<PAGE>

                                    FORM 10-K

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

           [x]    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                  OF THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
                                       OR
           [ ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                  OF THE SECURITIES EXCHANGE ACT OF 1934

                           Commission File No. 0-20100

                           BELDEN & BLAKE CORPORATION
             (Exact name of registrant as specified in its charter)

              OHIO                                  34-1686642
 (State or other jurisdiction        (I.R.S. Employer Identification Number)
of incorporation or organization)

                               5200 STONEHAM ROAD
                            NORTH CANTON, OHIO 44720
               (Address of principal executive offices) (Zip Code)

       Registrant's telephone number, including area code: (330) 499-1660

        Securities registered pursuant to Section 12(b) of the Act: NONE

           Securities registered pursuant to Section 12(g) of the Act:

                         COMMON STOCK, WITHOUT 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 such
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. X
                            ---

         As of February 28, 2002, Belden & Blake Corporation had outstanding
10,314,035 shares of common stock, without par value, which is its only class of
stock. The common stock of Belden & Blake Corporation is not traded on any
exchange and, therefore, its aggregate market value and the value of shares held
by non-affiliates cannot be determined.

DOCUMENTS INCORPORATED BY REFERENCE

         None.

<PAGE>

         The information in this document includes forward-looking statements
that are made pursuant to Safe Harbor Provisions of the Private Securities
Litigation Reform Act of 1995. Statements preceded by, followed by or that
otherwise include the statements "should," "believe," "expect," "anticipate,"
"intend," "will," "continue," "estimate," "plan," "outlook," "may," "future,"
"projection," variations of these statements and similar expressions are
forward-looking statements. These forward-looking statements are based on
current expectations and projections about future events. Forward-looking
statements, and the business prospects of Belden & Blake Corporation (the
"Company") are subject to a number of risks and uncertainties which may cause
the Company's actual results in future periods to differ materially from the
forward-looking statements contained herein. These risks and uncertainties
include, but are not limited to, the Company's access to capital, the market
demand for and prices of oil and natural gas, the Company's oil and gas
production and costs of operation, results of the Company's future drilling
activities, the uncertainties of reserve estimates, general economic conditions,
new legislation or regulatory changes, changes in accounting principles,
policies or guidelines and environmental risks. These and other risks are
described in the Company's 10-K and 10-Q reports and other filings with the
Securities and Exchange Commission ("SEC").

PART I
------

Item 1.  BUSINESS
         --------

GENERAL

         Belden & Blake Corporation is a privately held company owned by TPG
Partners II L.P. ("TPG") and certain other investors. The Company is an
independent energy company engaged in producing oil and natural gas; exploring
for and developing oil and gas reserves; acquiring and enhancing the economic
performance of producing oil and gas properties; and marketing and gathering
natural gas for delivery to intrastate and interstate gas transmission
pipelines. The Company provides oilfield services to itself and third-party
customers through its Arrow Oilfield Service Company ("Arrow"). Until 1995, the
Company conducted business exclusively in the Appalachian Basin where it has
operated since 1942 through several predecessor entities. It is currently among
the largest exploration and production companies operating in the Appalachian
Basin in terms of reserves, acreage held and wells operated. In early 1995, the
Company commenced production and drilling operations in the Michigan Basin
through the acquisition of Ward Lake Drilling, Inc. ("Ward Lake"), an
independent energy company, which owns and operates oil and gas properties in
Michigan's lower peninsula. On March 17, 2000, the Company sold a subsidiary
which owned oil and gas properties in West Virginia and Kentucky. At December
31, 2001, the Company operated in Ohio, Pennsylvania, New York, Michigan,
Indiana and West Virginia.

         At December 31, 2001, the Company's net production was approximately
51.8 Mmcf (million cubic feet) of natural gas and 1,651 Bbls (barrels) of oil
per day. At that date, the Company owned interests in 6,262 gross (5,238 net)
productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with
proved reserves totaling 334 Bcf (billion cubic feet) of natural gas and 5.6
Mmbbl (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 $225 million at December 31, 2001. The weighted average prices
related to proved reserves at December 31, 2001 were $2.92 per Mcf (thousand
cubic feet) for natural gas and $17.85 per Bbl for oil. At December 31, 2001,
the Company operated approximately 5,723 wells, including wells operated for
third parties. At that date, the Company held leases on 1,185,538 gross
(1,053,286 net) acres, including 734,933 gross (643,574 net) undeveloped acres.
The Company owned and operated 1,610 miles of gas gathering systems with access
to the commercial and industrial gas markets of the northeastern United States
at December 31, 2001.



                                       1
<PAGE>

         The Company has a successful track record of reserve replacement and
growth through both drilling and acquisitions. Since its formation in 1992
through December 31, 2001, the Company has added approximately 438 Bcfe (billion
cubic feet of natural gas equivalent) of proved developed reserves through
drilling and acquisitions at an average cost of $0.81 per Mcfe (thousand cubic
feet of natural gas equivalent). This represented approximately 197% of the oil
and gas produced by the Company during that period.

         During 2001, the Company drilled 175 gross (149.0 net) wells at a
direct cost, including exploratory dry hole expense, of approximately $24.6
million for the net wells. The 2001 drilling activity added 22.9 Bcfe of proved
developed reserves at an average cost of $1.08 per Mcfe. The Company also made
production enhancements to existing wells during the year which increased proved
developed reserves by 4.3 Bcfe at an average cost of $0.51 per Mcfe.
Acquisitions of properties in 2001 added 1.9 Bcfe of proved developed reserves
at an average cost of $0.91 per Mcfe. Proved developed reserves added through
drilling, enhancements and acquisitions in 2001 represented approximately 130%
of production.

         The Company maintains its corporate offices at 5200 Stoneham Road,
North Canton, Ohio 44720. Its telephone number at that location is (330)
499-1660. Unless the context otherwise requires, all references herein to the
"Company" are to Belden & Blake Corporation, its subsidiaries and predecessor
entities.

SIGNIFICANT EVENTS

         During 2001, the Company benefited from high natural gas prices. To
take advantage of the high market prices, the Company locked-in natural gas
prices on over 12.6 Bcf of its natural gas production in 2001 by entering into
fixed price gas contracts and through financial gas hedging instruments. The
Company also locked-in natural gas prices on over 13.3 Bcf of its natural gas
production in 2002 and 10.7 Bcf of its production in 2003 by entering into fixed
price gas contracts and through financial gas hedging instruments. In January
2002, the Company monetized $22.7 million of these positions and entered into
additional gas hedging instruments for 2002. See Note 19 to the Consolidated
Financial Statements.

         In 2001, the Company executed a leasing and geophysical program that
resulted in acquiring over 100,000 acres and shooting over 100 miles of seismic
in the deeper, less developed Trenton Black River ("TBR") trend in the
Appalachian Basin. As of February 1, 2002, the Company had approximately 286,000
gross (198,000 net) acres under lease in the TBR trend area. The Company
believes this acreage and seismic program, coupled with recent strategic
alliances, has enhanced its position to explore the TBR. The Company plans
exploratory drilling on this acreage in 2002. In addition, the Company plans to
continue to shoot additional seismic and lease additional Trenton Black River
acreage in 2002.

         On June 29, 2001, the Company amended its $100 million revolving credit
facility ("the Revolver") from Ableco Finance LLC and Foothill Capital
Corporation. The amendment extended the Revolver's final maturity date to April
22, 2004, from August 23, 2002, increased the letter of credit sub-limit from
$20 million to $30 million and eliminated the effects of Statement of Financial
Accounting Standards No. (SFAS) 133, "Accounting for Derivative Instruments and
Hedging Activities," from financial covenant calculations.

         On March 17, 2000, the Company sold the stock of Peake Energy, Inc.
("Peake"), a wholly owned subsidiary which owned oil and gas properties in West
Virginia and Kentucky. The sale resulted in net proceeds of approximately $69.2
million, which were used to reduce bank debt. At the time of the sale, Peake
accounted for approximately 20% of the Company's production and approximately
20% of its proved oil and gas reserves.


                                       2
<PAGE>

         When gas prices declined sharply in 1998, the Company's previous
lenders reduced the Company's borrowing base from $170 million to $126 million
in January of 1999. The Company's outstanding borrowings at that time exceeded
the redetermined borrowing base by $28 million. The resulting liquidity shortage
forced the Company to cease virtually all drilling in 1999 and to dispose of
certain non-strategic businesses and properties to reduce the Company's debt.
These included the Company's oilfield supply business, Target Oilfield Pipe and
Supply Company ("TOPS"), Belden Energy Services Company ("BESCO"), the Company's
retail natural gas marketing outlet in Ohio, and various oil and gas properties
representing approximately 0.8 Bcfe of oil and gas reserves.

DESCRIPTION OF BUSINESS

OVERVIEW

         The Company conducts operations in the United States in one reportable
segment which is oil and gas exploration and production. The Company is actively
engaged in producing oil and natural gas; exploring for and developing oil and
gas reserves; acquiring and enhancing the economic performance of producing oil
and gas properties; and marketing and gathering natural gas for delivery to
intrastate and interstate gas transmission pipelines. The Company operates
exclusively in the Appalachian and Michigan Basins (a region which includes
Ohio, Pennsylvania, New York, Michigan, Indiana and West Virginia) where it is
one of the largest oil and gas companies in terms of reserves, acreage held and
wells operated.

         The Appalachian Basin is the oldest and geographically one of the
largest oil and gas producing regions in the United States. Although the
Appalachian Basin has sedimentary formations indicating the potential for oil
and gas reservoirs to depths of 30,000 feet or more, oil and natural gas is
currently produced primarily from shallow, highly developed blanket formations
at depths of 1,000 to 6,200 feet. Drilling completion rates of the Company and
others drilling in these formations historically have exceeded 90% with
production generally lasting longer than 20 years.

         The combination of long-lived production and high drilling completion
rates at these shallower depths has resulted in a highly fragmented, extensively
drilled, low technology operating environment in the Appalachian Basin. As a
result of this environment, there has been limited testing or development of the
formations below the existing shallow production in the Appalachian Basin. The
Company believes that there are significant exploration and development
opportunities in these 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.

         The Company currently holds approximately 286,000 gross (198,000 net)
leasehold acres and approximately 500 miles of seismic in the deeper, less
developed Trenton Black River formations in the Appalachian Basin and intends to
continue to lease additional acreage and shoot additional seismic. The Company
plans to drill 26 gross (11.9 net) wells in the TBR formations in 2002.

         The Company currently operates 90 coalbed methane ("CBM") wells in
Pennsylvania and holds leases on approximately 95,000 acres of CBM properties in
Pennsylvania and 37,000 acres of CBM properties in West Virginia. The Company
drilled 27 CBM wells in 2001 and plans to drill an additional 54 CBM wells in
2002.

         In January 1995, the Company purchased Ward Lake Drilling, Inc., a
privately held energy company headquartered in Gaylord, Michigan, and commenced
operations in the Michigan Basin. The Company's primary objective in acquiring
Ward Lake was to allow the Company to pursue exploration


                                       3
<PAGE>

and production opportunities in the Michigan Basin with an established operating
company that provided the critical mass to operate efficiently. Ward Lake
currently operates 780 wells producing approximately 37.5 Mmcf (18.9 Mmcf net)
of natural gas per day in Michigan.

         The Company's rationale for entering the Michigan Basin was based on
geologic and operational similarities to the Appalachian Basin, geographic
proximity to the Company's operations in the Appalachian Basin and proximity to
premium gas markets. Geologically, the Michigan Basin resembles the Appalachian
Basin with shallow blanket formations and deeper formations with greater reserve
potential. Operationally, economies of scale and cost containment are essential
to operating profitability. The operating environment in the Michigan Basin is
also highly fragmented with substantial acquisition opportunities.

         Most of the Company's production in the Michigan Basin is derived from
the shallow (700 to 2,000 feet) blanket Antrim Shale formation. Completion rates
for companies drilling to this formation have exceeded 90%, with production
often lasting as long as 20 years. The Michigan Basin also contains deeper
formations with greater reserve potential. The Company has also established
production from certain of these deeper formations through its drilling
operations. Because the production rate from Antrim Shale wells is relatively
low, cost containment is a crucial aspect of operations. In contrast to the
shallow, highly developed blanket formations in the Appalachian Basin, the
operating environment in the Antrim Shale is more capital intensive because of
the low natural reservoir pressures and the high initial water content of the
formation.

         The proximity of the Appalachian and Michigan Basins to large
commercial and industrial natural gas markets has generally resulted in premium
wellhead gas prices compared with the New York Mercantile Exchange's ("NYMEX")
price for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas
prices in the Company's market areas are typically ten to fifty cents per Mcf
higher than comparable NYMEX prices.

BUSINESS STRATEGY

         The Company seeks to increase shareholder value by increasing reserves,
production and cash flow through the exploration and development of the
Company's extensive acreage base; further improvement in profit margins through
operational efficiencies; and utilization of the Company's advanced technology
to enhance production and reserves discovered. The key elements of the Company's
current strategy are as follows:

-    MAINTAIN A BALANCED DRILLING PROGRAM. The Company's exploration and
     development activities focus on a well-balanced portfolio of development
     and exploratory drilling in both the shallow blanket formations and the
     deeper, potentially more prolific formations. The Company believes this
     portfolio approach, coupled with its extensive knowledge of its operating
     areas, allows the Company to enhance economic returns and minimize much of
     the geological risk associated with oil and gas exploration and
     development. The Company believes that there are significant exploration
     and development opportunities in the less developed or deeper formations in
     the Appalachian and Michigan Basins and in the shallow coalbed methane
     formations in western Pennsylvania. The Company has identified numerous
     development and exploratory drilling locations in the deeper formations of
     these Basins, such as the Trenton Black River, and has established a
     substantial leasehold position overlying potentially productive coalbed
     methane formations in western Pennsylvania. In 2002, the Company plans to
     spend approximately 60% of its drilling capital expenditures on shallow
     blanket formations and approximately 40% of its drilling capital
     expenditures on deeper, potentially more prolific prospects.


                                       4
<PAGE>

-    IMPROVE THE COMPANY'S FINANCIAL POSITION. At December 31, 2001, the Company
     had a deficit in shareholders' equity of $27.3 million. The Company may
     sell additional non-strategic assets and use the proceeds, along with a
     portion of its available cash flow, to reduce its debt burden and enhance
     liquidity. The Company may also attempt to restructure portions of its
     existing debt to further reduce the amount of debt outstanding.

-    UTILIZE ADVANCED TECHNOLOGY. The combination of long-lived production and
     high drilling completion rates at the shallow depths has resulted in a
     highly fragmented, extensively drilled, low technology operating
     environment in the Appalachian and Michigan Basins. The Company has applied
     more advanced technology, including 3-D seismic, horizontal drilling,
     advanced fracturing techniques and production enhancement technologies to
     improve drilling completion rates, reserves discovered per well, production
     rates, reserve recovery rates and total economics in its operating areas.

-    IMPROVE PROFIT MARGINS. To become one of the most efficient operators in
     the Appalachian and Michigan Basins, the Company strives to improve its
     profit margins on production from existing and acquired properties through
     advanced production technologies, operating efficiencies and mechanical
     improvements. Through its production field offices, the Company reviews its
     properties, especially newly acquired properties, to determine what actions
     can be taken to reduce operating costs and/or improve production. The
     Company strives to control field level costs through improved operating
     practices such as computerized production scheduling and the use of
     hand-held computers to gather field data. On acquired properties, further
     efficiencies may be realized through improvements in production scheduling
     and reductions in oilfield labor. Actions that may be taken to improve
     production include modifying surface facilities, redesigning downhole
     equipment and recompleting existing wells.

-    EVALUATE POTENTIAL ACQUISITIONS. The Company may seek to acquire properties
     that complement its operations, provide exploration and development
     opportunities and potentially provide superior returns on investment.

OIL AND GAS OPERATIONS AND PRODUCTION

         Operations. The Company operates 91% of the wells in which it holds
working interests. It seeks to maximize the value of its properties through
operating efficiencies associated with economies of scale and through operating
cost reductions, advanced production technology, mechanical improvements and/or
the use of deliverability enhancement techniques.

         The Company currently maintains production field offices in Ohio,
Pennsylvania, New York and Michigan. Through these offices, the Company reviews
its properties to determine what action can be taken to reduce operating costs
and/or improve production.

         The Company has also provided its own oilfield services for more than
30 years in order to assure quality control and operational and administrative
support to its exploration and production operations. Arrow, the Company's
service division, provides the Company and third-party customers with necessary
oilfield services such as well workovers, well completions, brine hauling and
disposal and oil trucking.

         The Company currently operates approximately 1,610 miles of natural gas
gathering lines in Ohio, Pennsylvania, New York and Michigan which are connected
directly to various intrastate and interstate natural gas transmission systems.
The interconnections with these pipelines afford the Company potential marketing
access to numerous gas markets.



                                       5
<PAGE>


         Production, Sales Prices and Costs. The following table sets forth
certain information regarding the Company's net oil and natural gas production,
revenues and expenses for the years indicated:


<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                     ------------------------------------------------------------------------
                                        1997          1998            1999            2000           2001
                                     -----------   ------------    -----------     -----------    -----------
<S>                                    <C>            <C>            <C>             <C>            <C>
PRODUCTION
   Gas (Mmcf)                            27,213         30,140         26,988          20,037         18,541
   Oil (Mbbl)                               753            768            713             592            646
   Total production (Mmcfe)              31,734         34,750         31,267          23,591         22,415

AVERAGE PRICE
   Gas (per Mcf)                         $ 2.65         $ 2.57         $ 2.50          $ 3.17         $ 4.34
   Oil (per Bbl)                          18.10          12.61          16.57           27.29          23.04
   Mcfe                                    2.70           2.51           2.54            3.38           4.26

AVERAGE COSTS (PER Mcfe)
   Production expense                      0.68           0.68           0.70            0.89           1.01
   Production taxes                        0.10           0.09           0.10            0.10           0.11
   Depletion                               1.21           1.66           0.92            0.77           0.91
OPERATING MARGIN (PER Mcfe)                1.92           1.74           1.74            2.39           3.14
</TABLE>

Mmcf - Million cubic feet   Mmcfe - Million cubic feet equivalent   Bbl - barrel

Mbbl - Thousand barrels     Mcf - Thousand cubic feet

Operating margin (per Mcfe) - average price less production expense and
production taxes


         The following table sets forth certain information regarding the
Company's net oil and natural gas production, revenues and expenses for the
years indicated excluding Peake. See Note 3 to the Consolidated Financial
Statements:

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                     ------------------------------------------------------------------------
                                        1997          1998            1999            2000           2001
                                     -----------   ------------    -----------     -----------    -----------
<S>                                   <C>            <C>            <C>             <C>            <C>
PRODUCTION
   Gas (Mmcf)                            22,882         24,495         21,515          18,882         18,541
   Oil (Mbbl)                               658            686            642             576            646
   Total production (Mmcfe)              26,828         28,613         25,367          22,339         22,415

AVERAGE PRICE
   Gas (per Mcf)                         $ 2.57         $ 2.48         $ 2.50          $ 3.20         $ 4.34
   Oil (per Bbl)                          18.04          12.57          16.51           27.36          23.04
   Mcfe                                    2.63           2.43           2.54            3.41           4.26

AVERAGE COSTS (PER Mcfe)
   Production expense                      0.70           0.69           0.74            0.90           1.01
   Production taxes                        0.07           0.05           0.07            0.09           0.11
   Depletion                               1.23           1.71           0.98            0.77           0.91
OPERATING MARGIN (PER Mcfe)                1.86           1.69           1.73            2.42           3.14
</TABLE>

Mmcf - Million cubic feet   Mmcfe - Million cubic feet equivalent   Bbl - barrel

Mbbl - Thousand barrels     Mcf - Thousand cubic feet

Operating margin (per Mcfe) - average price less production expense and
production taxes




                                       6
<PAGE>


EXPLORATION AND DEVELOPMENT

         The Company's exploration and development activities include
development and exploratory drilling in both the highly developed or blanket
formations and the less developed formations of the Appalachian and Michigan
Basins. The Company's 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 has an extensive
inventory of acreage on which to conduct its exploration and development
activities.

         In 2001, the Company drilled 145 gross (133.6 net) wells to highly
developed or shallow blanket formations in its operating area at a direct cost
of approximately $21.1 million, including exploratory dry hole expense, for the
net wells. The Company also drilled 30 gross (15.4 net) wells to less developed
and deeper formations in 2001 at a direct cost of approximately $3.5 million,
including exploratory dry hole expense, for the net wells. The result of this
drilling activity is shown in the table on page 11.

         In 2002, the Company expects to spend approximately $26.6 million,
including exploratory dry hole expense, on development and exploratory drilling
of approximately 155 gross (114.6 net) wells. In 2002, the Company plans to
spend approximately 60% of its drilling capital expenditures on shallow blanket
formations and approximately 40% of its drilling capital expenditures on deeper,
potentially more prolific prospects.

         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
program profile.

         Highly Developed or Blanket Formations. In general, the highly
developed or blanket formations found in the Appalachian and Michigan Basins are
widespread in extent and hydrocarbon accumulations are not dependent upon local
stratigraphic or structural trapping. Drilling completion rates of the Company
and others drilling these formations historically have exceeded 90%. The
principal risk of such wells is uneconomic recoverable reserves.

         The Company is a pioneer in coalbed methane development and production
in Pennsylvania, presently operating 90 coalbed methane gas wells in Indiana and
Fayette counties. CBM wells in this area range in depth from 1,200 to 1,500 feet
and typically encounter three to six unmined coal seams.

         In September 2001, the Company acquired its partner's 40% working
interest in the Blacklick CBM field giving the Company 100% ownership of this
CBM project. With approximately 95,000 CBM acres currently under lease in
Pennsylvania and 37,000 acres in West Virginia, the Company believes the CBM
will contribute significantly to its drilling portfolio. The Company plans to
drill 54 CBM wells in 2002 including seven exploratory wells to test three new
areas in southwestern Pennsylvania.

         The Antrim Shale formation, the principal shallow blanket formation in
the Michigan Basin, is characterized by high formation water production in the
early years of a well's productive life with water production decreasing over
time. Antrim Shale wells typically produce at rates of 100 Mcf to 125 Mcf per
day for several years, with modest declines thereafter. Gas production often
increases in the early years, as the producing formation becomes less water
saturated. Average well lives are 20 years or more. The Company plans to drill
50 gross (33.7 net) wells to the Antrim Shale formation in 2002, including 15
wells on a 2,500 acre undeveloped lease acquired in January 2002. This lease
includes 29 Antrim drill sites and has proved undeveloped reserves of 10.4 Bcfe
which are not included in the Company's December 31, 2001 reserves.


                                       7
<PAGE>

         Certain typical characteristics of the highly developed or blanket
formations targeted by the Company are described below:




                                         Range of Average      Range of Average
                                           Drilling and         Gross Reserves
                      Range of Well      Completion Costs        per Completed
                         Depths              per Well                 Well
                   ----------------   ---------------------    ----------------
                      (in feet)             (in thousands)        (in Mmcfe)
Ohio:
   Clinton           3,000 -  5,500      $     125 - 185           80 -  150
Pennsylvania:
   Coalbed Methane   1,200 -  1,500            125 - 150          150 -  250
   Clarendon         1,100 -  2,000             45 -  55           30 -   50
   Medina            5,000 -  6,200            170 - 210          150 -  300
New York:
   Medina            3,000 -  5,000            100 - 150           75 -  300
Michigan:
   Antrim              700 -  2,000            190 - 240          400 -  600


         Deeper or Less Developed Formations. The Appalachian Basin has
productive and potentially productive sedimentary formations to depths of 30,000
feet or more, but the combination of long-lived production and high drilling
completion rates in the shallow formations has curbed the development of the
deeper formations in the basin. The Company believes it possesses the
technological expertise and the acreage position needed to explore the deeper
formations in a cost effective manner.

         The Trenton Black River formations have received significant attention
recently in the Appalachian Basin. Based on historical information available in
public records, wells completed in the TBR have reserves in the range of 1.0 to
2.5 Bcf of natural gas per well. With significant discoveries by other operators
in south-central New York and in central West Virginia, the Company believes the
potential exists for numerous opportunities in the Company's existing areas of
operations. While expected geologic conditions and gas shows were encountered in
all tests which the Company has undertaken in the TBR since 1998, economic
production has not been established to date.

         On June 29, 2001, the Company and Triana Energy, LLC ("Triana"), a West
Virginia oil and gas exploration company, entered into an exploration agreement
and a joint operating agreement ("JOA"). Pursuant to the JOA, Triana will manage
the exploration of the Oriskany and Trenton Black River formations on certain
properties in which the Company owns the leasehold working interest in
Pennsylvania and New York. It is anticipated that the Company's contribution of
its leasehold acreage coupled with the experience and professional skills
contributed by Triana should enhance the Company's drilling program with respect
to these properties and formations. Triana will manage all exploration and
drilling activities performed on the properties covered by this agreement. The
Company will be the operator following the completion of the wells. This
agreement is in effect until June 29, 2006.

         The Company has also entered into several exploration agreements with
other industry participants to jointly explore and develop the TBR in areas of
New York and Ohio.


                                       8
<PAGE>
         In 2001, the Company implemented a major leasing and geophysical
program in the TBR that resulted in acquiring over 100,000 additional acres and
more than 100 miles of additional seismic. As of February 1, 2002, the Company
had 286,000 gross (198,000 net) acres under lease in the TBR. The Company
believes this acreage and seismic program, coupled with recent strategic
alliances, has enhanced its position to explore the TBR.

         Exploration and drilling activities in the TBR formations, found at
depths ranging from 5,000 to 12,000 feet, are focused on testing many of the
currently identified prospects and confirming potential future drill sites. In
2002, the Company anticipates spending approximately $7.0 million to drill 26
gross (11.9 net) wells on TBR acreage. In addition, the Company plans to spend
$5.3 million to acquire additional acreage and seismic data in the TBR.

         The less developed formations in the Appalachian Basin also include the
Knox sequence of sandstones and dolomites, which includes the Rose Run,
Beekmantown and Trempealeau productive zones, at depths ranging from 2,500 feet
to 8,000 feet. The Company is an industry leader in the exploration,
development, and production from Knox formation wells. The geographical
boundaries of the Knox are generally well defined in Ohio with less definition
in New York and Pennsylvania. Through 2001, the Company had drilled 350 wells to
these formations. The Company's experience in the Knox demonstrates the
operational and economic potential of the deeper formations in the Appalachian
Basin.

         The Company began testing the Knox sequence in 1989 by selecting
certain wells that were targeted to be completed in the Clinton formation and
drilling them an additional 2,000 feet to 2,500 feet. In 1991, the Company began
using seismic analysis and other geophysical tools to select drilling locations
specifically targeting the Knox formations. Since 1991, the Company has added to
its technical staff to enhance its ability to develop drilling prospects in the
Knox and other less developed formations in the Appalachian Basin and the deeper
formations in the Michigan Basin.

         The Company's historical experience is that the average Knox well
produces 20% to 25% of its recoverable reserves in the first year of production
and approximately 50% of its recoverable reserves in the first three years with
a steady decline thereafter. Wells completed in the Knox formations have an
expected productive life ranging from 5 to 15 years.

         Productive Knox wells represented approximately 1.6% of the Company's
total productive wells at December 31, 2001. Production from Knox wells in 2001,
however, equaled 11% of the Company's total production on a Mcfe basis. The
Company plans to drill or participate in joint ventures to drill 12 gross (7.0
net) wells to the Knox formations in 2002.

         In addition to the TBR and Knox, the Company has also tested the
potentially more prolific Niagaran Carbonate, Onondaga Limestone and Oriskany
Sandstone formations.

         The Company is well positioned to exploit the undeveloped potential of
these deeper, less developed formations in the future because substantially all
of its leased acreage overlies deeper drilling locations in less developed
formations. In addition to its planned TBR and Knox drilling, the Company plans
to drill approximately 13 gross (8.0 net) wells to other deep formations in
2002.




                                       9
<PAGE>


         Certain typical characteristics of the less developed or deeper
formations targeted by the Company are described below:

<TABLE>
<CAPTION>

                                                                     Average Drilling Costs
                                                                     -------------------------     Average Gross
                                                    Range of Well        Dry        Completed      Reserves per
Formation                      Location                Depths            Hole          Well       Completed Well
------------------------  --------------------  -------------------  ---------  --------------    ---------------
                                                      (in feet)           (in thousands)            (in Mmcfe)
<S>                       <C>                     <C>       <C>          <C>         <C>         <C>
Trenton Black River
  Carbonates              PA, NY, WV, OH            5,000 - 12,000       $500         $1,000       1,000 - 2,500
Knox formations           OH, NY                    2,500 -  8,000        150            300         300 -   600
Niagaran Carbonate        MI                        4,500 -  5,500        300            600         900 - 1,500
Onondaga Limestone        PA                        4,000 -  5,500        150            250         200 - 1,500
Oriskany Sandstone        PA, NY                    4,500 -  7,000        200            350         300 - 1,000
</TABLE>








                                       10
<PAGE>


Drilling Results. The following table sets forth drilling results with respect
to wells drilled by the Company during the past five years:

<TABLE>
<CAPTION>
                                HIGHLY DEVELOPED OR BLANKET FORMATIONS (1)      LESS DEVELOPED OR DEEPER FORMATIONS (2)
                                ------------------------------------------   ---------------------------------------------
                                 1997      1998     1999    2000     2001    1997       1998       1999    2000       2001
                                 ----      ----     ----    ----     ----    ----       ----       ----    ----       ----
<S>                              <C>       <C>     <C>     <C>      <C>      <C>        <C>       <C>       <C>      <C>
Productive:
   Gross                           187       189     --       108      142      39(3)      29(4)       9(5)   17(6)      14(7)
   Net                           156.5     167.0     --      83.6    130.6    24.5       14.2        2.1     7.2        7.4
Dry:
   Gross                             7         3     --         3        3      28         28          9      21         16
   Net                             6.3       2.5     --       2.6      3.0    12.3       15.5        2.7    10.7        8.0
Reserves developed-net (Bcfe)     32.8      32.3     --      15.4     20.6     9.0        3.0        0.5     2.5        2.3
Approximate cost (in millions)  $ 31.2   $  28.4   $ --   $  11.5   $ 21.1   $ 9.3      $ 7.6      $ 0.8   $ 5.5      $ 3.5
</TABLE>


(1)      Consists of wells drilled to the Berea and Clinton Sandstone formations
         in Ohio, the Berea Sandstone, Devonian Brown Shale, Ravencliff
         Sandstone and Big Lime Limestone formations in West Virginia, the
         Clarendon, Upper Devonian, Coalbed Methane and Medina formations in
         Pennsylvania, the Medina Sandstone formation in New York, the New
         Albany Shale formation in Kentucky and the Antrim Shale formation in
         Michigan.

(2)      Consists of wells drilled to the Trenton Limestone and Knox formations
         in Ohio, the Niagaran and Dundee Carbonates in Michigan, the Oriskany
         Sandstone and Onondaga Limestone formations in Pennsylvania, and the
         Oriskany Sandstone, Onondaga Limestone, Trenton Black River Carbonates
         and Knox formations in New York.

(3)      Three additional wells which were dry in the Knox formations were
         subsequently completed in shallower formations.

(4)      Two additional wells which were dry in the Knox formations were
         subsequently completed in the shallower Clinton formation.

(5)      One additional well which was dry in the Knox formations was
         subsequently completed in shallower formations.

(6)      Three additional wells which were dry in the Knox formations were
         subsequently completed in the shallower Clinton formation.

(7)      Two additional wells which were dry in the Knox formations were
         subsequently completed in the shallower Clinton formation. One
         additional well which was dry in the Trenton Black River formation was
         subsequently completed in the shallower Clinton formation.







                                       11
<PAGE>


ACQUISITION OF PRODUCING PROPERTIES

         The Company employs a disciplined approach to acquisition analysis that
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. From 1992 through 1998, the Company
completed 46 acquisition transactions adding 235 Bcfe of proved developed
reserves for a combined purchase price allocated to proved developed reserves of
approximately $158 million. Despite several attractive opportunities, the
Company was unable to make any significant acquisitions in 1999 because of a
lack of available capital. During 2000, much of the Company's available capital
was used to pay down debt and restart its drilling program. In 2001, the Company
completed two acquisition transactions adding 1.9 Bcfe of proved developed
reserves for a combined purchase price allocated to proved developed reserves of
approximately $1.7 million. The primary transaction in 2001 was the purchase of
the remaining 40% working interest in a CBM project giving the Company 100%
ownership of the project. In 2002, the Company will primarily focus on its
drilling operations, and to a lesser extent, on the acquisition of producing
properties. The Company has the option under prior Section 29 tax credit
monetization transactions to purchase the remaining reserves at fair market
value in the first quarter of 2003.

DISPOSITION OF ASSETS

         On March 17, 2000, the Company sold the stock of Peake, a wholly-owned
subsidiary. The sale included substantially all of the Company's oil and gas
properties in West Virginia and Kentucky. The sale resulted in net proceeds of
approximately $69.2 million, which were used to reduce bank debt. At the time of
the sale, Peake represented approximately 20% of the Company's production and
proved oil and gas reserves.

         The Company regularly reviews its oil and gas properties for potential
disposition.

EMPLOYEES

         As of February 28, 2002, the Company had 391 full-time employees,
including 218 oil and gas exploration and production employees, 144 oilfield
service employees and 29 general and administrative employees. The Company's
management and technical staff in the categories above included 12 petroleum
engineers, 6 geologists and 3 geophysicists.

COMPETITION AND CUSTOMERS

         The oil and gas industry is highly competitive. Competition is
particularly intense with respect to the acquisition of producing properties,
acreage 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 competitors of the Company in oil and gas exploration, development
and production include major integrated oil and gas companies as well as
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 available to
the Company. Such competitors may be able to pay more for desirable prospects or
producing properties and to evaluate, bid for and purchase a greater number of
properties or prospects than the financial or personnel resources of the Company
will permit. The ability of the Company to add to its reserves in the future
will depend on the availability of capital, the ability to exploit its current
developed and undeveloped lease holdings and


                                       12
<PAGE>

the ability to select and acquire suitable producing properties and prospects
for future exploration and development.

         The only customer which accounted for 10% or more of the Company's
consolidated revenues during each of the years ended December 31, 2001 and 2000
was FirstEnergy Corp., sales to which amounted to $21.0 million and $21.6
million, respectively. No customer accounted for more than 10% of consolidated
revenues during the year ended December 31, 1999.

REGULATION

         Regulation of Production. In all states in which the Company is engaged
in oil and gas exploration and production, its activities are subject to
regulation. Such regulations may extend to requiring drilling permits, spacing
of wells, the prevention of waste and pollution, the conservation of oil and
natural gas and other matters. Such regulations may impose restrictions on the
production of oil and natural gas by reducing the rate of flow from individual
wells below their actual capacity to produce which could adversely affect the
amount or timing of the Company's revenues from such wells. Moreover, future
changes in local, state or federal laws and regulations could adversely affect
the operations and economics of the Company.

         Environmental Regulation. The Company's operations are subject to
numerous laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentration of various substances that can
be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas and impose substantial
liabilities for pollution resulting from the Company's operations. Management
believes the Company is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on the Company.

         Regulation of Sales and Transportation. The Federal Energy Regulatory
Commission regulates the transportation and sale for resale of natural gas in
interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. In the past, the federal government has regulated the prices
at which oil and natural gas could be sold. Currently, sales by producers of
natural gas and all sales of crude oil and condensate in natural gas liquids can
be made at uncontrolled market prices.




                                       13
<PAGE>


ITEM 2.  PROPERTIES
         ----------

OIL AND GAS RESERVES

         The following table sets forth the Company's proved oil and gas
reserves as of December 31, 1999, 2000 and 2001 determined in accordance with
the rules and regulations of the SEC. The estimates of proved reserves as of
December 31, 2001 and 2000 have been reviewed by Wright & Company, Inc.,
independent petroleum engineers. The estimates of proved reserves as of
December 31, 1999 have been reviewed by Ryder Scott Company Petroleum
Consultants, independent petroleum engineers. Proved reserves are the estimated
quantities of oil and gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

                                          December 31,
                               -----------------------------------
                                  1999         2000        2001
                               ----------   ---------   ----------
Estimated proved reserves
    Gas (Bcf)                     306.7       373.5        334.2
    Oil (Mbbl)                    6,699       8,653        5,587
    Bcfe                          346.9       425.4        367.7

         The higher reserves at December 31, 2000 were primarily due to the
higher gas price at that date compared to the gas prices at December 31, 1999
and 2001. 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 and the present value of such future net cash
flows as of December 31, 2001 determined in accordance with the rules and
regulations of the SEC.


Estimated future net cash flows (before income taxes)
attributable to estimated production during                   (in thousands)

    2002                                                         $  34,987
    2003                                                            16,497
    2004                                                            18,717
    2005 and thereafter                                            477,573
                                                                 ---------
Total                                                            $ 547,774
                                                                 =========
Present value before income taxes
(discounted at 10% per annum)                                    $ 224,988
                                                                 =========
Present value after income taxes
(discounted at 10% per annum)                                    $ 181,862
                                                                 =========



         Estimated future net cash flows represent estimated future gross
revenues from the production and sale of proved reserves, net of estimated 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.




                                       14
<PAGE>


         The following table sets forth the weighted average prices, including
fixed price contracts, for oil and gas utilized in determining the Company's
proved reserves.

                                      December 31,
                        ----------------------------------------
                           1999          2000           2001
                        ------------  ------------   -----------
Gas (per Mcf)              $ 2.61        $ 9.73        $ 2.92
Oil (per barrel)            23.53         23.41         17.85



         At December 31, 2001, as specified by the SEC, the prices for oil and
natural gas used in this calculation were regional cash price quotes on the last
day of the year except for volumes subject to fixed price contracts.
Consequently, these may not reflect the prices actually received or expected to
be received for oil and natural gas due to seasonal price fluctuations and other
varying market conditions. The prices shown above are weighted average prices
for the total reserves.

         The Company also calculated an alternative reserve case utilizing an
assumed NYMEX gas price of $3.50 per Mmbtu (million British thermal units) which
equated to a weighted average gas price of $3.80 per Mcf, including adjustments
for regional basis, Btu and fixed price contracts. The weighted average oil
price in the alternative case was $21.32 per Bbl. The alternative reserve case
used all of the same assumptions as the proved reserve case at year-end, other
than pricing. Total proved reserves calculated at the alternative prices were
403 Bcfe. Estimated future net cash flows from these reserves had a present
value (discounted at 10 percent) before income taxes of approximately $360
million.

IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS

         As described in Note 1 to the Consolidated Financial Statements, the
Company evaluates long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable. The
decline in oil and natural gas prices from 1997 to 1998 was significant and
negatively impacted the quantity and value of the Company's oil and gas
reserves. Given the impairment indicator at December 31, 1998, the Company
computed the expected future undiscounted cash flows, employing methods
consistent with those utilized to determine the estimated future net cash flows
from proved reserves discussed above. For those assets in which the sum of the
expected future undiscounted cash flows was less than the carrying amount, an
impairment loss was recognized for the difference between the fair value and the
carrying amount of the asset, with fair value determined based on discounted
cash flow analysis, sale of similar properties or recent offers for specific
assets. As a result of this evaluation, the Company recorded total impairment
charges of $160.7 million (pre-tax) in 1998, consisting of $148.0 million
relating to producing properties and related assets, $5.8 million for unproved
properties and $6.9 million relating to other long-lived assets. The magnitude
of the impairment charge was impacted by the merger with TPG in 1997, in which
the allocation of the purchase price at fair value resulted in a significant
increase in the book value of the Company's assets. No impairment was recorded
in 1999. Impairments of $477,000 and $1.4 million were recorded in 2000 and
2001, respectively.



                                       15
<PAGE>


PRODUCING WELL DATA

         As of December 31, 2001, the Company owned interests in 6,262 gross
(5,238 net) producing oil and gas wells and operated approximately 5,723 wells,
including wells operated for third parties. By operating a high percentage of
its properties, the Company is able to control expenses, capital allocation and
the timing of development activities in the areas in which it operates. As of
December 31, 2001, the Company's net production was approximately 51.8 Mmcf of
natural gas and 1,651 Bbls of oil per day.

         The following table summarizes by state the Company's productive wells
at December 31, 2001:

                                    December 31, 2001
                 -------------------------------------------------------
                    Gas Wells            Oil Wells           Total
                 ---------------     ---------------     ---------------
State            Gross      Net      Gross      Net      Gross      Net
-------------    -----     -----     -----     -----     -----     -----
Ohio             1,417     1,214     1,729     1,629     3,146     2,843
Pennsylvania       738       620       445       444     1,183     1,064
New York           875       845         7         6       882       851
Michigan         1,044       476         7         4     1,051       480
                 -----     -----     -----     -----     -----     -----
                 4,074     3,155     2,188     2,083     6,262     5,238
                 =====     =====     =====     =====     =====     =====

ACREAGE DATA

         The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 2001:

<TABLE>
<CAPTION>
                                                    December 31, 2001
                  -------------------------------------------------------------------------------
                      Developed Acreage         Undeveloped Acreage           Total Acreage
                  -----------------------     -----------------------     -----------------------
State               Gross          Net          Gross          Net           Gross            Net
---------------   ---------     ---------     ---------     ---------     ---------     ---------
<S>                 <C>           <C>           <C>           <C>         <C>           <C>

Ohio                312,789       281,855       272,066       228,042       584,855       509,897
Pennsylvania         48,590        40,978       267,711       247,837       316,301       288,815
New York             70,800        68,937       123,765       100,289       194,565       169,226
Michigan             18,426        17,942        61,688        57,756        80,114        75,698
Indiana                  --            --         8,559         8,506         8,559         8,506
West Virginia            --            --         1,144         1,144         1,144         1,144
                  ---------     ---------     ---------     ---------     ---------     ---------
                    450,605       409,712       734,933       643,574     1,185,538     1,053,286
                  =========     =========     =========     =========     =========     =========
</TABLE>





                                       16
<PAGE>


Item 3.  LEGAL PROCEEDINGS
         -----------------

         In February 2000, four individuals filed a suit in Chautauqua County,
New York on their own behalf and on the behalf of others similarly situated,
seeking damages for the alleged difference between the amount of lease royalties
actually paid and the amount of royalties that allegedly should have been paid.
Other natural gas producers in New York were served with similar complaints. The
Company believes the complaint is without merit and is defending the complaint
vigorously. Although the outcome is still uncertain, the Company believes the
action will not have a material adverse effect on its financial position,
results of operations or cash flows.

         The Company is involved in several lawsuits arising in the ordinary
course of business. The Company believes that the result of such proceedings,
individually or in the aggregate, will not have a material adverse effect on the
Company's financial position, results of operations or cash flows.


Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
         ---------------------------------------------------

         Not applicable.


PART II

Item 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
         -----------------------------------------------------
         STOCKHOLDER MATTERS
         -------------------

         There is no established public trading market for the Company's equity
securities.

         The number of record holders of the Company's equity securities at
February 28, 2002 was as follows:

                                                        Number of
        Title of Class                                Record Holders
        ----------------------------------------    --------------------
        Common Stock                                        14


DIVIDENDS

         No dividends have been paid on the Company's Common Stock.




                                       17
<PAGE>


Item 6.  SELECTED FINANCIAL DATA
         -----------------------

         The Selected Financial Data should be read in conjunction with the
Consolidated Financial Statements at Item 14(a).

<TABLE>
<CAPTION>
                                  PREDECESSOR  |
                                    COMPANY    |                          SUCCESSOR COMPANY
                                -------------- | ----------------------------------------------------------------------
                                   SIX MONTHS  |     SIX MONTHS
                                     ENDED     |       ENDED            AS OF OR FOR THE YEARS ENDED DECEMBER 31,
                                    JUNE 30,   |    DECEMBER 31,  -----------------------------------------------------
(IN THOUSANDS)                        1997     |        1997           1998          1999        2000(1)        2001
                                -------------- | ---------------- ------------  ------------ ------------  ------------
<S>                                  <C>       |        <C>         <C>           <C>          <C>           <C>
OPERATIONS:                                    |
Revenues                             $ 79,397  |        $ 84,126    $ 154,839     $ 135,761    $ 117,851     $ 131,530
Depreciation, depletion                        |
  and amortization                     15,366  |          31,694       68,488        41,412       27,460        27,332
Impairment of oil and gas                      |
  properties and other assets              --  |              --      160,690            --          477         1,398
(Loss) income before                           |
  extraordinary item                   (9,873) |         (11,372)    (130,550)      (18,303)       4,325         6,467
Preferred dividends paid                   45  |              --           --            --           --            --
BALANCE SHEET DATA:                            |  AS OF 12/31/97
                                               | ----------------
Working capital                                |          19,846       (6,268)      (43,032)       4,180        13,505
Oil and gas properties and                     |
  gathering systems, net                       |         491,183      319,013       285,081      228,937       239,391
Total assets                                   |         599,320      418,605       350,695      285,117       305,349
Long-term liabilities,                         |
  less current portion                         |         355,649      354,382       303,731      286,858       284,745
Total shareholders' equity (deficit)           |          96,858      (33,014)      (51,590)     (48,313)      (27,279)
</TABLE>

(1)      In March 2000, the Company sold Peake. See Note 3 to the Consolidated
         Financial Statements.


Item 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         -------------------------------------------------
         CONDITION AND RESULTS OF OPERATIONS
         -----------------------------------

         On March 27, 1997, the Company entered into a merger agreement with TPG
which resulted in all of the Company's common stock being acquired by TPG and
certain other investors on June 27, 1997 in a transaction accounted for as a
purchase.

         The Company's principal business is producing oil and natural gas;
exploring for and developing oil and gas reserves; acquiring and enhancing the
economic performance of producing oil and gas properties; and marketing and
gathering natural gas for delivery to intrastate and interstate gas transmission
pipelines. The Company currently operates in Ohio, Pennsylvania, New York,
Michigan, Indiana and West Virginia.

         The Company provides oilfield services to its own operations and to
third parties. Oilfield services provided to the Company's own operations are
provided at cost and all intercompany revenues and expenses are eliminated in
consolidation.

CRITICAL ACCOUNTING POLICIES
----------------------------
         The Company prepares its consolidated financial statements in
accordance with accounting principles generally accepted in the United States
("GAAP") and SEC guidance. See the "Notes to Consolidated Financial Statements"
included in "Item 8. Financial Statements and Supplementary Data" for a
comprehensive discussion of the Company's significant accounting policies. GAAP
requires information in financial statements about the accounting principles and
methods used and the risks and uncertainties inherent in significant estimates
including choices between acceptable methods. Following is a discussion of the
Company's most critical accounting policies:


                                       18
<PAGE>

SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
---------------------------------------
         The accounting for and disclosure of oil and gas producing activities
requires the Company's management to choose between GAAP alternatives and to
make judgments about estimates of future uncertainties.

         The Company utilizes the "successful efforts" method of accounting for
oil and gas producing activities as opposed to the alternate acceptable "full
cost" method. Under the successful efforts method, property acquisition and
development costs and certain productive exploration costs are capitalized while
non-productive exploration costs, which include certain geological and
geophysical costs, exploratory dry hole costs and costs of carrying and
retaining unproved properties, are expensed as incurred.

         The major difference between the successful efforts method of
accounting and the full cost method is under the full cost method of accounting,
such exploration costs and expenses are capitalized as assets, pooled with the
costs of successful wells and charged against the net income (loss) of future
periods as a component of depletion expense. During 2001, 2000 and 1999, the
Company recognized exploration expense of $8.3 million, $8.5 million and $6.4
million, respectively, under the successful efforts method.

OIL AND GAS RESERVES
         The Company's proved developed and proved undeveloped reserves are all
located within the Appalachian and Michigan Basins in the United States. The
Company cautions that there are many uncertainties inherent in estimating proved
reserve quantities and in projecting future production rates and the timing of
development expenditures. In addition, estimates of new discoveries are more
imprecise than those of properties with a production history. Accordingly, these
estimates are expected to change as future information becomes available.
Material revisions of reserve estimates may occur in the future, development and
production of the oil and gas reserves may not occur in the periods assumed and
actual prices realized and actual costs incurred may vary significantly from
assumptions used. Proved reserves represent estimated quantities of natural gas
and oil that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered through
wells and equipment in place and under operating methods being utilized at the
time the estimates were made. The accuracy of a reserve estimate is a function
of:

    --   the quality and quantity of available data;

    --   the interpretation of that data;

    --   the accuracy of various mandated economic assumptions; and

    --   the judgment of the persons preparing the estimate.

         The Company's proved reserve information included in this Report is
based on estimates it prepared. Estimates prepared by others may be higher or
lower than the Company's estimates. The Company's estimates of proved reserves
have been reviewed by independent petroleum engineers.

CAPITALIZATION, DEPRECIATION, DEPLETION AND IMPAIRMENT OF LONG-LIVED ASSETS
         See the "Successful Efforts Method of Accounting" discussion above.
Capitalized costs related to proved properties are depleted using the
unit-of-production method. Depreciation, depletion and amortization of proved
oil and gas properties is calculated on the basis of estimated recoverable
reserve quantities. These estimates can change based on economic or other
factors. No gains or losses are recognized upon the disposition of oil and gas
properties except in extraordinary transactions. Sales proceeds are credited to
the carrying value of the properties. Maintenance and repairs are expensed, and
expenditures which enhance the value of properties are capitalized.


                                       19
<PAGE>

         Unproved oil and gas properties are stated at cost and consist of
undeveloped leases. These costs are assessed periodically to determine whether
their value has been impaired, and if impairment is indicated, the costs are
charged to expense. Impairments recorded in 2001 and 2000 were $179,000 and
$477,000, respectively, which reduced the book value of unproved oil and gas
properties to their estimated fair value.

         Gas gathering systems are stated at cost. Depreciation expense is
computed using the straight-line method over 15 years.

         Property and equipment are stated at cost. Depreciation of non-oil and
gas properties is computed using the straight-line method over the useful lives
of the assets ranging from 3 to 15 years for machinery and equipment and 30 to
40 years for buildings. When assets other than oil and gas properties are
retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in
income for the period. The cost of maintenance and repairs is expensed as
incurred, and significant renewals and betterments are capitalized.

         Long-lived assets are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable. If the sum of the expected future undiscounted cash flows is less
than the carrying amount of the asset, a loss is recognized for the difference
between the fair value and the carrying amount of the asset. In performing the
review for long-lived asset recoverability during 2001, the Company recorded
$1.2 million of impairments which reduced the book value of producing properties
to their estimated fair value. Fair value was based on management's outlook of
future oil and natural gas prices and estimated future cash flows to be
generated by the assets, discounted at a market rate of interest. No impairment
was recorded in 2000 or 1999.

DERIVATIVES AND HEDGING
         On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. As a result of the
adoption of SFAS 133, the Company recognizes all derivative financial
instruments as either assets or liabilities at fair value. Derivative
instruments that are not hedges must be adjusted to fair value through net
income (loss). Under the provisions of SFAS 133, changes in the fair value of
derivative instruments that are fair value hedges are offset against changes in
the fair value of the hedged assets, liabilities, or firm commitments, through
net income (loss). Changes in the fair value of derivative instruments that are
cash flow hedges are recognized in other comprehensive income (loss) until such
time as the hedged items are recognized in net income (loss). Ineffective
portions of a derivative instrument's change in fair value are immediately
recognized in net income (loss). Deferred gains and losses on terminated
commodity hedges will be recognized as increases or decreases to oil and gas
revenues during the same periods in which the underlying forecasted transactions
are recognized in net income (loss).

         The relationship between the hedging instruments and the hedged items
must be highly effective in achieving the offset of changes in fair values or
cash flows attributable to the hedged risk both at the inception of the contract
and on an ongoing basis. The Company measures effectiveness on changes in the
hedge's intrinsic value. The Company considers these hedges to be highly
effective and expects there will be no ineffectiveness to be recognized in net
income (loss) since the critical terms of the hedging instruments and the hedged
forecasted transactions are the same. Ongoing assessments of hedge effectiveness
will include verifying and documenting that the critical terms of the hedge and
forecasted transaction do not change. The Company measures effectiveness on at
least a quarterly basis.

         The adoption of SFAS 133 resulted in a January 1, 2001 transition
adjustment to increase other current liabilities by $10.5 million, increase
current deferred income taxes by $3.8 million and increase


                                       20
<PAGE>

shareholders' deficit by $6.7 million to record the fair value of open cash flow
hedges and the related income tax effect. The increase in shareholders' deficit
is reflected as a cumulative effect of accounting change in accumulated other
comprehensive income (loss).

         Prior to January 1, 2001, under the deferral method, gains and losses
from derivative instruments that qualified as hedges were deferred until the
underlying hedged asset, liability or transaction monetized, matured or was
otherwise recognized under generally accepted accounting principles. When
recognized in net income (loss), hedge gains and losses were included as an
adjustment to gas revenue or interest expense.

REVENUE RECOGNITION
         Oil and gas production revenue is recognized as production and delivery
take place. Oil and gas marketing revenues are recognized when title passes.
Oilfield sales and service revenues are recognized when the goods or services
have been provided.

NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------
         In July 2001, the Financial Accounting Standards Board (FASB) issued
Statements of Financial Accounting Standards No. 141, "Business Combinations,"
and SFAS 142, "Goodwill and Other Intangible Assets." The adoption of SFAS 141
as of July 1, 2001 had no effect on the Company's financial position, results of
operations or cash flows. SFAS 141 eliminates the pooling-of-interests method of
accounting for business combinations except for qualifying business combinations
that were initiated prior to July 1, 2001. SFAS 141 further clarifies the
criteria to recognize intangible assets separately from goodwill. The
requirements of SFAS 141 are effective for any business combination accounted
for by the purchase method that was completed after June 30, 2001.

         Under SFAS 142, goodwill and indefinite lived intangible assets are no
longer amortized but are reviewed for impairment annually or if certain
impairment indicators arise. Separable intangible assets that are not deemed to
have an indefinite life will continue to be amortized over their useful lives
(but with no maximum life). The amortization provisions of SFAS 142 apply to
goodwill and intangible assets acquired after June 30, 2001. With respect to
goodwill and intangible assets acquired prior to July 1, 2001, the Company is
required to adopt SFAS 142 on January 1, 2002. Early adoption is not permitted
for calendar year companies.

         At December 31, 2001, the Company had $2.7 million of unamortized
goodwill which will be subject to the transition provisions of SFAS 142.
Amortization expense related to goodwill amounted to $130,000, $132,000 and
$208,000 for the years ended December 31, 2001, 2000 and 1999, respectively. The
Company is currently assessing the impact of SFAS 142 and has not yet determined
whether adoption will have a material effect on the Company's financial
position, results of operations or cash flows including any transitional
impairment losses which would be required to be recognized as the effect of a
change in accounting principle.

         In August 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 addresses obligations associated with the
retirement of tangible, long-lived assets and the associated asset retirement
costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies", and is effective for the Company's financial
statements beginning January 1, 2003. The Company is currently assessing the
impact of SFAS 143 and has not yet determined whether adoption will have a
material effect on the Company's financial position, results of operations or
cash flows.

         In October 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which establishes a single
accounting model to be used for long-lived assets to be



                                       21
<PAGE>

disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although
retaining many of the fundamental recognition and measurement provisions of SFAS
121, the new rules significantly change the criteria that would have to be met
to classify an asset as held-for-sale. This distinction is important because
assets to be disposed of are stated at the lower of their fair values or
carrying amounts and depreciation is no longer recognized. The new rules also
will supersede the provisions of Accounting Principles Board Opinion No. (APB)
30, "Reporting Results of Operations - Reporting the Effects of Disposal of a
Segment of Business," and will require the expected future operating losses from
discontinued operations to be displayed in discontinued operations in the
periods in which the losses are incurred rather than as of the measurement date
as presently required by APB 30. In addition, more dispositions will qualify for
discontinued operations treatment in the income statement. SFAS 144 is effective
as of January 1, 2002. The adoption of this standard is not expected to have a
material effect on the Company's financial position, results of operations or
cash flows.



















                                       22
<PAGE>


RESULTS OF OPERATIONS
         The following table sets forth financial data for the periods
indicated. Dollars are stated in thousands and as a percentage of revenues.

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                       --------------------------------------------------------------------
                                                                2001                 2000                    1999
                                                       --------------------  ---------------------   ----------------------
<S>                                                    <C>            <C>    <C>              <C>    <C>              <C>
REVENUES
   Oil and gas sales                                   $  95,395      72.5%  $  79,743        67.7%  $  79,299        58.4%
   Gas gathering, marketing, and
     oilfield sales and service                           34,087      25.9      34,850        29.6      51,445        37.9
   Other                                                   2,048       1.6       3,258         2.7       5,017         3.7
                                                       --------------------  ---------------------   ----------------------
                                                         131,530     100.0     117,851       100.0     135,761       100.0
EXPENSES
   Production expense                                     22,649      17.2      20,917        17.7      21,980        16.2
   Production taxes                                        2,372       1.8       2,409         2.0       3,260         2.4
   Gas gathering, marketing, and
     oilfield sales and service                           29,382      22.3      31,703        26.9      46,977        34.6
   Exploration expense                                     8,346       6.4       8,528         7.3       6,442         4.7
   General and administrative expense                      4,395       3.3       4,617         3.9       5,412         4.0
   Franchise, property and other taxes                       250       0.2         397         0.3         652         0.5
   Depreciation, depletion and amortization               27,332      20.8      27,460        23.3      41,412        30.5
   Impairment of oil and gas properties
     and other assets                                      1,398       1.1         477         0.4          --          --
   Severance and other nonrecurring expense                1,954       1.5         241         0.3       3,285         2.4
                                                       --------------------  ---------------------   ----------------------
                                                          98,078      74.6      96,749        82.1     129,420        95.3
                                                       --------------------  ---------------------   ----------------------
OPERATING INCOME                                          33,452      25.4      21,102        17.9       6,341         4.7

OTHER (INCOME) EXPENSE
   (Gain) loss on sale of subsidiaries
     and other income                                         --        --     (15,064)      (12.8)      1,521         1.1
   Interest expense                                       27,476      20.9      29,473        25.0      34,302        25.3
                                                       --------------------  ---------------------   ----------------------
INCOME (LOSS) BEFORE INCOME TAXES
   AND EXTRAORDINARY ITEM                                  5,976       4.5       6,693         5.7     (29,482)      (21.7)
   (Benefit) provision for income taxes                     (491)     (0.4)      2,368         2.0     (11,179)       (8.2)
                                                       --------------------  ---------------------   ----------------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM                    6,467       4.9       4,325         3.7     (18,303)      (13.5)
   Extraordinary item - early extinguishment
     of debt, net of tax benefit                              --        --      (1,364)       (1.2)         --          --
                                                       --------------------  ---------------------   ----------------------
NET INCOME (LOSS)                                      $   6,467       4.9%  $   2,961         2.5%  $ (18,303)      (13.5)%
                                                       ====================  =====================   ======================

EBITDAX                                                $  72,482      55.1%  $  57,808        49.1%  $   57,480       42.3%
</TABLE>



                                       23
<PAGE>


2001 COMPARED TO 2000
         Operating income increased $12.4 million (59%) from $21.1 million in
2000 to $33.5 million in 2001. This increase was primarily a result of a $15.5
million (26%) increase in operating margins partially offset by a $1.2 million
decrease in other income, a $1.7 million increase in severance and other
nonrecurring expense and a $921,000 increase in impairment of oil and gas
properties and other assets.

         The increase in operating margins was primarily due to a $14.0 million
increase in the oil and gas operating margin (oil and gas sales revenues less
production expense and production taxes) primarily as a result of an increase in
the average price realized for the Company's natural gas of approximately $21.7
million ($1.17 per Mcf) and an increase in the volumes of oil sold. These
increases were partially offset by a decrease in the average price realized for
the Company's oil and by a decrease in gas volumes sold as discussed below. The
net increase in operating margins from changes in prices and volumes was
partially offset by an increase in production expense. The operating margin from
oil and gas sales on a per unit basis increased 31% from $2.39 per Mcfe in 2000
to $3.14 per Mcfe in 2001. The $1.2 million decrease in other income was
primarily due to a reduction in income from the monetization of nonconventional
fuel source tax credits as a result of the Peake sale and proceeds received in
the second quarter of 2000 from the settlement of a lawsuit.

         Net income increased $3.5 million from net income of $3.0 million in
2000 to net income of $6.5 million in 2001. Gain on sale of subsidiary and other
income in 2000 was $15.1 million as discussed below. Other significant changes
in 2001 compared to 2000 were the $12.4 million increase in operating income
discussed above, a $2.0 million decrease in interest expense, a $2.9 million
decrease in provision for income taxes, a $921,000 increase in impairment of oil
and gas properties and other assets and a $1.4 million (net of tax benefit)
extraordinary loss from the early extinguishment of debt in 2000.

         Earnings before interest, income taxes, depreciation, depletion and
amortization, impairment, exploration expense and severance and other
nonrecurring items ("EBITDAX") increased $14.7 million from $57.8 million in
2000 to $72.5 million in 2001. This was primarily due to the $15.5 million
increase in the Company's operating margins discussed above partially offset by
the $1.2 million decrease in other income.

         Total revenues increased $13.7 million (12%) in 2001 compared to 2000
primarily as a result of a $1.17 per Mcf increase in the average price realized
for the Company's natural gas and an increase in the volumes of oil sold
partially offset by a $4.25 per Bbl decrease in the average price paid for the
Company's oil, a decrease in gas volumes sold and the decrease in other income
discussed above.

         Gas volumes sold decreased 1.5 Bcf (7%) from 20.0 Bcf in 2000 to 18.5
Bcf in 2001 resulting in a decrease in gas sales revenues of approximately $4.7
million. The gas volume decrease was due to the sale of Peake in the first
quarter of 2000 and the natural production decline of the wells partially offset
by production from wells drilled in 2000 and 2001. Oil volumes sold increased
approximately 54,000 Bbls (9%) from 592,000 Bbls in 2000 to 646,000 Bbls in 2001
resulting in an increase in oil sales revenues of approximately $1.5 million.

         The average price realized for the Company's natural gas increased
$1.17 per Mcf to $4.34 per Mcf in 2001 compared to 2000 which increased gas
sales revenues in 2001 by approximately $21.7 million. As a result of the
Company's hedging activities, gas sales revenues were increased by $4.5 million
($0.25 per Mcf) in 2001 and were reduced by $9.3 million ($0.47 per Mcf) in
2000. The average price paid for the Company's oil decreased from $27.29 per
barrel in 2000 to $23.04 per barrel in 2001 which decreased oil sales revenues
by approximately $2.7 million.


                                       24
<PAGE>

         Production expense increased $1.7 million (8%) from $20.9 million in
2000 to $22.6 million in 2001. The average production cost increased from $0.89
per Mcfe in 2000 to $1.01 per Mcf in 2001. The per unit increase was primarily
due to the sale of Peake, increased compensation related expenses, additional
costs incurred in 2001 to minimize production declines in order to take
advantage of higher gas prices and general cost increases due to current market
conditions. Production taxes were $2.4 million in 2000 and 2001. Average per
unit production taxes increased from $0.10 per Mcfe in 2000 to $0.11 per Mcfe in
2001.

         Exploration expense decreased $182,000 (2%) from $8.5 million in 2000
to $8.3 million in 2001 primarily due to a $1.1 million decrease in exploratory
dry hole expenses in 2001 compared to 2000 partially offset by $967,000 of costs
associated with increased 2001 leasing activity in exploratory areas.

         General and administrative expense decreased $222,000 (5%) from $4.6
million in 2000 to $4.4 million in 2001 due to decreases in employment and
compensation related expenses.

         Franchise, property and other taxes decreased $147,000 (37%) from
$397,000 in 2000 to $250,000 in 2001 primarily due to an $83,000 decrease in
franchise tax and a $79,000 decrease in personal property tax from the sale of
Peake in 2000, state scheduled reduction in taxable values and lower tax rates.

         Depreciation, depletion and amortization decreased by $128,000 from
$27.5 million in 2000 to $27.3 million in 2001. This decrease was primarily due
to a $930,000 reduction in amortization of loan costs from the extension of the
Revolver's final maturity date, a $680,000 reduction in amortization of
non-compete covenants due to expiration of the covenants in 2001 and a $660,000
reduction in the amortization of nonconventional fuel source tax credits in 2001
offset by an increase in depletion expense. Depletion expense increased $2.3
million (13%) from $18.1 million in 2000 to $20.4 million in 2001. Depletion per
Mcfe increased from $0.77 per Mcfe in 2000 to $0.91 per Mcfe in 2001. These
increases were primarily the result of a higher amortization rate per Mcfe due
to lower reserves resulting from lower oil and gas prices at year-end 2001.

         Impairment of oil and gas properties and other assets increased
$921,000 from $477,000 in 2000 to $1.4 million in 2001.

         The Company recorded a net nonrecurring charge of $2.0 million in 2001
which includes a charge of $2.3 million primarily related to the early
retirement of certain senior management members of the Company and other
severance charges incurred which included a non-cash charge of approximately
$200,000 due to the acceleration of certain related stock options. In 2001, the
Company recognized approximately $300,000 in other nonrecurring gains.

         Gain on sale of subsidiaries and other income in 2000 was $15.1 million
primarily due to the $13.7 million gain on the sale of Peake and the $1.3
million gain on terminated interest rate swaps in 2000.

         Interest expense decreased $2.0 million (7%) from $29.5 million in 2000
to $27.5 million in 2001. This decrease was due to a decrease in average
outstanding borrowings and lower blended interest rates. The Company's interest
expense was reduced by $141,000 in 2000 due to interest rate swaps.

         During 2001, the Company concluded an IRS income tax examination of the
years 1994 through 1997 and favorably settled other tax issues. A federal income
tax benefit of $2.0 million was recorded as a result. Also during 2001, a
federal income tax benefit was recorded for approximately $700,000 along


                                       25
<PAGE>

with a corresponding reduction in the valuation allowance as a result of certain
net operating loss carryforwards which the Company now believes it can fully
utilize.

2000 COMPARED TO 1999
         Operating income increased $14.8 million (233%) from $6.3 million in
1999 to $21.1 million in 2000. This increase was the result of a $13.9 million
decrease in depreciation, depletion and amortization expense, a $3.0 million
decrease in severance and other nonrecurring expense, a $1.0 million increase in
the Company's operating margin and a $795,000 decrease in general and
administrative expense partially offset by a $1.8 million decrease in other
income and a $2.1 million increase in exploration expense. The increase in
operating margins was due to increases in the average price paid for the
Company's oil and gas partially offset by a decrease in oil and gas volumes sold
as a result of the sale of Peake and the natural production decline of the
wells. The operating margin from oil and gas sales on a per unit basis increased
37% from $1.74 per Mcfe in 1999 to $2.39 per Mcfe in 2000. The decrease in other
income was primarily due to a reduction in income from the monetization of
nonconventional fuel source tax credits as a result of the Peake sale.

         Net income increased $21.3 million from a net loss of $18.3 million in
1999 to net income of $3.0 million in 2000. This increase was the result of the
$13.7 million gain on the sale of Peake in March 2000, a $4.8 million decrease
in interest expense, a $2.8 million loss due to the sale of TOPS in August 1999,
a $1.3 million gain on terminated interest rate swaps in 2000 and the changes in
operating income discussed above. These changes were partially offset by a $1.4
million extraordinary loss from the early extinguishment of debt, net of tax
benefit (See Note 7 to the Consolidated Financial Statements), a $1.3 million
gain on the sale of BESCO in November 1999 and a $13.5 million increase in the
provision for income taxes primarily due to an increase in income before income
taxes and extraordinary item.

         EBITDAX increased $328,000 from $57.5 million in 1999 to $57.8 million
in 2000. This was primarily due to the $1.0 million increase in the Company's
operating margin discussed above and the $795,000 decrease in general and
administrative expense partially offset by a $1.8 million decrease in other
income.

         Total revenues decreased $17.9 million (13%) in 2000 compared to 1999
due to the sale of the Company's subsidiaries, BESCO and TOPS, in the second
half of 1999, the sale of Peake in the first quarter of 2000 and decreases in
the volumes of oil and natural gas sold. These decreases were partially offset
by increases in the average price paid for the Company's oil and natural gas.

         Oil volumes sold decreased approximately 121,000 Bbls (17%) from
713,000 Bbls in 1999 to 592,000 Bbls in 2000 resulting in a decrease in oil
sales revenues of approximately $2.0 million. Gas volumes sold decreased 7.0 Bcf
(26%) from 27.0 Bcf in 1999 to 20.0 Bcf in 2000 resulting in a decrease in gas
sales revenues of approximately $17.4 million. These volume decreases were due
to the sale of Peake in the first quarter of 2000, the natural production
decline of the wells and curtailment of drilling to minimum levels in 1999 due
to capital constraints caused by the reduction in the Company's borrowing base
in 1999.

         The average price paid for the Company's oil increased from $16.57 per
barrel in 1999 to $27.29 per barrel in 2000 which increased oil sales revenues
by approximately $6.4 million. The average price paid for the Company's natural
gas increased $0.67 per Mcf to $3.17 per Mcf in 2000 compared to 1999 which
increased gas sales revenues in 2000 by approximately $13.4 million. As a result
of the Company's hedging activities, gas sales revenues were reduced by $9.3
million ($0.47 per Mcf) in 2000 and were enhanced by $1.0 million ($0.04 per
Mcf) in 1999.

         Production expense decreased $1.1 million (5%) from $22.0 million in
1999 to $20.9 million in 2000 primarily due to the sale of Peake partially
offset by increased employment and compensation


                                       26
<PAGE>

related expenses. The average production cost increased from $0.70 per Mcfe in
1999 to $0.89 per Mcf in 2000 primarily due to decreased production volumes
sold and to a lesser extent increased compensation related expenses. Production
taxes decreased approximately $851,000 (26%) in 2000 compared to 1999 as a
result of decreased oil and gas sales revenues primarily due to the sale of
Peake. Average production taxes were $0.10 per Mcfe in 2000 and 1999. A decrease
in the average production tax amount per Mcfe resulting from the sale of Peake
was offset by an increase in per unit production taxes due to higher oil and
natural gas prices in 2000.

         Exploration expense increased by $2.1 million (32%) from $6.4 million
in 1999 to $8.5 million in 2000. Increased geophysical expenses and dry hole
costs associated with the Company's active drilling program in 2000 and planned
drilling activity in 2001 were partially offset by decreased employment and
compensation related expense due to staff reductions in September 1999. Drilling
activity in 1999 was severely curtailed due to capital constraints caused by the
reduction in the Company's borrowing base.

         General and administrative expense decreased $795,000 in 2000 compared
to 1999 due to decreases in employment and compensation related expenses and a
decrease in Year 2000 ("Y2K") related costs.

         Severance and other nonrecurring expense decreased from $3.3 million in
1999 to $241,000 in 2000 primarily due to $2.4 million in employee reduction
costs and $880,000 in costs associated with an abandoned acquisition effort and
an abandoned public offering of a royalty trust in the third quarter of 1999.

         Depreciation, depletion and amortization decreased by $13.9 million
(34%) from $41.4 million in 1999 to $27.5 million in 2000. Depletion expense
decreased $10.8 million (37%) from $28.9 million in 1999 to $18.1 million in
2000. Depletion per Mcfe decreased from $0.92 per Mcfe in 1999 to $0.77 per Mcfe
in 2000. These decreases were primarily the result of decreased production
volumes and a lower amortization rate per Mcfe due to higher reserves resulting
from higher oil and gas prices at December 31, 2000.

         Interest expense decreased $4.8 million (14%) from $34.3 million in
1999 to $29.5 million in 2000. This decrease was due to a decrease in average
outstanding borrowings partially offset by higher blended interest rates. The
Company's interest expense was reduced by $141,000 in 2000 and increased by
$972,000 in 1999 due to interest rate swaps.

         (Gain) loss on sale of subsidiaries and other income increased from a
$1.5 million loss in 1999 to a $15.1 million gain in 2000 due to the $13.7
million gain on the sale of Peake in 2000, a $1.3 million gain on terminated
interest rate swaps in 2000 and a $2.8 million loss on the sale of the Company's
TOPS subsidiary in 1999 partially offset by a $1.3 million gain on the sale of
the Company's BESCO subsidiary in 1999.

LIQUIDITY AND CAPITAL RESOURCES
         The Company's liquidity and capital resources are closely related to
and dependent on the current prices paid for its oil and natural gas.

         The Company's current ratio at December 31, 2001 was 1.53 to 1. During
2001, working capital increased $9.3 million from $4.2 million at December 31,
2000 to $13.5 million at December 31, 2001. The increase was primarily due to an
increase in the fair value of derivatives in 2001 which increased working
capital by $20.0 million, net of a related increase in current deferred taxes of
$6.9 million and a $4.9 million decrease in accrued expenses. These increases
were offset by an $8.5 million decrease in


                                       27
<PAGE>

accounts receivable. The Company's operating activities provided cash flows of
$48.1 million during 2001.

         On June 29, 2001, the Company amended its $100 million revolving credit
facility from Ableco Finance LLC and Foothill Capital Corporation. The amendment
extended the Revolver's final maturity date to April 22, 2004, from August 23,
2002, increased the letter of credit sub-limit from $20 million to $30 million
and eliminated the effects of SFAS 133 from financial covenant calculations. The
Company paid approximately $200,000 in fees and expenses related to the
amendment.

         The amendment extended the financial covenant for the senior interest
coverage ratio of 3.2 to 1 for the quarters ending September 30, 2002, through
March 31, 2004; and the senior debt leverage ratio of 2.7 to 1 was extended for
the quarters ending September 30, 2002 through March 31, 2004. These ratios
will be calculated quarterly based on the financial results of the previous four
quarters.

         The amendment added an early termination fee equal to .25% of the
facility if terminated between the effective date and May 31, 2002. If
termination is after May 31, 2002 but on or before May 31, 2003, the termination
fee is .125% of the facility. There is no termination fee after May 31, 2003.
The Company is required to hedge, through financial instruments or fixed price
contracts, at least 20% but not more than 80% of its estimated hydrocarbon
production, on a Mcfe basis, for the succeeding 12 months on a rolling 12-month
basis. Based on the Company's hedges currently in place and its expected
production levels, the Company is in compliance with this hedging requirement
through March 2003.

         The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At December 31, 2001, the interest rate was 6.75%. At
December 31, 2001, the Company had $2.3 million of outstanding letters of
credit. At December 31, 2001, the outstanding balance under the credit agreement
was $59.3 million with $38.4 million of borrowing capacity available for general
corporate purposes.

         In January 2002, the Company monetized certain financial hedges and
paid down the Revolver by $21.7 million. As of February 28, 2002, there was
$33.0 million outstanding under the Revolver, letters of credit commitments of
$2.3 million and $64.7 million available for general corporate purposes.

         The Revolver is secured by security interests and mortgages against
substantially all of the Company's assets and is subject to periodic borrowing
base determinations. The borrowing base is the lesser of $100 million or the sum
of (i) 65% of the value of the Company's proved developed producing reserves
subject to a mortgage; (ii) 45% of the value of the Company's proved developed
non-producing reserves subject to a mortgage; and (iii) 40% of the value of the
Company's proved undeveloped reserves subject to a mortgage. The price forecast
used for calculation of the future net income from proved reserves is the
three-year NYMEX strip for oil and natural gas as of the date of the reserve
report. Prices beyond three years are held constant. Prices are adjusted for
basis differential, fixed price contracts and financial hedges in place. The
present value (using a 10% discount rate) of the Company's future net income at
December 31, 2001, under the borrowing base formula above, was approximately
$196 million for all proved reserves of the Company and $146 million for
properties secured by a mortgage.

         The Revolver is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 3.7 to 1 at December 31, 2001,
to 3.2 to 1 at March 31, 2004; and a senior debt leverage ratio ranging from 2.6
to 1 and 3.2 to 1 for the periods from December 31, 2001 through March 31,
2004. EBITDA, as defined in the Revolver, and consolidated interest expense on
senior debt in these ratios are calculated quarterly based on the financial
results of the previous four quarters. In addition, the Company is required to
maintain a current ratio (including available borrowing capacity in current
assets, excluding current debt and accrued interest from current liabilities and
excluding any effects from the application of SFAS 133 to other current assets
or current liabilities) of at least 1.0 to 1


                                       28
<PAGE>

and maintain liquidity of at least $5 million (cash and cash equivalents
including available borrowing capacity). As of December 31, 2001, the Company's
current ratio including the above adjustments was 3.11 to 1. The Company had
satisfied all financial covenants as of December 31, 2001.

         The Company issued $225 million of 9 7/8% Senior Subordinated Notes on
June 27, 1997. The notes mature June 15, 2007. Interest is payable semiannually
on June 15 and December 15 of each year.

         The notes are general unsecured obligations of the Company and are
subordinated in right of payment to senior debt. Except as otherwise described
in Note 7 to the Consolidated Financial Statements, the notes are not redeemable
prior to June 15, 2002. Thereafter, the notes are subject to redemption at the
option of the Company at specific redemption prices. Prior to June 15, 2002, the
notes may be redeemed as a whole at the option of the Company upon the
occurrence of a change in control.

         The notes were issued pursuant to an indenture which contains certain
covenants that limit the ability of the Company and its subsidiaries to incur
additional indebtedness and issue stock, pay dividends, make distributions, make
investments, make certain other restricted payments, enter into certain
transactions with affiliates, dispose of certain assets, incur liens securing
indebtedness of any kind other than permitted liens and engage in mergers and
consolidations.

         From time to time the Company may enter into interest rate swaps to
hedge the interest rate exposure associated with the credit facility, whereby a
portion of the Company's floating rate exposure is exchanged for a fixed
interest rate. The Company's interest expense was reduced by $141,000 in 2000
due to interest rate swaps. At December 31, 2000, the Company had no open
interest rate swap arrangements. There were no interest rate swaps open in 2001.

         During 2001, the Company invested $24.6 million, including exploratory
dry hole expense, to drill 165 development wells and 10 exploratory wells. Of
these wells, 153 development wells and three exploratory wells were completed as
producers in the target formation, for a completion rate of 93% and 30%,
respectively (an overall completion rate of 89%). In addition, $1.7 million was
invested in proved developed reserve acquisitions.

         The Company currently expects to spend approximately $44 million during
2002 on its drilling activities, including exploratory dry hole expense, and
other capital expenditures. The Company intends to finance its planned capital
expenditures through its available cash flow, available revolving credit line,
the sale of participating interests in its exploratory Trenton Black River
prospect areas and the sale of non-strategic assets. At December 31, 2001, the
Company had approximately $38.4 million available under the Revolver. At
February 28, 2002, the Company had approximately $64.7 million available under
the Revolver. The level of the Company's future cash flow will depend on a
number of factors including the demand for and price levels of oil and gas, the
scope and success of its drilling activities and its ability to acquire
additional producing properties.

         The Company has various commitments primarily related to leases for
office space, vehicles, natural gas compressors and computer equipment. The
Company expects to fund these commitments with cash generated from operations.
The following table summarizes the Company's contractual obligations at December
31, 2001.


<TABLE>
<CAPTION>
                                                          PAYMENTS DUE BY PERIOD
                                       -------------------------------------------------------------
CONTRACTUAL OBLIGATIONS AT                          LESS THAN      1 - 3        4 - 5      AFTER 5
DECEMBER 31, 2001                       TOTAL        1 YEAR        YEARS        YEARS       YEARS
------------------------------------   --------     --------     --------     --------     --------
                                                              (IN THOUSANDS)
<S>                                    <C>          <C>          <C>          <C>          <C>
Long term debt                         $284,434     $     19     $ 59,315     $      8     $225,092
Capital lease obligations                   326          137          189           --           --
Operating leases                          2,466        1,252          895          319           --
                                       --------     --------     --------     --------     --------
Total contractual cash obligations     $287,226     $  1,408     $ 60,399     $    327     $225,092
                                       ========     ========     ========     ========     ========
</TABLE>





         In addition to the items above, the Company has an employment agreement
with its Chief Executive Officer, a retirement agreement, a severance plan and a
change of control plan. See "Executive Compensation - Employment and Severance
Agreements" in Item 11 of this Report. The Company has entered into joint
operating agreements, area of mutual interest agreements and joint ventures
with other companies. These agreements may include drilling commitments or other
obligations in the normal course of business.


                                       29
<PAGE>

         The following table summarizes the Company's commercial commitments at
December 31, 2001.


<TABLE>
<CAPTION>
                                                        AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
                                                   ------------------------------------------------------
                                      TOTAL
COMMERCIAL COMMITMENTS AT            AMOUNTS       LESS THAN       1 - 3          4 - 5            OVER 5
DECEMBER 31, 2001                   COMMITTED       1 YEAR         YEARS          YEARS            YEARS
----------------------------------- ---------      ---------       -----          -----            ------
                                                               (IN THOUSANDS)
<S>                                   <C>           <C>           <C>             <C>             <C>
Standby Letters of Credit             $  2.3        $  2.3        $   --          $   --          $   --
                                      ------        ------        ------          ------          -------
Total Commercial Commitments          $  2.3        $  2.3        $   --          $   --          $   --
                                      ======        ======        ======          ======          =======
</TABLE>

         In the normal course of business, the Company has performance
obligations which are supported by surety bonds or letters of credit. These
obligations are primarily site restoration and dismantlement, royalty payments
and exploration programs where governmental organizations require such support.
The Company also has letters of credit with its hedging counterparty.

         The Company has certain other commitments and uncertainties related to
its normal operations, including any obligation to plug wells.

NATURAL GAS HEDGE POSITION MONETIZATION AND RESTRUCTURING
         On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion
British thermal units) of its 2002 natural gas hedge position at a weighted
average NYMEX price of $2.53 per Mmbtu and 3,840 Bbtu of its 2003 natural gas
hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net
proceeds of $22.7 million that will be recognized as increases to natural gas
revenues during the same periods in which the underlying forecasted transactions
are recognized in net income (loss).

         In January 2002, the Company entered into a collar for 9,350 Bbtu of
its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a
floor price of $2.25 per Mmbtu. The Company also sold a floor at $1.75 per Mmbtu
on this volume of gas. This aggregate structure has the effect of: 1) setting a
maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per
Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and
$2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if
the price is $1.75 or less. All prices are based on monthly NYMEX settle. The
Company paid $1.0 million for the options.

         The Company used the net proceeds of $21.7 million from the two
transactions above to pay down on its credit facility. At February 28, 2002, the
Company had $2.3 million of outstanding letters of credit. At February 28, 2002,
the outstanding balance under the credit facility was $33.0 million with $64.7
million of borrowing capacity available for general corporate purposes.




                                       30
<PAGE>


         The following table summarizes, as of January 21, 2002, the Company's
deferred gains on terminated natural gas hedges. Cash has been received and the
deferred gains recorded in accumulated other comprehensive income. The deferred
gains will be recognized as increases to gas revenues during the same periods in
which the underlying forecasted transactions are recognized in net income
(loss).

<TABLE>
<CAPTION>
                                                              2002                            2003
                                        ----------------------------------------------       ------
                                         FIRST         SECOND      THIRD       FOURTH
                                        QUARTER        QUARTER    QUARTER      QUARTER
                                        -------        -------    -------      -------
                                                               (IN THOUSANDS)

<S>                                      <C>           <C>         <C>          <C>          <C>
        Natural Gas Hedges
        Terminated in January 2002       $4,521        $5,620      $5,188       $4,560       $2,851
</TABLE>


         To manage its exposure to natural gas or oil price volatility, the
Company may partially hedge its physical gas or oil sales prices by selling
futures contracts on the NYMEX or by selling NYMEX based commodity derivative
contracts which are placed with major financial institutions that the Company
believes are minimal credit risks. The contracts may take the form of futures
contracts, swaps, collars or options.




                                       31
<PAGE>


         The Company's financial results and cash flows can be significantly
impacted as commodity prices fluctuate widely in response to changing market
conditions. Accordingly, the Company may modify its fixed price contract and
financial hedging positions by entering into new transactions or terminating
existing contracts. The following tables reflect the natural gas volumes and the
weighted average prices under financial hedges (including settled hedges) and
fixed price contracts at January 21, 2002:


<TABLE>
<CAPTION>
                                            NATURAL GAS SWAPS                        FIXED PRICE CONTRACTS
                                -------------------------------------------    --------------------------------
                                                              ESTIMATED                           ESTIMATED
                                            NYMEX PRICE        WELLHEAD          ESTIMATED         WELLHEAD
QUARTER ENDING                  Bbtu         PER Mmbtu       PRICE PER Mcf          Mmcf         PRICE PER Mcf
-----------------------------   ----        -----------      -------------       ---------       -------------

<S>                              <C>           <C>               <C>               <C>             <C>
March 31, 2002                   850           $ 4.95            $ 5.20            1,070           $ 4.48
June 30, 2002                     --               --                --              820             4.20
September 30, 2002                --               --                --              690             4.32
December 31, 2002                 --               --                --              570             4.49
                                ----          -------           -------           ------          -------
                                 850           $ 4.95            $ 5.20            3,150           $ 4.37
                                ====          =======           =======           ======          =======

March 31, 2003                                                                        65           $ 2.50
June 30, 2003                                                                         65             2.50
September 30, 2003                                                                    65             2.50
December 31, 2003                                                                     65             2.50
                                                                                     ---             ----
                                                                                     260           $ 2.50
                                                                                    ====           ======
</TABLE>


<TABLE>
<CAPTION>
                                              MONTHLY NYMEX SETTLE OF       MONTHLY NYMEX SETTLE LOWER
                                                  $1.75 OR HIGHER                   THAN $1.75
                                         --------------------------------   --------------------------
                                              NYMEX
                                            PRICE PER        ESTIMATED        NYMEX       ESTIMATED
                                              Mmbtu           WELLHEAD      PRICE PER     WELLHEAD
QUARTER ENDING                 Bbtu         FLOOR/CAP       PRICE PER Mcf     Mmbtu     PRICE PER Mcf
-----------------            -------    --------------     --------------   ---------   --------------
<S>                           <C>       <C>               <C>               <C>         <C>
March 31, 2002                 1,700     $ 2.25 - 4.00     $ 2.50 - 4.25     Monthly       Monthly
June 30, 2002                  2,550       2.25 - 4.00       2.40 - 4.15      NYMEX         NYMEX
September 30, 2002             2,550       2.25 - 4.00       2.40 - 4.15    settle plus   settle plus
December 31, 2002              2,550       2.25 - 4.00       2.47 - 4.22      $0.50     $0.65 to $0.75
                              ------    --------------     -------------
                               9,350     $ 2.25 - 4.00     $ 2.44 - 4.19
                              ======    ==============     =============
</TABLE>

                                       NATURAL GAS COLLARS
                         ------------------------------------------------
                                            NYMEX
                                          PRICE PER         ESTIMATED
                                            Mmbtu            WELLHEAD
                               Bbtu       FLOOR/CAP       PRICE PER Mcf
                         -------------  --------------   ---------------
March 31, 2003                 1,650    $ 3.40 - 5.23     $ 3.65 - 5.48
June 30, 2003                  1,650      3.40 - 5.23       3.55 - 5.38
September 30, 2003             1,650      3.40 - 5.23       3.55 - 5.38
December 31, 2003              1,650      3.40 - 5.23       3.62 - 5.45
                              ------    -------------     -------------
                               6,600    $ 3.40 - 5.23     $ 3.59 - 5.42
                              ======    =============     =============

Mcf  -  Thousand cubic feet     Mmbtu - Million British thermal units
Mmcf -  Million cubic feet      Bbtu  - Billion British thermal units


                                       32
<PAGE>

ENRON EXPOSURE
         The Company had physical natural gas sales to Enron from operated and
non-operated gas wells. The Company's aggregate exposure related to Enron at
December 31, 2001 was approximately $500,000. The Company has fully reserved
this amount in the fourth quarter of 2001. Enron was not a counterparty to any
of the Company's financial hedging positions.

INFLATION AND CHANGES IN PRICES
         During 1999, the price paid for the Company's crude oil increased from
a low of $9.25 per barrel at year-end 1998 to a high of $23.25 per barrel at
year-end 1999, with an average price of $16.57 per barrel. During 2000, the
price paid for the Company's crude oil fluctuated between a low of $20.75 per
barrel and a high of $33.25 per barrel, with an average price of $27.29 per
barrel. During 2001, the price paid for the Company's crude oil fluctuated
between a low of $13.50 per barrel and a high of $28.50 per barrel, with an
average price of $23.04 per barrel. The average price of the Company's natural
gas increased from $2.50 per Mcf in 1999 to $3.17 per Mcf in 2000, then
increased to $4.34 per Mcf in 2001.

         The price of oil and natural gas has a significant impact on the
Company's results of operations. Oil and natural gas prices fluctuate based on
market conditions and, accordingly, cannot be predicted. Costs to drill,
complete and service wells can fluctuate based on demand for these services
which is generally influenced by high or low commodity prices. The Company's
costs and expenses may be subject to inflationary pressures if oil and gas
prices are favorable.

         Prior to 1999, a large portion of the Company's natural gas had been
sold subject to long-term fixed price contracts. In 1999, the Company shifted
its price risk management procedures to reduce reliance on fixed price
contracts. Currently, a large portion of its natural gas is sold subject to
market sensitive contracts. Natural gas price risk is mitigated (hedged) by the
utilization of over-the-counter NYMEX swaps, options or collars. Natural gas
price hedging decisions are made in the context of the Company's strategic
objectives, taking into account the changing fundamentals of the natural gas
marketplace.

FORWARD-LOOKING INFORMATION
         The forward-looking statements regarding future operating and financial
performance contained in this report involve risks and uncertainties that
include, but are not limited to, the Company's availability of capital,
production and costs of operation, the market demand for, and prices of oil and
natural gas, results of the Company's future drilling, the uncertainties of
reserve estimates, environmental risks, availability of financing and other
factors detailed in the Company's filings with the SEC. Actual results may
differ materially from forward-looking statements made in this report.


Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
          ----------------------------------------------------------

         The Company is exposed to, among other risks, interest rate and
commodity price risks.

         The interest rate risk relates to existing debt under the Company's
revolving credit facility as well as any new debt financing needed to fund
capital requirements. The Company may manage its interest rate risk through the
use of interest rate swaps to hedge the interest rate exposure associated with
the credit agreement, whereby a portion of the Company's floating rate exposure
is exchanged for a fixed interest rate. A portion of the Company's long-term
debt consists of senior subordinated notes where the interest component is
fixed. The Company had no derivative financial instruments for managing interest
rate risks in place as of December 31, 2001 and 2000. If market interest rates
for short-term borrowings increased 1%, the increase in the Company's interest
expense would be approximately $593,000. This sensitivity analysis is based on
the Company's financial structure at December 31, 2001.


                                       33
<PAGE>

         The commodity price risk relates to natural gas and crude oil produced,
held in storage and marketed by the Company. The Company's financial results can
be significantly impacted as commodity prices fluctuate widely in response to
changing market forces. From time to time the Company may enter into a
combination of futures contracts, commodity derivatives and fixed-price physical
contracts to manage its exposure to commodity price volatility. The fixed-price
physical contracts generally have terms of a year or more. The Company employs a
policy of hedging gas production sold under NYMEX based contracts by selling
NYMEX based commodity derivative contracts which are placed with major financial
institutions that the Company believes are minimal credit risks. The contracts
may take the form of futures contracts, swaps or options. If NYMEX gas prices
decreased $0.25 per Mcf, the Company's gas sales revenues would decrease by $1.3
million, after considering the effects of the hedging contracts in place at
December 31, 2001. If the price of crude oil decreased $2.00 per Bbl, the
Company's oil sales revenues would decrease by $1.3 million. This sensitivity
analysis is based on the Company's 2001 oil and gas sales volumes.

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
         -------------------------------------------

         The Index to Consolidated Financial Statements and Schedules on page
F-1 sets forth the financial statements included in this Annual Report on Form
10-K and their location herein. Schedules have been omitted as not required or
not applicable because the information required to be presented is included in
the financial statements and related notes.

         The financial statements have been prepared by management in conformity
with accounting principles generally accepted in the United States. Management
is responsible for the fairness and reliability of the financial statements and
other financial data included in this report. In the preparation of the
financial statements, it is necessary to make informed estimates and judgments
based on currently available information on the effects of certain events and
transactions.

         The Company maintains accounting and other controls which management
believes provide reasonable assurance that financial records are reliable,
assets are safeguarded and that transactions are properly recorded. However,
limitations exist in any system of internal control based upon the recognition
that the cost of the system should not exceed benefits derived.

         The Company's independent auditors, Ernst & Young LLP ("E&Y"), are
engaged to audit the financial statements and to express an opinion thereon.
Their audit is conducted in accordance with auditing standards generally
accepted in the United States to enable them to report whether the financial
statements present fairly, in all material respects, the financial position and
results of operations in accordance with accounting principles generally
accepted in the United States.

         The aggregate fees for professional services rendered by E&Y for the
audit of the Company's financial statements for the year ended December 31,
2001, and the reviews of the financial information included in the Company's
Form 10-Q's for the year were $136,200. E&Y did not provide the Company any
financial information systems design and implementation services during 2001.
The aggregate fees for other services rendered by E&Y in 2001, related primarily
to tax consulting and tax compliance services, were $46,100.

Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
         ------------------------------------------------
         ACCOUNTING AND FINANCIAL DISCLOSURE
         -----------------------------------

         Not applicable.



                                       34
<PAGE>


PART III

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
          --------------------------------------------------

         Executive officers and directors of the Company as of March 5, 2002
were as follows:

<TABLE>
<CAPTION>
Name                         Age      Position
---------------------       -----    ----------
<S>                          <C>      <C>
John L. Schwager             53       President, Chief Executive Officer and Director

Richard R. Hoffman           51       Senior Vice President Exploration and Production

Robert W. Peshek             47       Vice President Finance and Chief Financial Officer

David M. Becker              40       Vice President and General Manager, Michigan Exploration
                                      and Production District

Duane D. Clark               46       Vice President Legal Affairs/Gas Marketing

John G. Corp                 42       Vice President and General Manager, Arrow Oilfield Service
                                      Company

William F. Murray            40       Vice President and General Manager, Ohio Exploration and
                                      Production District

Lawrence W. Kellner          43       Director

Robert S. Maust              64       Director

William S. Price, III        46       Director

Gareth Roberts               49       Director

Jeffrey C. Smith             40       Director
</TABLE>


         All executive officers of the Company serve at the pleasure of its
Board of Directors. None of the executive officers of the Company is related to
any other executive officer or director. The Board of Directors consists of six
members each of whom is elected annually to serve one-year terms. The business
experience of each executive officer and director is summarized below.

         JOHN L. SCHWAGER has been Chief Executive Officer of the Company since
June of 1999. Mr. Schwager was elected to the Board of Directors in August of
1999 and was appointed to the additional position of President upon the
departure of the former President in September 1999. He has over 30 years of
diversified experience in the oil and gas industry. Prior to joining the
Company, he spent two years as President of AnnaCarol Enterprises, Inc., an
energy consulting firm specializing in financial and engineering advisory
services to exploration and production sector companies. From 1984 to 1997, he
was employed by Alamco, Inc., an Appalachian Basin exploration and production
company, serving as President and Chief Executive Officer from 1987 to 1997;
Executive Vice President from May 1987 to October 1987; and, Senior Vice
President - Operations from 1984 to 1987. He also served as Chairman of the
Board of TGX Corporation and led TGX out of bankruptcy in 1992. From 1980 to
1984, Mr. Schwager was employed as the Vice President of Production for Callon
Petroleum Company in Natchez,



                                       35
<PAGE>

Mississippi. From 1970 to 1980, he worked for Shell Oil Company in New Orleans
in both engineering and supervisory positions. He last worked at Shell as a
Division Drilling Superintendent in the Offshore Division.

         Mr. Schwager graduated from the University of Missouri at Rolla in 1970
with a Bachelor of Science Degree in Petroleum Engineering. He is a past
president and director of the Independent Oil and Gas Association of West
Virginia and is currently a member of the Ohio Oil and Gas Association. He also
was the cofounder of the Oil and Gas Political Action Committee of West
Virginia, serving as cochairman for many years.

         RICHARD R. HOFFMAN joined the Company as Senior Vice President of
Exploration and Production in March of 2001. Mr. Hoffman has worked in the oil
and gas industry for 29 years and has extensive operational experience in the
Appalachian Basin. From 1998 to 2000, he served as Manager of Production for
Dominion Appalachian Development Inc., a subsidiary of Dominion Resources, Inc.,
specializing in natural gas exploration and production. From 1982 to 1997, he
was Executive Vice President and Chief Operating Officer of Alamco, Inc., and
served on its Board of Directors from 1988 to 1997. Mr. Hoffman served as
Superintendent Production and Drilling/Field Engineer for Cabot Oil and Gas
Corporation from 1980 to 1982, and from 1977 to 1980 he was employed by Flint
Oil and Gas, Inc., as a Field Engineer. From 1973 to 1977, he held the title of
Assistant Production Superintendent/Engineer with The Wiser Oil Company.

          Mr. Hoffman graduated from West Virginia University with a Bachelor of
Science degree in Geology. He is affiliated with numerous oil and gas
associations including the Ohio Oil and Gas Association, the West Virginia Oil
and Natural Gas Association and the Independent Oil and Gas Association of West
Virginia where he served as a Director from 1995 to 1997. He is also a member of
the Society of Petroleum Engineers.

         ROBERT W. PESHEK has served as Vice President of Finance for the
Company since 1997 and in 1999 was appointed Chief Financial Officer.
Previously, he served as Corporate Controller and Tax Manager from 1994 to 1997.
Prior to joining the Company, Mr. Peshek served as a Senior Manager of the Tax
Department at Ernst & Young LLP from 1981 to 1994. He is a Certified Public
Accountant with extensive experience in taxation, finance, accounting and
auditing. Mr. Peshek holds a Bachelor of Business Administration degree in
Accounting from Kent State University where he graduated with honors. His
professional affiliations include the American Institute of Certified Public
Accountants and the Ohio Society of Certified Public Accountants. Mr. Peshek is
a member of the Ohio Oil and Gas Association.

         DAVID M. BECKER was appointed Vice President of the Company in May
2000, and has been President and Chief Operating Officer of Ward Lake Drilling,
Inc., a wholly-owned subsidiary of the Company, and General Manager of the
Michigan Exploration and Production District since 1995. Mr. Becker joined the
Company as a result of the acquisition of Ward Lake in February of 1995. He
worked for Ward Lake Energy, Inc. from 1988 to 1995, serving most recently as
President and COO. Previously, he served as Facility Engineer for Shell Oil
Company in New Orleans, Louisiana from 1984 to 1988. He has 20 years of
experience in the oil and gas industry. Mr. Becker received his Bachelor of
Science degree in Mechanical Engineering from Michigan Technical University. His
professional affiliations include the Michigan Oil and Gas Association and the
American Petroleum Institute.


                                       36
<PAGE>

         DUANE D. CLARK has been Vice President of Legal Affairs/Gas Marketing
for the Company since April 2001. Previously, he served as Vice President of Gas
Marketing. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to
joining the Company, Mr. Clark held various management positions with Quaker
State Corporation from 1978 to 1995. He has 23 years of experience in the oil
and gas industry. Mr. Clark received his BA degree in Mathematics and Economics
from Ohio Wesleyan University. His professional affiliations include the Ohio
Oil and Gas Association, the Independent Oil and Gas Association of West
Virginia and the Pennsylvania Oil and Gas Association.


         JOHN G. CORP was appointed Vice President of the Company in May 2000,
and has been the General Manager of Arrow Oilfield Service Company, the
Company's oil field service division, since November 1999. Prior to that he
served as General Manager of the Company's Southern Ohio E&P District from 1987
to 1999. Mr. Corp joined the Company as a Petroleum Engineer. Previously he
worked for Park-Ohio Energy as Drilling/Production Engineer from 1979 to 1986.
Mr. Corp has 23 years of experience in the oil and gas industry. He attended
Marietta College where he received a Bachelor of Science degree in Petroleum
Engineering. He is a member of the Society of Petroleum Engineers, the Ohio Oil
and Gas Association and a member of the Technical Advisory Committee for the
Ohio Department of Natural Resources.


         WILLIAM F. MURRAY was appointed Vice President of the Company in May
2000, and has served as General Manager of the Company's Ohio E&P District since
November 1999. Prior to that he served as General Manager of the Northern
OH/Western NY E&P District for the Company from 1983 to 1999. He has 19 years of
experience in the industry. Mr. Murray graduated from Marietta College and holds
a Bachelor of Science degree in Petroleum Engineering. He is a member of the
Society of Petroleum Engineers and a former Board member of the Ohio Society of
Petroleum Engineers. His other professional affiliations include the New York
Independent Oil and Gas Association, where he is a former member of the Board of
Directors, and the Ohio Oil and Gas Association where he currently serves on the
Legal Affairs Committee.

         LAWRENCE W. KELLNER has been a director since 1997. He has been
President of Continental Airlines, Inc. since May 2001. He was Executive Vice
President and Chief Financial Officer of Continental Airlines, Inc. from
November 1996 to May 2001. Mr. Kellner graduated magna cum laude with a Bachelor
of Science, Business Administration degree from the University of South
Carolina. Mr. Kellner is also a director of Continental Airlines, Inc.

         ROBERT S. MAUST has been a director since February 2001. He is the
Louis F. Tanner Distinguished Professor of Public Accounting at West Virginia
University where he has been the Director of the Division of Accounting since
1987. He has been a professor at the University since 1963 and has received
numerous teaching and professional honors during his 39-year career. He has
published several papers and has contributed to various books and manuals on
accounting and business. Mr. Maust is a Certified Public Accountant and has
served as an officer of several state, regional and national professional
organizations. He received his Bachelor and Master degrees from West Virginia
University and Certificate of Ph.D. Candidacy from the University of Michigan.
From 1987 to 1997, he served on the Board of Directors of Alamco, Inc., an
Appalachian Basin-based firm engaged in the acquisition, exploration,
development and production of domestic gas and oil.

         WILLIAM S. PRICE, III, who became a director upon consummation of the
merger with TPG in 1997, was a founding partner of Texas Pacific Group in 1992.
Prior to forming Texas Pacific, Mr. Price was Vice President of Strategic
Planning and Business Development for G.E. Capital, reporting to the Chairman.
In this capacity, Mr. Price was responsible for acquiring new business units and
determining


                                       37
<PAGE>

the business and acquisition strategies for existing businesses.
From 1985 to 1991, Mr. Price was employed by the management consulting firm of
Bain & Company, attaining officer status and acting as co-head of the Financial
Services Practice. Prior to 1985, Mr. Price was employed as an associate
specializing in corporate securities transactions with the legal firm of Gibson,
Dunn & Crutcher. Mr. Price is a member of the California Bar and graduated with
honors in 1981 from the Boalt Hall School of Law at the University of
California, Berkeley. He is a 1978, Phi Beta Kappa graduate of Stanford
University. Mr. Price serves on the Board of Directors of Continental Airlines,
Inc., Del Monte Foods Company, Denbury Resources, Inc., Gemplus International,
S.A., Verado Holdings and several private companies.

         GARETH ROBERTS has been a director since 1997. He is President, Chief
Executive Officer and a Director of Denbury Resources, Inc. ("Denbury"), and is
the founder of the operating subsidiary of Denbury, which was founded in April
1990. Mr. Roberts has 27 years of experience in the exploration and development
of oil and gas properties with Texaco, Inc., Murphy Oil Corporation and Coho
Resources, Inc. His expertise is particularly focused in the Gulf Coast region
where he specializes in the acquisition and development of old fields with low
productivity. Mr. Roberts holds honors and masters degrees in Geology and
Geophysics from St. Edmund Hall, Oxford University.

         JEFFREY C. SMITH has been a director since February 2001. He joined the
Texas Pacific Group in 2000 in the capacity of Portfolio Operations Manager. Mr.
Smith has 10 years of experience in management consulting, serving most recently
as a Strategy Consultant for the management consulting firm of Bain & Company
from 1993 to 1999. He was employed by the consulting firms of The L/E/K
Partnership and McKinsey & Co., from 1991 to 1993. From 1987 to 1990, he was
employed by Exxon USA as a Senior Engineer and from 1985 to 1986, he conducted
Academic Research at the Research and Development Division of Conoco, Inc. He
received his Bachelor of Science and Master of Science degrees in Petroleum
Engineering from the University of Texas. Mr. Smith received his Master of
Business Administration degree from the Wharton School of Business.



                                       38
<PAGE>

Item 11.  EXECUTIVE COMPENSATION
          ----------------------

         The following table shows the annual and long-term compensation for
services in all capacities to the Company during the fiscal years ended December
31, 2001, 2000 and 1999 of the Company's Chief Executive Officer and its other
four most highly compensated executive officers.

                           SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                                                      Long-Term
                                                                                     Compensation
                                             Annual Compensation                         Awards
                               --------------------------------------------------   --------------
                                                                                     No. of Shares
                                                                     Other Annual      Underlying       All Other
Name and Principal Position    Year      Salary        Bonus         Compensation     Options/SARs    Compensation(1)
----------------------------   -----    ---------   ----------       ------------   --------------    ---------------

<S>                            <C>      <C>          <C>                <C>            <C>              <C>
John L. Schwager               2001     $ 317,692    $ 292,277(7)        $   --         100,000         $  8,500
President and                  2000       308,654      157,500               --          66,692            8,500
Chief Executive Officer        1999       173,077      300,000               --         139,383          113,358(2)

Richard R. Hoffman(8)          2001       145,385       83,769               --          82,500           43,742(3)
Senior Vice President of
Exploration and Production

Leo A. Schrider                2001       145,948       58,380               --              --            8,500
Senior Vice President of       2000       142,777       36,487            1,370(6)       27,500            7,804
Technical Development          1999       133,000       13,300               --          55,000(4)         7,635

Robert W. Peshek               2001       164,915       90,703               --          17,500            8,500
Vice President of Finance and  2000       144,721       40,851               --          27,500            8,500
Chief Financial Officer        1999       110,617       13,000               --          55,000(5)         5,531

David M. Becker                2001       139,644       41,893               --              --            7,831
Vice President of              2000       128,180       33,181               --          10,000            6,809
Michigan Operations            1999       117,996       11,120               --          20,000            5,900
</TABLE>

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

(1)      Represents contributions of cash and common stock to the Company's
         401(k) Profit Sharing Plan for the account of the named executive
         officer.

(2)      Includes moving expenses of $113,358.

(3)      Includes moving expenses of $41,373.

(4)      Includes options for 54,946 shares originally granted in 1997 and
         repriced in 1999 plus options for 54 shares granted in 1999.

(5)      Includes options for 25,000 shares originally granted in 1997 and
         repriced in 1999 plus 30,000 options granted in 1999.

(6)      Includes amounts related to taxes from a prior year paid by the Company
         on behalf of the named executive.

(7)      For financial statement presentation purposes, the Company has accrued
         an additional bonus of $165,000 for Mr. Schwager. This represents one
         half of the retention bonus payable to Mr. Schwager on June 30, 2002 if
         he is still an employee of the Company on that date. The $292,277
         represents the annual performance bonus paid to Mr. Schwager.

(8)      Mr. Hoffman joined the Company in March 2001.



                                       39
<PAGE>


                     OPTION/SAR GRANTS IN LAST FISCAL YEAR

<TABLE>
<CAPTION>
                          Number of    Percentage of Total
                            Shares        Options/SARs
                          Underlying       Granted to      Exercise or
                         Options/SARs     Employees in      Base Price   Expiration     Grant Date
        Name               Granted        Fiscal Year       per Share       Date         Value(1)
---------------------   -------------   ----------------   -----------   -----------    -----------

<S>                          <C>              <C>            <C>          <C>           <C>
John L. Schwager              25,000           6.97%         $ 3.59       02/07/11      $ 26,500(2)
John L. Schwager              25,000                           2.14       12/05/11        14,750(2)
John L. Schwager              75,000          20.92%           2.14       12/05/11        44,250
Richard R. Hoffman            82,500          23.01%           3.59       03/05/11        84,975(3)
Richard R. Hoffman            82,500                           2.14       12/31/11        50,325(3)
Robert W. Peshek              17,500           4.88%           2.14       12/31/11        10,675
</TABLE>

(1)      This is a hypothetical valuation using the Black-Scholes valuation
         method. The Company's use of this model should not be considered as an
         endorsement of its accuracy at valuing options. All stock option
         valuation methods, including the Black-Scholes model, require a
         prediction about the future movement of the stock price. Since all
         options are granted at an exercise price equal to the market value of
         the Company's common stock, as determined by the Company on that date,
         no value will be realized if there is no appreciation in the market
         price of the stock. The value for these stock options was estimated at
         the date of grant using a Black-Scholes option pricing model with the
         following weighted-average assumptions: risk-free interest rate of
         5.0%; volatility factor of the expected market price of the Company's
         common stock of near zero; dividend yield of zero; and a
         weighted-average expected life of the option of seven years. See Note 9
         to the Consolidated Financial Statements.

(2)      The granted option for 25,000 shares had a value of $26,500 on the
         grant date of February 7, 2001. These options were repriced on
         December 5, 2001 to $2.14, resulting in a new fair value of $14,750 on
         the repricing date.

(3)      The granted option for 82,500 shares had a value of $84,975 on the
         grant date of March 5, 2001. These options were repriced on
         December 31, 2001 to $2.14, resulting in a new fair value of $50,325 on
         the repricing date.

               AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
                     AND FISCAL YEAR-END OPTION/SAR VALUES

<TABLE>
<CAPTION>

                                                                                                  Value of Unexercised
                                                  Number of Shares Underlying Unexercised             In-the-Money
                          Shares                        Options/SARs at FY-End                   Options/SARs at FY-End
                        Acquired on     Value     ---------------------------------------     ----------------------------
Name                     Exercise     Realized     Exercisable              Unexercisable     Exercisable    Unexercisable
------------------      -----------   --------    ------------              -------------     -----------    -------------
<S>                     <C>           <C>          <C>                      <C>                <C>             <C>
John L. Schwager        39,203        $135,991     26,134                   191,471            $53,923        $186,993
Richard R. Hoffman          --              --         --                    82,500                 --              --
Leo A. Schrider             --              --     82,500                        --            170,225              --
Robert W. Peshek            --              --     29,219                    57,031             59,830          81,107
David M. Becker             --              --     10,625                    14,375             21,757          29,494
</TABLE>




                                       40
<PAGE>




                        TEN-YEAR OPTIONS/SAR REPRICING



<TABLE>
<CAPTION>
                                                              Market
                                        Number of Shares     Price of                                          Number of Months
                                           Underlying        Stock at       Exercise Price                 of Original Option Term
                                           Options/SARs       Time of         at Time of        New            Remaining at Date
                            Date of        Repriced or       Repricing       Repricing or     Exercise           of Repricing
Name                       Repricing         Amended       or Amendment(1)     Amendment        Price            or Amendment
----------------------   -------------      ---------      --------------     -----------   -------------  -----------------------
<S>                         <C>               <C>            <C>            <C>             <C>               <C>
John L. Schwager            12/05/01          25,000         $   2.14       $    3.59       $   2.14          110 (2)
Richard R. Hoffman          12/31/01          82,500             2.14            3.59           2.14          111 (3)
Leo A. Schrider             10/01/99          20,000             0.01           10.82           0.01           98 (4)
Robert W. Peshek            10/01/99          25,000             0.01           10.82           0.01           98 (4)
Duane D. Clark              10/01/99          15,000             0.01           10.82           0.01           98 (4)
David M. Becker             10/01/99          15,000             0.01           10.82           0.01           98 (4)
John G. Corp                10/01/99          15,000             0.01           10.82           0.01           98 (4)
William F. Murray           10/01/99          15,000             0.01           10.82           0.01           98 (4)
</TABLE>

(1)      Under the stock option plan, options cannot be issued for less than
         fair market value at the time of a grant. Since the Company's stock is
         not actively traded, the Company has determined the value of the stock
         at October 1, 1999 to be $.01 per share and to be $2.14 per share at
         December 5, 2001 and December 31, 2001. These values were the basis for
         the repricings.

(2)      Options were originally granted on February 7, 2001, leaving 110 months
         remaining from the original grant date.

(3)      Options were originally granted on March 5, 2001, leaving 111 months
         remaining from the original grant date.

(4)      Options were originally granted on December 1, 1997, leaving 98 months
         remaining from the original grant date.


COMPENSATION OF DIRECTORS
         The outside directors of the Company are compensated $7,500 per quarter
for their services. Directors employed by the Company or by TPG are not
compensated for their services.

EMPLOYMENT AND SEVERANCE AGREEMENTS
         Effective July 1, 2001, John Schwager's employment agreement with the
Company was amended and restated (the "Agreement"). The term of the Agreement is
for three years, subject to extension by mutual agreement.

         Under the Agreement, Mr. Schwager is entitled to base compensation of
$325,000 per annum beginning July 1, 2001 with an increase of $25,000 beginning
on January 1, 2003. The Agreement provides for an incentive based bonus, at the
discretion of the Board of Directors, of up to 100% of base compensation. There
is no minimum incentive based bonus established in the Agreement. The Agreement
also provides for an annual retention bonus of $330,000 each year during the
term of the Agreement. The annual retention bonus is accelerated and payable in
the event of change in control which is defined as any occurrence which would
cause TPG's fully diluted equity ownership to drop below 35%. The Agreement
further provides for a special retention bonus of $1,000,000, should a change of
control occur during or within six months after the expiration of the Agreement,
unless Mr. Schwager is employed as the chief executive officer of the surviving
company.


                                       41
<PAGE>

         Either Mr. Schwager or the Company may terminate the Agreement at any
time, with or without cause. If Mr. Schwager terminates his employment or is
removed for cause, he will not be entitled to receive any compensation or
severance pay except for the base compensation, benefits, bonuses and expense
reimbursements that have accrued up to and including the final day of his
employment with the Company. If the Company terminates Mr. Schwager's employment
without cause or if he resigns for good reason (as defined in the Agreement),
Mr. Schwager will be entitled to receive monthly payments of 150% of his base
salary plus the remaining annual retention bonus payments and continued health
care benefits at the Company's expense for two years. In the event of a change
of control, all of the aforementioned payments become due and payable at the
closing. With the exception of the cost of health care benefits, the amounts
payable to Mr. Schwager as outlined above cannot exceed $1,990,000. Mr. Schwager
is also entitled to receive an additional payment plus any associated interest
and penalties (the "gross up") sufficient to cover any tax imposed by Section
4999 of the Internal Revenue Code on payments made under the Agreement.

         On February 7, 2001, Mr. Schwager was granted an option to purchase
25,000 shares of the common stock of the Company at $3.59 per share which were
repriced on December 5, 2001 at $2.14 per share. He was also granted an option
to purchase 75,000 shares of the common stock of the Company on December 5, 2001
at $2.14 per share. One fourth of the option shares shall become exercisable on
the last day of each calendar quarter commencing June 30, 2003, provided that he
is then an employee or director of the Company.

         On December 21, 2001, the Company and Leo A. Schrider entered into a
Letter of Agreement for Mr. Schrider's transition into retirement. During the
transition period from January 2, 2002 through December 31, 2003, Mr. Schrider
will work as a part-time employee of the Company, performing such duties as may
be assigned. During the transition period, Mr. Schrider will be entitled to
receive the full base salary per year that he was receiving as of December 31,
2001.

         Under the Company's 1999 Severance Pay Plan, all employees whose
employment is terminated by the Company without "cause" (as defined therein) are
eligible to receive severance benefits ranging from four weeks to twenty-four
months, depending on their years of service and position with the Company. Under
the Plan, Messrs. Becker, Hoffman and Peshek would be eligible to receive
severance pay ranging from twelve months to twenty-four months.

         The Company has a 1999 Change in Control Protection Plan for Key
Employees providing severance benefits for such employees if, within six months
prior to a change in control or within two years thereafter, their employment is
terminated without "cause" (as defined therein) or if they resign in response to
a reduction in duties, responsibilities, position, compensation or medical
benefits or a change in the location of their place of work as defined in the
agreement. Such benefits range from twelve months to twenty-four months,
depending on their position with the Company. Under the Plan, Messrs. Becker,
Hoffman and Peshek would be eligible to receive severance pay of twenty-four
months.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
         The Compensation and Organization Committee consisted of three outside
directors, William S. Price III, Gareth Roberts and Henry S. Belden IV. On
September 12, 2001 Mr. Belden resigned his position of director, leaving Mr.
Price and Mr. Roberts as the remaining committee members. No executive officer
of the Company was a director or member of a compensation committee of any
entity of which a member of the Company's Board of Directors was or is an
executive member.




                                       42
<PAGE>


Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND  MANAGEMENT
          ---------------------------------------------------------------

         The following table sets forth certain information as of February 28,
2002 regarding the beneficial ownership of the Company's common stock by each
person who beneficially owns more than five percent of the Company's outstanding
common stock, each director, the chief executive officer and the four other most
highly compensated executive officers and by all directors and executive
officers of the Company, as a group:

<TABLE>
<CAPTION>
                                                                                          PERCENTAGE OF
                  FIVE PERCENT SHAREHOLDERS                       NUMBER OF SHARES           SHARES
-------------------------------------------------------------    ------------------     ----------------
<S>                                                               <C>                        <C>
TPG Advisors II, Inc.
201 Main Street, Suite 2420
Fort Worth, Texas 76102                                              9,353,038(1)               88.7%

State Treasurer of the State of Michigan, Custodian of the
Public School Employees' Retirement System, State Employees
Retirement System, Michigan State Police Retirement System
and Michigan Judges Retirement System
430 West Allegan
Lansing, MI 48922                                                      554,376                   5.3%

                    OFFICERS AND DIRECTORS
-------------------------------------------------------------
William S. Price, III                                                9,353,038(1)               88.7%
John L. Schwager                                                       130,670(2)                1.2%
Lawrence W. Kellner                                                        -0-                   -0-
Gareth Roberts                                                             -0-                   -0-
Robert S. Maust                                                            -0-                   -0-
Jeffrey C. Smith                                                           -0-                   -0-
Richard R. Hoffman                                                         -0-                   -0-
Robert W. Peshek                                                        48,126(2)                 *
Leo A. Schrider                                                         82,500(2)                 *
David M. Becker                                                         17,500(2)                 *
All directors and executive
   officers (13) as a group                                          9,684,334                  91.8%
</TABLE>

* Less than 1%

(1)      Neither TPG Advisors II, Inc. nor Mr. Price is the record owner of any
         shares of the Company's common stock. Mr. Price is, however, a
         director, executive officer and shareholder of TPG Advisors II, Inc.,
         which is the general partner of TPG GenPar II, L.P., which in turn is
         the general partner of each of TPG Partners II, L.P., TPG Investors II,
         L.P. and TPG Parallel II, L.P. which are the direct beneficial owners
         of 7,976,645, 832,047 and 544,346 shares of common stock, respectively.

(2)      Consists of shares subject to stock options exercisable within 60 days
         by Mr. Schwager as to 13,066 shares, Mr. Peshek as to 34,376 shares,
         Mr. Schrider as to 82,500 shares and Mr. Becker as to 12,500 shares.







                                       43
<PAGE>


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         In connection with the merger with TPG in 1997, the Company entered
into a Transaction Advisory Agreement with TPG Partners II, L.P. pursuant to
which TPG Partners II, L.P. received a cash financial advisory fee of $5.0
million upon the closing of the merger as compensation for its services as
financial advisor in connection with the merger. TPG Partners II, L.P. also will
be entitled to receive (but, at its discretion, may waive) fees of up to 1.5% of
the "transaction value" for each subsequent transaction (a tender offer,
acquisition, sale, merger, exchange offer, recapitalization, restructuring or
other similar transaction) in which the Company is involved. The term
"transaction value" means the total value of any subsequent transaction,
including, without limitation, the aggregate amount of the funds required to
complete the subsequent transaction (excluding any fees payable pursuant to the
Transaction Advisory Agreement and fees, if any, paid to any other person or
entity for financial advisory, investment banking, brokerage or any other
similar services rendered in connection with such transaction) including the
amount of any indebtedness, preferred stock or similar items assumed (or
remaining outstanding). The Transaction Advisory Agreement shall continue until
the earlier of (i) 10 years from the execution date or (ii) the date on which
TPG Partners II, L.P. and its affiliates cease to own, beneficially, directly or
indirectly, at least 25% of the voting power of the securities of the Company.
In management's opinion, the fees provided for under the Transaction Advisory
Agreement reasonably reflect the benefits received and to be received by the
Company.



                                       44
<PAGE>


                                     PART IV
                                     -------

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

         (a)      Documents filed as a part of this report:

         1.  Financial Statements

         The financial statements listed in the accompanying Index to
Consolidated Financial Statements and Schedules are filed as part of this Annual
Report on Form 10-K.

         2.  Financial Statement Schedules

         No financial statement schedules are required to be filed as part of
this Annual Report on Form 10-K.

         3.  Exhibits

No.                               Description
---                               -----------

2.1      Agreement and Plan of Merger dated as of March 27, 1997 by and among
         TPG Partners II, BB Merger Corp. and Belden & Blake
         Corporation--incorporated by reference to Exhibit 2.1 to the Company's
         Registration Statement on Form S-4 (Registration No. 333-33407)

3.1      Amended and Restated Articles of Incorporation of Belden & Blake
         Corporation (fka Belden & Blake Energy Corporation)--incorporated by
         reference to Exhibit 3.1 to the Company's Registration Statement on
         Form S-4 (Registration No. 333-33407)

3.2      Code of Regulations of Belden & Blake Corporation --incorporated by
         reference to Exhibit 3.2 to the Company's Registration Statement on
         Form S-4 (Registration No. 333-33407)

4.1      Indenture dated as of June 27, 1997 between the Company, the Subsidiary
         Guarantors and LaSalle National Bank, as trustee, relating to the Notes
         --incorporated by reference to Exhibit 4.1 to the Company's
         Registration Statement on Form S-4 (Registration No. 333-33407)

4.2      Registration Rights Agreement dated as of June 27, 1997 between the
         Company, the Guarantors and Chase Securities, Inc. --incorporated by
         reference to Exhibit 4.2 to the Company's Registration Statement on
         Form S-4 (Registration No. 333-33407)

4.3      Form of 9 7/8% Senior Subordinated Notes due 2007, Original Notes
         (included in Exhibit 4.1)--incorporated by reference to Exhibit 4.3 to
         the Company's Registration Statement on Form S-4 (Registration No.
         333-33407)

4.4      Form of 9 7/8% Senior Subordinated Notes due 2007, Exchange Notes
         (included in Exhibit 4.1)--incorporated by reference to Exhibit 4.4 to
         the Company's Registration Statement on Form S-4 (Registration No.
         333-33407)


                                       45
<PAGE>

10.1(a)  Peake Energy, Inc. Stock Purchase Agreement between the Company and
         North Coast Energy, Inc. --incorporated by reference to Exhibit 10.1 to
         the Company's Quarterly Report on Form 10-Q for the quarter ended March
         31, 2000.

10.1(b)  Credit Agreement dated as of August 23, 2000 by and among the Company,
         Ableco Finance LLC and Foothill Capital Corporation. --incorporated by
         reference to Exhibit 10.1 to the Company's Quarterly Report on Form
         10-Q for the quarter ended September 30, 2000.

10.1(c)* Amendment to the Credit Agreement dated as of June 29, 2001 by and
         among the Company, Ableco Finance LLC and Foothill Capital Corporation.

10.2     Transaction Advisory Agreement dated as of June 27, 1997 by and between
         the Company and TPG Partners II, L.P. --incorporated by reference to
         Exhibit 10.2 to the Company's Registration Statement on Form S-4
         (Registration No. 333-33407)

10.3     Retirement and noncompetition agreement dated May 26, 1999 by and
         between the Company and Ronald L. Clements --incorporated by reference
         to Exhibit 10.3(b) to the Company's Annual Report on Form 10-K for the
         year ended December 31, 1999.

10.5     Belden & Blake Corporation 1997 Non-Qualified Stock Option
         Plan--incorporated by reference to Exhibit 10.5 to the Company's
         Registration Statement on Form S-4 (Registration No. 333-33407)

10.7     Change in Control Severance Pay Plan for Key Employees of the Company
         dated August 12, 1999 --incorporated by reference to Exhibit 10.7 to
         the Company's Annual Report on Form 10-K for the year ended December
         31, 1999.

10.8     Severance Pay Plan for Employees of Belden & Blake Corporation dated
         August 12, 1999 --incorporated by reference to Exhibit 10.8 to the
         Company's Annual Report on Form 10-K for the year ended December 31,
         1999.

10.10    Employment Agreement dated June 1, 1999 and amended November 1, 1999 by
         and between the Company and John L. Schwager --incorporated by
         reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K
         for the year ended December 31, 1999.

10.11*   Amended and Restated Employment Agreement dated July 1, 2001 by and
         between the Company and John L. Schwager.

10.12*   Letter of Agreement dated December 21, 2001 by and between the Company
         and Leo A. Schrider.

21*      Subsidiaries of the Registrant

23*      Consent of Independent Auditors

*Filed herewith



                                       46
<PAGE>


         (b)      Reports on Form 8-K

         On November 14, 2001 the Company filed a Current Report on Form 8-K
dated November 13, 2001 related to Regulation FD disclosures.

         (c)      Exhibits required by Item 601 of Regulation S-K

         Exhibits required to be filed by the Company pursuant to Item 601 of
Regulation S-K are contained in the Exhibits listed under Item 14(a)3.

         (d)      Financial Statement Schedules required by Regulation S-X

         The items listed in the accompanying index to financial statements are
filed as part of this Annual Report on Form 10-K.



                                       47
<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.

                                   BELDEN & BLAKE CORPORATION


March 21, 2002                     By:   /s/ John L. Schwager
---------------------------------      ----------------------------------------
Date                                     John L. Schwager, Director, 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>
<S>                                         <C>                                <C>
     /s/ John L. Schwager                   Director, President                March 21, 2002
-------------------------------------       and Chief Executive Officer        --------------
John L. Schwager                            (Principal Executive Officer)      Date



     /s/ Robert W. Peshek                   Vice President Finance and         March 21, 2002
-------------------------------------       Chief Financial Officer            --------------
Robert W. Peshek                            (Principal Financial and           Date
                                            Accounting Officer)



     /s/ Lawrence W. Kellner                Director                           March 21, 2002
-------------------------------------                                          --------------
Lawrence W. Kellner                                                            Date


     /s/ Robert S. Maust                    Director                           March 21, 2002
-------------------------------------                                          --------------
Robert S. Maust                                                                Date


     /s/ William S. Price, III              Director                           March 13, 2002
-------------------------------------                                          --------------
William S. Price, III                                                          Date


     /s/ Gareth Roberts                     Director                           March 21, 2002
-------------------------------------                                          --------------
Gareth Roberts                                                                 Date


     /s/ Jeffrey C. Smith                   Director                           March 15, 2002
-------------------------------------                                          --------------
Jeffrey C. Smith                                                               Date
</TABLE>




                                       48
<PAGE>


                           BELDEN & BLAKE CORPORATION
                              INDEX TO CONSOLIDATED
                       FINANCIAL STATEMENTS AND SCHEDULES

                             ITEM 14(a)(1) AND (2)


CONSOLIDATED FINANCIAL STATEMENTS                                         Page

     Report of Independent Auditors.....................................   F-2
     Consolidated Balance Sheets as of December 31, 2001 and 2000.......   F-3
     Consolidated Statements of Operations:
       Years ended December 31, 2001, 2000 and 1999.....................   F-4
     Consolidated Statements of Shareholders' Equity (Deficit):
       Years ended December 31, 2001, 2000 and 1999.....................   F-5
     Consolidated Statements of Cash Flows:
       Years ended December 31, 2001, 2000 and 1999.....................   F-6
     Notes to Consolidated Financial Statements.........................   F-7


All financial statement schedules have been omitted since the required
information is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the financial
statements.





                                      F-1
<PAGE>
                         REPORT OF INDEPENDENT AUDITORS





To the Shareholders and Board of Directors
Belden & Blake Corporation

We have audited the accompanying consolidated balance sheets of Belden & Blake
Corporation ("Company") as of December 31, 2001 and 2000, and the related
consolidated statements of operations, shareholders' equity (deficit) and cash
flows for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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 Belden & Blake
Corporation at December 31, 2001 and 2000 and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.

As discussed in Note 4 to the Consolidated Financial Statements, on January 1,
2001, Belden & Blake Corporation adopted Statements of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities."




                                          ERNST & YOUNG LLP


Cleveland, Ohio
March 13, 2002



                                      F-2
<PAGE>


                           BELDEN & BLAKE CORPORATION
                           CONSOLIDATED BALANCE SHEETS
                        (IN THOUSANDS, EXCEPT SHARE DATA)

<TABLE>
<CAPTION>
                                                                                         DECEMBER 31,
                                                                                 ---------------------------
                                                                                   2001              2000
                                                                                 ---------         ---------
<S>                                                                              <C>               <C>
ASSETS
------
CURRENT ASSETS
  Cash and cash equivalents                                                      $   1,935         $   1,798
  Accounts receivable, net                                                          14,160            22,620
  Inventories                                                                        1,695             2,222
  Deferred income taxes                                                                 --             1,475
  Other current assets                                                               1,094             1,448
  Fair value of derivatives                                                         19,965                --
                                                                                 ---------         ---------
            TOTAL CURRENT ASSETS                                                    38,849            29,563

PROPERTY AND EQUIPMENT, AT COST
  Oil and gas properties (successful efforts method)                               446,977           413,824
  Gas gathering systems                                                             14,094            13,445
  Land, buildings, machinery and equipment                                          24,113            23,469
                                                                                 ---------         ---------
                                                                                   485,184           450,738
  Less accumulated depreciation, depletion and amortization                        233,396           208,435
                                                                                 ---------         ---------
            PROPERTY AND EQUIPMENT, NET                                            251,788           242,303
FAIR VALUE OF DERIVATIVES                                                            3,748                --
OTHER ASSETS                                                                        10,964            13,251
                                                                                 ---------         ---------
                                                                                 $ 305,349         $ 285,117
                                                                                 =========         =========

LIABILITIES AND SHAREHOLDERS' DEFICIT
-------------------------------------
CURRENT LIABILITIES
  Accounts payable                                                               $   5,253         $   5,926
  Accrued expenses                                                                  14,465            19,316
  Current portion of long-term liabilities                                             156               141
  Deferred income taxes                                                              5,470                --
                                                                                 ---------         ---------
            TOTAL CURRENT LIABILITIES                                               25,344            25,383

LONG-TERM LIABILITIES
  Bank and other long-term debt                                                     59,415            61,535
  Senior subordinated notes                                                        225,000           225,000
  Other                                                                                330               323
                                                                                 ---------         ---------
                                                                                   284,745           286,858

DEFERRED INCOME TAXES                                                               22,539            21,189

SHAREHOLDERS' DEFICIT
  Common stock without par value; $.10 stated value per share; authorized
     58,000,000 shares; issued 10,425,103 and 10,357,255 shares
     (which includes 135,369 and 53,972 treasury shares, respectively)               1,029             1,030
  Paid in capital                                                                  107,402           107,921
  Deficit                                                                         (150,797)         (157,264)
  Accumulated other comprehensive income                                            15,087                --
                                                                                 ---------         ---------
            TOTAL SHAREHOLDERS' DEFICIT                                            (27,279)          (48,313)
                                                                                 ---------         ---------
                                                                                 $ 305,349         $ 285,117
                                                                                 =========         =========
</TABLE>

See accompanying notes.



                                      F-3
<PAGE>

                           BELDEN & BLAKE CORPORATION
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                  YEAR ENDED DECEMBER 31,
                                                                     -------------------------------------------------
                                                                       2001                2000                1999
                                                                     ---------           ---------           ---------
<S>                                                                  <C>                 <C>                 <C>
REVENUES
   Oil and gas sales                                                 $  95,395           $  79,743           $  79,299
   Gas gathering, marketing, and oilfield sales and service             34,087              34,850              51,445
   Other                                                                 2,048               3,258               5,017
                                                                     ---------           ---------           ---------
                                                                       131,530             117,851             135,761
EXPENSES
   Production expense                                                   22,649              20,917              21,980
   Production taxes                                                      2,372               2,409               3,260
   Gas gathering, marketing, and oilfield sales and service             29,382              31,703              46,977
   Exploration expense                                                   8,346               8,528               6,442
   General and administrative expense                                    4,395               4,617               5,412
   Franchise, property and other taxes                                     250                 397                 652
   Depreciation, depletion and amortization                             27,332              27,460              41,412
   Impairment of oil and gas properties and other assets                 1,398                 477                  --
   Severance and other nonrecurring expense                              1,954                 241               3,285
                                                                     ---------           ---------           ---------
                                                                        98,078              96,749             129,420
                                                                     ---------           ---------           ---------
OPERATING INCOME                                                        33,452              21,102               6,341

OTHER (INCOME) EXPENSE
   (Gain) loss on sale of subsidiaries and other income                     --             (15,064)              1,521
   Interest expense                                                     27,476              29,473              34,302
                                                                     ---------           ---------           ---------
                                                                        27,476              14,409              35,823
                                                                     ---------           ---------           ---------
INCOME (LOSS) BEFORE INCOME TAXES AND
   EXTRAORDINARY ITEM                                                    5,976               6,693             (29,482)
   (Benefit) provision for income taxes                                   (491)              2,368             (11,179)
                                                                     ---------           ---------           ---------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM                                  6,467               4,325             (18,303)
   Extraordinary item - early extinguishment of debt,
     net of tax benefit                                                     --              (1,364)                 --
                                                                     ---------           ---------           ---------
NET INCOME (LOSS)                                                    $   6,467           $   2,961           $ (18,303)
                                                                     =========           =========           =========
</TABLE>

See accompanying notes.


                                      F-4
<PAGE>

                           BELDEN & BLAKE CORPORATION
            CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                                            ACCUMULATED
                                                                                                              OTHER         TOTAL
                                                           COMMON       COMMON     PAID IN                COMPREHENSIVE    EQUITY
                                                           SHARES       STOCK      CAPITAL      DEFICIT       INCOME      (DEFICIT)
                                                           ------       ------     --------    ---------  -------------   ---------

<S>                                                        <C>         <C>         <C>            <C>        <C>          <C>
JANUARY 1, 1999                                            10,111       $1,011     $107,897    $(141,922)    $     --     $(33,014)

Net loss                                                                                         (18,303)                  (18,303)
Stock options exercised                                        31            3                                                   3
Stock-based compensation                                      118           12         (288)                                  (276)
------------------------------------------------------     ------       ------     --------    ---------     --------     --------
DECEMBER 31, 1999                                          10,260        1,026      107,609     (160,225)          --      (51,590)

Net income                                                                                         2,961                     2,961
Stock options exercised                                        97           10           (9)                                     1
Stock-based compensation                                                                336                                    336
Treasury stock                                                (54)          (6)         (15)                                   (21)
------------------------------------------------------     ------       ------     --------    ---------     --------     --------
DECEMBER 31, 2000                                          10,303        1,030      107,921     (157,264)          --      (48,313)

Comprehensive income:
Net income                                                                                         6,467                     6,467
Other comprehensive income, net of tax:
  Cumulative effect of accounting change                                                                       (6,691)      (6,691)
  Change in derivative fair value                                                                              24,667       24,667
  Reclassification adjustments - contract settlements                                                          (2,889)      (2,889)
                                                                                                                          ---------
Total comprehensive income                                                                                                  21,554
                                                                                                                          ---------
Stock options exercised                                        68            7           (1)                                     6
Stock-based compensation                                                                275                                    275
Repurchase of stock options                                                            (772)                                  (772)
Tax benefit of repurchase of stock options
    and stock options exercised                                                         260                                    260
Treasury stock                                                (81)          (8)        (281)                                  (289)
------------------------------------------------------     ------       ------     --------    ---------     --------     --------
DECEMBER 31, 2001                                          10,290       $1,029     $107,402    $(150,797)     $15,087     $(27,279)
======================================================     ======       ======     ========    =========     ========     ========
</TABLE>

See accompanying notes.


                                      F-5
<PAGE>

                           BELDEN & BLAKE CORPORATION
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31,
                                                                    -----------------------------------
                                                                       2001         2000         1999
                                                                    ---------    ---------    ---------
<S>                                                                 <C>          <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
   Net income (loss)                                                $   6,467    $   2,961    $ (18,303)
   Adjustments to reconcile net income (loss) to net cash
     provided by operating activities:
        Net loss on early extinguishment of debt                           --        1,364           --
        Depreciation, depletion and amortization                       27,332       27,460       41,412
        Impairment of oil and gas properties and other assets           1,398          477           --
        (Gain) loss on sale of subsidiaries                                --      (13,794)       1,521
        Loss on disposal of property and equipment                         92          500          136
        Exploration expense                                             8,346        8,528        6,442
        Deferred income taxes                                            (605)       2,077      (11,179)
        Stock-based compensation                                          275          169         (565)
        Change in operating assets and liabilities, net of
          effects of disposition of subsidiaries:
             Accounts receivable and other operating assets             9,200         (442)       8,580
             Inventories                                                  571         (674)       2,413
             Accounts payable and accrued expenses                     (5,001)        (102)      (7,867)
                                                                    ---------    ---------    ---------
              NET CASH PROVIDED BY OPERATING ACTIVITIES                48,075       28,524       22,590

CASH FLOWS FROM INVESTING ACTIVITIES:
   Acquisition of businesses, net of cash acquired                     (2,149)          --           --
   Disposition of businesses, net of cash                                 897       69,031        7,887
   Proceeds from property and equipment disposals                       1,162          218        3,011
   Exploration expense                                                 (8,346)      (8,528)      (6,442)
   Additions to property and equipment                                (35,730)     (18,624)      (2,996)
   (Increase) decrease in other assets                                    (81)         (83)       2,140
                                                                    ---------    ---------    ---------
              NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES     (44,247)      42,014        3,600

CASH FLOWS FROM FINANCING ACTIVITIES:
   Proceeds from revolving line of credit and term loan               181,645      123,096       21,000
   Repayment of long-term debt and other obligations                 (184,071)    (190,814)     (50,582)
   Debt issue costs                                                      (210)      (5,537)      (2,766)
   Proceeds from stock options exercised                                    6           --            3
   Repurchase of stock options                                           (772)          --           --
   Purchase of treasury stock                                            (289)         (21)          --
                                                                    ---------    ---------    ---------
              NET CASH USED IN FINANCING ACTIVITIES                    (3,691)     (73,276)     (32,345)
                                                                    ---------    ---------    ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                      137       (2,738)      (6,155)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                        1,798        4,536       10,691
                                                                    ---------    ---------    ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD                          $   1,935    $   1,798    $   4,536
                                                                    =========    =========    =========
</TABLE>

See accompanying notes.


                                      F-6
<PAGE>

                           BELDEN & BLAKE CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)      BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
--------
         Belden & Blake Corporation (the "Company") is a privately held company
owned by TPG Partners II L.P. ("TPG") and certain other investors. The Company
operates in the oil and gas industry. The Company's principal business is the
production, development, acquisition and marketing and gathering of oil and gas
reserves. Sales of oil are ultimately made to refineries. Sales of natural gas
are ultimately made to gas utilities and industrial consumers in Ohio, Michigan,
Pennsylvania and New York. The price of oil and natural gas has a significant
impact on the Company's working capital and results of operations.

PRINCIPLES OF CONSOLIDATION AND FINANCIAL PRESENTATION
------------------------------------------------------
         The accompanying consolidated financial statements include the
financial statements of the Company and its subsidiaries. All significant
intercompany accounts and transactions have been eliminated in consolidation.
Certain reclassifications have been made to conform to the presentation in 2001.

USE OF ESTIMATES IN THE FINANCIAL STATEMENTS
--------------------------------------------
         The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts. Significant estimates used in the
preparation of the Company's financial statements which could be subject to
significant revision in the near term include estimated oil and gas reserves.
Although actual results could differ from these estimates, significant
adjustments to these estimates historically have not been required.

CASH EQUIVALENTS
----------------
         For purposes of the statements of cash flows, cash equivalents are
defined as all highly liquid investments purchased with an initial maturity of
three months or less.

CONCENTRATIONS OF CREDIT RISK
-----------------------------
         Credit limits, ongoing credit evaluation and account monitoring
procedures are utilized to minimize the risk of loss. Collateral is generally
not required. Expected losses are provided for currently and actual losses have
been within management's expectations.

INVENTORIES
-----------
         Inventories of material, pipe and supplies are valued at average cost.
Crude oil and natural gas inventories are stated at the lower of average cost or
market.

PROPERTY AND EQUIPMENT
----------------------
         The Company utilizes the "successful efforts" method of accounting for
its oil and gas properties. Under this method, property acquisition and
development costs and certain productive exploration costs are capitalized while
non-productive exploration costs, which include certain geological and
geophysical costs, exploratory dry holes and costs of carrying and retaining
unproved properties, are expensed as incurred. Capitalized costs related to
proved properties are depleted using the unit-of-production method.
Depreciation, depletion and amortization of proved oil and gas properties is
calculated on the basis of estimated recoverable reserve quantities. These
estimates can change based on economic or other factors. No gains or losses are
recognized upon the disposition of oil and gas properties except in
extraordinary transactions. Sales proceeds are credited to the carrying value of
the properties. Maintenance and repairs are expensed, and expenditures which
enhance the value of properties are capitalized.


                                      F-7
<PAGE>

         Unproved oil and gas properties are stated at cost and consist of
undeveloped leases. These costs are assessed periodically to determine whether
their value has been impaired, and if impairment is indicated, the costs are
charged to expense. Impairments recorded in 2001 and 2000 were $179,000 and
$477,000, respectively, which reduced the book value of unproved oil and gas
properties to their estimated fair value.

         Gas gathering systems are stated at cost. Depreciation expense is
computed using the straight-line method over 15 years.

         Property and equipment are stated at cost. Depreciation of non-oil and
gas properties is computed using the straight-line method over the useful lives
of the assets ranging from 3 to 15 years for machinery and equipment and 30 to
40 years for buildings. When assets other than oil and gas properties are
retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in
income for the period. The cost of maintenance and repairs is expensed as
incurred, and significant renewals and betterments are capitalized.

         Long-lived assets are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable. If the sum of the expected future undiscounted cash flows is less
than the carrying amount of the asset, a loss is recognized for the difference
between the fair value and the carrying amount of the asset. In performing the
review for long-lived asset recoverability during 2001, the Company recorded
$1.2 million of impairments which reduced the book value of producing properties
to their estimated fair value. Fair value was based on estimated future cash
flows to be generated by the assets, discounted at a market rate of interest. No
impairment was recorded in 2000 or 1999.

INTANGIBLE ASSETS
-----------------
         Intangible assets totaling $9.5 million at December 31, 2001, include
deferred debt issuance costs, goodwill and other intangible assets and are being
amortized over 25 years or the shorter of their respective terms.

REVENUE RECOGNITION
-------------------
         Oil and gas production revenue is recognized as production and delivery
take place. Oil and gas marketing revenues are recognized when title passes.
Oilfield sales and service revenues are recognized when the goods or services
have been provided.

INCOME TAXES
------------
         The Company uses the liability method of accounting for income taxes.
Deferred income taxes are provided for temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and
the amounts used for income tax purposes. Deferred income taxes also are
recognized for operating losses that are available to offset future taxable
income and tax credits that are available to offset future federal income taxes.

STOCK-BASED COMPENSATION
------------------------
         The Company measures expense associated with stock-based compensation
under the provisions of Accounting Principles Board Opinion No. (APB) 25,
"Accounting for Stock Issued to Employees" and its related interpretations.

         In March 2000, the Financial Accounting Standards Board (FASB) issued
FASB Interpretation No. (FIN) 44, "Accounting for Certain Transactions involving
Stock Compensation, an interpretation of APB 25." The Interpretation, which has
been adopted prospectively as of July 1, 2000, requires that stock


                                      F-8
<PAGE>

options that have been modified to reduce the exercise price be accounted for as
variable. Prior to the adoption of the Interpretation, the Company accounted for
these repriced stock options as fixed. The effect of adopting the Interpretation
was to increase compensation expense by $298,000 in the second half of the year
ended December 31, 2000.

         The Company repriced 318,892 stock options (298,392 outstanding prior
to July 1, 2000) in October 1999, and reduced the exercise price to $0.01 per
share. Under the Interpretation, the options are accounted for as variable from
July 1, 2000 until the options are exercised, forfeited or expire unexercised.
The Company repriced 227,500 stock options in December 2001, which had been
granted in 2001 at $3.59 per share and reduced the exercise price to $2.14 per
share.

         The definition of a public company under FIN 44 is less restrictive
than previous practice. Specifically, a company with publicly-traded debt, but
not publicly-traded equity securities, would not be considered public. Prior to
July 1, 2000, Belden & Blake Corporation common stock held in the 401(k) plan
was subject to variable plan accounting.

         The changes in share value are reported as adjustments to compensation
expense. The change in share value in 2001 and 2000 resulted in an increase in
compensation expense of $275,000 and $336,000, respectively. The reduction in
share value in 1999 resulted in a reduction in compensation expense of $858,000.

DERIVATIVES AND HEDGING
-----------------------
         On January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. (SFAS) 133, "Accounting for Derivative Instruments and
Hedging Activities" which was issued in June, 1998 by the FASB, as amended by
SFAS 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of Effective Date of SFAS 133" and SFAS 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" issued in June 1999 and
June 2000, respectively. SFAS 133, as amended, was applied as the cumulative
effect of an accounting change effective January 1, 2001.

         As a result of the adoption of SFAS 133, the Company recognizes all
derivative financial instruments as either assets or liabilities at fair value.
Derivative instruments that are not hedges must be adjusted to fair value
through net income (loss). Under the provisions of SFAS 133, changes in the fair
value of derivative instruments that are fair value hedges are offset against
changes in the fair value of the hedged assets, liabilities, or firm
commitments, through net income (loss). Changes in the fair value of derivative
instruments that are cash flow hedges are recognized in other comprehensive
income (loss) until such time as the hedged items are recognized in net income
(loss). Ineffective portions of a derivative instrument's change in fair value
are immediately recognized in net income (loss). Deferred gains and losses on
terminated commodity hedges will be recognized as increases or decreases to oil
and gas revenues during the same periods in which the underlying forecasted
transactions are recognized in net income (loss). See Note 4.

         The relationship between the hedging instruments and the hedged items
must be highly effective in achieving the offset of changes in fair values or
cash flows attributable to the hedged risk, both at the inception of the
contract and on an ongoing basis. The Company measures effectiveness on changes
in the hedge's intrinsic value. The Company considers these hedges to be highly
effective and expects there will be no ineffectiveness to be recognized in net
income (loss) since the critical terms of the hedging instruments and the hedged
forecasted transactions are the same. Ongoing assessments of hedge effectiveness
will include verifying and documenting that the critical terms of the hedge and
forecasted transaction do not change. The Company measures effectiveness at
least on a quarterly basis.



                                      F-9
<PAGE>

         The adoption of SFAS 133 resulted in a January 1, 2001, transition
adjustment to increase other current liabilities by $10.5 million, increase
current deferred income taxes by $3.8 million and increase shareholders' deficit
by $6.7 million to record the fair value of open cash flow hedges and the
related income tax effect. The increase in shareholders' deficit is reflected as
a cumulative effect of accounting change in accumulated other comprehensive
income (loss).

         Prior to January 1, 2001, under the deferral method, gains and losses
from derivative instruments that qualified as hedges were deferred until the
underlying hedged asset, liability or transaction monetized, matured or was
otherwise recognized under generally accepted accounting principles. When
recognized in net income (loss), hedge gains and losses were included as an
adjustment to gas revenue or interest expense.

(2)      NEW ACCOUNTING PRONOUNCEMENTS
         In July 2001, the FASB issued Statements of Financial Accounting
Standards No. 141, "Business Combinations," and SFAS 142, "Goodwill and Other
Intangible Assets." The adoption of SFAS 141 as of July 1, 2001 had no effect on
the Company's financial position, results of operations or cash flows. SFAS 141
eliminates the pooling-of-interests method of accounting for business
combinations except for qualifying business combinations that were initiated
prior to July 1, 2001. SFAS 141 further clarifies the criteria to recognize
intangible assets separately from goodwill. The requirements of SFAS 141 are
effective for any business combination accounted for by the purchase method that
was completed after June 30, 2001.

         Under SFAS 142, goodwill and indefinite lived intangible assets are no
longer amortized but are reviewed for impairment annually or if certain
impairment indicators arise. Separable intangible assets that are not deemed to
have an indefinite life will continue to be amortized over their useful lives
(but with no maximum life). The amortization provisions of SFAS 142 apply to
goodwill and intangible assets acquired after June 30, 2001. With respect to
goodwill and intangible assets acquired prior to July 1, 2001, the Company is
required to adopt SFAS 142 on January 1, 2002. Early adoption is not permitted
for calendar year companies.

         At December 31, 2001, the Company had $2.7 million of unamortized
goodwill which will be subject to the transition provisions of SFAS 142.
Amortization expense related to goodwill amounted to $130,000, $132,000 and
$208,000 for the years ended December 31, 2001, 2000 and 1999, respectively. The
Company is currently assessing the impact of SFAS 142 and has not yet determined
whether adoption will have a material effect on the Company's financial
position, results of operations or cash flows including any transitional
impairment losses which would be required to be recognized as the effect of a
change in accounting principle.

         In August 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 addresses obligations associated with the
retirement of tangible, long-lived assets and the associated asset retirement
costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies", and is effective for the Company's financial
statements beginning January 1, 2003. The Company is currently assessing the
impact of SFAS 143 and has not yet determined whether adoption will have a
material effect on the Company's financial position, results of operations or
cash flows.

         In October 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which establishes a single
accounting model to be used for long-lived assets to be disposed of. The new
rules supersede SFAS 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of." Although retaining many of the
fundamental recognition and measurement provisions of SFAS 121, the new rules
significantly change the criteria that would have


                                      F-10
<PAGE>

to be met to classify an asset as held-for-sale. This distinction is important
because assets to be disposed of are stated at the lower of their fair values or
carrying amounts and depreciation is no longer recognized. The new rules also
will supersede the provisions of APB 30, "Reporting Results of Operations -
Reporting the Effects of Disposal of a Segment of Business," with regard to
reporting the effects of a disposal of a segment of a business and will require
the expected future operating losses from discontinued operations to be
displayed in discontinued operations in the periods in which the losses are
incurred rather than as of the measurement date as presently required by APB 30.
In addition, more dispositions will qualify for discontinued operations
treatment in the income statement. SFAS 144 is effective as of January 1, 2002.
The adoption of this standard is not expected to have a material effect on the
Company's financial position, results of operations or cash flows.

(3)      SALE OF SUBSIDIARIES
         On March 17, 2000, the Company sold the stock of Peake Energy, Inc.
("Peake"), a wholly owned subsidiary, to North Coast Energy, Inc., an
independent oil and gas company. The sale included substantially all of the
Company's oil and gas properties in West Virginia and Kentucky. The sale
resulted in net proceeds of approximately $69.2 million. The Company recorded a
$13.7 million gain on the sale in 2000.

         At December 31, 1999, using Securities and Exchange Commission ("SEC")
pricing parameters, Peake had proved developed reserves of approximately 66.5
Bcfe (billion cubic feet of natural gas equivalent) and proved undeveloped
reserves of approximately 3.7 Bcfe. At the time of the sale, Peake's reserves
represented 20.2% of the Company's total proved reserves. The unaudited pro
forma results of operations of the Company for the years ended December 31, 2000
and 1999 are as follows: revenues of $113.8 million and $118.2 million,
respectively. The pro forma effects on net income were not material. The
unaudited pro forma information presented above assumes the disposition occurred
prior to each period presented and does not purport to be indicative of the
results that actually would have been obtained and is not intended to be a
projection of future results or trends.

         In November 1999, the Company sold Belden Energy Services Company
("BESCO"), its Ohio retail natural gas marketing subsidiary, to FirstEnergy
Corp. In the future, that portion of the Company's Ohio natural gas production
not committed to existing sales contracts will be sold on the wholesale market.
The Company recorded a $1.3 million gain on the sale in 1999.

         In August 1999, the Company and its wholly owned subsidiary, The Canton
Oil and Gas Company ("COG"), completed a stock sale of Target Oilfield Pipe and
Supply ("TOPS"), a wholly owned subsidiary of COG, to an oilfield supply
company. The buyer purchased all of the issued and outstanding shares of capital
stock of TOPS from COG. The Company recorded a $2.8 million loss on the sale in
1999.

(4)      DERIVATIVES AND HEDGING
         On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. As a result of the
adoption of SFAS 133, the Company recognizes all derivative financial
instruments as either assets or liabilities at fair value. Derivative
instruments that are not hedges must be adjusted to fair value through net
income (loss). Under the provisions of SFAS 133, changes in the fair value of
derivative instruments that are fair value hedges are offset against changes in
the fair value of the hedged assets, liabilities, or firm commitments, through
net income (loss). Changes in the fair value of derivative instruments that are
cash flow hedges are recognized in other comprehensive income (loss) until such
time as the hedged items are recognized in net income (loss). The hedging
relationship between the hedging instruments and hedged item must be highly
effective in achieving the offset of changes in fair values or cash flows
attributable to the hedged risk both at the inception of the contract and on an
ongoing basis. The Company measures effectiveness at least on a


                                      F-11
<PAGE>

quarterly basis. Ineffective portions of a derivative instrument's change in
fair value are immediately recognized in net income (loss). If there is a
discontinuance of a cash flow hedge because it is probable that the original
forecasted transaction will not occur, deferred gains or losses are recognized
in earnings immediately.

         From time to time the Company may enter into a combination of futures
contracts, commodity derivatives and fixed-price physical contracts to manage
its exposure to natural gas or oil price volatility. The Company employs a
policy of hedging gas production sold under New York Mercantile Exchange
("NYMEX") based contracts by selling NYMEX based commodity derivative contracts
which are placed with major financial institutions that the Company believes are
minimal credit risks. The contracts may take the form of futures contracts,
swaps, collars or options. At December 31, 2001, the Company's derivative
contracts consisted of natural gas swaps and natural gas costless collars. All
of these NYMEX based derivative contracts were designated as cash flow hedges.

         Adoption of SFAS 133 on January 1, 2001 resulted in recording a $10.5
million ($6.7 million net of tax) net liability related to the decline in fair
value of the Company's derivative financial instruments with a corresponding
reduction in shareholders' equity to other comprehensive loss. The net liability
consisted of $11.8 million in current fair value of derivative liabilities and
$1.3 million in current fair value of derivative assets. The fair value of
derivative assets and liabilities represents the difference between hedged
prices and market prices on hedged volumes of natural gas as of December 31,
2001. During 2001, a net gain on contract settlements of $4.5 million ($2.9
million after tax) was reclassified from accumulated other comprehensive income
to earnings and the fair value of open hedges increased by $38.8 million ($24.7
million after tax). At December 31, 2001, the estimated net gains in accumulated
other comprehensive income that are expected to be reclassified into earnings
within the next 12 months are approximately $20.0 million. The Company has
partially hedged its exposure to the variability in future cash flows through
December 2003.

         On January 17 and 18, 2002, the Company monetized and restructured
9,350 Bbtu (Billion British thermal units) of its 2002 and 3,840 Bbtu of its
2003 natural gas hedge positions for net proceeds of $21.7 million. See Note 19.

(5)      SEVERANCE AND OTHER NONRECURRING EXPENSE
         Effective April 1, 2001, certain senior management members of the
Company accepted early retirements. These retirements resulted in a cash charge
of approximately $760,000 and an additional non-cash charge of approximately
$100,000 related to the acceleration of certain stock options.

         The Company recorded a net nonrecurring charge of $2.0 million in 2001
which includes a charge of $2.3 million primarily related to these retirement
agreements and other retirement and severance charges incurred which included
non-cash charges totaling approximately $200,000 due to the acceleration of
certain related stock options. In 2001, the Company recognized approximately
$300,000 in other nonrecurring gains.

         The Company expensed approximately $241,000 and $880,000 in 2000 and
1999, respectively, for costs primarily associated with investment banking fees,
an abandoned acquisition effort and the abandonment of a proposed public
offering of a royalty trust.

         In September 1999, the Company implemented a plan to reduce costs and
improve operating efficiencies. The plan included actions to bring the Company's
employment level in line with current and anticipated future staffing needs
which resulted in staff reductions of approximately 10%. The Company recorded a
charge of $2.4 million in 1999 for severance and other costs associated with
implementing this plan.


                                      F-12
<PAGE>


(6)      DETAILS OF BALANCE SHEETS



                                                        DECEMBER 31,
                                                -------------------------
                                                   2001              2000
                                                ---------       ---------
ACCOUNTS RECEIVABLE                                    (IN THOUSANDS)
     Accounts receivable                        $   6,701       $  12,333
     Allowance for doubtful accounts               (1,684)         (1,245)
     Oil and gas production receivable              8,614          11,358
     Current portion of notes receivable              529             174
                                                ---------       ---------
                                                $  14,160       $  22,620
                                                =========       =========
INVENTORIES
     Oil                                        $   1,352       $   1,272
     Natural gas                                       27             104
     Material, pipe and supplies                      316             846
                                                ---------       ---------
                                                $   1,695       $   2,222
                                                =========       =========
PROPERTY AND EQUIPMENT, GROSS
  OIL AND GAS PROPERTIES
     Producing properties                       $ 419,206       $ 390,229
     Non-producing properties                      12,097           7,676
     Other                                         15,674          15,919
                                                ---------       ---------
                                                $ 446,977       $ 413,824
                                                =========       =========
  LAND, BUILDINGS, MACHINERY AND EQUIPMENT
     Land, buildings and improvements           $   5,526       $   5,632
     Machinery and equipment                       18,587          17,837
                                                ---------       ---------
                                                $  24,113       $  23,469
                                                =========       =========
ACCRUED EXPENSES
     Accrued expenses                           $   4,877       $   5,901
     Accrued drilling and completion costs            827           1,624
     Accrued income taxes                              93             481
     Ad valorem and other taxes                     1,903           2,449
     Compensation and related benefits              2,748           2,685
     Undistributed production revenue               4,017           6,176
                                                ---------       ---------
                                                $  14,465       $  19,316
                                                =========       =========

                                     F-13




<PAGE>

(7)      LONG-TERM DEBT
         Long-term debt consists of the following (in thousands):



                                                      DECEMBER 31,
                                               ------------------------
                                                 2001           2000
                                               --------       --------
          Revolving line of credit             $ 59,292       $ 61,393
          Senior subordinated notes             225,000        225,000
          Other                                     142            161
                                               --------       --------
                                                284,434        286,554
          Less current portion                       19             19
                                               --------       --------
          Long-term debt                       $284,415       $286,535
                                               ========       ========

         On June 27, 1997, the Company completed a private placement (pursuant
to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A,
which mature on June 15, 2007 ("the Notes"). The Notes were issued under an
indenture which requires interest to be paid semiannually on June 15 and
December 15 of each year, commencing December 15, 1997. The Notes are
subordinate to the senior revolving credit agreement. In September 1997, the
Company completed a registration statement on Form S-4 providing for an exchange
offer under which each Series A Senior Subordinated Note would be exchanged for
a Series B Senior Subordinated Note. The terms of the Series B Notes are the
same in all respects as the Series A Notes except that the Series B Notes have
been registered under the Securities Act of 1933 and therefore will not be
subject to certain restrictions on transfer.

         The Notes are redeemable in whole or in part at the option of the
Company, at any time on or after the dates below, at the redemption prices set
forth plus, in each case, accrued and unpaid interest, if any, thereon.

            June 15, 2002....................................... 104.938%
            June 15, 2003....................................... 103.292%
            June 15, 2004....................................... 101.646%
            June 15, 2005 and thereafter........................ 100.000%

         The indenture under which the subordinated notes were issued contains
certain covenants that limit the ability of the Company and its subsidiaries to
incur additional indebtedness and issue stock, pay dividends, make
distributions, make investments, make certain other restricted payments, enter
into certain transactions with affiliates, dispose of certain assets, incur
liens securing indebtedness of any kind other than permitted liens, and engage
in mergers and consolidations.

         On December 14, 1999, the Company and its bank group amended its senior
revolving credit facility. The revolving credit commitment in the amended
agreement provided for a $75 million revolving portion which would have matured
on June 27, 2002 and a $50 million term portion which would have matured on
March 31, 2000. Proceeds from the Peake sale were used to repay the term portion
and repay and permanently reduce the revolving credit commitment. In March 2000,
the Company obtained the unanimous consent of its bank group to further amend
the revolving credit agreement to establish a borrowing base of $62.7 million
and to forego the May 2000 borrowing base redetermination.

         On August 23, 2000, the Company obtained a new $125 million credit
facility ("the Facility") comprised of a $100 million revolving credit facility
("the Revolver") and a $25 million term loan (the



                                      F-14
<PAGE>

"Term Loan"). The Facility allowed for up to $40 million ($25 million under the
Term Loan and $15 million under the Revolver) to be used to purchase the
Company's outstanding 9 7/8% senior subordinated notes due 2007. No amounts were
drawn under the Term Loan. The Term Loan commitment terminated on December 26,
2000 and the Company wrote off approximately $740,000 of unamortized deferred
loan costs in 2000 due to the modification of borrowing capacity. The Revolver
bears interest at the prime rate plus two percentage points, payable monthly. At
December 31, 2001, the interest rate was 6.75%. Up to $30 million in letters of
credit may be issued pursuant to the conditions of the Revolver. At December 31,
2001, the Company had $2.3 million of outstanding letters of credit.

         Initial proceeds from the Revolver of approximately $66 million in 2000
were used to pay outstanding loans and interest due under the Company's former
credit facility of approximately $46 million; repay a term loan of $14 million
to Chase Manhattan Bank; pay fees and expenses associated with the new credit
facility of approximately $4 million; and to close out certain natural gas
hedging transactions with Chase Manhattan Bank. Due to the payment of the
outstanding loans under the former credit facility the Company took a charge of
$2.1 million ($1.4 million net of tax benefit) in 2000 representing the
unamortized deferred loan costs pertaining to the former credit facility. The
charge was recorded as an extraordinary item.

         On June 29, 2001, the Company amended the Revolver. The amendment
extended the Revolver's final maturity date to April 22, 2004, from August 23,
2002, increased the letter of credit sub-limit from $20 million to $30 million
and eliminated the effects of SFAS 133, "Accounting for Derivative Instruments
and Hedging Activities," from financial covenant calculations. The Company paid
approximately $200,000 in fees and expenses related to the amendment. At
December 31, 2001, the Company had $2.3 million of outstanding letters of
credit. At December 31, 2001, the outstanding balance under the credit agreement
was $59.3 million with $38.4 million of borrowing capacity available for general
corporate purposes.

         The amendment added an early termination fee equal to .25% of the
facility if terminated between the effective date and May 31, 2002. If
termination is after May 31, 2002 but on or before May 31, 2003, the termination
fee is .125% of the facility. There is no termination fee after May 31, 2003.
The Company is required to hedge, through financial instruments or fixed price
contracts, at least 20% but not more than 80% of its estimated hydrocarbon
production, on an Mcfe (thousand cubic feet of natural gas equivalent) basis,
for the succeeding 12 months on a rolling 12-month basis. Based on the Company's
hedges currently in place and its expected production levels, the Company is in
compliance with this hedging requirement through March 2003.

         The Revolver is secured by security interests and mortgages against
substantially all of the Company's assets and is subject to periodic borrowing
base determinations. The borrowing base is the lesser of $100 million or the sum
of (i) 65% of the value of the Company's proved developed producing reserves
subject to a mortgage; (ii) 45% of the value of the Company's proved developed
non-producing reserves subject to a mortgage; and (iii) 40% of the value of the
Company's proved undeveloped reserves subject to a mortgage. The price forecast
used for calculation of the future net income from proved reserves is the
three-year NYMEX strip for oil and natural gas as of the date of the reserve
report. Prices beyond three years are held constant. Prices are adjusted for
basis differential, fixed price contracts and financial hedges in place. The
present value (using a 10% discount rate) of the Company's future net income at
December 31, 2001, under the borrowing base formula above was approximately $196
million for all proved reserves of the Company and $146 million for properties
secured by a mortgage.

         The Revolver is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 3.7 to 1 at December 31, 2001,
to 3.2 to 1 at March 31, 2004; and a senior debt leverage ratio ranging from 2.6
to 1 and 3.2 to 1 for the periods from December 31, 2001 through


                                      F-15
<PAGE>

March 31, 2004. EBITDA, as defined in the Revolver, and consolidated interest
expense on senior debt in these ratios are calculated quarterly based on the
financial results of the previous four quarters. In addition, the Company is
required to maintain a current ratio (including available borrowing capacity in
current assets and excluding current debt and accrued interest from current
liabilities and excluding any effects from the application of SFAS 133 to other
current assets or current liabilities) of at least 1.0 to 1 and maintain
liquidity of at least $5 million (cash and cash equivalents including available
borrowing capacity). As of December 31, 2001, the Company's current ratio
including the above adjustments was 3.11 to 1. The Company had satisfied all
financial covenants as of December 31, 2001.

         From time to time the Company may enter into interest rate swaps to
hedge the interest rate exposure associated with the credit facility, whereby a
portion of the Company's floating rate exposure is exchanged for a fixed
interest rate. During October 1997, the Company entered into two interest rate
swap arrangements covering $90 million of debt. The Company swapped $40 million
of floating three-month LIBOR (London Interbank Offered Rate) for a fixed rate
of 7.485% (which includes an applicable margin of 1.5%) for three years,
extendible at the institution's option for an additional two years. The Company
also swapped $50 million of floating three-month LIBOR for a fixed rate of
7.649% (which includes an applicable margin of 1.5%) for five years. During June
1998, the Company entered into a third interest rate swap covering $50 million
of debt. The Company swapped $50 million of floating rate three-month LIBOR for
a fixed rate of 7.2825% (which includes an applicable margin of 1.5%) for three
years. On December 27, 1999, the Company terminated $20 million of the third
interest rate swap. On March 21, 2000, the Company terminated the second swap
and the remainder of the third swap for a total of $80 million which resulted in
a gain of $1.3 million. The remaining swap arrangements covering $40 million of
debt expired in October 2000.

         At December 31, 2001, the aggregate long-term debt maturing in the next
five years is as follows: $19,000 (2002); $19,000 (2003); $59,296,000 (2004);
$4,000 (2005); and $225,096,000 (2006 and thereafter).

(8)      LEASES
         The Company leases certain computer equipment, vehicles, natural gas
compressors and office space under noncancelable agreements with lease periods
of one to five years. Rent expense amounted to $2.9 million, $2.7 million and
$3.1 million for the years ended December 31, 2001, 2000 and 1999, respectively.

         The Company also leases certain computer equipment accounted for as
capital leases. Property and equipment includes $647,000 and $239,000 of
computer equipment under capital leases at December 31, 2001 and 2000,
respectively. Accumulated depreciation for such equipment includes approximately
$289,000 and $90,000 at December 31, 2001 and 2000, respectively.




                                      F-16
<PAGE>


         Future minimum commitments under leasing arrangements at December 31,
2001 were as follows:



                                                      OPERATING         CAPITAL
          YEAR ENDING DECEMBER 31,                      LEASES           LEASES
  -------------------------------------------------- --------------  -----------
                                                             (IN THOUSANDS)
  2002                                                  $1,252          $  137
  2003                                                     481             127
  2004                                                     414              62
  2005                                                     267              --
  2006 and thereafter                                       52              --
                                                        ------          -------
  Total minimum rental payments                         $2,466             326
                                                        ======
  Less amount representing interest                                          3
                                                                        ------
  Present value of net minimum rental payments                             323
  Less current portion                                                     137
                                                                        ------
  Long-term capitalized lease obligations                               $  186
                                                                        ======

(9)      STOCK OPTION PLANS
         In connection with the TPG merger, certain executives of the Company
agreed not to exercise or surrender certain stock options granted under the
Company's 1991 stock option plan. On June 27, 1997, these options were exchanged
for 165,083 in new stock options. As of December 31, 2001, none of these options
were outstanding. No additional options may be granted under the 1991 plan.

         The Company has a 1997 non-qualified stock option plan under which it
is authorized to issue up to 1,824,195 shares of common stock to officers and
employees. The exercise price of options may not be less than the fair market
value of a share of common stock on the date of grant. Options expire on the
tenth anniversary of the grant date unless cessation of employment causes
earlier termination. As of December 31, 2001, options to purchase 781,606 shares
were outstanding under the plan. These options, except for the 100,000 options
described below, become exercisable at a rate of one fourth of the shares one
year from the date of grant and an additional one twelfth of the remaining
shares on every three-month anniversary thereafter. The remaining 100,000
options become exercisable at a rate of one fourth of the shares on the last day
of each quarter commencing June 30, 2003.

         The Company has elected to follow Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees" and related Interpretations
in accounting for its employee stock options. As discussed below, the
alternative fair value accounting provided for under SFAS 123, "Accounting for
Stock-Based Compensation" requires use of option valuation models that were not
developed for use in valuing employee stock options. Under APB 25, no
compensation expense is recognized when the exercise price of the Company's
employee stock options equals the market price of the underlying stock on the
date of the grant. There were 358,500, 274,692 and 303,491 options granted in
2001, 2000 and 1999, respectively, and 227,500 and 318,892 options were repriced
in 2001 and 1999, respectively, which had an immaterial effect on compensation
expense in 2001 and 1999. As a result of adopting FIN 44, compensation expense
increased $298,000 in the second half of 2000.

         In December 2001, the Company repriced 227,500 stock options from an
exercise price of $3.59 to $2.14 per share.


                                      F-17
<PAGE>

         Pro forma information regarding net income is required by Statement
123, and has been determined as if the Company had accounted for its employee
stock options under the fair value method of that Statement. The fair value for
these stock options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for 2001,
2000 and 1999, respectively: risk-free interest rates of 5.0%, 6.4% and 6.2%;
volatility factor of the expected market price of the Company's common stock of
near zero; dividend yield of zero; and a weighted-average expected life of the
option of seven years.

         The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its stock options.

         For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The changes in
net income or loss for the years ended December 31, 2001, 2000 and 1999 were not
material.

         During 2001, certain employees that retired or were previously
terminated elected to put their vested stock options back to the Company. As a
result, the Company paid $772,000 to purchase and cancel 219,644 options.



                                      F-18
<PAGE>


         Stock option activity consisted of the following:

                                                                      WEIGHTED
                                                                       AVERAGE
                                                      NUMBER OF       EXERCISE
                                                        SHARES          PRICE
                                                      ---------       ---------
BALANCE AT DECEMBER 31, 1998                            817,707         $8.66
     Granted                                            303,491          1.26
     Forfeitures                                       (333,632)        10.82
     Exercised                                          (31,268)         0.13
     Reissued and repriced                             (318,892)        10.82
     Reissued and repriced                              318,892          0.01
                                                       --------
BALANCE AT DECEMBER 31, 1999                            756,298          0.53
     Granted                                            274,692          0.22
     Forfeitures                                        (65,000)         5.83
     Exercised                                          (96,798)         0.01
                                                       --------
BALANCE AT DECEMBER 31, 2000                            869,192          0.09
     Granted                                            358,500          3.14
     Forfeitures                                       (158,594)         0.56
     Exercised or put                                  (287,492)         0.08
     Reissued and repriced                             (227,500)         3.59
     Reissued and repriced                              227,500          2.14
                                                       --------
BALANCE AT DECEMBER 31, 2001                            781,606          0.97
                                                       ========
OPTIONS EXERCISABLE AT DECEMBER 31, 2001                225,322         $0.08
                                                       ========

         The weighted average fair value of options granted during 2001, 2000
and 1999 was $0.79, $0.07 and $0.50, respectively. The exercise price for the
options outstanding as of December 31, 2001 ranged from $0.01 to $2.14 per
share. At December 31, 2001, the weighted average remaining contractual life of
the outstanding options is 8.8 years.




                                      F-19
<PAGE>


(10)     TAXES
         The (benefit) provision for income taxes on income (loss) before
extraordinary item includes the following (in thousands):



                                      YEAR ENDED DECEMBER 31,
                              ---------------------------------------
                               2001             2000           1999
                              ------           ------        --------
         CURRENT
            Federal            $114             $290         $     --
            State                --                1               --
                              -----           ------         --------
                                114              291               --
         DEFERRED
            Federal            (600)           2,073          (10,449)
            State                (5)               4             (730)
                              -----           ------         --------
                               (605)           2,077          (11,179)
                              -----           ------         --------
            TOTAL             $(491)          $2,368         $(11,179)
                              =====           ======         ========

         The effective tax rate for income (loss) before extraordinary item
differs from the U.S. federal statutory tax rate as follows:

<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                           -------------------------------
                                                           2001          2000         1999
                                                           ----          ----         ----
<S>                                                       <C>           <C>           <C>
Statutory federal income tax rate                           35.0%        35.0%         35.0%
Increases (reductions) in taxes resulting from:
     State income taxes, net of federal tax benefit           --          1.8           2.0
     Settlement of IRS exam and other tax issues           (33.0)          --            --
     Change in valuation allowance                         (11.7)          --            --
     Other, net                                              1.5         (1.4)          0.9
                                                           -----        -----         -----
Effective income tax rate for the period                    (8.2)%       35.4%         37.9%
                                                           =====        =====         =====
</TABLE>

         During 2001, the Company concluded an IRS income tax examination of the
years 1994 through 1997 and favorably settled other tax issues. A federal income
tax benefit of $2.0 million was recorded as a result. Also during 2001, a
federal income tax benefit was recorded for approximately $700,000 along with a
corresponding reduction in the valuation allowance as a result of certain net
operating loss carryforwards which the Company now believes it can fully
utilize.




                                      F-20
<PAGE>


         Significant components of deferred income tax liabilities and assets
are as follows (in thousands):

<TABLE>
<CAPTION>
                                                         DECEMBER 31,        DECEMBER 31,
                                                            2001                 2000
                                                          --------             --------
<S>                                                       <C>                  <C>
Deferred income tax liabilities:
     Property and equipment, net                          $ 45,086             $ 45,065
     Fair value of derivatives                               8,627                   --
     Other, net                                              1,608                  753
                                                          --------             --------
         Total deferred income tax liabilities              55,321               45,818
Deferred income tax assets:
     Accrued expenses                                        1,338                1,192
     Net operating loss carryforwards                       25,401               25,372
     Tax credit carryforwards                                1,103                  990
     Other, net                                                610                  390
     Valuation allowance                                    (1,140)              (1,840)
                                                          --------             --------
         Total deferred income tax assets                   27,312               26,104
                                                          --------             --------
         Net deferred income tax liability                $ 28,009             $ 19,714
                                                          ========             ========

     Current liability                                    $  5,470             $     --
     Long-term liability                                    22,539               21,189
     Current asset                                              --               (1,475)
                                                          --------             --------
         Net deferred income tax liability                $ 28,009             $ 19,714
                                                          ========             ========
</TABLE>

         SFAS No. 109 requires a valuation allowance to be recorded when it is
more likely than not that some or all of the deferred tax assets will not be
realized. The valuation allowance at December 31, 2001 relates principally to
certain net operating loss carryforwards which management estimates will expire
before they can be utilized.

         At December 31, 2001, the Company had approximately $61 million of net
operating loss carryforwards available for federal income tax reporting
purposes. These net operating loss carryforwards, if unused, will expire in
2012, 2018 and 2019. The Company has alternative minimum tax credit
carryforwards of approximately $1.1 million which have no expiration date. The
Company has approximately $823,000 of statutory depletion carryforwards, which
have no expiration date.

(11)     PROFIT SHARING AND RETIREMENT PLANS
         The Company has a non-qualified profit sharing arrangement under which
the Company contributes discretionary amounts determined by the compensation
committee of its Board of Directors based on attainment of performance targets.
Amounts are allocated to substantially all employees based on relative
compensation. The Company expensed $1.4 million, $1.6 million and $845,000 for
the years ended December 31, 2001, 2000 and 1999, respectively, for
contributions to the profit sharing plan and discretionary bonuses. All amounts
were paid in cash.

         As of December 31, 2001, the Company has a qualified defined
contribution plan (a 401(k) plan) covering substantially all of the employees of
the Company. Under the plan, an amount equal to 2% of


                                      F-21
<PAGE>

participants' compensation is contributed by the Company to the plan each year.
Eligible employees may also make voluntary contributions which the Company
matches $0.50 for every $1.00 contributed up to 6% of an employee's annual
compensation. Retirement plan expense amounted to $550,000, $650,000 and
$830,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

         Effective January 1, 2002, the Company modified the 401(k) plan as
described above. Included as part of the modifications was the change in the
amount the Company matches on voluntary contributions which was increased to
$1.00 for every $1.00 contributed up to 4% of compensation and a $0.50 match for
every $1.00 contributed up to the next 2% of compensation. The previous
contribution made by the Company in the amount equal to 2% of participants'
compensation each year was eliminated as part of the modifications.

         The Company also has non-qualified deferred compensation plans which
permit certain key employees to elect to defer a portion of their compensation.

(12)     COMMITMENTS AND CONTINGENCIES
         In February 2000, four individuals filed a suit in Chautauqua County,
New York on their own behalf and on the behalf of others similarly situated,
seeking damages for the alleged difference between the amount of lease royalties
actually paid and the amount of royalties that allegedly should have been paid.
Other natural gas producers in New York were served with similar complaints. The
Company believes the complaint is without merit and is defending the complaint
vigorously. Although the outcome is still uncertain, the Company believes the
action will not have a material adverse effect on its financial position,
results of operations or cash flows.

         The Company is involved in various legal actions arising in the normal
course of business. In the opinion of management, the ultimate disposition of
these matters will not have a material adverse effect on the financial position,
results of operations or cash flows of the Company.

(13)     SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                      -------------------------------------
(IN THOUSANDS)                                         2001           2000           1999
                                                      -------        -------        -------
<S>                                                   <C>            <C>            <C>
CASH PAID DURING THE PERIOD FOR:
  Interest                                            $27,737        $30,634        $34,426
  Income taxes, net of refunds                            359              1             --

NON-CASH INVESTING AND FINANCING ACTIVITIES:
  Acquisition of assets in exchange for
     long-term liabilities                                443            239            125
  Non-compete agreement and related obligation             --             --            705
</TABLE>

(14)     FAIR VALUE OF FINANCIAL INSTRUMENTS
         The fair value of the financial instruments disclosed herein is not
representative of the amount that could be realized or settled, nor does the
fair value amount consider the tax consequences, if any, of realization or
settlement. The amounts in the financial statements for cash equivalents,
accounts receivable and notes receivable approximate fair value due to the short
maturities of these instruments.


                                      F-22
<PAGE>

The recorded amounts of outstanding bank and other long-term debt approximate
fair value because interest rates are based on LIBOR or the prime rate or due to
the short maturities. The $225 million in senior subordinated notes had an
approximate fair value of $180 million at December 31, 2001 based on quoted
market prices.

         From time to time the Company may enter into a combination of futures
contracts, commodity derivatives and fixed-price physical contracts to manage
its exposure to natural gas or oil price volatility. The Company employs a
policy of hedging gas production sold under NYMEX based contracts by selling
NYMEX based commodity derivative contracts which are placed with major financial
institutions that the Company believes are minimal credit risks. The contracts
may take the form of futures contracts, swaps, collars or options. At December
31, 2001, the Company's derivative contracts consisted of natural gas swaps and
natural gas costless collars. All of these NYMEX based derivative contracts are
designated as cash flow hedges. The Company incurred a pre-tax gain on its
hedging activities of $4.5 million in 2001, a pre-tax loss on its hedging
activities of $9.3 million in 2000 and a pre-tax gain of $1.2 million in 1999.
At December 31, 2001, the fair value of futures contracts covering 2002 and 2003
natural gas production represented an unrealized gain of $23.7 million.

(15)     SUPPLEMENTARY INFORMATION ON OIL AND GAS ACTIVITIES
         The following disclosures of costs incurred related to oil and gas
activities are presented in accordance with SFAS 69.


                                   YEAR ENDED DECEMBER 31,
                               -------------------------------
(IN THOUSANDS)                   2001        2000        1999
                               --------    --------     ------
Acquisition costs:
     Proved properties         $  2,399    $    220     $   --
     Unproved properties          5,574       2,093        855
Developmental costs              23,409      13,849        186
Exploratory costs                 8,346       8,528      6,442


PROVED OIL AND GAS RESERVES (UNAUDITED)
         The Company's proved developed and proved undeveloped reserves are all
located within the United States. The Company cautions that there are many
uncertainties inherent in estimating proved reserve quantities and in projecting
future production rates and the timing of development expenditures. In addition,
estimates of new discoveries are more imprecise than those of properties with a
production history. Accordingly, these estimates are expected to change as
future information becomes available. Material revisions of reserve estimates
may occur in the future, development and production of the oil and gas reserves
may not occur in the periods assumed, and actual prices realized and actual
costs incurred may vary significantly from those used. Proved reserves represent
estimated quantities of natural gas, crude oil and condensate that geological
and engineering data demonstrate, with reasonable certainty, to be recoverable
in future years from known reservoirs under economic and operating conditions
existing at the time the estimates were made. Proved developed reserves are
proved reserves expected to be recovered through wells and equipment in place
and under operating methods being utilized at the time the estimates were made.
The estimates of proved reserves as of December 31, 2001 and 2000 have been
reviewed by Wright & Company, Inc., independent petroleum engineers. The
estimates of proved reserves as of December 31, 1999 have been reviewed by Ryder
Scott Company Petroleum Consultants, independent petroleum engineers.



                                      F-23
<PAGE>


         The following table sets forth changes in estimated proved and proved
developed reserves for the periods indicated:


                                                       OIL                GAS

                                                    (Mbbl)(1)          (Mmcf)(2)
                                                   --------            --------
DECEMBER 31, 1998                                     4,243             315,259
Extensions and discoveries                               12                 416
Purchase of reserves in place                            --                  --
Sale of reserves in place                               (29)               (632)
Revisions of previous estimates                       3,186              18,636
Production                                             (713)            (26,988)
                                                   --------            --------
DECEMBER 31, 1999                                     6,699             306,691
Extensions and discoveries                              386              15,622
Purchase of reserves in place                            --               7,223
Sale of reserves in place                              (606)            (65,567)
Revisions of previous estimates                       2,766             129,597
Production                                             (592)            (20,037)
                                                   --------            --------
DECEMBER 31, 2000                                     8,653             373,529
Extensions and discoveries                              285              13,591
Purchase of reserves in place                            --              28,557
Sale of reserves in place                               (54)             (1,129)
Revisions of previous estimates                      (2,651)            (61,780)
Production                                             (646)            (18,541)
                                                   --------            --------
DECEMBER 31, 2001                                     5,587             334,227
                                                   ========            ========

PROVED DEVELOPED RESERVES
December 31, 1999                                     5,898             267,942
                                                   ========            ========
December 31, 2000                                     5,954             251,747
                                                   ========            ========
December 31, 2001                                     4,788             218,148
                                                   ========            ========

(1)  Thousand barrels
(2)  Million cubic feet


                                      F-24
<PAGE>


STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES (UNAUDITED)
         The following tables, which present a standardized measure of
discounted future net cash flows and changes therein relating to proved oil and
gas reserves, are presented pursuant to SFAS No. 69. In computing this data,
assumptions other than those required by the FASB could produce different
results. Accordingly, the data should not be construed as representative of the
fair market value of the Company's proved oil and gas reserves. The following
assumptions have been made:

         -    Future revenues were based on year-end oil and gas prices.
              Future price changes were included only to the extent provided
              by existing contractual agreements.
         -    Production and development costs were computed using year-end
              costs assuming no change in present economic conditions.
         -    Future net cash flows were discounted at an annual rate of 10%.
         -    Future income taxes were computed using the approximate
              statutory tax rate and giving effect to available net
              operating losses, tax credits and statutory depletion.

         The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves is presented below:


<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                 ---------------------------------------------------
                                                    2001                2000                 1999
                                                 -----------       -------------         -----------
                                                                   (IN THOUSANDS)
<S>                                              <C>                 <C>                 <C>
Estimated future cash inflows (outflows)
    Revenues from the sale of oil and gas        $ 1,075,151         $ 3,835,298         $   957,046
    Production and development costs                (527,377)           (805,025)           (411,881)
                                                 -----------         -----------         -----------
Future net cash flows before income taxes            547,774           3,030,273             545,165
Future income taxes                                 (133,992)         (1,037,843)           (124,561)
                                                 -----------         -----------         -----------
Future net cash flows                                413,782           1,992,430             420,604
10% timing discount                                 (231,920)         (1,171,666)           (203,716)
                                                 -----------         -----------         -----------
Standardized measure of discounted
    future net cash flows                        $   181,862         $   820,764         $   216,888
                                                 ===========         ===========         ===========
</TABLE>

         At December 31, 2001, as specified by the SEC, the prices for oil and
natural gas used in this calculation were regional cash price quotes on the last
day of the year except for volumes subject to fixed price contracts.



                                      F-25
<PAGE>


         The principal sources of changes in the standardized measure of future
net cash flows are as follows:


<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                  ---------------------------------------------------
                                                      2001                2000               1999
                                                  -----------         -----------         -----------
                                                                     (IN THOUSANDS)

<S>                                               <C>                 <C>                 <C>
Beginning of year                                 $   820,764         $   216,888         $   208,663
Sale of oil and gas, net of
    production costs                                  (72,132)            (56,416)            (54,059)
Extensions and discoveries, less
    related estimated future
    development and production costs                    8,721              69,990               1,233
Purchase of reserves in place less
    estimated future production costs                   7,924              13,383                  --
Sale of reserves in place less
    estimated future production costs                  (3,226)            (50,817)               (578)
Revisions of previous quantity estimates              (63,294)            445,976              31,128
Net changes in prices and production costs         (1,026,055)            608,442              32,836
Change in income taxes                                371,059            (363,561)             (2,729)
Accretion of 10% timing discount                      123,495              26,751              25,656
Changes in production rates (timing)
    and other                                          14,606             (89,872)            (25,262)
                                                  -----------         -----------         -----------
End of year                                       $   181,862         $   820,764         $   216,888
                                                  ===========         ===========         ===========
</TABLE>

(16)     INDUSTRY SEGMENT FINANCIAL INFORMATION
         The Company operates in one reportable segment, as an independent
energy company engaged in producing oil and natural gas; exploring for and
developing oil and gas reserves; acquiring and enhancing the economic
performance of producing oil and gas properties; and marketing and gathering
natural gas for delivery to intrastate and interstate gas transmission
pipelines. The Company's operations are conducted entirely in the United States.

MAJOR CUSTOMERS
---------------
         One customer accounted for more than 10% of consolidated revenues
during each of the years ended December 31, 2001 and 2000 sales to which
amounted to $21.0 million and $21.6 million, respectively. No customer accounted
for more than 10% of consolidated revenues during the year ended December 31,
1999.



                                      F-26
<PAGE>


(17)     QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
         The results of operations for the four quarters of 2001 and 2000 are
shown below (in thousands).

<TABLE>
<CAPTION>
                                                              FIRST           SECOND           THIRD            FOURTH
                                                             --------        --------         --------         --------
2001
----
<S>                                                          <C>             <C>              <C>              <C>
Sales and other operating revenues                           $ 34,654        $ 32,918         $ 30,373         $ 31,537
Gross profit                                                   11,109          10,300            8,505            5,840
Net income (loss)                                               2,062           3,792              682              (69)

<CAPTION>

                                                               FIRST          SECOND            THIRD           FOURTH
                                                             --------        --------         --------         --------
2000
----
<S>                                                          <C>             <C>              <C>              <C>
Sales and other operating revenues                           $ 28,238        $ 26,245         $ 26,508         $ 33,602
Gross profit                                                    4,887           4,179            5,793            7,743
Income (loss) before extraordinary item                         7,744          (1,698)          (1,175)            (546)
Net income (loss)                                               7,744          (1,698)          (2,535)            (550)
</TABLE>

         The Company reclassified certain gas marketing revenues in the fourth
quarter of 2000. This had no impact on gross profit or net income (loss). Prior
quarters in 2000 have been restated to conform to the current presentation. In
March 2000 the Company sold Peake. See Note 3.


(18)     SALE OF TAX CREDIT PROPERTIES
         In March 1998, the Company sold certain interests that qualify for the
nonconventional fuel source tax credit. The interests were sold for
approximately $730,000 in cash and a volumetric production payment under which
100% of the cash flow from the properties will go to the Company until
approximately 10.8 Bcf (billion cubic feet) of gas has been produced and sold.
In addition to receiving 100% of the cash flow from the properties, the Company
will receive quarterly incentive payments based on production from the interests
through 2002. The Company has the option to repurchase the interests after
December 31, 2002.

(19)     SUBSEQUENT EVENTS - NATURAL GAS HEDGE POSITION MONETIZATION AND
         RESTRUCTURING
         On January 17 and 18, 2002, the Company monetized 9,350 Bbtu of its
2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per
Mmbtu (million British thermal units) and 3,840 Bbtu of its 2003 natural gas
hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net
proceeds of $22.7 million that will be recognized as increases to natural gas
revenues during the same periods in which the underlying forecasted transactions
are recognized in net income (loss).

         In January 2002, the Company entered into a collar for 9,350 Bbtu of
its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a
floor price of $2.25 per Mmbtu. The Company also sold a floor at $1.75 per Mmbtu
on this volume of gas. This aggregate structure has the effect of: 1) setting a
maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per
Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and
$2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if
the price is $1.75 or less. All prices are based on monthly NYMEX settle. The
Company paid $1.0 million for the options.


                                      F-27
<PAGE>

         The Company used the net proceeds of $21.7 million from the two
transactions above to pay down on its credit facility. The following table
summarizes, as of January 21, 2002, the Company's deferred gains on terminated
natural gas hedges. Cash has been received and the deferred gains recorded in
accumulated other comprehensive income. The deferred gains will be recognized as
increases to gas revenues during the periods in which the underlying forecasted
transactions are recognized in net income (loss).


<TABLE>
<CAPTION>
                                                      2002                                 2003
                                 -------------------------------------------------       --------
                                  FIRST        SECOND        THIRD         FOURTH
                                 QUARTER       QUARTER      QUARTER        QUARTER
                                 -------       -------      -------        -------
                                                         (IN THOUSANDS)
<S>                               <C>           <C>           <C>           <C>           <C>
Natural Gas Hedges
Terminated in January 2002        $4,521        $5,620        $5,188        $4,560        $2,851
</TABLE>



                                      F-28