<PAGE>   1
                                   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, 2000
                                       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 of                              (I.R.S. Employer
incorporation or organization)                            Identification Number)

                               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, 2001, Belden & Blake Corporation had outstanding
10,303,159 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>   2


PART I
------

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

         Belden & Blake Corporation (the "Company") 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 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 Services 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. The sale resulted in net proceeds
of approximately $69.2 million, which were used to reduce bank debt. At December
31, 2000, the Company operated in Ohio, Pennsylvania, New York and Michigan.

         At December 31, 2000, the Company's net production was approximately
48.5 Mmcf (million cubic feet) of natural gas and 1,465 Bbls (barrels) of oil
per day. At that date, the Company owned interests in 6,337 gross (5,272 net)
productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with
proved reserves totaling 374 Bcf (billion cubic feet) of natural gas and 8.7
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 $1.2 billion at December 31, 2000. At December 31, 2000, the
Company operated approximately 5,817 wells, including wells operated for third
parties. At that date, the Company held leases on 990,904 gross (878,042 net)
acres, including 538,970 gross (467,675 net) undeveloped acres. The Company
owned and operated 1,741 miles of gas gathering systems with access to the
commercial and industrial gas markets of the northeastern United States at
December 31, 2000.

         The Company has a consistent and successful track record of reserve
replacement and growth through both drilling and acquisitions. Since its
formation in 1992 through December 31, 2000, the Company has added approximately
413 Bcfe (billion cubic feet of natural gas equivalent) of proved developed
reserves through drilling and acquisitions at an average cost of $.79 per Mcfe
(thousand cubic feet of natural gas equivalent). This represented approximately
207% of the oil and gas produced by the Company during that period.

         During 2000, the Company drilled 149 gross (104.1 net) wells at a
direct cost of approximately $17.0 million for the net wells. The 2000 drilling
activity added 17.9 Bcfe of proved developed reserves at an average cost of $.94
per Mcfe. Proved developed reserves added through drilling in 2000 represented
approximately 76% of 2000 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,



                                       1
<PAGE>   3


all references herein to the "Company" are to Belden & Blake Corporation, its
subsidiaries and predecessor entities.

SIGNIFICANT EVENTS

         When gas prices declined sharply in 1998, the Company's previous
lenders reduced its 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 .8 Bcfe of oil and gas reserves.

         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.

         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 "Term Loan"). The Facility has
a two year term. 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 ("the Notes").
No amounts were drawn under the Term Loan and the Term Loan commitment
terminated on December 26, 2000. The Revolver bears interest at the prime rate
plus two percentage points, payable monthly. Up to $20 million in letters of
credit may be issued pursuant to the conditions of the Revolver.

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 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 and Michigan) 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 5,500 feet. Drilling success rates of the Company and
others drilling in these formations historically have exceeded 90% with
production generally lasting longer than 20 years.



                                       2
<PAGE>   4


         The combination of long-lived production and high drilling success
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.
In addition, the Company is a pioneer in the production of methane from coalbed
formations in Pennsylvania.

         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 and production
opportunities in the Michigan Basin with an established operating company that
provided the critical mass to operate efficiently. Ward Lake currently operates
755 wells producing approximately 41 Mmcf (20 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 1,700 feet) blanket Antrim Shale formation. Success 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.




                                       3
<PAGE>   5


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; utilization of the Company's advanced technology to
enhance production and reserves discovered; and, further expansion of the
Company's natural gas gathering network. 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
     drilling in shallow blanket formations and development and exploratory
     drilling in deeper, more prolific formations. Coupled with its extensive
     knowledge of its operating areas, this broad portfolio approach allows the
     Company to optimize economic returns and minimize much of the geological
     risk associated with oil and gas exploration and development. The result is
     analogous to a manufacturing process, in that the Company is able to
     predict with a high degree of accuracy the expected reserve additions and
     overall finding costs of its drilling activities. 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 and has established a
     substantial leasehold position overlying potentially productive coalbed
     methane formations in western Pennsylvania. The Company's drilling budget
     in 2001 is approximately $29.2 million, which is expected to fund the
     drilling of approximately 158 gross (150.9 net) wells to shallow blanket
     formations and 47 gross (24.7 net) wells to the deeper more prolific
     formations in the Appalachian and Michigan Basins.

-    IMPROVE THE COMPANY'S FINANCIAL POSITION. At December 31, 2000, the Company
     had a deficit in shareholders' equity of $48.3 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 consider attempting 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 success rates at the shallow depths has resulted in a highly
     fragmented, extensively drilled, low technology operating environment in
     the Appalachian Basin. The Company has been applying more advanced
     technology, including 3-D seismic, horizontal drilling, advanced fracturing
     techniques and enhanced oil recovery methods. The Company is implementing
     these techniques to improve drilling success 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 intends to improve its
     profit margins on the production from existing and acquired properties
     through advanced production technologies, operating efficiencies,
     mechanical improvements and the use of enhanced recovery techniques.
     Through its production field offices, the Company continuously 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 reduce 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



                                       4
<PAGE>   6


     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.

-    EXPAND NATURAL GAS GATHERING. The Company's extensive gas gathering systems
     are an integral part of the Company's business strategy. The Company
     currently operates approximately 1,489 miles of natural gas gathering lines
     in Ohio, Pennsylvania and New York and 252 miles of lines in Michigan, all
     of which are connected or have the ability to connect to various intrastate
     and interstate natural gas transmission and distribution systems. The
     interconnections with these pipelines affords the Company access to
     numerous major gas markets, including existing and proposed electric power
     generating facilities. It is the Company's intention to expand its gas
     gathering systems to further improve the rate of return on the Company's
     drilling and development activities. The Company has excellent business
     relationships with a number of utilities and industrial end users located
     within the Company's operating areas, providing it with a direct outlet for
     a portion of its natural gas production.

-    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 substantially all 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 enhanced and secondary recovery techniques.

         The Company currently maintains production field offices in Ohio,
Pennsylvania, New York and Michigan. Through these offices, the Company
continuously reviews its properties to determine what action can be taken to
reduce operating costs and/or improve production. The Company also uses
secondary recovery techniques, which typically involve methods of oil extraction
in which external energy sources are applied to extract additional 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.




                                       5
<PAGE>   7


         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,
                                          -------------------------------------------------------------
                                           1996         1997         1998          1999          2000
                                          -------      -------      -------       -------       -------
<S>                                       <C>          <C>          <C>           <C>           <C>
Production:
      Gas (Bcf)                              25.4         27.2         30.1          27.0          20.0
      Oil (Mbbl)(1)                           719          753          768           713           592
Average sales price:
      Gas (per Mcf)(2)                    $  2.56      $  2.65      $  2.57       $  2.50       $  3.17
      Oil (per barrel)                      20.24        18.10        12.61         16.57         27.29
      Mcfe                                   2.67         2.70         2.51          2.54          3.38
Average production costs per Mcfe
(including production taxes)                 0.72         0.78         0.77          0.80          0.99
Operating margin per Mcfe                    1.95         1.92         1.74          1.74          2.39
Total oil and gas revenues
(in thousands)                             79,491       85,756       87,055        79,299        79,743
Total production expenses
(in thousands)                             21,266       24,668       26,725        25,240        23,326
</TABLE>

         (1)  Thousand barrels
         (2)  Thousand cubic feet

         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,
                                          -------------------------------------------------------------
                                           1996         1997         1998          1999          2000
                                          -------      -------      -------       -------       -------
<S>                                       <C>          <C>          <C>           <C>           <C>
Production:
      Gas (Bcf)                              21.8         22.9         24.5          21.5          18.9
      Oil (Mbbl)                              612          658          686           642           576
Average sales price:
      Gas (per Mcf)                       $  2.48      $  2.57      $  2.48       $  2.50       $  3.20
      Oil (per barrel)                      20.23        18.04        12.57         16.51         27.36
      Mcfe                                   2.61         2.63         2.43          2.54          3.41
Average production costs per Mcfe
(including production taxes)                 0.72         0.77         0.74          0.81          1.00
Operating margin per Mcfe                    1.89         1.86         1.69          1.73          2.41
Total oil and gas revenues
(in thousands)                             66,297       70,635       69,458        64,489        76,252
Total production expenses
(in thousands)                             18,243       20,598       21,239        20,602        22,272
</TABLE>




                                       6
<PAGE>   8


         Gas Gathering. The Company currently operates approximately 1,741 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 major gas markets. The Company's
gas gathering revenues totaled $3.1 million in 2000. Direct costs associated
with gas gathering in 2000 totaled $1.5 million.

EXPLORATION AND DEVELOPMENT

         The Company's exploration and development activities include
development drilling in the highly developed or blanket formations and
development and exploratory drilling in 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 2000, the Company drilled 111 gross (86.2 net) wells to highly
developed or shallow blanket formations in its four state operating area at a
direct cost of approximately $11.5 million for the net wells. The Company also
drilled 38 gross (17.9 net) wells to less developed and deeper formations in
2000 at a direct cost of approximately $5.5 million for the net wells. The
result of this drilling activity is shown in the table on page 12.

         In 2001, the Company expects to spend approximately $29.2 million on
development and exploratory drilling of approximately 205 gross (175.6 net)
wells.

         The Company believes that its diversified portfolio approach to its
drilling activities results in more consistent and predictable economic results
than might be experienced with a less diversified or higher risk drilling
program profile.

         Highly Developed 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 success rates exceed 90%. The
principal risk of such wells is uneconomic recoverable reserves.

         The highly developed formations in the Appalachian Basin are relatively
tight reservoirs that produce 20% to 30% of their recoverable reserves in the
first year and 40% to 50% of their total recoverable reserves in the first three
years, with steady declines thereafter. Average well lives range from 15 years
to 25 years or more.

         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
28 gross (26.1 net) wells to the Antrim Shale formation in 2001.

         Producing natural gas in the form of methane from coalbed formations is
a common practice in the Rocky Mountain, Mid-Continent and southern Appalachian
sections of the United States. It is just beginning to become a factor in the
northern Appalachian Basin region. The Company is a pioneer in coalbed methane
development and production in Pennsylvania, presently operating 70 coalbed
methane


                                       7
<PAGE>   9


("CBM") 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.

         Eight of the 14 CBM wells drilled by the Company in 2000 are currently
producing at or above expected levels. The remaining 6 wells drilled in 2000
were drilled in areas of known coal deposits that had not been tested for CBM
production. These wells have all been drilled to their targeted total depth and
are currently being tested for production volumes and economic viability. The
Company currently holds leases on approximately 65,000 net undeveloped acres
with potential for CBM production and plans to drill 34 wells to the CBM
formations in 2001.

         Certain typical characteristics of the highly developed or blanket
formations drilled by the Company in recent years are described below:

<TABLE>
<CAPTION>
                                                                            Range of                 Range of Average
                                                                        Average Drilling              Gross Reserves
                                               Range of                  and Completion                per Completed
                                             Well Depths                 Costs per Well                    Well
                                             -----------                 --------------               --------------
                                              (in feet)                  (in thousands)               (in Mmcfe) (1)
<S>                                          <C>                         <C>                          <C>
Ohio                                         1,200-5,500                   $  75-160                       80-150
Pennsylvania:
      Coalbed Methane                          900-1,800                     100-125                      150-250
      Clarendon                              1,100-2,000                       45-55                        30-50
      Medina                                 5,000-6,200                     170-210                      150-300
New York                                     3,000-5,000                     100-150                       75-300
Michigan                                     1,000-1,500                     190-240                      400-600
</TABLE>

(1)  Million cubic feet equivalent

         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 success 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 less developed formations in the Appalachian Basin 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. Approximately 3,000 wells have been drilled to the Knox formations
during the past 10 years. Through 2000, the Company had drilled 323 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.




                                       8
<PAGE>   10


         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.

         For the data in the tables that follow, "gross" refers to the total
wells or acres in which the Company owns a working interest and "net" refers to
gross wells or acres multiplied by the percentage working interest it owns.

         The following table shows the Company's drilling results in the Knox
sequence:

<TABLE>
<CAPTION>
                                                    Drilling Results in the Knox Formations
                              ---------------------------------------------------------------------------------
                                                                                                 Average Gross
                                 Wells Drilled                 Wells Completed (1)                Reserves per
                              -------------------             --------------------               Completed Well
  Period                      Gross          Net              Gross           Net                   (Mmcfe)
-----------                   -----          ---              -----           ---                   -------
<S>                           <C>            <C>              <C>             <C>                <C>
  1989-1990                     18           14.5                5             4.0                    456
  1991                          11           10.3                5             4.7                    170
  1992                          15           12.5                8             6.4                    285
  1993                          30           20.2               16             8.8                    360
  1994                          25           14.2               17             9.8                    389
  1995                          34           16.3               18             8.8                    343
  1996                          38           22.0               25            15.5                    422
  1997                          54           26.6               30            16.4                    450
  1998                          47           22.7               26            11.4                    370
  1999                          18            4.8                9             2.1                    320
  2000                          33           12.9               16             6.2                    400
</TABLE>

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

(1)  Completed as producing wells in the Knox formations.


         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 in the Knox formations have an expected
productive life ranging from 10 to 15 years.



                                       9
<PAGE>   11


         The following table demonstrates the impact of Knox formation wells on
the Company's annual production since 1996:

<TABLE>
<CAPTION>
                                                PRODUCING WELLS AND PRODUCTION FROM KNOX FORMATIONS
                                        ------------------------------------------------------------------
                                        1996           1997           1998           1999           2000
                                        ----           ----           ----           ----           ----
<S>                                     <C>            <C>            <C>            <C>            <C>
Number of wells in production:
     Gross                                 82            112            140            131            147
     Net                                 58.9           75.6           88.0           74.8           80.4
     Percent of total net wells           0.9%           1.0%           1.2%           1.1%           1.5%
Annual production (net):
     Gas (Mmcf)                         2,788          3,600          4,111          2,603          2,144
     Oil (Mbbl)                          78.2          111.2          181.9          161.5          144.1
     Combined (Mmcfe)                   3,257          4,267          5,202          3,572          3,009
     Percent of total combined
     production                            11%            13%            15%            11%            13%
</TABLE>

         Productive Knox wells represented approximately 1.5% of the Company's
total productive wells at December 31, 2000. Production from Knox wells in 2000,
however, equaled 13% of the Company's total production on an Mcfe basis. The
Company plans to drill or participate in joint ventures to drill 41 gross (19.8
net) wells to the Knox formation in 2001.

         In addition, the Company has also tested the more prolific Niagaran
Carbonate, Dundee Carbonate, Trenton/Black River Carbonates ("TBR"), Onondaga
Limestone and Oriskany Sandstone formations. Development of the TBR began in the
mid-1990's in south-central New York and more recently in central West Virginia.
Since that time, approximately 80 wells have been drilled to this formation,
establishing commercial gas production in several areas. Based on historical
information available in public records, wells completed in the TBR formation
have reserves in the range of 1.0 to 2.0 Bcf of natural gas per well. The
Company drilled one TBR well in 1998 and three TBR wells in 2000. While expected
geologic conditions and gas shows were encountered in all four of these wells,
economic production was not established.

         The Company currently holds leases on approximately 70,000 net
undeveloped acres with potential for TBR production and approximately 400 miles
of proprietary and nonproprietary seismic data for the region. The Company
currently plans to drill two wells to test the TBR formation in 2001.

         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 Knox and TBR formation drilling, the
Company plans to drill approximately 4 gross (3.4 net) wells to other deep
formations in 2001.




                                       10
<PAGE>   12


         Certain typical characteristics of the less developed or deeper
formations drilled by the Company in recent years are described below:

<TABLE>
<CAPTION>
                                                                            Average
                                                                        Drilling Costs
                                                                   ------------------------          Average Gross
                                                   Range of         Dry           Completed           Reserves per
Formation                     Location           Well Depths        Hole             Well            Completed Well
-------------------           --------           -----------        ----             -----           --------------
                                                  (in feet)             (in thousands)                 (in Mmcfe)
<S>                           <C>                <C>               <C>               <C>             <C>
Knox formations               OH, NY             2,500-8,000       $ 130             $ 260                 300-600
Trenton/Black River
  Carbonates                  NY                 5,000-9,000         400               750             1,000-2,000
Niagaran Carbonate            MI                 4,500-5,500         275               600               900-1,500
Onondaga Limestone            PA                 4,000-5,500         150               250               200-1,500
Oriskany Sandstone            PA, NY             4,500-7,000         150               350               300-1,000
</TABLE>







                                       11
<PAGE>   13


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

<TABLE>
<CAPTION>
                    HIGHLY DEVELOPED OR BLANKET FORMATIONS (1)             LESS DEVELOPED OR DEEPER FORMATIONS (2)
                  ----------------------------------------------     -------------------------------------------------
                   1996       1997       1998     1999     2000      1996       1997      1998       1999     2000
                   ----       ----       ----     ----     ----      ----       ----      ----       ----     ----
<S>               <C>        <C>        <C>       <C>      <C>       <C>        <C>       <C>        <C>      <C>
Productive:
   Gross             153        187        189      --       108        34         39(3)     29(4)      9(5)     17(6)
   Net             126.3      156.5      167.0      --      83.6      22.2       24.5      14.2       2.1       7.2
Dry:
   Gross               2          7          3      --         3        18         28        28         9        21
   Net               2.0        6.3        2.5      --       2.6      10.2       12.3      15.5       2.7      10.7
Reserves
developed-
net (Bcfe)          32.7       32.8       32.3      --      15.4       7.7        9.0       3.0       0.5       2.5
Approximate
cost (in
millions)         $ 22.2     $ 31.2     $ 28.4    $ --     $11.5     $ 9.0      $ 9.3     $ 7.6      $0.8     $ 5.5
</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.





                                       12
<PAGE>   14


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. The following table sets forth
information pertaining to acquisitions completed during the period 1992 through
2000. 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 will primarily focus on
its drilling operations, and to a lesser extent, on the acquisition of producing
properties.

<TABLE>
<CAPTION>
                                                                             Proved Developed Reserves
                                                                     ----------------------------------------
                       Number of                 Purchase             Oil             Gas            Combined
 Period              Transactions                Price (1)           (Mbbl)          (Mmcf)           (Mmcfe)
--------             ------------                ---------           ------          ------          --------
                                              (in thousands)
<S>                       <C>                 <C>                    <C>             <C>              <C>
 1992                      5                     $ 23,733              466            41,477           44,273
 1993                      8                        3,883              119             4,121            4,835
 1994                     11                       20,274              223            26,877           28,215
 1995                      6                       77,388            1,850            97,314          108,414
 1996                      3                        4,103              205             6,000            7,230
 1997                     10                       21,295              101            32,800           33,406
 1998                      3                        7,640               34             8,574            8,778
 1999                     --                           --               --                --               --
 2000                     --                           --               --                --               --
                       -------                   --------            -----           -------          -------
 Total                    46                     $158,316            2,998           217,163          235,151
                       =======                   ========            =====           =======          =======
</TABLE>

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

(1)  Represents the portion of the purchase price allocated to proved developed
     reserves.


DISPOSITION OF ASSETS

         On March 17, 2000, the Company sold the stock of Peake. 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.

EMPLOYEES

         As of February 28, 2001, the Company had 393 full-time employees,
including 227 oil and gas exploration and production employees, 13 petroleum
engineers, 7 geologists, 2 geophysicists, 114 oilfield service employees and 30
general and administrative employees.




                                       13
<PAGE>   15


COMPETITION AND CUSTOMERS

         The oil and gas industry is highly competitive. Competition is
particularly intense with respect to the acquisition of producing properties and
the sale of oil and gas production. There is competition among oil and gas
producers as well as with other industries in supplying energy and fuel to end
users.

         The 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 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 the year ended December 31, 2000 was FirstEnergy
Corp., sales to which totaled $21.6 million. No customer accounted for more than
10% of consolidated revenues during the years ended December 31, 1999 and 1998.

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 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.



                                       14
<PAGE>   16


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

OIL AND GAS RESERVES

         The following table sets forth the Company's proved oil and gas
reserves as of December 31, 1998, 1999 and 2000 determined in accordance with
the rules and regulations of the Securities and Exchange Commission ("SEC").
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.

<TABLE>
<CAPTION>
                                                                 December 31,
                                                       ---------------------------------
                                                       1998          1999          2000
                                                       ----          ----          ----
<S>                                                    <C>           <C>           <C>
Estimated proved reserves
       Gas (Bcf)                                       315.3         306.7         373.5
       Oil (Mbbl)                                      4,243         6,699         8,653
       Bcfe                                            340.7         346.9         425.4
</TABLE>


         See Note 16 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,
2000 determined in accordance with the rules and regulations of the SEC.

<TABLE>
<CAPTION>
Estimated future net cash flows (before income taxes)    (in thousands)
attributable to estimated production during
<S>                                                       <C>
 2001                                                     $  127,601
 2002                                                        153,290
 2003                                                        162,456
 2004 and thereafter                                       2,586,926
                                                          ----------
Total                                                     $3,030,273
                                                          ==========
Present value before income taxes
(discounted at 10% per annum)                             $1,234,949
                                                          ==========
Present value after income taxes
(discounted at 10% per annum)                             $  820,764
                                                          ==========
</TABLE>


         Estimated future net cash flows represent estimated future gross
revenues from the production and sale of proved reserves, net of estimated
production costs (including production taxes, ad valorem taxes, operating costs,
development costs and additional capital investment). Estimated future net cash
flows were calculated on the basis of prices and costs estimated to be in effect
at December 31, 2000 without escalation, except where changes in prices were
fixed and readily determinable under existing contracts.



                                       15
<PAGE>   17


         The following table sets forth the weighted average year-end prices for
oil and gas utilized in determining the Company's reserves.

<TABLE>
<CAPTION>
                                                      December 31,
                                              ---------------------------
                                               1998       1999       2000
                                               ----       ----       ----
           <S>                                <C>       <C>        <C>
           Gas (per Mcf)                      $2.49     $ 2.61     $ 8.33
           Oil (per barrel)                    9.73      23.47      23.50
</TABLE>


         At December 31, 2000, 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. The average
prices of natural gas used in the calculation were higher than the Company
actually realized in December 2000. Further, based on market conditions in
February 2001, these prices are not indicative of those that the Company expects
to realize consistently in the future. If reserves had been valued using assumed
constant wellhead prices of $23.50 per barrel of oil and $4.50 per Mmbtu
(million British thermal units) of natural gas, total proved reserves would be
401.9 Bcfe instead of 425.4 Bcfe with a discounted future net cash flows before
income taxes of $469.0 million instead of $1.2 billion.


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 and $477,000 was recorded in 2000.







                                       16
<PAGE>   18


PRODUCING WELL DATA

         As of December 31, 2000 the Company owned interests in 6,337 gross
(5,272 net) producing oil and gas wells and operated approximately 5,817 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, 2000, the Company's net production was approximately 48.5 Mmcf of
natural gas and 1,465 Bbls of oil per day.

         The following table summarizes by state the Company's productive wells
at December 31, 2000:

<TABLE>
<CAPTION>
                                                                December 31, 2000
                                ---------------------------------------------------------------------------------
                                  Gas Wells                       Oil Wells                        Total
                                ------------------             -------------------            -------------------
State                           Gross         Net              Gross          Net             Gross          Net
------------                    -----        -----             -----         -----            -----         -----
<S>                             <C>          <C>               <C>           <C>              <C>           <C>
Ohio                            1,548        1,345             1,784         1,680            3,332         3,025
Pennsylvania                      678          535               421           407            1,099           942
New York                          869          840                 7             7              876           847
Michigan                        1,024          455                 6             3            1,030           458
                                -----        -----             -----         -----            -----         -----
                                4,119        3,175             2,218         2,097            6,337         5,272
                                =====        =====             =====         =====            =====         =====
</TABLE>


ACREAGE DATA

         The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 2000:

<TABLE>
<CAPTION>
                                                      December 31, 2000
                        -------------------------------------------------------------------------------
                          Developed Acreage          Undeveloped Acreage             Total Acreage
                        ---------------------       --------------------        -----------------------
State                    Gross          Net          Gross         Net           Gross            Net
------------            -------       -------       -------      -------        -------         -------
<S>                     <C>           <C>           <C>          <C>            <C>             <C>
Ohio                    320,428       289,956       218,367      174,610        538,795         464,566
Pennsylvania             45,340        36,573       167,911      152,191        213,251         188,764
New York                 70,000        68,537       115,137      106,822        185,137         175,359
Michigan                 16,166        15,301        37,555       34,052         53,721          49,353
                        -------       -------       -------      -------        -------         -------
                        451,934       410,367       538,970      467,675        990,904         878,042
                        =======       =======       =======      =======        =======         =======
</TABLE>






                                       17
<PAGE>   19


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

         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 or the results of operations.


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, 2001 was as follows:

                                                                 Number of
                Title of Class                                Record Holders
                ----------------------------------------    --------------------
                Common Stock                                        16


DIVIDENDS

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






                                       18
<PAGE>   20

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

<TABLE>
<CAPTION>
                                           PREDECESSOR COMPANY      |                       SUCCESSOR COMPANY
                                      ----------------------------  |  ----------------------------------------------------------
                                                                    |                              AS OF OR FOR THE YEAR
                                      AS OF OR FOR THE  SIX MONTHS  |   SIX MONTHS                   ENDED DECEMBER 31,
                                         YEAR ENDED       ENDED     |     ENDED          ----------------------------------------
                                        DECEMBER 31,     JUNE 30,   |  DECEMBER 31,
(IN THOUSANDS)                             1996           1997      |     1997             1998            1999           2000(1)
                                      ----------------  ----------  |  ------------      ---------       ---------       --------
<S>                                   <C>               <C>         |   <C>              <C>             <C>             <C>
OPERATIONS:                                                         |
  Revenues                               $153,235       $  79,397   |   $  84,126        $ 154,839       $ 135,761       $117,851
  Depreciation, depletion                                           |
    and amortization                       29,752          15,366   |      31,694           68,488          41,412         27,460
  Impairment of oil and gas                                         |
    properties and other assets                --              --   |          --          160,690              --            477
  Income (loss) from continuing                                     |
    operations before extraordinary                                 |
    item                                   15,194          (9,873)  |     (11,372)        (130,550)        (18,303)         4,325
  Preferred dividends paid                    180              45   |          --               --              --             --
                                                                    |
                                                                    |
BALANCE SHEET DATA:                                                 |     AS OF
                                                                    |    12/31/97
                                                                    |    --------
  Working capital                          22,110                   |      19,846           (6,268)        (43,032)          4,180
  Oil and gas properties and                                        |
    gathering systems, net                222,127                   |     491,183          319,013         285,081         228,937
  Total assets                            303,763                   |     599,320          418,605         350,695         285,117
  Long-term liabilities,                                            |
    less current portion                   97,642                   |     355,649          354,382         303,731         286,858
  Preferred stock                           2,400                   |          --               --              --              --
  Total shareholders' equity (deficit)    158,918                   |      96,858          (33,014)        (51,590)        (48,313)
</TABLE>

(1)  In March 2000, the Company sold Peake (See Note 3 to the Consolidated
     Financial Statements). In August 2000, the Company obtained a new credit
     facility (See Note 7 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.

         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. Due to
sustained significantly lower oil and natural gas prices in 1998, the quantity
and value of the Company's oil and gas reserves were negatively impacted. Given
this impairment indicator, 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 in Note 16 to the
Consolidated Financial Statements. 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. No



                                       19
<PAGE>   21


impairment was recorded in 1999 and $477,000 was recorded in 2000. The
impairment charge in 1998 resulted in a significant decrease in the book value
of the Company's assets which resulted in significantly lower charges for
depreciation, depletion and amortization in 2000 and 1999 compared to 1998.

         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 gathering natural
gas for delivery to intrastate and interstate gas transmission pipelines. The
Company currently operates in Ohio, Pennsylvania, New York and Michigan.

         The Company utilizes the "successful efforts" method of accounting for
its oil and gas properties. Under this method, property acquisition and
development costs and productive exploration costs are capitalized while
non-productive exploration costs, which include dry holes, expired leases and
delay rentals, are expensed as incurred. Capitalized costs related to proved
properties are depleted using the unit-of-production method. 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.

         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.




                                       20
<PAGE>   22


RESULTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                    ------------------------------------------------------------------------
                                                              2000                     1999                     1998
                                                    -----------------------    --------------------    ---------------------
                                                                                  (in thousands)
<S>                                                 <C>               <C>      <C>            <C>      <C>             <C>
REVENUES
   Oil and gas sales                                $  79,743          67.7%   $  79,299       58.4%   $  87,055        56.2%
   Gas gathering, marketing, and oilfield sales
     and service                                       34,850          29.6       51,445       37.9       63,348        40.9
   Other                                                3,258           2.7        5,017        3.7        4,436         2.9
                                                    -----------------------    --------------------    ---------------------
                                                      117,851         100.0      135,761      100.0      154,839       100.0
EXPENSES
   Production expense                                  20,917          17.7       21,980       16.2       23,739        15.3
   Production taxes                                     2,409           2.0        3,260        2.4        2,986         1.9
   Gas gathering, marketing, and oilfield sales
     and service                                       31,703          26.9       46,977       34.6       56,813        36.7
   Exploration expense                                  8,528           7.3        6,442        4.7        9,982         6.5
   General and administrative expense                   4,617           3.9        5,412        4.0        4,536         2.9
   Depreciation, depletion and amortization            27,460          23.3       41,412       30.5       68,488        44.2
   Impairment of oil and gas properties
       and other assets                                   477           0.4           --         --      160,690       103.8
   Franchise, property and other taxes                    397           0.3          652        0.5        1,084         0.7
   Other nonrecurring expense                             241           0.3        3,285        2.4          373         0.3
                                                    -----------------------    --------------------    ---------------------
                                                       96,749          82.1      129,420       95.3      328,691       212.3
                                                    -----------------------    --------------------    ---------------------
OPERATING INCOME (LOSS)                                21,102          17.9        6,341        4.7     (173,852)     (112.3)

   (Gain) loss on sale of subsidiaries and other
     income                                           (15,064)        (12.8)       1,521        1.1           --          --
   Interest expense                                    29,473          25.0       34,302       25.3       32,903        21.2
                                                    -----------------------    --------------------    ---------------------
INCOME (LOSS) BEFORE INCOME TAXES AND
  EXTRAORDINARY ITEM                                    6,693           5.7      (29,482)     (21.7)    (206,755)     (133.5)
   Provision (benefit) for income taxes                 2,368           2.0      (11,179)      (8.2)     (76,205)      (49.2)
                                                    -----------------------    --------------------    ---------------------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM                 4,325           3.7      (18,303)     (13.5)    (130,550)      (84.3)
   Extraordinary item - early extinguishment of
     debt, net of tax benefit                          (1,364)         (1.2)          --         --           --          --
                                                    -----------------------    --------------------    ---------------------
NET INCOME (LOSS)                                   $   2,961           2.5%   $ (18,303)     (13.5)%  $(130,550)      (84.3)%
                                                    =======================    ====================    =====================

EBITDAX                                             $  57,808          49.1%   $  57,480       42.3%   $  65,681        42.4%
</TABLE>


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 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



                                       21
<PAGE>   23


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.

         Earnings before interest, income taxes, depreciation, depletion and
amortization, impairment, exploration expense and other nonrecurring items
("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 volume 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 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 of
approximately $2.0 million. Gas volumes decreased 7.0 Bcf (26%) from 27.0 Bcf in
1999 to 20.0 Bcf in 2000 resulting in a decrease in gas sales 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 by
approximately $6.4 million. The average price paid for the Company's natural gas
increased $.67 per Mcf to $3.17 per Mcf in 2000 compared to 1999 which increased
gas sales in 2000 by approximately $13.4 million. As a result of the Company's
hedging activities, gas sales were reduced by $9.3 million ($.47 per Mcf) in
2000 and were enhanced by $1.0 million ($.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 related expenses. The average
production cost increased from $.70 per Mcfe in 1999 to $.89 per Mcf in 2000
primarily due to decreased production volumes 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
primarily due to the sale of Peake. Average production taxes were $.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.

         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.

         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.



                                       22
<PAGE>   24


         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 $.92 per Mcfe in 1999 to $.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.

         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.

1999 COMPARED TO 1998

         Operating income increased $180.2 million from an operating loss of
$173.9 million in 1998 to operating income of $6.3 million in 1999. This
increase was the result of the $160.7 million asset impairment in 1998, a $27.1
million decrease in depreciation, depletion and amortization expense and a $3.6
million decrease in exploration expense. These changes were partially offset by
a $2.9 million increase in other nonrecurring expense and a $8.3 million
decrease in the Company's operating margin primarily due to decreases in natural
gas prices and the volume of oil and natural gas sold offset by an increase in
the average price paid for the Company's oil. The volume decrease was due to the
natural production decline of the wells and curtailment of drilling due to
capital constraints caused by the reduction in the Company's borrowing base. The
operating margin from oil and gas sales on a per unit basis was $1.74 per Mcfe
in 1998 and 1999.

         Net loss decreased $112.3 million from a loss of $130.6 million in 1998
to a loss of $18.3 million in 1999. This decrease was the result of the changes
in operating income discussed above and a $1.3 million gain on the sale of BESCO
in November 1999 partially offset by a decrease in the income tax benefit of
$65.0 million primarily due to the decrease in loss before income taxes, a $2.8
million loss on the sale of TOPS in August 1999 and a $1.4 million increase in
interest expense.

         EBITDAX decreased $8.2 million (12%) from $65.7 million in 1998 to
$57.5 million in 1999. This was primarily due to the $8.3 million decrease in
the Company's operating margin discussed above.

         Total revenues decreased $19.1 million (12%) in 1999 compared to 1998
due to the sale of TOPS and decreases in natural gas prices and the volume of
oil and natural gas sold offset by an increase the average price paid for the
Company's oil.

         Oil volumes decreased approximately 55,000 Bbls (7%) from 768,000 Bbls
in 1998 to 713,000 Bbls in 1999 resulting in a decrease in oil sales of
approximately $697,000. Gas volumes decreased 3.1 Bcf (10%) from 30.1 Bcf in
1998 to 27.0 Bcf in 1999 resulting in a decrease in gas sales of



                                       23
<PAGE>   25


approximately $8.1 million. These volume decreases were primarily due to the
natural production decline of the wells and curtailment of drilling due to
capital constraints caused by the reduction in the Company's borrowing base.

         The average price paid for the Company's oil increased from $12.61 per
barrel in 1998 to $16.57 per barrel in 1999 which increased oil sales by
approximately $2.8 million. The average price paid for the Company's natural gas
decreased $.07 per Mcf to $2.50 per Mcf in 1999 compared to 1998 which decreased
gas sales in 1999 by approximately $1.9 million. As a result of the Company's
hedging activities, gas sales were enhanced by $1.0 million ($.04 per Mcf) and
$1.3 million ($.04 per Mcf) in 1999 and 1998, respectively.

         Production expense decreased $1.7 million (7%) from $23.7 million in
1998 to $22.0 million in 1999. The average production cost increased from $.68
per Mcfe in 1998 to $.70 per Mcf in 1999 primarily due to decreased volumes.
Production taxes increased approximately $274,000 in 1999 compared to 1998.
Average production taxes increased from $.09 per Mcfe in 1998 to $.10 per Mcfe
in 1999.

         General and administrative expense increased approximately $876,000 in
1999 compared to 1998. This increase was the result of increased compensation
and bonus, costs associated with executive transitions and Y2K related costs.

         Exploration expense decreased by $3.6 million (35%) from $10.0 million
in 1998 to $6.4 million in 1999 as a result of the curtailment of the Company's
drilling program previously discussed.

         Other nonrecurring expense increased from $373,000 in 1998 to $3.3
million in 1999 due to $2.4 million in employee reduction costs and an increase
of $507,000 in costs associated with an abandoned acquisition effort and an
abandoned public offering of a royalty trust in 1999.

         Depreciation, depletion and amortization decreased by $27.1 million
(40%) from $68.5 million in 1998 to $41.4 million in 1999. Depletion expense
decreased $28.8 million (50%) from $57.7 million in 1998 to $28.9 million in
1999. Depletion per Mcfe decreased from $1.66 per Mcfe in 1998 to $.92 per Mcfe
in 1999. These decreases were primarily the result of the $160.7 million
write-down of certain permanently impaired assets in the fourth quarter of 1998.

         Interest expense increased $1.4 million (4%) from $32.9 million in 1998
to $34.3 million in 1999. This increase was due to an increase in average
outstanding borrowings and higher blended interest rates. The Company incurred
$972,000 and $499,000 in additional interest expense during 1999 and 1998,
respectively, related to interest rate swaps.

         (Gain) loss on sale of subsidiaries and other income in 1999 includes a
$2.8 million loss on the sale of TOPS offset by a $1.3 million gain on the sale
of BESCO.

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, 2000 was 1.16 to 1. During
2000, working capital increased $47.2 million from a deficit of $43.0 million to
working capital of $4.2 million. The increase



                                       24
<PAGE>   26


was primarily due to a decrease in current portion of long-term liabilities of
$50.8 million. The Company's operating activities provided cash flows of $28.5
million during 2000.

         On December 14, 1999, the Company and its bank group amended its senior
revolving credit agreement. The revolving credit commitment in the amended
agreement provided for a $75 million revolving portion and a $50 million term
portion. 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 and its bank group further amended the credit agreement to provide a
borrowing base of $62.7 million and to forego the May 2000 borrowing base
redetermination.

         On August 23, 2000, the Company obtained a $125 million Facility
comprised of a $100 million Revolver and a $25 million Term Loan. The Facility
has a two year term. 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 Notes. 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 due to the
modification of borrowing capacity. The Revolver bears interest at the prime
rate plus two percentage points, payable monthly. At December 31, 2000, the
interest rate was 11.5%. Up to $20 million in letters of credit may be issued
pursuant to the conditions of the Revolver. At December 31, 2000, the Company
had $12.8 million of outstanding letters of credit.

         Initial proceeds from the Revolver of approximately $66 million 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) representing the unamortized deferred loan
costs pertaining to the former credit facility. The charge was recorded as an
extraordinary item. As of December 31, 2000, the outstanding balance under the
Revolver was $61.4 million with $25.8 million of borrowing capacity available
for general corporate purposes.

         The Facility 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, 2000, under this formula was approximately $265 million for all
proved reserves of the Company and $211 million for properties secured by a
mortgage.

         The Facility is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 5.8 to 1 at December 31, 2000,
to 3.2 to 1 at June 30, 2002; and a senior debt leverage ratio ranging from 2.4
to 1 at December 31, 2000 to 3.2 to 1 at June 30, 2002. EBITDA, as defined in
the Facility, 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) 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



                                       25
<PAGE>   27


December 31, 2000, the Company's current ratio including the above adjustments
was 2.34 to 1. The Company has satisfied all financial covenants as of December
31, 2000.

         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
below, 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.

         The Company currently expects to spend approximately $39 million during
2001 on its drilling activities and other capital expenditures. The Company
intends to finance its planned capital expenditures through its available cash
flow, available revolving credit line and the sale of non strategic assets. At
February 28, 2001, the Company had approximately $37 million available under its
existing revolving credit line. The level of the Company's cash flow in the
future 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.

         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. With the May 10, 1999 amendment to the credit
agreement, the applicable margin relating to these swaps was increased from 1.5%
to 2.5%. Effective with the December 14, 1999 amendment to the credit agreement,
the applicable margin relating to these swaps was increased from 2.5% to a range
up to 3.5%.



                                       26
<PAGE>   28


         To manage its exposure to natural gas price volatility, the Company may
partially hedge its physical gas 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 or
options. The Company had a pretax loss on its hedging activities of $9.3 million
in 2000 and pretax gains of $1.0 million and $1.3 million in 1999 and 1998,
respectively.

         As of December 31, 2000, the Company had hedged 4.35 Bcf of 2001
natural gas production at a weighted average NYMEX price of $4.50 per Mcf which
represented a net unrealized loss of $10.5 million. This amount includes an
unrealized loss of $1.2 million associated with terminated financial swaps on
750 Mmcf of second quarter of 2001 natural gas.

         The following table reflects the natural gas volumes and the weighted
average prices under financial hedges and fixed price contracts (including
settled hedges) at December 31, 2000:

<TABLE>
<CAPTION>
                                                FINANCIAL HEDGES                  FIXED PRICE CONTRACTS
                                      -----------------------------------        ----------------------
                                                                ESTIMATED                     ESTIMATED
                                                    NYMEX       WELLHEAD                      WELLHEAD
QUARTER ENDING                        MMCF          PRICE        PRICE            MMCF         PRICE
--------------------                  -----         -----       ---------        -----        ---------
<S>                                   <C>           <C>           <C>            <C>           <C>
  March 31, 2001                      1,250         $4.75         $5.00          2,100         $3.78
  June 30, 2001                       1,050          4.40          4.55          1,300          3.53
  September 30, 2001                  1,050          4.40          4.55          1,050          3.57
  December 31, 2001                   1,000          4.43          4.63            450          3.22
</TABLE>

         The quarter ending June 30, 2001 in the above table does not include an
unrealized loss of $1.2 million associated with terminated financial swaps on
750 Mmcf of natural gas.

         Since December 31, 2000, the Company has financially hedged 3.0 Bcf of
2002 gas production at a NYMEX price of $4.75 per Mcf. As of February 28, 2001,
the Company had hedges totaling 6.6 Bcf of 2001 and 2002 natural gas production
which represented a net unrealized loss of $4.4 million.

         As of January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. (SFAS) 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended.

         As a result of the adoption of SFAS 133, the Company will recognize 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).



                                       27
<PAGE>   29


         The adoption of SFAS 133 will result in a January 1, 2001 transition
adjustment to increase other current liabilities by $10.5 million, increase
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 will be reflected as a
transition adjustment in other comprehensive income (loss) as of January 1,
2001.

         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.

INFLATION AND CHANGES IN PRICES

         During 1998, the price paid for the Company's crude oil increased to a
high of $14.50 per barrel in January, then decreased to a low of $8.50 per
barrel in December and increased to $9.25 per barrel at year-end 1998, with an
average price of $12.61 per barrel. 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. The average price of the Company's natural
gas decreased from $2.57 per Mcf in 1998 to $2.50 per Mcf in 1999, then
increased to $3.17 per Mcf in 2000.

         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. As a result of
increased competition among drilling contractors and suppliers in the Company's
operating area, costs to drill, complete and service wells have remained
relatively constant in recent years. The Company's costs and expenses may be
subject to inflationary pressures if oil and gas prices remain favorable.

         Historically, a large portion of the Company's natural gas has 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. 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.




                                       28
<PAGE>   30


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

         The Company is exposed to 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, 2000. At December 31, 1999 and 1998 the
principal amount of the swaps totaled $120 million and $140 million,
respectively. If market interest rates for short-term borrowings increased 1%,
the increase in the Company's interest expense would be approximately $615,000.
This sensitivity analysis is based on the Company's financial structure at
December 31, 2000.

         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
increased $.25 per Mcf, the Company's gas sales would increase by $2.5 million,
after considering the effects of the hedging contracts in place at December 31,
2000. This sensitivity analysis is based on the Company's 2000 gas sales
volumes.

         The information included in this Item is considered to constitute
"forward looking statements" for purposes of the statutory safe harbor provided
in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Forward-Looking
Information" in Item 7 of this Report.

Item 8. FINANCIAL STATEMENTS AND 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.



                                       29
<PAGE>   31


         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, 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.

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

         Not applicable.








                                       30
<PAGE>   32


PART III
--------

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

         Executive officers and directors of the Company as of March 5, 2001
were as follows:

<TABLE>
<CAPTION>
Name                         Age      Position
----                         ---      --------
<S>                          <C>      <C>
John L. Schwager             52       President, Chief Executive Officer and Director

Joseph M. Vitale             59       Senior Vice President Legal, General Counsel, Secretary
                                      and Director

Richard R. Hoffman           50       Senior Vice President Exploration and Production

Leo A. Schrider              62       Senior Vice President Technical Development

Robert W. Peshek             46       Vice President Finance and Chief Financial Officer

David M. Becker              39       Vice President and General Manager, Michigan Exploration
                                      and Production District

Carl J. Carlson              47       Vice President and General Manager, Pennsylvania/New York
                                      Exploration and Production District

Duane D. Clark               45       Vice President Gas Marketing

John G. Corp                 41       Vice President and General Manager, Arrow Oilfield Service
                                      Company

James C. Ewing               58       Vice President Human Resources

Charles P. Faber             59       Vice President Corporate Development

William F. Murray            39       Vice President and General Manager, Ohio Exploration and
                                      Production District

Henry S. Belden IV           61       Director

Lawrence W. Kellner          42       Director

Max L. Mardick               66       Director

Robert S. Maust              63       Director

William S. Price, III        45       Director

Gareth Roberts               48       Director

Jeffrey C. Smith             39       Director
</TABLE>





                                       31
<PAGE>   33


         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 nine
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, 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.

         JOSEPH M. VITALE has been Senior Vice President Legal of the Company
since 1989 and has served as its General Counsel since 1974. He has been a
director of the Company since 1991. He holds a BS degree from John Carroll
University and a JD degree from Case Western Reserve Law School. He is a member
of the Ohio Oil and Gas Association, the Stark County, Ohio State and American
Bar Associations, and the Interstate Oil and Gas Compact Commission. Mr. Vitale
is a past Chairman of the Natural Resources Law Committee of the Ohio State Bar
Association.

         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 28 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 it's 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 Tennessee Oil and
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.



                                       32
<PAGE>   34


         LEO A. SCHRIDER has been Senior Vice President of Technical Development
since 1993. He previously served as Senior Vice President of Exploration,
Drilling and Engineering for the Company since 1986. Mr. Schrider is a Petroleum
Engineer with more than 35 years of experience in oil and gas production,
principally in the Appalachian Basin. Prior to joining the Company in 1981, he
served as Assistant and Deputy Director of Morgantown Energy Technology Center
from 1976 to 1980. From 1973 to 1976, Mr. Schrider served as Project Manager of
the Laramie Energy Research Center. He has also held various research positions
with the U.S. Department of Energy in Wyoming and West Virginia.

         Mr. Schrider received his BS degree from the University of Pittsburgh
in 1961 and did graduate work at West Virginia University. He has published more
than 35 technical papers on oil and gas production. He was an Adjunct Professor
at West Virginia University and also served as a member of the International
Board of Directors of the Society of Petroleum Engineers. In 1994, Mr. Schrider
was elected to the Board of Directors of the Petroleum Technology Transfer
Council and currently serves as its chairman.

         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 19 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.

         CARL J. CARLSON was appointed Vice President of the Company in May
2000, and has been General Manager of the Pennsylvania/New York Exploration and
Production District of the Company since 1995. Mr. Carlson joined the Company as
a result of the Quaker State acquisition in May of 1995. He was employed by
Quaker State Corporation from 1976 to 1995, serving most recently as President
of the Natural Gas E&P Division. He has 25 years of experience in the oil and
gas industry. Mr. Carlson graduated from Pennsylvania State University where he
received a Bachelor of Science degree in Geological Science.


         DUANE D. CLARK has been Vice President of Gas Marketing for the Company
since 1997. Previously, he served as General Manager of Gas Marketing from 1996
to 1997. 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



                                       33
<PAGE>   35


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 Services 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 22 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.

         JAMES C. EWING has been Vice President of Human Resources for the
Company since 1997. He previously served as Human Resources Manager. Mr. Ewing
joined the Company in April of 1986 and has 15 years of experience in the oil
and gas industry and more than 20 years of experience in the Human Resource
field. Prior to joining the Company, he was the Director of Personnel for the
Union Metal Manufacturing Company from 1978 to 1986. Mr. Ewing holds a Bachelor
of Arts degree in Psychology from West Liberty State College. He is a member of
the Society for Human Resource Management. He is a founder and current member of
the Stark County Health Care Coalition; President of the Stark County Historical
Society; and, Chairman of the Business Advisory Board and adjunct faculty member
of Kent State University.

         CHARLES P. FABER has been Vice President of Corporate Development for
the Company since 1993. He previously served as Senior Vice President of Capital
Markets from 1988 to 1993. Prior to joining the Company, Mr. Faber was employed
as Senior Vice President of Marketing for Heritage Asset Management from 1986 to
1988. From 1983 to 1986 he served as President and Chief Executive Officer of
Samson Properties, Incorporated. Mr. Faber holds a BA degree in Marketing and an
MBA in Finance from the University of Wisconsin where he graduated with honors.
He is a member of the Independent Petroleum Association of America and the Ohio
Oil and Gas Association.

         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 18 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.

         HENRY S. BELDEN IV served as Chairman and Chief Executive Officer of
the Company from 1982 to 1997. He resigned as Chairman and Chief Executive
Officer upon the merger with TPG in 1997, and was appointed to serve on the
Board of Directors upon consummation of the merger. Mr. Belden has been involved
in oil and gas production since 1955 and associated with the Company since 1967.
Prior to joining the Company, he was employed by Ashland Oil & Refining Company
and Halliburton Services, Incorporated. Mr. Belden attended Florida State
University and the University of Akron and is a current member and previous
board member of the Ohio Oil and Gas Association and the Independent Petroleum



                                       34
<PAGE>   36


Association of America. He is also a member of the Interstate Oil Compact
Commission. Other professional memberships include the World Business Council
and the World Presidents Organization. Mr. Belden is a director of Phoenix
Packaging Corporation and Family Office Services, LLC.

         LAWRENCE W. KELLNER has been a director since 1997. He has been
Executive Vice President and Chief Financial Officer of Continental Airlines,
Inc. since November 1996. Previously, he served as Senior Vice President and
Chief Financial Officer at Continental from June 1995 to November 1996. Mr.
Kellner graduated magna cum laude with a Bachelor of Science, Business
Administration degree from the University of South Carolina.

         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 38-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.

         MAX L. MARDICK was President and Chief Operating Officer of the Company
from 1990 to 1997, a director from 1992 to 1997 and a director of predecessor
companies from 1988 to 1992. He resigned as President and Chief Operating
Officer upon consummation of the merger with TPG in 1997 and was appointed to
serve on the Board of Directors upon consummation of the merger. He previously
served as Executive Vice President and Chief Operating Officer from 1988 to
1990. Mr. Mardick is a Petroleum Engineer with more than 35 years of experience
in domestic and international production, engineering, drilling operations and
property evaluation. Prior to joining the Company, he was employed for more than
30 years by Shell Oil Company in various engineering, supervisory and senior
management positions, including: Manager, Property Acquisitions and Business
Development (1986-1988); Production Manager for Shell's Onshore and Eastern
Divisions (1981-1986); Production Manager of Shell's Rocky Mountain Division
(1980-1981); Operations Manager (1977-1980); and Engineering Manager
(1975-1977). Mr. Mardick holds a BS degree in Petroleum Engineering from the
University of Kansas. He has served as Vice Chairman of the Alabama-Mississippi
section of the Mid-Continent Oil and Gas Association.

         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 1993.
Prior to forming Texas Pacific Group, Mr. Price was Vice President of Strategic
Planning and Business Development for G.E. Capital, and from 1985 to 1991 he was
employed by the management consulting firm of Bain & Company, attaining
partnership status and acting as co-head of the Financial Services Practice. Mr.
Price is a 1978 graduate of Stanford University and received a JD degree from
the Boalt Hall School of Law at the University of California, Berkeley. Mr.
Price serves on the Boards of Directors of Continental Airlines, Inc., Del
Monte, Inc., 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 25 years of experience in the exploration



                                       35
<PAGE>   37


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.








                                       36
<PAGE>   38


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, 2000, 1999 and 1998 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
                                 ------------------------------------------------      -------------
                                                                        Other          No. of Shares
Name and                                                                Annual           Underlying        All Other
Principal Position               Year       Salary       Bonus       Compensation       Options/SARs    Compensation(1)
------------------               ----       ------       -----       ------------       ------------    ---------------
<S>                              <C>       <C>         <C>             <C>               <C>              <C>
John L. Schwager                 2000      $308,654    $157,500        $   --             66,692          $  8,500
President and Chief              1999       173,077     300,000            --            139,383           113,358 (2)
Executive Officer

Joseph M. Vitale                 2000       185,192      47,250             --            27,500             8,500
Senior Vice President Legal,     1999       180,000      57,416             --            55,000 (3)         8,084
General Counsel and Secretary    1998       186,493      52,525             --                --            14,248

Tommy L. Knowles  (7)            2000       185,300      49,039            337 (6)        27,500             8,500
Senior Vice President of         1999       172,009      17,201             --            55,000 (3)         7,878
Exploration and Production       1998       175,158       6,244             --               --             14,444

Leo A. Schrider                  2000       142,777      36,487          1,370 (6)        27,500             7,804
Senior Vice President of         1999       133,000      13,300             --            55,000 (4)         7,635
Technical Development            1998       137,962      12,719             --                --            11,669

Robert W. Peshek                 2000       144,721      40,851             --            27,500             8,500
Vice President of Finance        1999       110,617      13,000             --            55,000 (5)         5,531
and Chief Financial Officer      1998       102,708       7,320             --                --             5,818
</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 options for 54,946 shares originally granted in 1997 and repriced
     in 1999 plus options for 54 shares granted in 1999.

(4)  Includes options for 20,000 shares originally granted in 1997 and repriced
     in 1999 plus options for 35,000 shares granted in 1999.

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

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

(7)  Employment with the Company terminated effective March 4, 2001.





                                       37
<PAGE>   39

                      OPTION/SAR GRANTS IN LAST FISCAL YEAR


<TABLE>
<CAPTION>
                              Number of       Percentage/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               69,692              25.37%            $  0.21          03/21/10         $  4,668
Joseph M. Vitale               27,500              10.01%               0.21          03/21/10            1,925
Tommy L. Knowles               27,500              10.01%               0.21          03/21/10            1,925
Leo A. Schrider                27,500              10.01%               0.21          03/21/10            1,925
Robert W. Peshek               27,500              10.01%               0.21          03/21/10            1,925
</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.



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

<TABLE>
<CAPTION>
                                                                                       Value of Unexercised
                                                       Number of Unexercised                In-the Money
                                                      Options/SARs at FY-End           Options/SARs at FY-End
                                                      ----------------------           ----------------------
                           Shares
                          Acquired       Value
         Name           on Exercise    Realized    Exercisable    Unexercisable    Exercisable    Unexercisable
         ----           -----------    --------    -----------    -------------    -----------    -------------
<S>                        <C>         <C>            <C>            <C>             <C>             <C>
John L. Schwager           52,267      $ 23,520           --         156,808         $    --         390,626
Joseph M. Vitale           13,750        22,138           --          68,750              --         171,875
Tommy L. Knowles               --            --       13,750          68,750          35,475         171,875
Leo A. Schrider                --            --       13,750          68,750          35,475         171,875
Robert W. Peshek           13,750        22,138           --          68,750              --         171,875
</TABLE>


COMPENSATION OF DIRECTORS

         The outside directors of the Company are compensated for their services
at $7,500 per quarter. Directors employed by the Company or affiliated with TPG
are not compensated for their services. Two directors had additional
compensation of $3,603 and $12,495, respectively, in 2000 related to taxes from
a prior year paid by the Company on their behalf.

EMPLOYMENT AND SEVERANCE AGREEMENTS

         John L. Schwager entered into an Employment Agreement effective as of
June 1, 1999 providing for his employment as Chief Executive Officer of the
Company at an annual base salary of not less than $300,000, and entitling him to
an annual bonus of up to 100% of his annual base salary subject to the
attainment of certain goals to be agreed upon annually by Mr. Schwager and the
Board of Directors. The



                                       38
<PAGE>   40


Company agreed to reimburse Mr. Schwager for expenses incurred in connection
with his relocation to Canton, Ohio, including any loss on the sale of his
former residence. If his employment is terminated by the Company without "cause"
(as defined in the agreement) or if Mr. Schwager resigns in response to a
substantial and adverse change in his status or position or a substantial
reduction in duties, responsibilities or base salary or a relocation of his
place of work or a sale of the Company, Mr. Schwager will be entitled to
severance pay equal to three times his total compensation for the previous
calendar year, or if such termination occurs in 2000, three times his total
annualized 1999 compensation. Mr. Schwager would also be entitled to receive an
additional payment (the "gross up") sufficient to cover any tax imposed by
Section 4999 of the Internal Revenue Code on the severance payments and the
gross up. In addition, Mr. Schwager received options to purchase 139,383 shares
of common stock of the Company at a price of $0.01 per share, subject to upward
adjustment in the event of the sale by the Company of new equity securities to
TPG Partners II or its affiliates for at least $30 million, in which case he
will receive additional options for such number of shares as will, when added to
139,383, equal 1.25% of the Company's outstanding stock. In such event, the
exercise price of all options shall be equal to the fair market value of the
underlying shares.

         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 six (6) months to
twenty-four (24) months, depending on their years of service and position with
the Company. Under the Plan, Messrs. Schrider, Peshek and Vitale would be
eligible to receive severance pay ranging from twelve (12) months to twenty-four
(24) months, and Mr. Knowles will receive twenty-four (24) months of severance
pay in connection with the termination of his employment.

         The Company has a 1999 Change in Control Protection Plan for Key
Employees providing severance benefits for such employees if within six (6)
months prior to a change in control or within two (2) 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. Such
benefits range from twelve (12) months to thirty-six (36) months, depending on
their position with the Company. Under the Plan, Messrs. Schrider, Peshek and
Vitale would be eligible to receive severance pay ranging from twenty-four (24)
to thirty-six (36) months.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

         During 2000, the Compensation and Organizational Committee of the Board
of Directors consisted of William S. Price, III, Henry S. Belden IV and Gareth
Roberts, all of whom are outside directors. No executive officer of the Company
was a director or member of the compensation committee of any entity of which a
member of the Company's Board of Directors or its Compensation and
Organizational Committee was or is an executive officer.






                                       39
<PAGE>   41


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

         The following table sets forth certain information as of February 28,
2001 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>
             FIVE PERCENT SHAREHOLDERS                            NUMBER OF SHARES             PERCENTAGE OF SHARES
             -------------------------                            ----------------             --------------------
<S>                                                                 <C>                        <C>
TPG Advisors II, Inc.
201 Main Street, Suite 2420
Fort Worth, Texas  76102                                            9,353,038 (1)                      89.4%

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                                 554,376                           5.3%

              OFFICERS AND DIRECTORS
              ----------------------

William S. Price, III                                               9,353,038 (1)                      89.4%
Henry S. Belden IV                                                     63,360 (2)                         *
John L. Schwager                                                       78,401 (2)                         *
Lawrence W. Kellner                                                       -0-                           -0-
Max L. Mardick                                                         39,387 (2)                         *
Gareth Roberts                                                            -0-                           -0-
Robert S. Maust                                                           -0-                           -0-
Jeffrey C. Smith                                                          -0-                           -0-
Joseph M. Vitale                                                       27,500 (2)                         *
Tommy L. Knowles  (3)                                                  17,188 (2)                         *
Leo A. Schrider                                                        27,500 (2)                         *
Robert W. Peshek                                                       27,500 (2)                         *
All directors and executive
   officers (19) as a group                                         9,706,374                          92.8%
</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 II, 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 26,134 shares, Mr. Vitale as to 13,750 shares, Mr.
     Peshek as to 13,750 shares and as to all shares for Messrs. Belden,
     Mardick, Knowles and Schrider.

(3)  Employment with the Company terminated effective March 4, 2001.





                                       40
<PAGE>   42


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.





                                       41
<PAGE>   43


                                    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)



                                       42
<PAGE>   44


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.

10.2              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.

21*               Subsidiaries of the Registrant

23*               Consent of independent auditors


* Filed herewith




                                       43
<PAGE>   45


         (b) Reports on Form 8-K

         No reports on Form 8-K were filed by the Company during the last
quarter of the year covered by this report.

         (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.






                                       44
<PAGE>   46


                                   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, 2001                       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, 2001
---------------------------------                    and Chief Executive Officer                 --------------
John L. Schwager                                     (Principal Executive Officer)               Date


     /s/ Robert W. Peshek                            Vice President Finance and                  March 21, 2001
---------------------------------                    Chief Financial Officer                     --------------
Robert W. Peshek                                     (Principal Financial and                    Date
                                                     Accounting Officer)


     /s/ Joseph M. Vitale                            Senior Vice President Legal,                March 21, 2001
---------------------------------                    General Counsel, Secretary                  --------------
Joseph M. Vitale                                     and Director                                Date



     /s/ Henry S. Belden IV                          Director                                    March 21, 2001
---------------------------------                                                                --------------
Henry S. Belden IV                                                                               Date


     /s/ Lawrence W. Kellner                         Director                                    March 21, 2001
---------------------------------                                                                --------------
Lawrence W. Kellner                                                                              Date


     /s/ Max L. Mardick                              Director                                    March 21, 2001
---------------------------------                                                                --------------
Max L. Mardick                                                                                   Date
</TABLE>



                                       45
<PAGE>   47


<TABLE>
<S>                                                  <C>                                         <C>
     /s/ Robert S. Maust                             Director                                    March 21, 2001
---------------------------------                                                                --------------
Robert S. Maust                                                                                  Date


     /s/ William S. Price, III                       Director                                    March 21, 2001
---------------------------------                                                                --------------
William S. Price, III                                                                            Date


     /s/ Gareth Roberts                              Director                                    March 21, 2001
---------------------------------                                                                --------------
Gareth Roberts                                                                                   Date


     /s/ Jeffrey C. Smith                            Director                                    March 21, 2001
---------------------------------                                                                --------------
Jeffrey C. Smith                                                                                 Date



</TABLE>





                                       46
<PAGE>   48


                           BELDEN & BLAKE CORPORATION
                              INDEX TO CONSOLIDATED
                       FINANCIAL STATEMENTS AND SCHEDULES

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


<TABLE>
<CAPTION>
                                                                                           PAGE
                                                                                           ----
CONSOLIDATED FINANCIAL STATEMENTS
---------------------------------
<S>                                                                                        <C>
    Report of Independent Auditors.....................................................     F-2
    Consolidated Balance Sheets as of December 31, 2000 and 1999.......................     F-3
    Consolidated Statements of Operations:
       Years ended December 31, 2000, 1999 and 1998....................................     F-4
    Consolidated Statements of Shareholders' Equity (Deficit):
       Years ended December 31, 2000, 1999 and 1998....................................     F-5
    Consolidated Statements of Cash Flows:
       Years ended December 31, 2000, 1999 and 1998....................................     F-6
    Notes to Consolidated Financial Statements.........................................     F-7
</TABLE>



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>   49


                         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, 2000 and 1999, 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, 2000. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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, 2000 and 1999 and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.




                                                 ERNST & YOUNG LLP


Cleveland, Ohio
March 9, 2001





                                      F-2
<PAGE>   50


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


<TABLE>
<CAPTION>
                                                                                    DECEMBER 31,
                                                                           -----------------------------
                                                                             2000                1999
                                                                           ---------           ---------
<S>                                                                        <C>                 <C>
ASSETS
------
CURRENT ASSETS
     Cash and cash equivalents                                             $   1,798           $   4,536
     Accounts receivable, net                                                 22,620              25,301
     Inventories                                                               2,222               2,106
     Deferred income taxes                                                     1,475               2,006
     Other current assets                                                      1,448               1,154
                                                                           ---------           ---------
                TOTAL CURRENT ASSETS                                          29,563              35,103

PROPERTY AND EQUIPMENT, AT COST
     Oil and gas properties (successful efforts method)                      413,824             534,515
     Gas gathering systems                                                    13,445              22,193
     Land, buildings, machinery and equipment                                 23,469              24,242
                                                                           ---------           ---------
                                                                             450,738             580,950
     Less accumulated depreciation, depletion and amortization               208,435             280,047
                                                                           ---------           ---------
                PROPERTY AND EQUIPMENT, NET                                  242,303             300,903
OTHER ASSETS                                                                  13,251              14,689
                                                                           ---------           ---------
                                                                           $ 285,117           $ 350,695
                                                                           =========           =========

LIABILITIES AND SHAREHOLDERS' DEFICIT
-------------------------------------
CURRENT LIABILITIES
     Accounts payable                                                      $   5,926           $   4,132
     Accrued expenses                                                         19,316              23,024
     Current portion of long-term liabilities                                    141              50,979
                                                                           ---------           ---------
                TOTAL CURRENT LIABILITIES                                     25,383              78,135

LONG-TERM LIABILITIES
     Bank and other long-term debt                                            61,535              78,161
     Senior subordinated notes                                               225,000             225,000
     Other                                                                       323                 570
                                                                           ---------           ---------
                                                                             286,858             303,731

DEFERRED INCOME TAXES                                                         21,189              20,419

SHAREHOLDERS' DEFICIT
     Common stock without par value; $.10 stated value per share;
       authorized 58,000,000 shares; issued 10,357,255 (which
       includes 53,972 treasury shares) and 10,260,457 shares                  1,030               1,026
     Paid in capital                                                         107,921             107,609
     Deficit                                                                (157,264)           (160,225)
                                                                           ---------           ---------
                TOTAL SHAREHOLDERS' DEFICIT                                  (48,313)            (51,590)
                                                                           ---------           ---------
                                                                           $ 285,117           $ 350,695
                                                                           =========           =========
</TABLE>

See accompanying notes.



                                      F-3
<PAGE>   51


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


<TABLE>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31,
                                                                      -------------------------------------------------
                                                                         2000               1999                1998
                                                                      ---------           ---------           ---------
<S>                                                                   <C>                 <C>                 <C>
REVENUES
    Oil and gas sales                                                 $  79,743           $  79,299           $  87,055
    Gas gathering, marketing, and oilfield sales and service             34,850              51,445              63,348
    Other                                                                 3,258               5,017               4,436
                                                                      ---------           ---------           ---------
                                                                        117,851             135,761             154,839
EXPENSES
    Production expense                                                   20,917              21,980              23,739
    Production taxes                                                      2,409               3,260               2,986
    Gas gathering, marketing, and oilfield sales and service             31,703              46,977              56,813
    Exploration expense                                                   8,528               6,442               9,982
    General and administrative expense                                    4,617               5,412               4,536
    Depreciation, depletion and amortization                             27,460              41,412              68,488
    Impairment of oil and gas properties
      and other assets                                                      477                  --             160,690
    Franchise, property and other taxes                                     397                 652               1,084
    Other nonrecurring expense                                              241               3,285                 373
                                                                      ---------           ---------           ---------
                                                                         96,749             129,420             328,691
                                                                      ---------           ---------           ---------
OPERATING INCOME (LOSS)                                                  21,102               6,341            (173,852)

    (Gain) loss on sale of subsidiaries and other income                (15,064)              1,521                  --
    Interest expense                                                     29,473              34,302              32,903
                                                                      ---------           ---------           ---------
                                                                         14,409              35,823              32,903
                                                                      ---------           ---------           ---------
INCOME (LOSS) BEFORE INCOME TAXES AND
    EXTRAORDINARY ITEM                                                    6,693             (29,482)           (206,755)
    Provision (benefit) for income taxes                                  2,368             (11,179)            (76,205)
                                                                      ---------           ---------           ---------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM                                   4,325             (18,303)           (130,550)
    Extraordinary item - early extinguishment of debt,
      net of tax benefit                                                 (1,364)                 --                  --
                                                                      ---------           ---------           ---------
NET INCOME (LOSS)                                                     $   2,961           $ (18,303)          $(130,550)
                                                                      =========           =========           =========
</TABLE>



See accompanying notes.




                                      F-4
<PAGE>   52


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


<TABLE>
<CAPTION>
                                                                                                                  TOTAL
                                    COMMON            COMMON              PAID IN                                EQUITY
                                    SHARES             STOCK              CAPITAL             DEFICIT           (DEFICIT)
                                    ------           ---------           ---------           ---------          ---------
<S>                                 <C>              <C>                 <C>                 <C>                 <C>
JANUARY 1, 1998                     10,000           $   1,000           $ 107,230           $ (11,372)          $ 96,858

Stock-based compensation               111                  11                 667                                    678
Net loss                                                                                     (130,550)           (130,550)
-------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998                   10,111               1,011             107,897            (141,922)           (33,014)

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

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

See accompanying notes.



                                      F-5
<PAGE>   53


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


<TABLE>
<CAPTION>
                                                                                           YEAR ENDED DECEMBER 31,
                                                                               -------------------------------------------------
                                                                                   2000               1999                1998
                                                                                ---------           --------           ---------
<S>                                                                             <C>                 <C>                <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)                                                               $   2,961           $(18,303)          $(130,550)
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                                    27,460             41,412              68,488
       Impairment of oil and gas properties and other assets                          477                 --             160,690
       (Gain) loss on sale of subsidiaries                                        (13,794)             1,521                  --
       Loss on disposal of property and equipment                                     500                136                 100
       Exploration expense                                                          8,528              6,442               9,982
       Deferred income taxes                                                        2,077            (11,179)            (75,702)
       Deferred compensation and stock grants                                         169               (565)                993
       Change in operating assets and liabilities, net of effects of
         purchases of businesses and disposition of subsidiaries:
           Accounts receivable and other operating assets                            (442)             8,580               3,218
           Inventories                                                               (674)             2,413                (261)
           Accounts payable and accrued expenses                                     (102)            (7,867)             (1,689)
                                                                                ---------           --------           ---------
                    NET CASH PROVIDED BY OPERATING ACTIVITIES                      28,524             22,590              35,269

CASH FLOWS FROM INVESTING ACTIVITIES:
  Acquisition of businesses, net of cash acquired                                      --                 --             (11,827)
  Disposition of businesses, net of cash                                           69,031              7,887                  --
  Proceeds from property and equipment disposals                                      218              3,011               4,082
  Exploration expense                                                              (8,528)            (6,442)             (9,982)
  Additions to property and equipment                                             (18,624)            (2,996)            (38,165)
  (Increase) decrease in other assets                                                 (83)             2,140              (1,294)
                                                                                ---------           --------           ---------
                   NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES             42,014              3,600             (57,186)

CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from revolving line of credit and term loan                            123,096             21,000              44,000
  Repayment of long-term debt and other obligations                              (190,814)           (50,582)            (17,929)
  Debt issue costs                                                                 (5,537)            (2,766)                (15)
  Proceeds from sale of common stock and stock options                                 --                  3                  --
  Purchase of treasury stock                                                          (21)                --                  --
                                                                                ---------           --------           ---------
                  NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES             (73,276)           (32,345)             26,056
                                                                                ---------           --------           ---------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS                               (2,738)            (6,155)              4,139
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                    4,536             10,691               6,552
                                                                                ---------           --------           ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD                                      $   1,798           $  4,536           $  10,691
                                                                                =========           ========           =========
</TABLE>


See accompanying notes.



                                      F-6


<PAGE>   54

                           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 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 2000.

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, dry holes, expired leases and delay rentals, 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>   55


         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 2000 and 1998 were $477,000 and $5.8
million, respectively, which wrote-down 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 charged to income
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 1998, the Company recorded
$148.0 million and $6.9 million of impairments which wrote-down producing
properties and other assets, respectively, 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 and
1999.

INTANGIBLE ASSETS
-----------------

         Intangible assets totaling $11.7 million at December 31, 2000, 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. 25, "Accounting
for Stock Issued to Employees" (APB 25).

         As of July 1, 2000, stock options repriced in October 1999 are subject
to variable plan accounting (see Note 2). The changes in share value are
reported as adjustments to compensation expense. The increase in share value in
2000 resulted in an increase in compensation expense of $336,000. The reduction
in share value in 1999 and 1998 resulted in a reduction in compensation expense
of $858,000 and $403,000, respectively.



                                      F-8
<PAGE>   56


DERIVATIVES AND HEDGING
-----------------------

          As of 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 Financial Accounting
Standards Board (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, will be applied prospectively as the cumulative effect of an
accounting change effective January 1, 2001.

         As a result of the adoption of SFAS 133, the Company will recognize 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).

         The adoption of SFAS 133 will result 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 stockholders' deficit
by $6.7 million to record the fair value of open cash flow hedges and the
related income tax effect. The increase in stockholders' deficit will be
reflected as a transition adjustment in other comprehensive income (loss) as of
January 1, 2001.

         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 March 2000, the Financial Accounting Standards Board issued
FASB Interpretation No. (FIN) 44, "Accounting for Certain Transactions involving
Stock Compensation, an interpretation of APB Opinion No. 25." The
Interpretation, which has been adopted prospectively as of July 1, 2000,
requires that stock options that have been modified to reduce the exercise price
be accounted for as variable. The Company repriced 318,892 stock options
(298,392 outstanding prior to July 1, 2000) in October 1999, and reduced the
exercise price to $.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. Prior to the adoption of the Interpretation,
the Company accounted for these repriced stock options as fixed. Because the
value of the Company's stock increased since July 1, 2000, 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 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.



                                      F-9
<PAGE>   57


         In December 1999, the Securities and Exchange Commission (SEC) issued
Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial
Statements." SAB 101, as amended, summarizes the SEC's views in applying
generally accepted accounting principles to revenue recognition in financial
statements. The adoption of SAB 101 on October 1, 2000 did not have a material
effect on the Company's financial position or results of operations.

(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 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 for the year
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 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.

         In November 1999, the Company sold Belden Energy Services Company
("BESCO"), its Ohio retail natural gas marketing subsidiary, to FirstEnergy
Corp. ("FirstEnergy"). 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.

(4) ACQUISITIONS

         The following acquisitions were accounted for as purchase business
combinations. Accordingly, the results of operations of the acquired businesses
are included in the Company's consolidated statements of operations from the
date of the respective acquisitions.

         During 1998, the Company acquired working interests in oil and gas
wells in Ohio, West Virginia, Michigan and New York for approximately $7.6
million. Estimated proved developed reserves associated with the wells totaled
8.8 Bcfe net to the Company's interest at the time of acquisition. The Company
also acquired undeveloped properties and other assets for $4.2 million. The pro
forma effects of the 1998 acquisitions were not material.

(5) OTHER NONRECURRING EXPENSE

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



                                      F-10
<PAGE>   58


         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.

         On March 19, 1998, the Company entered into an agreement in principle
with FirstEnergy to form an equally-owned joint venture to be named FE Holdings
L.L.C. ("FE Holdings") to engage in the exploration, development, production,
transportation and marketing of natural gas. Formation of the joint venture was
subject to the negotiation and execution of a definitive joint venture
agreement. The Company was unable to reach agreement with FirstEnergy regarding
certain terms of the joint venture agreement and in June 1998, the Company
determined it would not participate in the proposed joint venture. Costs of
$373,000 related to the proposed formation of the joint venture and due
diligence associated with a proposed acquisition by FE Holdings were written-off
to other nonrecurring expense in 1998.

(6)      DETAILS OF BALANCE SHEETS

<TABLE>
<CAPTION>
                                                            DECEMBER 31,
                                                    -----------------------------
                                                      2000                1999
                                                    ---------           ---------
ACCOUNTS RECEIVABLE                                         (IN THOUSANDS)
<S>                                                 <C>                 <C>
     Accounts receivable                            $  12,333           $  13,280
     Allowance for doubtful accounts                   (1,245)             (1,215)
     Oil and gas production receivable                 11,358              12,626
     Current portion of notes receivable                  174                 610
                                                    ---------           ---------
                                                    $  22,620           $  25,301
                                                    =========           =========
INVENTORIES
     Oil                                            $   1,272           $   1,552
     Natural gas                                           27                  27
     Material, pipe and supplies                          923                 527
                                                    ---------           ---------
                                                    $   2,222           $   2,106
                                                    =========           =========
PROPERTY AND EQUIPMENT, GROSS
  OIL AND GAS PROPERTIES
     Producing properties                           $ 390,229           $ 506,266
     Non-producing properties                           7,676               7,078
     Other                                             15,919              21,171
                                                    ---------           ---------
                                                    $ 413,824           $ 534,515
                                                    =========           =========
  LAND, BUILDINGS, MACHINERY AND EQUIPMENT
     Land, buildings and improvements               $   5,632           $   6,592
     Machinery and equipment                           17,837              17,650
                                                    ---------           ---------
                                                    $  23,469           $  24,242
                                                    =========           =========
ACCRUED EXPENSES
     Accrued expenses                               $   5,901           $   9,500
     Accrued drilling and completion costs              1,624                 615
     Accrued income taxes                                 481                 190
     Ad valorem and other taxes                         2,449               3,733
     Compensation and related benefits                  2,685               2,324
     Undistributed production revenue                   6,176               6,662
                                                    ---------           ---------
                                                    $  19,316           $  23,024
                                                    =========           =========
</TABLE>




                                      F-11
<PAGE>   59


(7) LONG-TERM DEBT

         Long-term debt consists of the following (in thousands):

<TABLE>
<CAPTION>
                                            DECEMBER 31,
                                   --------------------------
                                     2000              1999
                                   --------          --------
<S>                                <C>               <C>
Revolving line of credit           $ 61,393          $114,000
Term loans                               --            14,000
Senior subordinated notes           225,000           225,000
Other                                   161               180
                                   --------          --------
                                    286,554           353,180
Less current portion                     19            50,019
                                   --------          --------
Long-term debt                     $286,535          $303,161
                                   ========          ========
</TABLE>

         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 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 and the term loans. 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 June 15, 2002, at the redemption prices set
forth below plus, in each case, accrued and unpaid interest, if any, thereon.

<TABLE>
<CAPTION>
                  YEAR                                                  PERCENTAGE
                  ----                                                  ----------
                  <S>                                                   <C>
                  2002.................................................  104.938%
                  2003.................................................  103.292%
                  2004.................................................  101.646%
                  2005 and thereafter..................................  100.000%
</TABLE>

         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 June 27, 1997, the Company entered into a senior revolving credit
agreement with several lenders. These lenders committed, subject to compliance
with the borrowing base, to provide the Company with revolving credit loans of
up to $200 million, of which $25 million was available for the issuance of
letters of credit. The credit agreement was a senior revolving credit facility
secured by substantially all of the Company's assets. The borrowing base was
determined by an evaluation of the Company's proved developed reserves, proved
undeveloped reserves and related processing and gathering assets and other
assets of the Company, adjusted by the engineering committee of the banks in
accordance with their standard oil and gas lending practices.



                                      F-12
<PAGE>   60


         The Company's borrowing base at December 31, 1998 was $170 million. On
January 15, 1999, the Company's borrowing base was redetermined at $126 million.
The Company had $154 million outstanding under this agreement at December 31,
1998 which resulted in a borrowing base deficiency of $28 million. The Company
agreed with its lenders to reduce this deficiency by $14 million on March 22,
1999 and by $14 million on May 10, 1999.

         On March 22, 1999, the Company made the $14 million payment to reduce
the outstanding amount under the credit agreement to $140 million. On May 10,
1999, the Company and its lenders further amended the credit agreement to
increase the Company's borrowing base to $136 million, subject to
redetermination in November 1999, and the Company paid $4 million to reduce the
outstanding loan balance to $136 million. The funds for these payments were
provided by internally generated cash flow and $14 million in term loans
provided by Chase Manhattan Bank. The Company was further required to make
additional payments which would lower the borrowing base and outstanding balance
to $126 million. The Company paid $5 million on July 29, 1999 and $6 million on
September 10, 1999 to reduce the outstanding balance to $125 million at
September 30, 1999. The amended agreement increased the interest rate to LIBOR
(London Interbank Offered Rate) plus 2.5% and provided certain covenant ratio
relief. The Company paid approximately $2 million in fees to the lenders and
expenses associated with the amendment.

         On December 14, 1999, the Company and its bank group further amended
the credit agreement. The revolving credit commitment in the amended agreement
provided for a $75 million revolving portion which matures on June 27, 2002 and
a $50 million term portion which would have matured on March 31, 2000. The
Company paid approximately $900,000 in fees to the lenders and expenses
associated with the amendment and wrote off $1.9 million of unamortized deferred
loan costs due to the modification of the borrowing base. 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 "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 ("the Notes"). 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 due
to the modification of borrowing capacity. The Revolver bears interest at the
prime rate plus two percentage points, payable monthly. At December 31, 2000,
the interest rate was 11.5%. Up to $20 million in letters of credit may be
issued pursuant to the conditions of the Revolver. At December 31, 2000, the
Company had $12.8 million of outstanding letters of credit.

         Initial proceeds from the Revolver of approximately $66 million 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) representing the unamortized deferred loan
costs pertaining to the former credit facility. The charge was recorded as an
extraordinary item. As of December 31, 2000, the outstanding balance under the
Revolver was $61.4 million with $25.8 million of borrowing capacity available
for general corporate purposes.



                                      F-13
<PAGE>   61


         The Facility 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 New York Mercantile Exchange ("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, 2000, under this formula was
approximately $265 million for all proved reserves of the Company and $211
million for properties secured by a mortgage.

         The Facility is subject to certain financial covenants. These include a
senior debt interest coverage ratio ranging from 5.8 to 1 at December 31, 2000,
to 3.2 to 1 at June 30, 2002; and a senior debt leverage ratio ranging from 2.4
to 1 at December 31, 2000 to 3.2 to 1 at June 30, 2002. EBITDA, as defined in
the Facility, 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) 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, 2000, the Company's current
ratio including the above adjustments was 2.34 to 1. The Company had satisfied
all financial covenants as of December 31, 2000.

         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 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. Effective with the May 10, 1999 amendment to the credit
agreement, the applicable margin relating to these swaps was increased from 1.5%
to 2.5%. Effective with the December 14, 1999 amendment to the credit agreement,
the applicable margin relating to these swaps was increased from 2.5% to a range
up to 3.5%.

         At December 31, 2000, the aggregate long-term debt maturing in the next
five years is as follows: $19,000 (2001); $61,412,000 (2002); $20,000 (2003);
$5,000 (2004); $6,000 (2005); and $225,092,000 (2006 and thereafter).



                                      F-14
<PAGE>   62


(8) LEASES

         The Company leases certain computer equipment, vehicles and office
space under noncancelable agreements with lease periods of one to five years.
Rent expense amounted to $1.6 million, $1.9 million and $2.2 million for the
years ended December 31, 2000, 1999 and 1998, respectively. Future commitments
under leasing arrangements were not significant at December 31, 2000.

(9) SHAREHOLDERS' EQUITY

         In November 1998, the Company awarded 118,274 shares of common stock to
employees as profit sharing and bonuses. These shares were issued in the
subsequent year.

(10) 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, 2000 there were 133,915 of
these options 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, 2000, options to purchase 735,277 shares
were outstanding under the plan. These options become exercisable as to 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 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 because, 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 no options granted in 1998. There were 274,692 and
303,491 options granted in 2000 and 1999, respectively, and 318,892 options were
repriced in 1999 which had an immaterial effect on compensation expense in 1999.
As a result of adopting FIN 44 compensation expense increased $298,000 in the
second half of 2000.

         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 1999
and 2000, respectively: risk-free interest rates of 6.2% and 6.4%; 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.



                                      F-15
<PAGE>   63


         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 loss for the years ended December 31, 2000, 1999 and 1998 were not material.

         Stock option activity consisted of the following:

<TABLE>
<CAPTION>
                                                                       WEIGHTED
                                                   NUMBER               AVERAGE
                                                     OF                EXERCISE
                                                   SHARES               PRICE
                                                  --------              ------
<S>                                               <C>                   <C>
BALANCE AT DECEMBER 31, 1997                       817,707              $ 8.66
                                                  --------
BALANCE AT DECEMBER 31, 1998                       817,707                8.66
                                                  --------
     Granted                                       303,491                1.26
     Forfeitures                                  (333,632)              10.82
     Exercised                                     (31,268)                .13
     Reissued and repriced                        (318,892)              10.82
     Reissued and repriced                         318,892                 .01
                                                  --------
BALANCE AT DECEMBER 31, 1999                       756,298                 .53
     Granted                                       274,692                 .22
     Forfeitures                                   (65,000)               5.83
     Exercised                                     (96,798)                .01
                                                  --------
BALANCE AT DECEMBER 31, 2000                       869,192                 .09
                                                  ========
OPTIONS EXERCISABLE AT DECEMBER 31, 2000           220,007              $  .07
                                                  ========
</TABLE>

         The weighted average fair value of options granted during 2000 and 1999
was $.07 and $.50, respectively. No options were granted in 1998. The exercise
price for the options outstanding as of December 31, 2000 ranged from $.01 to
$.30 per share. At December 31, 2000 the weighted average remaining
contractual life of the outstanding options is 8.5 years.

(11) TAXES

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

<TABLE>
<CAPTION>
                                    YEAR ENDED DECEMBER 31,
                        -----------------------------------------------
                          2000               1999               1998
                        --------           --------           --------
<S>                     <C>                <C>                <C>
CURRENT
       Federal          $    290           $     --           $   (503)
       State                   1                 --                 --
                        --------           --------           --------
                             291                 --               (503)
DEFERRED
       Federal             2,073            (10,449)           (69,976)
       State                   4               (730)            (5,726)
                        --------           --------           --------
                           2,077            (11,179)           (75,702)
                        --------           --------           --------
       TOTAL            $  2,368           $(11,179)          $(76,205)
                        ========           ========           ========
</TABLE>





                                      F-16
<PAGE>   64


         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,
                                                              ------------------------------------
                                                              2000            1999           1998
                                                              ----            ----           ----
<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            2.0
   Other, net                                                 (1.4)            0.9           (0.1)
                                                              ----            ----           ----
Effective income tax rate for the period                      35.4%           37.9%          36.9%
                                                              ====            ====           ====
</TABLE>

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

<TABLE>
<CAPTION>
                                                     DECEMBER 31,      DECEMBER 31,
                                                        2000              1999
                                                     ------------      ------------
<S>                                                  <C>               <C>
Deferred income tax liabilities:
     Property and equipment, net                      $ 45,065           $ 48,619
     Other, net                                            753                625
                                                      --------           --------
       Total deferred income tax liabilities            45,818             49,244
Deferred income tax assets:
     Accrued expenses                                    1,192              1,446
     Inventories                                            --                 17
     Net operating loss carryforwards                   25,372             30,014
     Tax credit carryforwards                              990                699
     Other, net                                            390                708
     Valuation allowance                                (1,840)            (2,053)
                                                      --------           --------
       Total deferred income tax assets                 26,104             30,831
                                                      --------           --------
       Net deferred income tax liability              $ 19,714           $ 18,413
                                                      ========           ========

     Long-term liability                              $ 21,189           $ 20,419
     Current asset                                      (1,475)            (2,006)
                                                      --------           --------
       Net deferred income tax liability              $ 19,714           $ 18,413
                                                      ========           ========
</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, 2000 relates principally to
certain net operating loss carryforwards which management estimates will expire
before they can be utilized.

         At December 31, 2000, the Company had approximately $71 million of net
operating loss carryforwards available for federal income tax reporting
purposes. Approximately $1 million of the net operating loss carryforwards are
limited as to their annual utilization as a result of prior ownership changes.
These net operating loss carryforwards, if unused, will expire from 2001 to
2006. The remaining net operating loss carryforwards will expire in 2012 and
2019. The Company has alternative minimum tax credit carryforwards of
approximately $990,000 which have no expiration date. The Company has
approximately $700,000 of statutory depletion carryforwards, which have no
expiration date.

(12) 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. Amounts are allocated to substantially all
employees based on relative compensation. The Company



                                      F-17
<PAGE>   65


expensed $1.6 million, $845,000 and $938,000 for the years ended December 31,
2000, 1999 and 1998, respectively, for contributions to the profit sharing plan
and discretionary bonuses. The 2000 and 1999 amounts were paid in cash. For the
1998 period one half was paid in cash and one half was paid in shares of the
Company's common stock contributed into each eligible employee's 401(k) plan
account.

         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 participants' compensation is contributed by the Company
to the plan each year. Eligible employees may also make voluntary contributions
which the Company matches $.50 for every $1.00 contributed up to 6% of an
employee's annual compensation. Retirement plan expense amounted to $650,000,
$830,000 and $867,000 for the years ended December 31, 2000, 1999 and 1998,
respectively.

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

(13) COMMITMENTS AND CONTINGENCIES

         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
of the Company.

(14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

<TABLE>
<CAPTION>
                                                                     YEAR ENDED DECEMBER 31,
                                                           ------------------------------------------
(IN THOUSANDS)                                              2000             1999              1998
                                                           -------          -------          --------
CASH PAID DURING THE PERIOD FOR:
<S>                                                        <C>              <C>              <C>
     Interest                                              $30,634          $34,426          $ 32,048
     Income taxes, net of refunds                                1               --            (1,970)
NON-CASH INVESTING AND FINANCING ACTIVITIES:
     Acquisition of assets in exchange for
        long-term liabilities                                  239              125               415
     Non-compete agreement and related obligation               --              705                --
</TABLE>

(15) 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. 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 $191 million at
December 31, 2000 based on rates available for similar instruments.

         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 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 or options. Under the deferral
method, gains and losses on these instruments are deferred on the balance



                                      F-18
<PAGE>   66


sheet and are included as an adjustment to gas revenue for the production being
hedged in the contract month. The Company incurred a pre-tax loss on its hedging
activities of $9.3 million in 2000 and pre-tax gains of $1.2 million in 1999 and
$1.5 million in 1998. At December 31, 2000 the fair value of futures contracts
covering 2001 natural gas production represented an unrealized loss of $10.5
million.

(16) 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.

<TABLE>
<CAPTION>
                                              YEAR ENDED DECEMBER 31,
                                       ----------------------------------------
         (IN THOUSANDS)                  2000            1999             1998
                                       -------          ------          -------
         <S>                           <C>              <C>             <C>
         Acquisition costs
          Proved properties            $   220          $   --          $ 9,194
          Unproved properties            2,093             855            1,857
         Developmental costs            13,849             186           30,090
         Exploratory costs               8,528           6,442            9,982
</TABLE>

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 have been reviewed by independent petroleum
engineers.




                                      F-19
<PAGE>   67


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

<TABLE>
<CAPTION>
                                                   OIL               GAS
                                                (MBBL) (1)        (MMCF) (2)
                                                ----------        ----------
         <S>                                    <C>               <C>
         DECEMBER 31, 1997                         5,552            291,645
         Extensions and discoveries                  255             29,331
         Purchase of reserves in place                34             20,296
         Sale of reserves in place                   (21)            (6,939)
         Revisions of previous estimates            (809)            11,066
         Production                                 (768)           (30,140)
                                                  ------           --------
         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
                                                  ======           ========



         PROVED DEVELOPED RESERVES
         December 31, 1998                         3,974            280,669
                                                  ======           ========
         December 31, 1999                         5,898            267,942
                                                  ======           ========
         December 31, 2000                         5,954            251,747
                                                  ======           ========
</TABLE>


         (1)  Thousand barrels
         (2)  Million cubic feet





                                      F-20
<PAGE>   68


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,
                                                             ---------------------------------------------------
                                                                2000                 1999                1998
                                                             -----------           ---------           ---------
                                                                                (IN THOUSANDS)
         <S>                                                 <C>                   <C>                 <C>
         Estimated future cash inflows (outflows)
              Revenues from the sale of oil and gas          $ 3,835,298           $ 957,046           $ 818,401
              Production and development costs                  (805,025)           (411,881)           (340,321)
                                                             -----------           ---------           ---------
         Future net cash flows before income taxes             3,030,273             545,165             478,080
         Future income taxes                                  (1,037,843)           (124,561)           (102,358)
                                                             -----------           ---------           ---------
         Future net cash flows                                 1,992,430             420,604             375,722
         10% timing discount                                  (1,171,666)           (203,716)           (167,059)
                                                             -----------           ---------           ---------
         Standardized measure of discounted
              future net cash flows                          $   820,764           $ 216,888           $ 208,663
                                                             ===========           =========           =========
</TABLE>

         At December 31, 2000, 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. The average
prices of natural gas used in the calculation were higher than the Company
actually realized in December 2000. Further, based on market conditions in
February 2001, these prices are not indicative of those that the Company expects
to realize consistently in the future. If reserves had been valued using assumed
constant wellhead prices of $23.50 per barrel of oil and $4.50 per Mmbtu
(million British thermal units) of natural gas, total proved reserves would be
401.9 Bcfe instead of 425.4 Bcfe with a discounted future net cash flows before
income taxes of $469.0 million instead of $1.2 billion.




                                      F-21
<PAGE>   69


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

<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31,
                                                             -------------------------------------------------
                                                                2000                1999                1998
                                                             ---------           ---------           ---------
                                                                               (IN THOUSANDS)
         <S>                                                 <C>                 <C>                 <C>
         Beginning of year                                   $ 216,888           $ 208,663           $ 219,720
         Sale of oil and gas, net of
             production costs                                  (56,416)            (54,059)            (60,330)
         Extensions and discoveries, less
             related estimated future
             development and production costs                   69,990               1,233              30,821
         Purchase of reserves in place less
             estimated future production costs                  13,383                  --              10,528
         Sale of reserves in place less
             estimated future production costs                 (50,817)               (578)             (3,373)
         Revisions of previous quantity estimates              445,976              31,128                (673)
         Net changes in prices and production costs            608,442              32,836             (30,512)
         Change in income taxes                               (363,561)             (2,729)             24,977
         Accretion of 10% timing discount                       26,751              25,656              29,259
         Changes in production rates (timing)
             and other                                         (89,872)            (25,262)            (11,754)
                                                             ---------           ---------           ---------
         End of year                                         $ 820,764           $ 216,888           $ 208,663
                                                             =========           =========           =========
</TABLE>

(17) 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 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 the year ended December 31, 2000 which amounted to $21.6 million. No
customer accounted for more than 10% of consolidated revenues during the years
ended December 31, 1999 and 1998.


                                      F-22

<PAGE>   70


(18) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

         The results of operations for the four quarters of 2000 and 1999 are
shown below (in thousands).

<TABLE>
<CAPTION>
                                                      FIRST              SECOND              THIRD             FOURTH
                                                     --------           --------           --------           --------
         <S>                                         <C>                <C>                <C>                <C>
         2000
         ----
         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>

<TABLE>
<CAPTION>
                                                      FIRST              SECOND              THIRD             FOURTH
                                                     --------           --------           --------           --------
         <S>                                         <C>                <C>                <C>                <C>
         1999
         ----
         Sales and other operating revenues          $ 34,257           $ 33,099           $ 30,685           $ 32,703
         Gross profit (loss)                            1,512              1,516               (593)             4,474
         Net loss                                      (4,157)            (4,854)            (7,691)            (1,601)
</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 2).


(19) 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 cubit 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. The Company has the option to repurchase the interests at a future
date.





                                      F-23