with the
United States Bankruptcy Court for the Southern District of New York. The
Company intends to pursue its claims against Enron in bankruptcy as follows:

<Table>
<Caption>
      CONTRACT                                 PERIOD OWING                           AMOUNT
      --------                                 ------------                          --------
<S>                    <C>                                                           <C>
Fixed price contract   November 2001...............................................  $279,840
Spot market contract   October and November 2001...................................    97,259
Commodity Swap         November and December 2001..................................    49,650
                                                                                     --------
                                                                                     $426,749
                                                                                     ========
</Table>

     At December 31, 2001, the Company had provided a reserve for 100% of the
amounts due from Enron. The Company plans to vigorously pursue its claims
against Enron but believes it was appropriate to fully reserve the amounts due
from Enron at December 31, 2001.

     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 F-1)

ITEM 9.  DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     Not Applicable.

                                        23
<PAGE>

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     Executive officers and directors of the Company as of February 28, 2002
were as follows:

<Table>
<Caption>
NAME                                    AGE                  POSITION
----                                    ---                  --------
<S>                                     <C>   <C>
Omer Yonel............................  38    President, Chief Executive Officer and
                                              Director
Dale E. Stitt.........................  56    Chief Financial Officer
Dean A. Swift.........................  49    Secretary and General Counsel
Carel W. J. Kok.......................  35    Chairman of the Board and Director
Cok van der Horst.....................  56    Director
Ron L. Langenkamp.....................  56    Director
Ralph L. Bradley......................  60    Director
Joop G. Drechsel......................  47    Director
Garry Regan...........................  51    Director
</Table>

     OMER YONEL is President, Chief Executive Officer and a Director of North
Coast Energy, Inc. He was appointed Executive Vice President - Corporate
Development in January 1999. In May 1999 he was promoted to Chief Operating
Officer and in October 1999 he was named Chief Executive Officer and appointed
as a Director. In May 2001, he was appointed to the additional position of
President.

     Prior to his election as an officer of North Coast Energy, Inc., Mr. Yonel
was employed by n.v. NUON, the largest public utility in The Netherlands.
Previous to his tenure at NUON, Mr. Yonel was a project manager for the
construction of co-generation and power plants at Schelde Engineering &
Contractors bv, a Netherlands company. Prior to his service with Schelde, Mr.
Yonel held various project-engineering, management and sales positions at ABB
Lummus, an Asea Brown Boveri subsidiary that provides engineering, management
and consultancy services to global chemical, petrochemical, petroleum refining,
oil and gas and other industries.

     Mr. Yonel holds a BS and MS Degree in Engineering from Delft University of
Technology in The Netherlands. Additionally, Mr. Yonel has a certification of
Project Management, is a certified Cost Engineer through the International Cost
Engineering Council, and holds several certifications from executive education
programs and post-graduate programs from Columbia University in New York, J.L.
Kellogg Graduate School of Business at Northwestern University and Harvard
University. Mr. Yonel is also a graduate of the Advanced Management Program at
The Wharton School, University of Pennsylvania. He is a member of the Ohio Oil &
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 oil and gas 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 & Gas Association, the Ohio Petroleum Producers Accountants Society
and the Miami University Business Advisory Council.

     DEAN A. SWIFT was appointed Secretary and General Counsel of the Company in
July 2001. From 1998 to 2001, he was engaged in the private practice of law and
consulting. From 1989 to 1998 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

                                        24
<PAGE>

degree from the University of the South and 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 Oil and Gas Association.

     CAREL W. J. KOK was elected as a Director in December 1998 and currently
serves as Chairman of the Board of Directors of the Company. Mr. Kok has been
Chief Growth Officer and a member of the NUON Executive Management Board since
July 1, 2000. Previously he was Director of Mergers & Acquisitions and Strategy
with the NUON Energy Group. Prior to that he held various positions with NUON's
International Division. From 1990 to 1995, he was with Royal Dutch Shell Group
working in a variety of downstream commercial, trading and new business
development functions in East Asia, the Middle East as well as Europe. Mr. Kok
holds various board positions with subsidiaries of the NUON Group and is a
Supervisory Board Member of the Amsterdam Power Exchange (APX). Mr. Kok holds a
B.A. from Princeton University and an M.B.A. from the Rotterdam School of
Management at Erasmus University.

     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.

     JOOP G. DRECHSEL is currently CEO-elect 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 located in The Netherlands and holds numerous advisory
positions in both the energy and the communications 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 University in Rotterdam and
has studied in the MBA program at the University of Michigan. He currently
chairs the Audit Committee of the Company's Board of Directors.

     RON L. LANGENKAMP is currently Manager of Energy and Wholesale Trading for
NUON. 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.

     RALPH L. BRADLEY was elected a Director in December 1997. Mr. Bradley is
currently President of Bradley Energy USA, which provides energy solutions for
the oil and gas industry. Prior to forming this entity, Mr. Bradley was chief
executive officer of The Eastern Group, Inc., and its predecessor, Eastern
States Exploration Company, Inc. Mr. Bradley currently chairs the Stock Option
and Compensation Committee of the Company's Board of Directors.

     GARRY REGAN participated in the organization of North Coast Energy's
predecessor in 1981, and has served as an executive officer and Director since
that time, serving 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
                                        25
<PAGE>

degree from Indiana University. He is a member of the Independent Petroleum
Association of America, the Ohio Oil & 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 "Executive Compensation" in the
Company's definitive Proxy Statement for the 2002 Annual Meeting of
Stockholders, since such Proxy Statement will be filed with the Securities and
Exchange Commission not later than 120 days after the end of the Company's
fiscal period ended December 31, 2001, pursuant to Regulation 14A.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information required by this Item 12 is incorporated by reference to
the information set forth under the captions "Principal Shareholders" and "Share
Ownership of Directors and Officers" in the Company's definitive Proxy Statement
for the 2002 Annual Meeting of Stockholders, since such Proxy Statement will be
filed with the Securities and Exchange Commission not later than 120 days after
the end of the Company's fiscal period ended December 31, 2001, pursuant to
Regulation 14A.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information required by this Item 13 is incorporated by reference to
the information set forth under the caption "Transactions with Management" in
the Company's definitive Proxy Statement for the 2002 Annual Meeting of
Stockholders, since such Proxy Statement will be filed with the Securities and
Exchange Commission not later than 120 days after the end of the Company's
fiscal period ended December 31, 2001, pursuant to Regulation 14A.

                                        26
<PAGE>

                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)(1) Financial Statements

     The following Consolidated Financial Statements of the Registrant and its
subsidiaries are included in Part II, Item 8:

<Table>
<Caption>
                                                                 PAGE(S)
                                                               -----------
<S>                                                            <C>
Auditor's Report on the Financial Statements................           F-3
Consolidated balance sheets.................................     F-4 - F-5
Consolidated statements of income...........................           F-6
Consolidated statements of stockholders' equity.............           F-7
Consolidated statements of cash flows.......................     F-8 - F-9
Notes to consolidated financial statements..................   F-10 - F-31
</Table>

(a)(2) Financial Statements Schedules

     All schedules for which provision is made in the applicable accounting
regulation of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable, and therefore have been omitted.

(a)(3) Exhibits

     Reference is made to the Exhibit Index.

(b) Reports on Form 8-K

     The Company's report on Form 8-K dated August 10, 2001.

                                        27
<PAGE>

                                   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
                    ---------                                              -----
<S>     <C>                                          <C>

                  /s/ OMER YONEL                      President, Chief Executive Officer and Director
 ------------------------------------------------              (principal executive officer)
                    Omer Yonel


                /s/ DALE E. STITT                     Chief Financial Officer and Secretary (principal
 ------------------------------------------------            accounting and financial officer)
                  Dale E. Stitt


                                                             Chairman of the Board and Director
 ------------------------------------------------
                 Carel W. J. Kok


                                                                          Director
 ------------------------------------------------
                Cok van der Horst


                                                                          Director
 ------------------------------------------------
                Ron L. Langenkamp


               /s/ RALPH L. BRADLEY                                       Director
 ------------------------------------------------
                 Ralph L. Bradley


               /s/ JOOP G. DRECHSEL                                       Director
 ------------------------------------------------
                 Joop G. Drechsel


                 /s/ GARRY REGAN                                          Director
 ------------------------------------------------
                   Garry Regan
</Table>

                                        28
<PAGE>

                                 EXHIBIT INDEX

<Table>
<Caption>
EXHIBIT                                                                SEQUENTIAL
NUMBER                     DESCRIPTION OF DOCUMENTS                       PAGE
-------                    ------------------------                    ----------
<C>      <S>                                                           <C>
   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>

                                        29
<PAGE>

<Table>
<Caption>
EXHIBIT                                                                SEQUENTIAL
NUMBER                     DESCRIPTION OF DOCUMENTS                       PAGE
-------                    ------------------------                    ----------
<C>      <S>                                                           <C>
  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 between North Coast Energy, Inc.
         as maker and NUON International Projects, bv as holder dated
         March 17, 2000.                                                      (L)
  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, Inc. as Borrower, Union Bank of
         California, NA, as Agent, Bank One, Texas, NA, as
         Syndication Agent, and certain financial institutions as
         Lenders.                                                             (N)
  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)
  21.1   List of Subsidiaries.                                                (M)
  23.1   Consent of Hausser + Taylor. LLP
</Table>

(A)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's Registration Statement on Form S-2 (Reg. No. 33-54288).

(B)  Incorporated herein by reference to the appropriate exhibits to the
     Company's Registration Statement on Form S-1 (File No. 33-24656).

(C)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's Annual Report on Form 10-K for the fiscal year ended March 31,
     1991.

(D)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's Annual Report on Form 10-K for the fiscal year ended March 31,
     1993.

(E)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's Annual Report on Form 10-K for the fiscal year ended March 31,
     1994.

(F)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's Quarterly Report on form 10-Q for the fiscal quarter ended
     September 30, 1994.

(G)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's Annual Report on Form 10-K for the fiscal year ended March 31,
     1995.

(H)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's Annual Report on Form 10-K for the fiscal year ended March 31,
     1996.

(I)  Incorporated herein by reference to the appropriate exhibit to the
     Registrant's 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.

(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.

                                        30
<PAGE>

(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.

                                        31
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

                       2001 CONSOLIDATED FINANCIAL REPORT

                                        32
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

                                    CONTENTS

<Table>
<Caption>
                                                                PAGE(S)
                                                               ---------
<S>                                                            <C>
AUDITOR'S REPORT ON THE FINANCIAL STATEMENTS................   34

FINANCIAL STATEMENTS
     Consolidated balance sheets............................   35 - 36
     Consolidated statements of income......................   37
     Consolidated statements of stockholders' equity........   38
     Consolidated statements of cash flows..................   39 - 40
     Notes to consolidated financial statements.............   41 - 48
</Table>

                                        33
<PAGE>

                    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, 2001
and March 31, 2001, and the related consolidated statements of income,
stockholders' equity and cash flows for the nine month period ended December 31,
2001 and the years ended March 31, 2001 and 2000. 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, 2001 and March 31, 2001, and
the consolidated results of their operations and their cash flows for the nine
month period ended December 31, 2001 and the years ended March 31, 2001 and
2000, in conformity with accounting principles generally accepted in the United
States of America.

                                          HAUSSER + TAYLOR LLP

Cleveland, Ohio
February 22, 2002

                                        34
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                              DECEMBER 31,    MARCH 31,
                                                                  2001           2001
                                                              ------------   ------------
<S>                                                           <C>            <C>
                           ASSETS

CURRENT ASSETS
  Cash and equivalents......................................  $ 22,035,924   $ 18,288,814
  Accounts receivable -- trade..............................     6,006,622      7,846,469
  Inventories...............................................       290,481        307,195
  Other, net................................................       474,411        161,819
                                                              ------------   ------------
       Total current assets.................................    28,807,438     26,604,297
PROPERTY AND EQUIPMENT, at cost
  Land......................................................       222,822        222,822
  Oil and gas properties (successful efforts)...............   121,195,745    108,466,905
  Gathering systems.........................................    16,411,433     16,092,838
  Vehicles..................................................     2,249,507      1,986,671
  Furniture and fixtures....................................       748,974        659,103
  Building and improvements.................................     1,862,382      1,847,463
                                                              ------------   ------------
                                                               142,690,863    129,275,802
  Less accumulated depreciation, depletion, amortization and
     impairment.............................................    29,442,909     24,032,646
                                                              ------------   ------------
                                                               113,247,954    105,243,156
OTHER ASSETS, net...........................................     2,734,966      3,505,711
                                                              ------------   ------------
TOTAL ASSETS................................................  $144,790,358   $135,353,164
                                                              ============   ============
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        35
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                              DECEMBER 31,    MARCH 31,
                                                                  2001           2001
                                                              ------------   ------------
<S>                                                           <C>            <C>
            LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
  Current portion of long-term debt.........................  $         --   $    557,400
  Accounts payable..........................................     3,395,272      3,012,992
  Accrued expenses..........................................     6,906,337      6,081,521
  Billings in excess of costs on uncompleted contracts......     2,062,094        877,281
                                                              ------------   ------------
       Total current liabilities............................    12,363,703     10,529,194
LONG-TERM DEBT, net of current portion
  Affiliates................................................    10,000,000     10,000,000
  Non-affiliates............................................    57,000,000     57,166,626
                                                              ------------   ------------
                                                                67,000,000     67,166,626
ACCRUED PLUGGING LIABILITY..................................       367,394        638,877
DEFERRED INCOME TAXES.......................................     5,680,027      3,066,200
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
  Series A, 6% Noncumulative Convertible Preferred stock,
     par value $.01 per share; 563,270 shares authorized;
     73,096 issued and outstanding (aggregate liquidation
     value of $730,960).....................................           731            731
  Series B, Cumulative Convertible Preferred stock, par
     value $.01 per share; 625,000 shares authorized;
     232,864 issued and outstanding (aggregate liquidation
     value oft $2,328,640)..................................         2,329          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 and 15,208,031 issued and outstanding.......       152,080        152,080
  Additional paid-in capital................................    50,213,422     50,213,422
  Retained earnings.........................................     8,431,042      3,583,705
  Accumulated other comprehensive income....................       579,630             --
                                                              ------------   ------------
       Total stockholders' equity...........................    59,379,234     53,952,267
                                                              ------------   ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................  $144,790,358   $135,353,164
                                                              ============   ============
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        36
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF INCOME

<Table>
<Caption>
                                                         NINE MONTH
                                                        PERIOD ENDED   YEAR ENDED    YEAR ENDED
                                                        DECEMBER 31,    MARCH 31,     MARCH 31,
                                                            2001          2001          2000
                                                        ------------   -----------   -----------
<S>                                                     <C>            <C>           <C>
REVENUE
  Oil and gas production..............................  $22,851,489    $29,399,487   $ 8,223,202
  Drilling revenues...................................    1,795,047      5,710,640     4,375,922
  Well operating, gathering and other.................    7,474,679     10,425,066     3,040,547
                                                        -----------    -----------   -----------
                                                         32,121,215     45,535,193    15,639,671
COSTS AND EXPENSES
  Oil and gas production expenses.....................    6,399,658      9,071,659     3,572,027
  Drilling costs......................................    1,990,415      4,758,722     3,454,287
  Well operating, gathering and other.................    4,061,170      5,306,277     1,573,963
  General and administrative expenses.................    2,725,611      3,011,233     1,492,000
  Depreciation, depletion, amortization, impairment
     and other........................................    6,330,099      8,032,873     2,402,800
                                                        -----------    -----------   -----------
                                                         21,506,953     30,180,764    12,495,077
                                                        -----------    -----------   -----------
INCOME FROM OPERATIONS................................   10,614,262     15,354,429     3,144,594
OTHER INCOME (EXPENSE)
  Interest income.....................................      420,226        724,367       162,413
  Other...............................................           --             --        62,548
  Interest expense....................................   (3,190,118)    (6,620,152)   (2,057,739)
                                                        -----------    -----------   -----------
                                                         (2,769,892)    (5,895,785)   (1,832,778)
                                                        -----------    -----------   -----------
INCOME BEFORE PROVISION FOR INCOME TAXES..............    7,844,370      9,458,644     1,311,816
PROVISION FOR INCOME TAXES............................    2,496,376      2,700,000            --
                                                        -----------    -----------   -----------
NET INCOME............................................  $ 5,347,994    $ 6,758,644   $ 1,311,816
                                                        ===========    ===========   ===========
NET INCOME APPLICABLE TO COMMON STOCK (after dividends
  on cumulative Preferred Stock of $174,647 $232,864
  and $232,864, respectively).........................  $ 5,173,347    $ 6,525,780   $ 1,078,952
                                                        ===========    ===========   ===========
NET INCOME PER SHARE (basic and diluted)..............  $      0.34    $      0.46   $      0.21
                                                        ===========    ===========   ===========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        37
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

  NINE MONTH PERIOD ENDED DECEMBER 31, 2001 AND YEARS ENDED MARCH 31, 2001 AND
                                      2000
<Table>
<Caption>
                                                 SERIES A           SERIES B
                                              PREFERRED STOCK   PREFERRED STOCK        COMMON STOCK        ADDITIONAL
                                              ---------------   ----------------   ---------------------     PAID-IN
                                              SHARES   AMOUNT   SHARES    AMOUNT     SHARES      AMOUNT      CAPITAL
                                              ------   ------   -------   ------   ----------   --------   -----------
<S>                                           <C>      <C>      <C>       <C>      <C>          <C>        <C>
BALANCE, MARCH 31, 1999.....................  73,816    $738    232,864   $2,329    4,556,814   $ 45,568   $21,914,939
  Net income................................     --       --         --      --            --         --            --
  Shares converted and other transactions...   (720)      (7)        --      --           767          8            (1)
  Dividends on Series B Preferred stock
    ($1.00 per share).......................     --       --         --      --            --         --            --
  Issuance of common stock..................     --       --         --      --     1,042,125     10,421     4,359,636
                                              ------    ----    -------   ------   ----------   --------   -----------
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
    ($1.00 per share).......................     --       --         --      --            --         --            --
  Issuance of common stock..................     --       --         --      --     9,608,325     96,083    23,938,848
                                              ------    ----    -------   ------   ----------   --------   -----------
BALANCE, MARCH 31, 2001.....................  73,096     731    232,864   2,329    15,208,031    152,080    50,213,422
  Net income................................     --       --         --      --            --         --            --
  Derivative mark-to-market, net of taxes...     --       --         --      --            --         --            --
    Total comprehensive income..............
  Dividends on Series B Preferred stock
    ($.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
                                              ======    ====    =======   ======   ==========   ========   ===========

<Caption>
                                                             ACCUMULATED
                                               RETAINED         OTHER           TOTAL
                                               EARNINGS     COMPREHENSIVE   STOCKHOLDERS'
                                               (DEFICIT)       INCOME          EQUITY
                                              -----------   -------------   -------------
<S>                                           <C>           <C>             <C>
BALANCE, MARCH 31, 1999.....................  $(4,021,027)    $     --       $17,942,547
  Net income................................    1,311,816           --         1,311,816
  Shares converted and other transactions...           --           --                --
  Dividends on Series B Preferred stock
    ($1.00 per share).......................     (232,864)          --          (232,864)
  Issuance of common stock..................           --           --         4,370,057
                                              -----------     --------       -----------
BALANCE, MARCH 31, 2000.....................   (2,942,075)          --        23,391,556
  Net income................................    6,758,644           --         6,758,644
  Dividends on Series B Preferred stock
    ($1.00 per share).......................     (232,864)          --          (232,864)
  Issuance of common stock..................           --           --        24,034,931
                                              -----------     --------       -----------
BALANCE, MARCH 31, 2001.....................    3,583,705           --        53,952,267
  Net income................................    5,347,994                      5,347,994
  Derivative mark-to-market, net of taxes...           --      579,630           579,630
    Total comprehensive income..............                                   5,927,624
  Dividends on Series B Preferred stock
    ($.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
                                              ===========     ========       ===========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                        38
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                        NINE MONTH
                                                       PERIOD ENDED   YEAR ENDED    YEAR ENDED
                                                       DECEMBER 31,   MARCH 31,     MARCH 31,
                                                           2001          2001          2000
                                                       ------------   ----------   ------------
<S>                                                    <C>            <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net income.........................................  $  5,347,994   $6,758,644   $  1,311,816
  Adjustments to reconcile net income to net cash
     provided by operating activities:
     Depreciation, depletion, amortization,
       impairment and other..........................     6,330,099    8,032,873      2,402,800
     (Gain) Loss on sale of property and equipment...       (28,541)      26,743
     Deferred income taxes...........................     2,496,376    2,700,000
     Stock bonus.....................................            --       34,931
     Change in:
       Accounts receivable...........................     2,647,297     (438,202)      (826,595)
       Inventories and other current assets..........      (158,034)     279,424       (104,776)
       Other assets, net.............................        16,138      197,783        289,815
       Accounts payable and accrued expenses.........       712,644    3,687,979        259,213
       Billings in excess of costs on uncompleted
          contracts..................................     1,184,813      309,225        568,056
                                                       ------------   ----------   ------------
          Total adjustments..........................    13,200,792   14,830,756      2,588,513
                                                       ------------   ----------   ------------
          Net cash provided by operating
            activities...............................    18,548,786   21,589,400      3,900,329

CASH FLOWS FROM INVESTING ACTIVITIES
  Purchases of property and equipment................   (13,801,713)  (7,136,990)    (2,238,712)
  Proceeds on sale of property and equipment.........       224,720       34,535             --
  Acquisition of North Coast Energy Eastern..........            --           --    (69,704,000)
  Acquisition of net assets of Environmental
     Exploration.....................................            --           --     (3,500,000)
                                                       ------------   ----------   ------------
          Net cash used by investing activities......   (13,576,993)  (7,102,455)   (75,442,712)
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                        39
<PAGE>

                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

               CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

<Table>
<Caption>
                                                        NINE MONTH
                                                       PERIOD ENDED    YEAR ENDED    YEAR ENDED
                                                       DECEMBER 31,    MARCH 31,      MARCH 31,
                                                           2001           2001          2000
                                                       ------------   ------------   -----------
<S>                                                    <C>            <C>            <C>
CASH FLOWS FROM FINANCING ACTIVITIES
  Borrowings under long-term credit facilities.......  $        --    $ 63,000,000   $ 2,000,000
  Proceeds from issuance of long-term debt...........           --              --    72,595,691
  Repayment of long-term debt -- affiliates..........           --     (38,500,000)           --
  Payments on long-term debt.........................     (724,026)    (26,022,755)   (2,940,432)
  Cash paid for deferred financing fees..............           --        (649,198)           --
  Net proceeds from issuance of common stock.........           --              --     4,370,057
  Distributions and dividends........................     (500,657)       (232,864)     (232,864)
                                                       -----------    ------------   -----------
       Net cash (used) provided by financing
          activities.................................   (1,224,683)     (2,404,817)   75,792,452
                                                       -----------    ------------   -----------
INCREASE IN CASH AND EQUIVALENTS.....................    3,747,110      12,082,128     4,250,069
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD..........   18,288,814       6,206,686     1,956,617
                                                       -----------    ------------   -----------
CASH AND EQUIVALENTS AT END OF PERIOD................  $22,035,924    $ 18,288,814   $ 6,206,686
                                                       ===========    ============   ===========
Supplemental disclosures of cash flow information:
  Cash paid during the period for:
     Interest........................................  $ 3,556,283    $  5,943,446   $ 1,906,346
     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.
                                        40
<PAGE>

                   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, the acquisition of producing oil and gas
      properties, and the organization and management of oil and gas
      partnerships.

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 is
      not indicative of a full year (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 23 oil and gas drilling partnerships, which are
      accounted for under the proportional consolidation method, are reflected
      in the accompanying financial statements. The Company's ownership interest
      in these partnerships varies from 8% to 67%.

      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, and are
      a significant portion of, the cash and cash equivalents balances.

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, pipelines using the straight-line
      method over 10 to 25 years, vehicles, furniture and fixtures using
      accelerated methods over 3 to 15 years, 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 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 by the unit-of-production method based
      upon estimated proved developed reserves. To the extent that capitalized
      costs of groups of proved properties having similar characteristics exceed
      the estimated future net cash flows, the excess capitalized costs are
      written down to the present value of such amounts. Estimated future net
      cash flows are determined based primarily upon the estimated future proved
      reserves related to the Company's current proved properties and, to a
      lesser extent, certain future net cash flows related to operating and
      related fees due the Company related to its management of various
      partnerships. The Company follows Statement of Financial Accounting
      Standards ("SFAS") No. 121 which requires a
                                        41
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      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 not
      significant.

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. In the nine months ended December 31, 2001
      and the year ended March 31, 2001, oil and gas sales were increased by
      approximately $840,000 and reduced by approximately $3.9 million,
      respectively, for the effect of natural gas hedging activities. 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 -- The computation of basic and diluted earnings per
      share for the nine months ended December 31,2001 does not assume the
      conversion of the unconverted Series B Preferred stock because it was
      anti-dilutive. For the nine month period ended December 31, 2001 and the
      years ended March 31, 2001 and 2000, the conversion of Series A stock had
      the effect of increasing average outstanding shares by 33,624, 33,624 and
      16,847 shares, respectively. Assumed exercise of dilutive stock options
      had the effect of adding 3,705 and 3,645 shares to the average outstanding
      shares for 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 average outstanding shares by 76,321 shares and
      increased net income by approximately $58,000 for the years ended March
      31, 2001 and 2000. Assumed debt conversion of NUON's $24 million loan at
      the beginning of the year added approximately 400,000 common shares to the
      average outstanding shares and approximately $100,000 to income 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 15,208,031 and 15,245,360, 14,306,011 and
      14,419,601; and 5,084,434 and 5,577,602 for the nine month period ending
      December 31, 2001 and the years ended March 31, 2001 and 2000,
      respectively.

      Net income per share reported on a quarterly basis does not add up to the
      per share amount for the year due to the weighting of a large stock
      transaction in the first quarter of fiscal 2001.

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 continued ability to
      market drilling programs, the inherent risks of the search for,
      development of and production of oil and gas, the ability to sell oil and
      gas at prices which will provide attractive rates of return, 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.

                                        42
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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.

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.

M.    Reclassifications -- Certain reclassifications were made to prior period
      financial statement presentations to conform with current period
      presentations.

NOTE 2.  ACQUISITIONS

      On March 17, 2000, the Company acquired NCEE through a purchase of all of
      NCEE's outstanding capital stock from Belden & Blake Corporation ("BBC").
      NCEE owns oil and gas properties consisting of approximately 1,900 wells
      and in excess of 900 miles of natural gas gathering lines in West
      Virginia, Kentucky and Virginia. The acquisition was consummated pursuant
      to a Stock Purchase Agreement dated March 17, 2000 between the Company and
      BBC.

      The purchase price for the NCEE stock was $69.7 million including
      approximately $100,000 of acquisition costs. The acquisition was accounted
      for as a purchase and, accordingly, the operating results related to the
      acquisition are included in the Company's consolidated results of
      operations from the closing date of March 17, 2000.

NOTE 3.  DETAILS OF CURRENT LIABILITIES

      Accrued expenses consist of the following:

<Table>
<Caption>
                                                          DECEMBER 31,   MARCH 31,
                                                              2001          2001
                                                          ------------   ----------
<S>                                                       <C>            <C>
Production taxes........................................   $1,355,924    $1,635,696
Drilling Costs..........................................    3,414,318     2,054,740
Compensation............................................      625,330     1,179,103
Other Expenses..........................................    1,510,765     1,211,982
                                                           ----------    ----------
                                                           $6,906,337    $6,081,521
                                                           ==========    ==========
</Table>

                                        43
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      Billings in excess of costs on uncompleted contracts consist of the
      following:

<Table>
<Caption>
                                                     DECEMBER 31, 2001   MARCH 31, 2001
                                                     -----------------   --------------
<S>                                                  <C>                 <C>
Billings on uncompleted contracts..................     $2,062,094         $1,175,720
Costs incurred on uncompleted contracts............             --            298,439
                                                        ----------         ----------
                                                        $2,062,094         $  877,281
                                                        ==========         ==========
</Table>

      At December 31, 2001 and March 31, 2001, fourteen and seven wells,
      respectively, were in the process of being completed.

NOTE 4.  LONG-TERM DEBT

      Long-term debt consists of the following:

<Table>
<Caption>
                                                     DECEMBER 31, 2001   MARCH 31, 2001
                                                     -----------------   --------------
<S>                                                  <C>                 <C>
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
Other..............................................              --           724,026
                                                        -----------       -----------
                                                         67,000,000        67,724,026
Less current portion...............................              --           557,400
                                                        -----------       -----------
                                                        $67,000,000       $67,166,626
                                                        ===========       ===========
</Table>

      The Non-Negotiable Subordinated Promissory Note bears interest at the
      six-month LIBOR plus 2.3% or 4.2% and 7.8% at December 31, 2001 and March
      31, 2001, respectively. The weighted average interest rate was 4.9%, 9.0%
      and 8.7% for the nine-month period ended December 31, 2001, and the years
      ended March 31, 2001 and 2000, respectively. The note is subordinated to
      the Company's senior debt. NUON has the right to secure the indebtedness
      by a lien on Peake'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 $65,000,000 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, 2001
      and March 31, 2001, amounts outstanding under bank credit agreements bear
      interest at LIBOR plus 1.875% and 2%, respectively, or approximately 3.8%
      and 7.5%, respectively. The weighted average interest rate on bank
      borrowings was 4.7%, 8.7% and 8.4% for the nine-month period ended
      December 31, 2001 and the years ended March 31, 2001 and 2000,
      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, 2001, the
      Company's credit agreement restricts the Company from incurring additional
      debt or liens, prohibits dividends and distributions (except for
      distributions on the outstanding Preferred A and B shares), 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, 2001.

                                        44
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      Future maturities of long-term debt at December 31, 2001 are as follows:

<Table>
<S>                                                            <C>
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, a limited liability company organized under the
      laws of the Netherlands, 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 owns 86% of the Company's common shares at December 31, 2001,
      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 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.

                                        45
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      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 are entitled to receive,
      when, as and if declared by the Board of Directors, cash dividends at an
      annual rate of $1.00 per share, payable quarterly.

      In the event of any liquidation, dissolution or winding up of the Company,
      holders of shares of Series B Preferred stock are entitled to receive the
      liquidation preference of $10 per share, plus an amount equal to any
      accrued and unpaid dividends to the payment date, before any payment or
      distribution is made to the holders of common stock and Series A Preferred
      stock, as defined. After payment of the liquidation preference, the
      holders of such shares will not be entitled to any further participation
      in any distribution of assets by the Company.

      Generally, each outstanding share of Series B Preferred stock has no vote,
      however in certain instances required by Delaware General Corporation Law
      or by the certificate of designation, each share will be entitled to
      one-fifth vote, excluding shares held by the Company or any entity
      controlled by the Company, which shares shall have no voting rights. So
      long as any Series B Preferred stock is outstanding, the Company cannot,
      without the affirmative vote of the holders of at least 66 2/3 percent of
      all outstanding shares of Series B Preferred stock, voting separately as a
      class, (i) amend, alter or repeal any provision of the Company's Restated
      Certificate of Incorporation or Bylaws so as to affect adversely the
      relative rights, preferences, qualifications, limitations or restrictions
      of the Series B Preferred stock, (ii) authorize or issue, or increase the
      authorized amount of, any additional class or series of stock of the
      Corporation, or any security convertible into stock of such class or
      series, having rights senior to the Series B Preferred stock as to
      dividends or liquidation, or (iii) effect any reclassification of the
      Series B Preferred stock. Additionally, the Series A Preferred stock's
      certificate of designation restricts the ability to significantly modify
      the Company's capital structure where such modification could be at a
      detriment to the Series B Preferred stockholders.

      Whenever distributions on the Series B Preferred stock have not been paid,
      as defined, the number of directors of the Company may be increased, and
      the holders of the Series B will be entitled to elect such additional
      directors to the Board of Directors, as defined. Such voting right will
      terminate when all such distributions accrued and in default have been
      paid in full or set apart for payment, as defined. During the nine months
      ended December 31, 2001, the Company paid the regular quarterly dividends
      amounting to $174,647. In addition the Company paid all dividends in
      arrears, which amounted to $326,010. There were no dividends in arrears
      attributable to Series B Preferred as of December 31, 2001.

      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. The
      Company plans to exercise its option to redeem all Series B Preferred
      shares during 2002.

      There is no mandatory redemption or sinking fund obligation with respect
      to the Series B Preferred stock. In the event that the Company has failed
      to pay accrued dividends on the Series B Preferred stock, it may not
      redeem any of the outstanding shares of the Series B Preferred stock until
      all such accrued and unpaid distributions have been paid in full.

      The holders of Series B Preferred stock have the right, exercisable at
      their option, to convert any or all of such shares into 1.15 shares of
      common stock.

      During the nine month period ended December 31, 2001, the Company paid the
      normal quarterly dividends and all dividends that were in arrears.

                                        46
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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/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 shareholders 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 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 the nine-month period ending December 31,
      2001 and the years ending March 31, 2001 and 2000 are summarized as
      follows:

<Table>
<Caption>
                                                             OPTIONS        PRICE
                                                           OUTSTANDING      RANGE
                                                           -----------   -----------
<S>                                                        <C>           <C>
March 31, 1999...........................................     34,920     $3.90-$8.10
Options granted..........................................     30,715           $4.38
Options cancelled........................................     (3,500)          $8.10
                                                             -------
March 31, 2000...........................................     62,135     $3.90-$6.90
Options granted..........................................     60,000     $3.47-$3.99
Options cancelled........................................         --
                                                             -------
March 31, 2001...........................................    122,135     $3.47-$6.90
Options granted..........................................     60,000     $3.70-$4.38
Options cancelled........................................     23,384     $3.90-$6.90
                                                             -------
December 31, 2001........................................    158,751     $3.47-$6.88
                                                             =======
</Table>

      In the year ended March 31, 2000, the Company granted 20,000 options to a
      Company director with one-third of the shares vesting on April 1, 2000 and
      one-third vesting each year thereafter. In fiscal 2000, the Company also
      granted 5,000 options to a Director/Officer of the Company, 3,429 options
      to an executive officer and another 2,286 options to a key employee.

      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 shares vesting
      on April 1, 2001 and one-third vesting each year thereafter and 30,000
      options to an executive officer at $3.47 per share all of which vested
      upon grant.

                                        47
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      In the nine months ended December 31, 2001, the Company granted 35,000
      options 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
      vest one-half on each of May 7, 2002 and 2003.

      A summary of stock options outstanding and exercisable at December 31,
      2001 follows:

<Table>
<Caption>
                                                             OPTIONS       OPTION
EXERCISABLE AT DECEMBER 31, 2001 THROUGH:                  OUTSTANDING      PRICE
-----------------------------------------                  -----------   -----------
<S>                                                        <C>           <C>
March 19, 2003...........................................         58           $6.88
September 4, 2006........................................        360           $3.91
April 1, 2003............................................      6,667           $4.38
April 1, 2004............................................      6,666           $4.38
April 1, 2005............................................     13,334           $4.38
April 1, 2006............................................     16,666     $3.99-$4.38
October 18, 2009.........................................      5,000           $4.38
October 5, 2010..........................................     30,000           $3.47
October 6, 2011..........................................     35,000           $3.70
                                                             -------
                                                             113,751
Non vested options.......................................     45,000     $3.99-$4.38
                                                             -------
Total                                                        158,751
                                                             =======
</Table>

      Stock appreciation rights may be awarded by the Committee at the time or
      subsequent to the time of the granting of options. Stock appreciation
      rights awarded shall provide that the option holder shall have the right
      to receive an amount equal to 100% of the excess, if any, of the fair
      market value of the shares of common stock covered by the option over the
      option price payable, as defined. 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 in the nine month period ending
      December 31, 2001 and the years ending March 31, 2001 and 2000 consistent
      with the provisions of SFAS No. 123, the Company's net income per share
      would not change.

E.    Stock Bonus Plan

      The Company has a Key Employees Stock Bonus Plan ("the Bonus Plan") to
      provide key employees, as defined, with greater incentive to serve and
      promote the interests of the Company and its shareholders. The aggregate
      number of shares of common stock, which may be issued as bonuses, shall be
      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
      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

                                        48
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      in the Company's consolidated financial statements or tax returns. The
      provision for income taxes consisted of the following:

<Table>
<Caption>
                                          DECEMBER 31,
                                              2001        MARCH 31, 2001   MARCH 31, 2001
                                         --------------   --------------   --------------
<S>                                      <C>              <C>              <C>
Current provision......................    $   96,376       $       --       $       --
Deferred provision.....................     2,400,000        2,700,000               --
                                           ----------       ----------       ----------
     Total.............................    $2,496,376       $2,700,000       $       --
                                           ==========       ==========       ==========
</Table>

      Income taxes differed from the amount computed by applying the federal
      statutory rates to pretax book income as follows:

<Table>
<Caption>
                            DECEMBER 31, 2001    MARCH 31, 2001      MARCH 31, 2000
                            -----------------   -----------------   ----------------
                              AMOUNT      %       AMOUNT      %      AMOUNT      %
                            ----------   ----   ----------   ----   --------   -----
<S>                         <C>          <C>    <C>          <C>    <C>        <C>
Provision based on the
  statutory rate..........  $2,667,000   34.0   $3,216,000   34.0   $446,000    34.0
Tax effect of:
  Statutory depletion.....    (335,000)  (4.2)    (442,000)  (4.7)  (456,000)  (34.8)
  Other - net.............     164,376    2.0      (74,000)  (0.8)    10,000     0.8
                            ----------   ----   ----------   ----   --------   -----
     Total................  $2,496,376   31.8   $2,700,000   28.5   $     --      --
                            ==========   ====   ==========   ====   ========   =====
</Table>

      The components of the net deferred tax liability as of December 31, 2001
      and March 31, 2001 were as follows:

<Table>
<Caption>
                                                         DECEMBER 31,    MARCH 31,
                                                             2001          2001
                                                         ------------   -----------
<S>                                                      <C>            <C>
DEFERRED TAX LIABILITIES
  Property and equipment...............................  $(9,143,580)   $(5,916,000)
  Derivative mark to market............................     (340,420)            --
                                                         -----------    -----------
  Total deferred tax liabilities.......................   (9,484,000)    (5,916,000)
DEFERRED TAX ASSETS
  Alternative minimum tax credit carryforwards.........      524,000        524,000
  Net operating loss carryforwards.....................    1,895,000      1,340,000
  Statutory depletion carryforward.....................    1,199,000        864,000
  Other temporary differences..........................      217,000        178,800
                                                         -----------    -----------
       Total deferred tax assets.......................    3,835,000      2,906,800
                                                         -----------    -----------
     Net deferred tax liability........................  $(5,649,000)   $(3,009,200)
                                                         ===========    ===========
Current asset..........................................  $    31,027    $    57,000
Long-term liability....................................   (5,680,027)    (3,066,200)
                                                         -----------    -----------
     Net deferred tax liability........................  $(5,649,000)   $(3,009,200)
                                                         ===========    ===========
</Table>

      As of December 31, 2001, the Company had operating loss, percentage
      depletion and alternative minimum tax credit carryforwards of
      approximately $5,100,000, $3,800,000 and $524,000, respectively. The
      operating loss carryforwards begin to expire in 2012. 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

                                        49
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      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.  PROFIT SHARING PLAN

      The Company has a profit sharing plan that provides retirement and death
      benefits to participants and covers substantially all employees. Company
      contributions are discretionary and are allocated to the participants'
      accounts based upon their compensation and are subject to a graded vesting
      schedule which allows 20% vesting after two years of vesting service with
      an additional 20% vesting for each complete year of vesting service
      thereafter. Contributions are made in March each year and amounted to
      $120,000 and $75,000 in 2001 and 2000, respectively. The Plan was amended
      effective April 1, 2000, to permit the immediate participation of
      individuals who are employed by NCEE and to change the Plan's Trustee.

      NCE provides no significant post-retirement and/or post-employment
      benefits other than the profit sharing plan discussed above.

NOTE 8.  COMMITMENTS AND CONTINGENCIES

      North Coast Energy, Inc., as general partner of several limited
      partnerships, has committed to fund certain costs (primarily tangible well
      costs and saleslines additions) of the partnerships as they are incurred.
      At December 31, 2001, management estimates the commitment to fund such
      costs to be approximately $540,000. The commitment has since been funded.

      The Company has unlimited liability to third parties with respect to the
      operations of the partnerships it has sponsored and may be liable to
      limited partners for losses attributable to breach of fiduciary
      obligations. In certain partnerships, certain investors have participated
      as co-general partners in such partnerships. To make such investments more
      acceptable to potential investors (from a standpoint of risks to such
      investors), 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 or through limited partnerships sponsored by the
      Company.

      The Company's revenue is derived from oil and gas production and oil and
      gas related activities in the Appalachian Basin. Gas production revenues
      represented 93%, 91% and 92% of total oil and gas production revenues for
      the nine-month period ending December 31, 2001 and the years ended March
      31, 2001 and 2000, respectively. During the nine-month period ending
      December 31, 2001, two customers purchased 21% and 13% of the gas produced
      by the Company. During the years ended March 31, 2001 and 2000, two
      customers purchased 21% and 14% and 22% and 19%, respectively, of the gas
      produced by the Company.

      A significant portion of trade accounts receivable at December 31, 2001
      and March 31, 2001 was attributable to these purchasers.

                                        50
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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. Effective with
      May 2000 production, the Company entered into a natural gas hedge to
      lessen exposure to changes in natural gas prices that may affect a portion
      of its net production contracted to one large industrial customer. The
      hedge involved the use of a financial swap and fixes the Company's price
      at $3.51 per Mcf on 5,000 Mcf per day through December 2001. During 2001,
      the Company entered into the following costless collar arrangements:

<Table>
<Caption>
                                                    MONTHLY          PRICE/MCF
                                                    VOLUME       ------------------
                      TERM                            MCF        FLOOR      CEILING
-------------------------------------------------   -------      -----      -------
<S>                                                 <C>          <C>        <C>
July 1, 2001 to March 31, 2002...................   117,000      $4.10       $5.17
January 1, 2002 to December 31, 2002.............   130,000       3.34        4.77
November 1, 2002 to March 31, 2003...............    98,000       3.08        3.48
January 1, 2003 to December 31, 2003.............    98,000       3.33        4.45
January 1, 2003 to December 31, 2003.............   130,000       3.45        5.11
</Table>

      Gains or losses on the hedge relative to the market are recognized monthly
      as additions to or subtractions from oil and gas sales. To lessen its
      exposure to commodity price risk, NCE expects to continue to sell natural
      gas under fixed price contracts, on the spot market and to use financial
      hedging instruments to realize a fixed price on a portion of its
      production. The following table reflects the natural gas volumes and the
      weighted average prices under financial hedges and fixed price contracts
      at December 31, 2001:

<Table>
<Caption>
                                    FINANCIAL HEDGES (COLLARS)          FIXED PRICE
                                 ---------------------------------       CONTRACTS
                                                     ESTIMATED       ------------------
                                                 REALIZABLE PRICE            ESTIMATED
                                         NYMEX   -----------------           REALIZABLE
QUARTER ENDING                   MMCF    PRICE    FLOOR      CAP     MMCF      PRICE
--------------                   -----   -----   -------   -------   -----   ----------
<S>                              <C>     <C>     <C>       <C>       <C>     <C>
March 31, 2002.................    743  $2.56     $3.75     $4.82    1,315     $3.59
June 30, 2002..................    391   2.62      3.54      4.97    1,113      3.45
September 30, 2002.............    391   2.76      3.54      4.53    1,031      3.38
December 31, 2002..............    586   3.02      3.39      4.72      818      3.32
March 31, 2003.................    977   3.25      3.44      4.97      700      3.32
June 30, 2003..................    684   3.04      3.54      4.97      396      3.30
September 30, 2003.............    684   3.13      3.54      4.97      342      3.17
December 31, 2003..............    684   3.32      3.54      4.97      329      3.07
March 31, 2004.................     --     --        --        --      247      3.05
</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

                                        51
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      two years, thus reducing the impact of interest rate changes on future
      income. The following contracts were outstanding:

<Table>
<Caption>
                                                              LIBOR
                                              NOTIONAL        RATE         ALL-IN
                   TERM                        AMOUNT         FIXED      RATE FIXED
-------------------------------------------  -----------      -----      ----------
<S>                                          <C>              <C>        <C>
January 1, 2002 to December 31, 2002.......  $20,000,000       2.7%         4.6%
January 1, 2002 to December 31, 2003.......  $20,000,000       3.5%         5.4%
</Table>

      The mark-to-market amount associated with the two interest rate swap
      contracts was not material at December 31, 2001.

      On April 1, 2001, the Company adopted Financial Accounting Standards Board
      ("FASB") Statement of Financial Accounting Standards ("SFAS No. 133"),
      "Accounting for Derivative Instruments and Hedging Activities" (as
      amended). SFAS 133 establishes accounting and reporting standards for
      hedging activities and derivative instruments, including certain
      derivative instruments embedded in other contracts.

      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 of 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
      hedge 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 affect
      of a change in accounting principle. During the nine months ended December
      31, 2001, natural gas prices decreased and one hedge instrument expired.
      As a result, the liability at December 31, 2001 was eliminated along with
      the related deferred tax asset and a market-to-market asset of $920,050
      and a deferred tax liability of $340,420 have been recorded. As a result,
      accumulated other comprehensive income at December 31, 2001 is $579,630
      and total comprehensive income for the nine months ended December 31, 2001
      was $5,927,624.

      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. The
      Company does not require collateral on these financial instruments.

      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 at December 31, 2001 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.

                                        52
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      The carrying amounts and fair values of the Company's financial
      instruments are as follows:

<Table>
<Caption>
                                   DECEMBER 31, 2001            MARCH 31, 2001
                               -------------------------   -------------------------
                                CARRYING        FAIR        CARRYING        FAIR
                                 AMOUNT         VALUE        AMOUNT         VALUE
                               -----------   -----------   -----------   -----------
<S>                            <C>           <C>           <C>           <C>
Cash and cash equivalents....  $22,035,924   $22,035,924   $18,288,814   $18,288,814
Accounts receivable..........    6,006,622     6,006,622     7,846,469     7,846,469
Account payable..............    3,395,272     3,395,272     3,012,922     3,012,922
Long-term debt...............   67,000,000    67,000,000    67,724,026    67,724,026
Natural gas collars..........      920,050       920,050            --            --
</Table>

NOTE 11.  RELATED PARTY TRANSACTIONS

      A large portion of the Company's revenues, other than oil and gas
      production revenue, is generated from or a result from the organization
      and management of oil and gas partnerships sponsored by the Company. The
      Company believes that the terms of related party transactions are
      consistent with terms that could have been obtained from unaffiliated
      third parties.

      Accounts receivable from affiliates amounted to $985,559 and $308,381 at
      December 31, 2001 and March 31, 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. During the nine
      months ended December 31, 2001 and the years ended March 31, 2001 and
      2000, the Company acquired limited partnership interests in oil and gas
      drilling programs that it had sponsored at a cost of approximately
      $1,250,000, $676,000 and $90,000, respectively.

NOTE 12.  ACCOUNTING STANDARDS

      On October 1, 2000, the Company adopted the provisions of Staff Accounting
      Bulletin No. 101, "Revenue Recognition in Financial Statements" ("SAB
      101"). The adoption of SAB 101 did not have a material effect on the
      financial position or results of operations of the Company.

      On April 1, 2001, the Company adopted Financial Accounting Standards Board
      ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 133,
      "Accounting for Derivative Instruments and Hedging Activities" (as
      amended). SFAS 133 establishes accounting and reporting standards for
      hedging activities and derivative instruments, including certain
      derivative instruments embedded in other contracts (see note 10).

      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 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.

                                        53
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      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 the impact
      of these four SFAS will have a significant impact on its financial
      position and results of operations.

NOTE 13.  TRANSITION REPORTING

      The following table of consolidated financial data provides a nine-month
      comparison of the results of operations through December 31, 2001 (the
      transition period) and 2000. The 2000 transition period figures are
      unaudited and reflect all 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>
                                                              NINE MONTHS ENDED
                                                         ---------------------------
                                                         DECEMBER 31,   DECEMBER 31,
                                                             2001           2000
                                                         ------------   ------------
                                                                        (UNAUDITED)
<S>                                                      <C>            <C>
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..................    4,061,170      3,392,361
  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
OTHER INCOME (EXPENSE)
  Interest income......................................      420,226        399,267
  Other................................................           --          5,715
  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)...........  $ 5,173,347    $ 3,152,733
                                                         ===========    ===========
NET INCOME PER SHARE (basic and diluted)...............  $      0.34    $      0.22
                                                         ===========    ===========
</Table>

                                        54
<PAGE>
                   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,    MARCH 31,      MARCH 31,
                                             2001           2001           2000
                                         ------------   ------------   ------------
<S>                                      <C>            <C>            <C>
Proved oil and gas properties..........  $121,195,745   $108,466,905   $102,177,522
Accumulated depreciation, depletion,
  amortization and impairment..........   (24,069,473)   (19,681,628)   (14,432,570)
                                         ------------   ------------   ------------
Net capitalized costs..................  $ 97,126,272   $ 88,785,277   $ 87,744,952
                                         ============   ============   ============
</Table>

               COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

<Table>
<Caption>
                                         NINE MONTHS
                                            ENDED        YEAR ENDED     YEAR ENDED
                                         DECEMBER 31,    MARCH 31,      MARCH 31,
                                             2001           2001           2000
                                         ------------   ------------   ------------
<S>                                      <C>            <C>            <C>
Property acquisition costs.............   $1,259,000     $  937,592    $56,952,518
Exploration costs......................    1,351,000        299,452         86,812
Development costs......................    7,800,000      5,151,732      2,173,513
</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>
                                         PERIOD ENDED      YEARS ENDED MARCH 31,
                                         DECEMBER 31,   ---------------------------
                                             2001           2001           2000
                                         ------------   ------------   ------------
<S>                                      <C>            <C>            <C>
Oil and gas production.................  $22,851,489    $29,399,487    $ 8,223,202
Loss on sale of oil and gas
  properties...........................           --        (26,734)            --
Production costs.......................   (6,399,658)    (9,071,659)    (3,572,027)
Exploration expenses...................     (847,303)      (299,452)            --
Depreciation, depletion, amortization,
  impairment and other.................   (4,387,845)    (5,249,058)    (1,690,029)
                                         -----------    -----------    -----------
                                          11,216,683     14,752,584      2,961,146
Provision for income taxes.............    3,508,000      4,600,000        626,075
                                         -----------    -----------    -----------
Results of operations for oil and gas
  producing activities (excluding
  corporate overhead and financing
  costs)...............................  $ 7,708,683    $10,152,584    $ 2,335,071
                                         ===========    ===========    ===========
</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.

                                        55
<PAGE>
                   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)
                                                           ---------   -----------
<S>                                                        <C>         <C>
Balance, March 31, 1999..................................    425,200    52,521,000
  Extensions and discoveries.............................     45,900     6,483,000
  Purchase of reserves in place..........................    604,700    73,324,000
  Production.............................................    (31,000)   (2,947,000)
  Revisions of previous estimates........................    (23,400)   (4,513,000)
                                                           ---------   -----------
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
  Production.............................................    (82,000)   (6,404,000)
  Purchase of reserves in place..........................      8,800     1,857,000
  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
                                                           =========   ===========
PROVED DEVELOPED RESERVES
  March 31, 1999.........................................    322,700    41,214,000
  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
</Table>

                                        56
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

            STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

<Table>
<Caption>
                                          NINE MONTHS
                                             ENDED
                                         DECEMBER 31,      MARCH 31,       MARCH 31,
                                             2001            2001            2000
                                         -------------   -------------   -------------
<S>                                      <C>             <C>             <C>
Future cash inflows from sales of oil
  and gas (including transportation
  allowances)..........................  $ 481,414,000   $ 746,302,000   $ 372,429,000
Future production costs................   (159,398,000)   (205,754,000)   (137,203,000)
Future development costs...............    (19,755,000)    (19,492,000)    (13,417,000)
Future income tax expense..............    (90,319,000)   (155,951,000)    (66,169,000)
                                         -------------   -------------   -------------
Future net cash flows..................    211,942,000     365,105,000     155,640,000
Effect of discounting future net cash
  flows at 10% per annum...............   (133,520,000)   (236,774,000)    (87,320,000)
                                         -------------   -------------   -------------
Standardized measure of discounted
  future net cash flows................  $  78,422,000   $ 128,331,000   $  68,320,000
                                         =============   =============   =============
</Table>

                     CHANGES IN THE STANDARDIZED MEASURE OF
                        DISCOUNTED FUTURE NET CASH FLOWS

<Table>
<Caption>
                                          NINE MONTHS
                                             ENDED
                                         DECEMBER 31,      MARCH 31,       MARCH 31,
                                             2001            2001            2000
                                         -------------   -------------   -------------
<S>                                      <C>             <C>             <C>
Balance, beginning of period...........  $128,331,000    $ 68,320,000    $ 25,426,000
Extensions and discoveries.............     6,207,000      18,292,000       4,570,000
Purchase of reserves in place..........     1,145,000         724,000      60,482,000
Sales of oil and gas, net of production
  costs................................   (16,452,000)    (20,328,000)     (4,651,000)
Net changes in prices and production
  costs................................   (77,911,000)     62,374,000       1,477,000
Net changes in development costs.......      (263,000)     (6,075,000)     (1,820,000)
Revisions of previous quantity
  estimates............................    (3,876,000)     20,725,000      (3,497,000)
Sales of reserves in place.............       (16,000)             --              --
Net change in income taxes.............    21,400,000     (25,709,000)    (18,374,000)
Accretion of discount..................    18,284,000       9,712,000       3,586,000
Other..................................     1,573,000         296,000       1,121,000
                                         ------------    ------------    ------------
Balance, end of period.................  $ 78,422,000    $128,331,000    $ 68,320,000
                                         ============    ============    ============
</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 using a 10% 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,

                                        57
<PAGE>
                   NORTH COAST ENERGY, INC. AND SUBSIDIARIES

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      operating costs and development costs expected in the area of interest.
      The reserve quantities were reviewed by an independent petroleum
      engineering firm.

      The methodology and assumptions used in calculating the standardized
      measure are those required by SFAS No. 69. It is not intended to be
      representative of the fair market value of the Company's proved reserves.
      The valuation of revenues and costs 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.

                                        58