<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, 1999
                          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 29, 2000, Belden & Blake Corporation had outstanding
10,256,487 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
         --------

         Belden & Blake Corporation (the "Company") was acquired by TPG Partners
II L.P. ("TPG") and certain other investors on June 27, 1997 ("the
Acquisition"). For financial reporting purposes, the Acquisition is considered
effective June 30, 1997 and the operations of the Company prior thereto and
thereafter are respectively classified as predecessor company and successor
company operations. The operations of the successor company represent 100% of
the businesses of the predecessor. Therefore, certain operational data for the
twelve months ended December 31, 1997 have been presented on a combined basis
because such information is comparable to the historical data of the predecessor
and the current data of the successor.

         The historical financial statements of the successor company and its
predecessor are presented separately as described in Note 1 to the Consolidated
Financial Statements included under Item 8.

GENERAL

         Belden & Blake Corporation, an Ohio corporation, 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. Until 1995,
the Company conducted business exclusively in the Appalachian Basin where it has
operated since 1942 through several predecessor entities. It is currently one of
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. In September 1996, the Company entered the Illinois
Basin by acquiring a natural gas gathering system and the Shrewsbury Gas Field
in western Kentucky. At December 31, 1999, the Company operated in Ohio,
Pennsylvania, New York, West Virginia, Michigan and Kentucky.

         At December 31, 1999, the Company's net production was approximately
68.4 Mmcf (million cubic feet) of natural gas and 1,864 Bbls (barrels) of oil
per day. At that date the Company owned interests in 7,867 gross (6,891 net)
productive oil and gas wells in Ohio, Pennsylvania, New York, West Virginia,
Michigan and Kentucky with proved reserves totaling 306.7 Bcf (billion cubic
feet) of natural gas and 6.7 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 $267.5 million at December 31,
1999. At December 31, 1999, the Company operated approximately 7,565 wells,
including wells operated for third parties. At that date, the Company held
leases on 1,148,625 gross (1,006,977 net) acres, including 624,001 gross
(523,307 net) undeveloped acres. The Company owned and operated approximately
2,750 miles of gas gathering systems with access to the commercial and
industrial gas markets of the northeastern United States at December 31, 1999.

         The Company's production and reserves have grown principally through
the acquisition of producing properties and related gas gathering facilities and
exploration and development of its own acreage. From its formation in March 1992
through December 31, 1999, the Company acquired for $158.3 million producing
properties with 235.2 Bcfe (billion cubic feet of natural gas equivalent) of

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proved developed reserves at an average cost of $0.67 per Mcfe (thousand cubic
feet of natural gas equivalent) and spent $21.8 million to acquire and develop
additional gas gathering facilities. During the period from 1992 through 1999,
the Company drilled 1,075 gross (813.5 net) wells at an aggregate cost of
approximately $152.0 million for the net wells. This drilling added 159.8 Bcfe
to the Company's proved reserves. The Company originally budgeted $28 million of
capital expenditures to drill approximately 251 wells in 1999. However, due to a
borrowing base deficiency which occurred in January 1999, the Company reduced
its drilling budget to accommodate only those wells which had commenced drilling
before the borrowing base reduction and those wells in which it had contractual
obligations to participate. As a result of the reduction, the Company only
participated in drilling 18 gross (4.8 net) wells in 1999 at a direct cost of
approximately $840,000 for the net wells. This greatly diminished drilling
activity in 1999 added 0.49 Bcfe of proved developed reserves at an average cost
of $1.71 per Mcfe. Proved developed reserves added through drilling in 1999
represented approximately 2% of 1999 production.

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

SIGNIFICANT EVENTS

         In July 1998, the Company began development of a major expansion of its
gas marketing capability with the objective of substantially increasing the
number of commercial and industrial customers served, the volumes of natural gas
sold and the Company's future net operating margins from natural gas sales. The
expansion included the selection and installation of systems and technology to
enhance the efficiency of the gas marketing operation. The Company expensed
$732,000 in 1998 and $208,000 in 1999 relating to this expansion project. In
conjunction with the planned expansion of its gas marketing capability, the
Company formed Belden Energy Services Company ("BESCO"), a wholly-owned
subsidiary, in September 1998. See Note 4 to the Consolidated Financial
Statements.

         On January 15, 1999, the Company was notified that the several lenders
under its revolving credit agreement had reduced the Company's borrowing base
from $170 million to $126 million. The Company's outstanding borrowings on that
date exceeded the redetermined borrowing base by $28 million. In order to
satisfy the borrowing base deficiency, the Company immediately reduced its
capital expenditures to the minimum required to maintain prudent operations of
its producing oil and gas properties and gas gathering systems.

         In March 1999, the Company began a rigorous review of its strategic
direction given the Company's high debt level and greatly diminished liquidity.
In the course of reviewing its strategic direction, the Company determined that
its diminished financial position and liquidity would prevent it from
effectively expanding its gas marketing business given the need for additional
systems, more personnel and credit. As a result of this determination, the gas
marketing expansion project was abandoned in 1999.

         The Company's Chief Executive Officer ("CEO"), retired from the Company
on June 1, 1999. John L. Schwager, former CEO and President of Alamco, Inc., an
Appalachian Basin exploration and production company, was engaged as the new
CEO. Mr. Schwager's mission, as established by the Company's Board of Directors,
was to attempt to sell non strategic, non core assets, using any proceeds to
reduce debt; and further, to concentrate the Company's available resources on
its core exploration and

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<PAGE>   4
production business. Mr. Schwager was elected to the Board of Directors in
August 1999 and was appointed to the additional position of President upon the
departure of the former President in September 1999.

         In July 1999, the Company developed plans to transfer certain non
strategic producing and non producing oil and gas assets to a proposed $100
million to $120 million royalty trust and sell the royalty trust units in a
public offering. The Company planned to use the proceeds from the sale of
royalty trust units to reduce bank debt. In August 1999, the Company abandoned
the proposed royalty trust because of the withdrawal of the lead underwriter.
Approximately $374,000 of costs associated with the project were written off in
the third quarter of 1999.

         In August 1999, the Company and its wholly-owned subsidiary, The Canton
Oil and Gas Company ("COG") sold Target Oilfield Pipe and Supply Company
("TOPS"), a wholly-owned subsidiary of COG, to an oilfield supply company for
approximately $4 million. Proceeds from the sale were used to reduce the
Company's bank debt. The Company recorded a $2.8 million loss on the sale in the
third quarter of 1999. TOPS operated retail sales outlets in the Appalachian and
Michigan Basins from which it sold a broad range of oilfield supplies and
equipment. See Note 4 to the Consolidated Financial Statements.

         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%. Including employee
reductions through attrition and the sale of subsidiaries, total Company
employment was reduced by approximately 25% in 1999.

         In October 1999, the Company solicited offers for the sale of Peake
Energy, Inc. ("Peake"), a wholly owned exploration and production subsidiary
with operations in West Virginia and Kentucky. See Subsequent Events.

         In November 1999, the Company sold BESCO, its Ohio retail natural gas
marketing subsidiary, to FirstEnergy Corp. ("FirstEnergy"), an electric utility
holding company also engaged in oil and gas production and natural gas
marketing. Proceeds from the sale were used to reduce the Company's bank debt.
In the future, the Company's Ohio natural gas production not committed to
existing sales contracts will be sold on the wholesale market. See Note 4 to the
Consolidated Financial Statements.

         In December 1999, the Company and its lenders further amended the
senior revolving credit agreement. The revolving credit commitment in the
amended agreement provides for a $75 million revolving portion which matures on
June 27, 2002 and a $50 million term portion which matures on March 31, 2000.
The borrowing base on the revolving portion of the credit facility will remain
at $75 million until the earlier of (i) the sale of Peake; and (ii) the
redetermination of the borrowing base in the ordinary course, pursuant to the
terms of the existing credit agreement.

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<PAGE>   5
RECENT DEVELOPMENTS

SUBSEQUENT EVENTS

         On March 17, 2000, the Company sold the stock of Peake, a wholly owned
subsidiary, to North Coast Energy, Inc. ("North Coast"), an independent oil and
gas company, with an effective date of January 1, 2000.  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 million.

         At December 31, 1999, using SEC pricing parameters, Peake had proved
developed reserves of approximately 66.5 Bcfe and proved undeveloped reserves
of approximately 3.7 Bcfe.  Peake's reserves represented 20.2% of the Company's
total proved reserves.

         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.
The next scheduled borrowing base redetermination is in November 2000.


DESCRIPTION OF BUSINESS

OVERVIEW

         The Company conducts operations in the United States in one reportable
segment which is exploration and production. Founded in 1942, 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
principally in the Appalachian and Michigan Basins (a region which includes
Ohio, Pennsylvania, New York, West Virginia 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.

         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, there has been only 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 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

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<PAGE>   6
the critical mass to operate efficiently. Ward Lake currently operates 743 wells
producing approximately 51 Mmcf (21 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 which has not
been extensively developed. 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 that since 1992 have averaged $0.35 per Mcf (thousand cubic
feet) above the New York Mercantile Exchange's ("NYMEX") annual price for gas
delivered at the Henry Hub in Louisiana. The Company's average wellhead gas
price in 1999 was $0.23 per Mcf above the NYMEX's Henry Hub price.

BUSINESS STRATEGY

         The Company seeks to increase shareholder value by increasing reserves,
production and cash flow through a balanced program of exploration and
development drilling and strategic acquisitions. In 1999, the Company conducted
a rigorous examination of its business strategy to take into consideration its
high debt level and greatly diminished liquidity. As a result, the Company has
determined that it will concentrate its available resources on its core
exploration and production business. The Company also recognizes the necessity
of replacing its production with reserve additions through drilling and
acquisitions in order to sustain its existence over the longer term.

         The key elements of the Company's current strategy are as follows:

o    IMPROVE THE COMPANY'S FINANCIAL POSITION. At December 31, 1999, the Company
     had $128 million of bank debt outstanding with a weighted average interest
     rate of 9.43%, and $225 million of senior subordinated notes bearing
     interest at 9.875%. At that date, the Company had a deficit in
     shareholders' equity of $51.6 million. The Company intends to sell 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.

o    MAINTAIN A BALANCED DRILLING PROGRAM. The Company intends to maintain its
     production and reserves through a balanced program of developmental and
     exploratory drilling. The Company

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     believes that there are significant exploration and development
     opportunities in the less developed or deeper formations in the Appalachian
     and Michigan Basins and has identified numerous development and exploratory
     drilling locations in the deeper formations of these Basins. The company's
     drilling budget in 2000 is approximately $16.1 million, which will fund the
     drilling of approximately 125 gross (99 net) wells.

o    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.

o    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 in Ohio, Pennsylvania, New York and
     Michigan, the Company continuously reviews its properties, especially
     recently acquired properties, to determine what actions can be taken to
     reduce operating costs and/or improve production. The Company has
     successfully reduced field level costs through improved operating practices
     such as computerized production scheduling and the use of hand-held
     computers to gather field data. On acquired properties, further
     efficiencies may be realized through improvements in production scheduling
     and reductions in oilfield labor. Actions that may be taken to improve
     production include modifying surface facilities and redesigning downhole
     equipment.

o    PURSUE CONSOLIDATION OPPORTUNITIES. The energy industry is experiencing a
     general trend toward consolidation. The Appalachian and Michigan Basins are
     highly fragmented with the potential for significant consolidation. The
     Company believes this fragmented environment provides the basis for
     acquisition opportunities as capital constrained operators, the majority of
     which are privately held, seek liquidity or operating capital. The Company
     intends to use its geographic and technical expertise, low cost structure
     and decentralized organization to pursue additional strategic acquisitions
     in its areas of operations. The Company intends to finance such
     acquisitions using its available cash flow or additional debt.

o    EXPAND NATURAL GAS GATHERING. The Company's extensive gas gathering systems
     are integral to the Company's low cost structure and high revenues per unit
     of gas production. 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
     much of its natural gas production.

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<PAGE>   8
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, especially recently acquired 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's principal secondary recovery
technique in Ohio and Pennsylvania has been waterflooding.

         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 Oilfield Service
Company ("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.

         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,
                                        -------------------------------------------------------------------
                                          1995           1996           1997           1998           1999
                                        -------        -------        -------        -------        -------
<S>                                     <C>            <C>            <C>            <C>            <C>
Production:
      Gas (Bcf)                            17.0           25.4           27.2           30.1           27.0
      Oil (Mbbl - thousand barrels)         556            719            753            768            713

Average sales price:
      Gas (per Mcf)                     $  2.21        $  2.56        $  2.65        $  2.57        $  2.50
      Oil (per Bbl)                       16.78          20.24          18.10          12.61          16.57

Average production costs per Mcfe
(including production taxes)               0.68           0.72           0.78           0.77           0.81

Total oil and gas revenues
(in thousands)                           46,853         79,491         85,756         87,055         79,299

Total production expenses
(in thousands)                           13,816         21,266         24,668         26,725         25,240
</TABLE>

         Gas Gathering. The Company currently operates approximately 1,830 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 $5.0 million in 1999. Direct costs associated
with gas gathering in 1999 totaled $1.7 million.

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<PAGE>   9
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.

         The Company originally budgeted $28 million of capital expenditures to
drill approximately 251 wells in 1999. On January 15, 1999, the Company was
notified that the several lenders under its revolving credit agreement had
reduced the Company's borrowing base from $170 million to $126 million. The
Company's outstanding borrowings on that date exceeded the redetermined
borrowing base by $28 million. In order to satisfy the borrowing base
deficiency, the Company immediately reduced its capital expenditures on drilling
to only those wells which had commenced drilling before the borrowing base
reduction and those wells in which it had a contractual obligations to
participate. As a result of the reduction, the Company only participated in
drilling 18 gross (4.8 net) wells in 1999 at a direct cost of approximately
$840,000 for the net wells. This greatly diminished drilling activity in 1999
added 0.49 Bcfe of proved developed reserves at an average cost of $1.71 per
Mcfe. Proved developed reserves added through drilling in 1999 represented
approximately 2% of 1999 production. The results of this drilling activity is
shown in the table on page 13.

         In 2000, the Company expects to spend $16.1 million on development and
exploratory drilling of 125 gross (99 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
26 gross (26 net) wells to the Antrim Shale formation in 2000.

         Producing natural gas in the form of methane from coalbed formations is
becoming a more common practice, particularly in Pennsylvania. In 1998, the
Company completed its second project area near Connellsville, PA, with the
completion of 12 coalbed methane wells. This brings the Company's

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<PAGE>   10
total wells producing from this type of reservoir to 62. Because of financial
constraints, the Company did not drill any coalbed methane wells in 1999. With
over 60,000 acres under lease in the coal seam fairway, the Company believes
that substantial additional opportunities exist for coalbed methane drilling.
The Company currently plans to drill 15 gross (12.5 net) coalbed methane wells
in 2000.

         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 (1)
                                -----------        ----------------     ----------------
                                 (in feet)          (in thousands)          (in Mmcfe)
<S>                             <C>                <C>                  <C>
Ohio                            1,200-5,500            $ 75-145               80-150
West Virginia                   1,300-6,000             140-180              150-500
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                        1,000-1,200             200-250              400-600
Kentucky                        1,200-1,800              90-110              125-250
</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 geographical boundaries of the Knox sequence, which lies approximately
2,000 feet below the highly developed Clinton Sandstone, are generally well
defined in Ohio with less definition in New York and Pennsylvania. Nevertheless,
the Knox group has been only lightly explored, with fewer than 2,500 wells
drilled to this sequence of formations during the past 10 years.

         The Company began testing the Knox sequence in 1989 by selecting
certain wells that were targeted to be completed to the Clinton formation and
drilling them an additional 2,000 feet to 2,500 feet to test the Knox
formations. 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.

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All of the wells drilled by the Company in 1999 were Knox formation wells, the
majority of which were higher risk, exploratory tests. As a result, the success
rate and reserves discovered per well were lower than the Company's historical
experience.

         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
------------
</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 20 years.

                                       10
<PAGE>   12

         The following table shows the Company's production from Knox formation
wells since 1995:

<TABLE>
<CAPTION>
                                   PRODUCING WELLS AND PRODUCTION FROM KNOX FORMATIONS
                                   ---------------------------------------------------
                                     1995      1996        1997      1998        1999
                                     ----      ----        ----      ----        ----
<S>                                    <C>        <C>       <C>        <C>        <C>
Number of wells in production:
     Gross                             66         82        112        140        131
     Net                             41.5       58.9       75.6       88.0       74.8
     Percent of total net wells       0.7%       0.9%       1.0%       1.2%       1.1%
Annual production (net):
     Gas (Mmcf)                     1,624      2,788      3,600      4,111      2,603
     Oil (Mbbl)                      74.9       78.2      111.2      181.9      161.5
     Combined (Mmcfe)               2,074      3,257      4,267      5,202      3,572
     Percent of total combined
     production                        10%        11%        13%        15%        11%
</TABLE>

         Productive Knox wells represented approximately 1.1% of the Company's
total productive wells at December 31, 1999. Production from Knox wells in 1999,
however, equaled 11% of the Company's total production on an Mcfe basis. The
significant reduction in the Company's Knox drilling activity in 1999, coupled
with normal decline rates, resulted in a 31% decline in production from the Knox
formation in 1999. The Company plans to drill or participate in joint ventures
to drill 43 gross (19.7 net) wells to the Knox formation in 2000.

         In addition, the Company has also tested the more prolific Niagaran
Carbonate, Trenton/Black River Carbonates, Onondaga Limestone, Oriskany
Sandstone and Newburg Sandstone formations. Within recent years, other operators
have identified a deep play with significant reserve potential in the
Trenton/Black River formations in New York. Based on historical information
available in public records, wells drilled in this play have reserves in the
range of 1.0 to 2.0 Bcf of natural gas per well. Since 1997, Belden & Blake has
acquired significant seismic data and has substantially enhanced its acreage
position in areas believed to have production potential in the Trenton/Black
River formations. Currently, the Company has in excess of 24,000 acres in this
prospect area and has identified 36 potential well locations to test the
Trenton/Black River formations.

                                       11
<PAGE>   13
         The Company is well positioned to exploit the undeveloped potential of
these deeper, less developed formations in the future with substantially all of
its leased acreage overlying potential deeper, less developed formation drilling
locations. In addition to its planned Knox formation drilling, the Company plans
to drill approximately 5 gross (4.3 net) wells to these other deep formations in
2000. 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     $120     $240         300-500
Trenton/Black River
  Carbonates            NY         5,000-8,000      400      600     1,000-2,000
Niagaran Carbonate      MI         4,500-5,500      275      525       900-1,200
Onondaga Limestone      PA         4,000-5,500      150      250         200-750
Oriskany Sandstone      PA, NY     4,500-7,000      150      300       300-1,000
</TABLE>

                                       12
<PAGE>   14
         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)
                 ------------------------------------------------    ---------------------------------------------------
                 1995       1996       1997       1998       1999    1995        1996      1997          1998       1999
                 ----       ----       ----       ----       ----    ----        ----      ----          ----       ----
<S>              <C>        <C>        <C>        <C>        <C>     <C>         <C>       <C>          <C>         <C>
Productive:
   Gross         106          153        187        189       --       23(3)       34        39(4)        29(5)        9(6)
   Net          92.5        126.3      156.5      167.0       --     11.5        22.2      24.5         14.2         2.1
Dry:
   Gross           4            2          7          3       --       22          18        28           28           9
   Net           3.2          2.0        6.3        2.5       --     10.7        10.2      12.3         15.5         2.7
Reserves
developed-
net (Bcfe)      18.5         32.7       32.8       32.3       --      5.2         7.7       9.0          3.0         0.5
Approximate
cost (in
millions)      $15.1       $ 22.2     $ 31.2     $ 28.4     $ --    $ 5.3       $ 9.0     $ 9.3        $ 7.6        $0.8
</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)  Two additional wells which were dry in the Knox formations were
     subsequently completed in the shallower Clinton formation. One additional
     well which was dry in the Oriskany formation was subsequently completed in
     the shallower Berea/Shale formations.

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

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

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

                                       13
<PAGE>   15
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. Although the Company often reviews in
excess of 50 acquisition opportunities per year, this disciplined approach can
result in uneven annual spending on acquisitions. The following table sets forth
information pertaining to acquisitions completed during the period 1992 through
1999. Despite several attractive opportunities, the Company was unable to make
any significant acquisitions in 1999 because of a lack of available capital.

<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                   --                --          --            --            --
                       --          --------       -----       -------       -------
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

         During 1999, the Company performed a rigorous review of its strategic
direction given the Company's high debt level and greatly diminished liquidity.
As a result, certain non strategic businesses and properties were disposed to
reduce the Company's debt. The Company continues to evaluate its non strategic
producing and non producing oil and gas assets for possible future disposition.

         In August 1999, the Company and its wholly-owned subsidiary, COG, sold
TOPS, a wholly-owned subsidiary of COG, to an oilfield supply company for
approximately $4 million. Proceeds from the sale were used to reduce the
Company's bank debt. The Company recorded a $2.8 million loss on the sale in the
third quarter of 1999. TOPS operated retail sales outlets in the Appalachian and
Michigan Basins from which it sold a broad range of oilfield supplies and
equipment.

         In November 1999, the Company sold its BESCO subsidiary to FirstEnergy,
an electric utility holding company also engaged in oil and gas production and
natural gas marketing. Proceeds from the sale were used to reduce the Company's
bank debt. BESCO was the Company's retail natural gas

                                       14
<PAGE>   16

marketing outlet in Ohio. In the future, the Company's Ohio natural gas
production not committed to existing sales contracts will be sold on the
wholesale market.

         During 1999, the Company sold 315 gross (298.1 net) wells representing
an estimated 1.0 Bcfe of oil and gas reserves for $1.3 million.

EMPLOYEES

         As of February 29, 2000, the Company had 429 full-time employees,
including 277 oil and gas exploration and production employees, 16 petroleum
engineers, 8 geologists, 2 geophysicists, 96 oilfield service employees and 30
general and administrative employees.

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.

         No customer accounted for more than 10% of consolidated revenues during
the years ended December 31, 1999 and 1998, or the six months ended June 30,
1997 and December 31, 1997.

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

                                       15
<PAGE>   17
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 (the "NGA") and the
Natural Gas Policy Act of 1978 (the "NGPA"). 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.

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

OIL AND GAS RESERVES

         The following table sets forth the Company's proved oil and gas
reserves as of December 31, 1997, 1998 and 1999 determined in accordance with
the rules and regulations of the Securities and Exchange Commission. 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,
                                               -------------------------------
                                               1997          1998         1999
                                               ----          ----         ----
<S>                                            <C>           <C>          <C>
Estimated proved reserves
       Gas (Bcf)                               291.6         315.3        306.7
       Oil (Mbbl)                              5,552         4,243        6,699
</TABLE>

         See Note 17 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,
1999 determined in accordance with the rules and regulations of the Securities
and Exchange Commission.

<TABLE>
Estimated future net cash flows (before income                       (in thousands)
taxes) attributable to estimated production during
<S>                                                                     <C>
2000                                                                    $ 48,123
2001                                                                      36,385
2002                                                                      41,714
2003 and thereafter                                                      418,943
                                                                        --------
Total                                                                   $545,165
                                                                        ========
Present value before income taxes
(discounted at 10% per annum)                                           $267,511
                                                                        ========
Present value after income taxes
(discounted at 10% per annum)                                           $216,888
                                                                        ========
</TABLE>

                                       16
<PAGE>   18
         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, 1999 without escalation, except where changes in prices were
fixed and readily determinable under existing contracts. The following table
sets forth the weighted average year-end prices for oil and gas.

<TABLE>
<CAPTION>
                                                       December 31,
                                          -------------------------------------
                                          1997             1998            1999
                                          ----             ----            ----
<S>                                      <C>              <C>             <C>
Gas (per Mcf)                            $ 2.73           $2.49           $ 2.61
Oil (per Bbl)                             14.59            9.73            23.47
</TABLE>

IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS

         As described in Note 2 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. As
demonstrated by the table in the preceding section, 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 Acquisition 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.

                                       17
<PAGE>   19
PRODUCING WELL DATA

         As of December 31, 1999, the Company owned interests in 7,867 gross
(6,891 net) producing oil and gas wells and operated approximately 7,565 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, 1999, the Company's net production was approximately 68.4 Mmcf of
natural gas and 1,864 Bbls of oil per day.

         The following table summarizes by state the Company's productive wells
at December 31, 1999:

<TABLE>
<CAPTION>
                                            December 31, 1999
                         -------------------------------------------------------
                            Gas Wells          Oil Wells             Total
                         ---------------     ---------------     ---------------
State                    Gross      Net      Gross      Net      Gross      Net
-------------            -----      ---      -----      ---      -----      ---
<S>                      <C>       <C>       <C>       <C>       <C>       <C>
Ohio                     1,487     1,334     1,807     1,705     3,294     3,039
West Virginia            1,395     1,290       376       373     1,771     1,663
Pennsylvania               641       516       398       391     1,039       907
New York                   858       839         7         7       865       846
Michigan                   785       325         5         3       790       328
Kentucky                   108       108        --        --       108       108
                         -----     -----     -----     -----     -----     -----
                         5,274     4,412     2,593     2,479     7,867     6,891
                         =====     =====     =====     =====     =====     =====
</TABLE>

ACREAGE DATA

         The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 1999:

<TABLE>
<CAPTION>
                                            December 31, 1999
                  -------------------------------------------------------------------------
                   Developed Acreage       Undeveloped Acreage          Total Acreage
                  -------------------     ---------------------     -----------------------
State              Gross        Net        Gross          Net         Gross           Net
-------------      -----        ---        -----          ---         -----           ---
<S>               <C>         <C>         <C>           <C>           <C>           <C>
Ohio              320,794     290,406     226,045       182,849       546,839       473,255
West Virginia      64,894      63,428     119,784        75,305       184,678       138,733
Pennsylvania       43,270      35,633     167,682       160,266       210,952       195,899
New York           70,000      68,537      69,006        66,693       139,006       135,230
Michigan           13,216      13,216      35,152        31,909        48,368        45,125
Kentucky           12,450      12,450       6,332         6,285        18,782        18,735
                  -------     -------     -------     ---------     ---------     ---------
                  524,624     483,670     624,001       523,307     1,148,625     1,006,977
                  =======     =======     =======     =========     =========     =========
</TABLE>

                                       18
<PAGE>   20
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 29, 2000 was as follows:

                                                 Number of
Title of Class                                Record Holders
----------------------------------------    --------------------
Common Stock                                        10


DIVIDENDS

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

                                       19
<PAGE>   21
Item 6.  SELECTED FINANCIAL DATA
         -----------------------

<TABLE>
<CAPTION>
                                         PREDECESSOR COMPANY         |             SUCCESSOR COMPANY
                                 ----------------------------------- | -----------------------------------------
                                 AS OF OR FOR THE YEAR    SIX MONTHS |  SIX MONTHS      AS OF OR FOR THE YEAR
                                   ENDED DECEMBER 31,       ENDED    |     ENDED          ENDED DECEMBER 31,
                                 ---------------------     JUNE 30,  |  DECEMBER 31,    ----------------------
(IN THOUSANDS)                     1995         1996         1997    |      1997           1998           1999
                                 --------     --------    ---------- |  ------------    ---------     ----------
<S>                              <C>          <C>          <C>       |    <C>            <C>            <C>
OPERATIONS:                                                          |
  Revenues                       $110,067     $153,235     $79,397   |    $ 84,126       $ 154,839      $135,738
  Depreciation, depletion                                            |
    and amortization               19,717       29,752      15,366   |      31,694          68,488        41,412
  Impairment of oil and gas                                          |
    properties and other assets        --           --          --   |          --         160,690            --
  Income (loss) from                                                 |
    continuing operations           6,260       15,194      (9,873)  |     (11,372)       (130,550)      (18,303)
  Preferred dividends paid            180          180          45   |          --              --            --
BALANCE SHEET DATA:                                                  |  AS OF 12/31/97
                                                                     |  --------------
  Working capital                  17,359       22,110               |      19,846          (6,268)      (43,032)
  Oil and gas properties and                                         |
    gathering systems, net        216,848      222,127               |     491,183         319,013       285,081
  Total assets                    297,298      303,763               |     599,320         418,605       350,695
  Long-term liabilities,                                             |
    less current portion          110,523       97,642               |     355,649         354,382       303,731
  Preferred stock                   2,400        2,400               |          --              --            --
  Total shareholders' equity                                         |
     (deficit)                    142,291      158,918               |      96,858         (33,014)      (51,590)
</TABLE>

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

         As described in the accompanying Notes to Consolidated Financial
Statements, 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. For financial reporting purposes, the Acquisition is considered
effective June 30, 1997 and the operations of the Company prior to July 1, 1997
are classified as predecessor company operations. The consolidated balance
sheets at December 31, 1998 and 1999 include the application of purchase
accounting to measure the Company's assets and liabilities at fair value. Debt
incurred to finance the Acquisition and related transaction costs are reflected
in the December 31, 1997, 1998 and 1999 financial statements. A vertical black
line is shown in the financial statements to separate the results of operations
of the predecessor and successor companies.

         The allocation of the purchase price at fair value resulted in a
significant increase in the book value of the Company's assets. The increase in
the book value of assets resulted in materially higher charges for depreciation,
depletion and amortization in the second half of 1997 and all of 1998 and 1999.

         As described in Note 2 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 17 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

                                       20
<PAGE>   22
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 Acquisition 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. The impairment charge
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 1999 compared to 1998.

         The Company incurred transaction costs associated with the Acquisition
of $16.8 million. These costs were expensed in the second quarter of 1997. As a
result of the Acquisition, the Company is highly leveraged, resulting in
materially higher interest charges in the second half of 1997 and all of 1998
and 1999. These higher interest charges are expected to continue in subsequent
accounting periods.

         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 operates principally 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 service provided to the Company's own operations are
provided at cost and all intercompany revenues and expenses are eliminated in
consolidation.

                                       21
<PAGE>   23
RESULTS OF OPERATIONS
         As a result of the Acquisition, the results of operations for the
periods subsequent to June 30, 1997 are not necessarily comparable to those
prior to July 1, 1997. The following table combines the six-month predecessor
company period ended June 30, 1997 with the six-month successor company period
ended December 31, 1997 for purposes of the discussion of year-end results
(dollars are stated in thousands and as a percentage of revenue).

<TABLE>
<CAPTION>
                                                                               YEAR ENDED DECEMBER 31,
                                                    --------------------------------------------------------------------------------
                                                             1999                       1998                           1997
                                                    ---------------------     -------------------------      -----------------------
<S>                                                 <C>             <C>       <C>                 <C>        <C>               <C>
REVENUES
   Oil and gas sales                                $ 79,299        58.4%     $  87,055           56.2%      $ 85,756          52.4%
   Gas gathering, marketing, and oilfield sales
        and service                                   51,443        37.9         63,358           40.9         74,577          45.6

   Other                                               4,996         3.7          4,426            2.9          3,190           2.0
                                                    ---------------------     -------------------------      ----------------------
                                                     135,738       100.0        154,839          100.0        163,523         100.0
EXPENSES
   Production expense                                 21,980        16.2         23,739           15.3         21,496          13.2
   Production taxes                                    3,260         2.4          2,986            1.9          3,172           1.9
   Gas gathering, marketing, and oilfield sales
        and service                                   46,954        34.6         56,813           36.7         65,805          40.1
   Exploration expense                                 6,442         4.7          9,982            6.5         10,360           6.3
   General and administrative expense                  5,412         4.0          4,536            2.9          4,258           2.6
   Franchise, property and other taxes                   652         0.5          1,084            0.7          1,875           1.2
   Depreciation, depletion and amortization           41,412        30.5         68,488           44.2         47,060          28.8
   Impairment of oil and gas properties
       and other assets                                   --          --        160,690          103.8             --            --
   Interest expense                                   34,302        25.3         32,903           21.2         19,132          11.7
   Net loss on sale of subsidiaries and
        other nonrecurring expense                     4,806         3.5            373            0.3             --            --
   Transaction-related expenses                           --          --             --             --         16,758          10.3
                                                    ---------------------     -------------------------      ----------------------
                                                     165,220       121.7        361,594          233.5        189,916         116.1
                                                    ---------------------     -------------------------      ----------------------

LOSS BEFORE INCOME TAXES                             (29,482)      (21.7)      (206,755)        (133.5)       (26,393)        (16.1)
   Income tax benefit                                (11,179)       (8.2)       (76,205)         (49.2)        (5,148)         (3.1)
                                                    ---------------------     -------------------------      ----------------------
NET LOSS                                            $(18,303)      (13.5)%    $(130,550)         (84.3)%     $(21,245)       (13.0)%
                                                    =====================     =========================      ======================

EBITDAX                                             $ 57,480        42.3%     $  65,681           42.4%      $ 66,917          40.9%
</TABLE>


1999 COMPARED TO 1998
         Net loss decreased $112.3 million (86%) 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
$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 decreases in expense were offset by a $4.4 million
increase in net loss on sale of subsidiaries and other nonrecurring expense, a
decrease in the income tax benefit of $65.0 million primarily due to the
decrease in loss before income taxes 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.

         Earnings before interest, income taxes, depreciation, depletion,
amortization, exploration expense and other nonrecurring items ("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.

                                       22
<PAGE>   24
         Total revenues decreased $19.1 million (12%) in 1999 compared to 1998
due to the sale of the Company's TOPS subsidiary 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 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 $273,000 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 Year 2000 ("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.

         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.

         Net loss on sale of subsidiaries and other nonrecurring expense
increased from $373,000 in 1998 to $4.8 million in 1999 due to a $2.8 million
loss on the sale of the Company's TOPS subsidiary, $2.4 million in employee
reduction costs and a $507,000 increase in costs associated with abandoned
acquisition efforts and an abandoned public offering of a royalty trust in 1999,
offset by a $1.3 million gain on the sale of the Company's BESCO subsidiary.

                                       23
<PAGE>   25
1998 COMPARED TO 1997
         Net loss increased $109.4 million from a loss of $21.2 million in 1997
to a loss of $130.6 million in 1998. This increase was the result of the $160.7
million asset impairment, a $21.4 million increase in depreciation, depletion
and amortization expense from significant increases in the book value of
property, equipment and other assets as a result of the purchase accounting
associated with the Acquisition discussed above and an increase of $13.8 million
in interest expense. These increases in expense were offset by the $16.8 million
of transaction-related expenses in 1997 and an increase in the income tax
benefit of $71.1 million. This increase in the income tax benefit was primarily
due to the increase in loss before income taxes combined with a change in the
effective tax rate due to the nondeductibility of certain transaction-related
expenses and a decrease in the utilization of nonconventional fuel source tax
credits in 1998.

         EBITDAX was $65.7 million in 1998 compared to $66.9 million in 1997.

         Total revenues decreased $8.7 million (5%) in 1998 compared to 1997.
Gross operating margins decreased $3.0 million (4%) in 1998 compared to 1997.

         Oil volumes increased 15,000 Bbls (2%) from 753,000 Bbls in 1997 to
768,000 Bbls in 1998 resulting in an increase in oil sales of approximately
$272,000. Gas volumes increased 2.9 Bcf (11%) from 27.2 Bcf in 1997 to 30.1 Bcf
in 1998 resulting in an increase in gas sales of approximately $7.8 million.
These volume increases were primarily due to production from properties acquired
and wells drilled in 1997 and 1998.

         The average price paid for the Company's oil decreased from $18.10 per
barrel in 1997 to $12.61 per barrel in 1998 which decreased oil sales by
approximately $4.2 million. The average price paid for the Company's natural gas
decreased $.08 per Mcf to $2.57 per Mcf in 1998 compared to 1997 which decreased
gas sales in 1998 by approximately $2.4 million.

         Production expense increased $2.2 million (10%) from $21.5 million in
1997 to $23.7 million in 1998. The average production cost of $.68 per Mcfe in
1998 was consistent when compared to the same period in 1997. Production taxes
decreased $186,000 from $3.2 million in 1997 to $3.0 million in 1998. Average
production taxes decreased from $.10 per Mcfe in 1997 to $.09 per Mcfe in 1998.

         Depreciation, depletion and amortization increased by $21.4 million
(46%) from $47.1 million in 1997 to $68.5 million in 1998. Depletion expense
increased $19.2 million (50%) from $38.5 million in 1997 to $57.7 million in
1998. Depletion per Mcfe increased from $1.21 per Mcfe in 1997 to $1.66 per Mcfe
in 1998. These increases were primarily the result of significant increases in
the book value of property, equipment and other assets as a result of the
purchase accounting associated with the Acquisition discussed above.

         Interest expense increased $13.8 million (72%) from $19.1 million in
1997 to $32.9 million in 1998. This increase was due to substantial additional
debt incurred primarily to finance the Acquisition.

                                       24
<PAGE>   26
LIQUIDITY AND CAPITAL RESOURCES
         The Company's liquidity and capital resources are closely related to
and dependent on the current prices for its oil and natural gas.

         The Company's current ratio at December 31, 1999 was .45 to 1.00.
During 1999, working capital decreased $36.7 million from a deficit of $6.3
million to a deficit of $43.0 million. The decrease was primarily due to an
increase in current portion of long-term liabilities of $21.6 million, a net
decrease in working capital of $9.7 million due to the sales of the Company's
TOPS and BESCO subsidiaries and a $6.2 million decrease in cash. The Company's
operating activities provided cash flows of $19.8 million during 1999.

         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 will be available for the issuance of
letters of credit. The credit agreement is a senior revolving credit facility
which is secured by substantially all of the Company's assets. The borrowing
base is 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. If less than
75% of the borrowing base is utilized, the borrowing base will be redetermined
annually. If more than 75% of the borrowing base is utilized, the borrowing base
will be redetermined semi-annually.

         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 the 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 of $5 million on the earlier of the receipt of aggregate
proceeds from asset sales totaling $5 million or August 10, 1999 and $5 million
on November 9, 1999, 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. Future borrowing base revisions will require approval
from all lenders and any deficiency must be repaid within 30 days of the
effective date of the redetermination. 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
provides for a $75 million revolving portion which matures on June 27, 2002 and
a $50 million term portion which matures on March 31, 2000. The borrowing base
on the revolving portion will remain at $75 million until the earlier of (i) the
sale of Peake and (ii) the redetermination of the borrowing base in the ordinary
course, pursuant to the terms of

                                       25
<PAGE>   27
the existing credit agreement. 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. The amended agreement also increased the interest rate from
LIBOR plus 2.5% to LIBOR plus 3.5% until the $50 million term portion is paid in
full and thereafter a range of LIBOR plus 2.5% to 3.0% based on the percent of
the borrowing base usage. The amendment also replaced certain financial
covenants with a minimum EBITDA (EBITDAX) test. Proceeds from the Peake sale
will be used to repay and permanently reduce the revolving credit commitment by
an amount equal to the proceeds up to $60 million and 25% of the proceeds in
excess of $60 million. The reduction in the revolving credit commitment shall be
applied, first, to the term portion and, second, to the revolving portion.

         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.
The next scheduled borrowing base redetermination is in November 2000.

         At December 31, 1999, the outstanding balance under the credit
agreement was $114 million. This included $64 million under the revolving
portion of the facility and $50 million under the term portion. The outstanding
balances under the agreement incur interest at the Company's choice of several
indexed rates, the most favorable being 9.50% at December 31, 1999. The
Company's $14 million in term loans from Chase Manhattan Bank are due on January
1, 2001 with interest payable at LIBOR plus 2.5%. If the bank group materially
reduces the borrowing base there is no assurance that the Company could meet the
required repayment obligation. The Company expects to be able to meet its 2000
debt service requirements through internally generated cash flow, the sale of
non strategic assets and additional debt.

         The credit agreement contains a number of covenants that, among other
things, restricts the ability of the Company and its subsidiaries to dispose of
assets, incur additional indebtedness, prepay other indebtedness or amend
certain debt instruments, pay dividends, create liens on assets, enter into sale
and leaseback transactions, make investments, loans or advances, make
acquisitions, engage in mergers or consolidations, change the business conducted
by the Company or its subsidiaries, make capital expenditures or engage in
certain transactions with affiliates and otherwise restricts certain corporate
activities. In addition, under the credit agreement, the Company is required to
maintain specified financial ratios and tests, including minimum interest
coverage ratios and maximum leverage ratios. The agreement requires a minimum
working capital ratio of 1.00 to 1.00. As of December 31, 1999, the Company's
working capital ratio was .45 to 1.00. As part of the May 10, 1999 amendment,
the Company and its lenders have agreed to exclude the current portion of
certain long term debt from this calculation. After making these adjustments the
working capital ratio as of December 31, 1999 was 1.25 to 1.00.

         The Company issued $225 million of 9.875% 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, 2000, the Company may, at its option, on
any one or more occasions, redeem up to 40% of the original aggregate principal
amount of the notes at a redemption price equal to 109.875% of the principal
amount, plus accrued and unpaid interest, if any on the redemption date, with
all or a portion of net proceeds of public sales of common stock of the Company;
provided that at least 60% of the original aggregate principal amount of the
notes remains outstanding immediately after the occurrence of such redemption;
and provided, further, that such redemption shall occur within 60 days of the
date of the closing of the related sale of common stock of the Company. 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.

                                       26
<PAGE>   28
         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 $18 million during
2000 on its drilling activities and other capital expenditures. The Company
intends to finance such activities, as well as its acquisition program, through
its available cash flow, available revolving credit line or additional debt. The
level of the Company's cash flow in the future will depend on a number of
factors including the demand and price levels for oil and natural gas, its
ability to acquire additional producing properties and the scope and success of
its drilling activities.

         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. 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%.

         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 gain on its hedging activities of $1.0 million
in 1999 and a pretax gain of $1.3 million in 1998. As of December 31, 1999, the
Company had hedged 9.1 Bcf of 2000 and 2001 natural gas production at a weighted
average NYMEX price of $2.41 per Mcf which represented a net unrealized gain of
$300,000. On February 22, 2000, the Company entered into a transaction which
effectively terminated 2.1 Bcf of these hedges. As of February 29, 2000, the
Company had hedges totaling 6.0 Bcf and an estimated net unrealized loss of $2.5
million on its natural gas hedging activities.

INFLATION AND CHANGES IN PRICES
         During 1997, the price paid for the Company's crude oil increased from
$22.50 per barrel at year-end 1996 to a high of $23.50 per barrel in early 1997,
then decreased to a low of $14.25 at year-end 1997, with an average price of
$18.10 per barrel. 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. The

                                       27
<PAGE>   29
average price of the Company's natural gas decreased from $2.65 per Mcf in 1997
to $2.57 per Mcf in 1998, then decreased to $2.50 per Mcf in 1999.

         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 and continuing
low levels of drilling activity in the Company's operating area, costs to drill,
complete and service wells have remained relatively constant in recent years.

         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.

YEAR 2000
         The Company engaged in a comprehensive project of assessment,
remediation, testing and implementation of necessary modifications to its key
applications (which consist of third party software, hardware and embedded chip
systems, as well as internally developed computer applications). The Y2K
rollover date passed with no apparent disruptions experienced by the Company's
systems and processes. It is possible that third parties may have experienced
disruptions which have not yet impacted the Company, but could in the future.
Accordingly, the Company is prepared to implement contingency plans should any
disruptions occur.

         As of December 31, 1999, the Company had incurred expenses in 1999 and
1998 of $297,000 and $10,000 respectively, and does not expect to incur any
remaining material costs in 2000. The Company only tracked incremental expenses
related to its Y2K project. Costs of the Y2K project related to employees of the
Company, including their direct salaries and benefits, have not been included in
the estimated costs of the project. Costs of new systems for which the principal
justification is improved business functionality, rather than Y2K compliance,
were capitalized.

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 Securities and Exchange
Commission. Actual results may differ materially from forward-looking statements
made in this report.

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

         The Company is exposed to 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 manages its interest rate risk through the use
of interest rate swaps to hedge the interest rate exposure associated with the

                                       28
<PAGE>   30
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 derivative financial instruments for managing interest rate risks in
place as of December 31, 1999 and 1998. The principal amount of the swaps
totaled $120 million and $140 million at December 31, 1999 and 1998,
respectively. If market interest rates for short-term borrowings increased 1%,
the increase in the Company's interest expense, after considering the effects of
its interest rate swap and cap agreements, would be immaterial. This sensitivity
analysis is based on the Company's financial structure at December 31, 1999.

         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 $2.7 million,
after considering the effects of the hedging contracts in place at December 31,
1999. This sensitivity analysis is based on the Company's 1999 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 generally accepted accounting principles. Management is responsible for the
fairness and reliability of the financial statements and other financial data
included in this report. In the preparation of the financial statements, it is
necessary to make informed estimates and judgments based on currently available
information on the effects of certain events and transactions.

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

         The Company's independent auditors, Ernst & Young LLP, are engaged to
audit the financial statements and to express an opinion thereon. Their audit is
conducted in accordance with generally accepted auditing standards to enable
them to report whether the financial statements present fairly, in all

                                       29
<PAGE>   31
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.


PART III
--------

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

         Executive officers and directors of the Company as of February 29, 2000
were as follows:

<TABLE>
<CAPTION>
Name                      Age  Position
----                      ---  --------
<S>                        <C> <C>
John L. Schwager           51  President, Chief Executive Officer and Director

Joseph M. Vitale           58  Senior Vice President Legal, General Counsel, Secretary and
                               Director

Tommy L. Knowles           49  Senior Vice President Exploration and Production

Leo A. Schrider            61  Senior Vice President Technical Development

Robert W. Peshek           45  Vice President Finance and Chief Financial Officer

Duane D. Clark             44  Vice President Gas Marketing

James C. Ewing             57  Vice President Human Resources

Charles P. Faber           58  Vice President Corporate Development

Henry S. Belden IV         60  Director

Lawrence W. Kellner        41  Director

Max L. Mardick             65  Director

William S. Price, III      44  Director

Gareth Roberts             47  Director

David M. Stanton           37  Director
</TABLE>

                                       30
<PAGE>   32
         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
eight 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 Belden & Blake
Corporation 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 Belden & Blake, 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. 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 Compact Commission. Mr. Vitale is a
past Chairman of the Natural Resources Law Committee of the Ohio State Bar
Association.

         TOMMY L. KNOWLES has been Senior Vice President of Exploration and
Production of the Company since 1997. Previously he served as Vice President of
Production from 1996 to 1997. He has 26 years of petroleum engineering and
production experience. Prior to joining Belden & Blake, Mr. Knowles served as
President of FWA Drilling Company, a subsidiary of Texas Oil & Gas Corporation.
From 1982 to 1988 he worked for TXO Production Corporation in Sacramento,
California, serving in various management positions including Vice President;
from 1979 to 1982 he held the position of Drilling and Production Manager for
Texas Oil & Gas Corporation; and, from 1973 to 1979 he held various engineering,
supervisory and management positions with Exxon Corporation.

         Mr. Knowles holds a BS degree in Mechanical Engineering from the
University of Texas at Austin where he graduated with honors. He is a member of
the Society of Petroleum Engineers and the Ohio Oil & Gas Association.

         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 Belden & Blake in 1981,
he served as Assistant and Deputy Director of Morgantown Energy Technology
Center from 1976 to 1980. From

                                       31
<PAGE>   33
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 Belden & Blake, 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.

         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 Belden & Blake, Mr. Clark held various management positions with Quaker
State Corporation from 1978 to 1995. He has 22 years of experience in the oil
and gas industry . Mr. Clark received his BA degree in Mathematics and Economics
from Ohio Wesleyan University. His professional affiliations include the Ohio
Oil and Gas Association, the Independent Oil and Gas Association of West
Virginia and the Pennsylvania Oil and Gas Association.

         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 Belden & Blake in April of 1986 and has 14 years of experience in the oil
and gas industry and more than 20 years of experience in the Human Resource
field. Prior to joining Belden & Blake, 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 Belden & Blake, 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.

         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 Acquisition, and was appointed to serve on the Board of
Directors upon consummation of the Acquisition. Mr. Belden has been involved in
oil and gas production since 1955 and associated with Belden & Blake since 1967.

                                       32
<PAGE>   34
Prior to joining Belden & Blake, 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 member of the 25-Year Club
of the Petroleum Industry and the Board of Trustees of the Ohio Oil and Gas
Association. He is also a member of the Regional Advisory Board of the
Independent Petroleum Association of America and a director and a member of the
Executive Committee of the Pennsylvania Grade Crude Oil Association. He is a
member of the Interstate Oil Compact Commission. Other professional memberships
include the World Business Council and the Association of Ohio Commodores. He is
a director of KeyBank-Canton District and Phoenix Packaging Corporation.

         LAWRENCE W. KELLNER 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. Prior to joining Continental, he was Executive
Vice President and Chief Financial Officer of American Savings Bank, F.A. from
November 1992 to May 1995. Mr. Kellner graduated magna cum laude with a Bachelor
of Science, Business Administration degree from the University of South
Carolina.

         MAX L. MARDICK was President and Chief Operating Office 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 Acquisition and was appointed to serve on the
Board of Directors upon consummation of the Acquisition. 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 Belden & Blake, 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 is a member of the Society of Petroleum Engineers and
the Ohio Oil and Gas Association. 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
Acquisition, 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 Beringer Wine Estates Holdings, Inc., Continental
Airlines, Inc., Del Monte, Inc., Denbury Resources, Inc., FirstWorld
Communications, Inc., and several private companies.

         GARETH ROBERTS 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 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.

                                       33
<PAGE>   35

         DAVID M. STANTON, who became a director upon consummation of the
Acquisition, is a partner of Francisco Partners. From 1994 to 1999, he was a
partner with Texas Pacific Group. From 1991 until he joined Texas Pacific Group
in 1994, Mr. Stanton was a venture capitalist with Trinity Ventures, where he
specialized in information technology, software and telecommunications
investing. Mr. Stanton earned a BS degree in Chemical Engineering from Stanford
University and received an MBA from the Stanford Graduate School of Business.
Mr. Stanton serves on the Boards of Directors of Denbury Resources, Globespan,
GT Com, ON Semiconductor, Paradyne Networks and Zilog.

                                       34
<PAGE>   36
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, 1999, 1998 and 1997 of the Company's Chief Executive Officer and its other
four most highly compensated executive officers.

<TABLE>
                                             SUMMARY COMPENSATION 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                  1999     $173,077     $300,000     $   --          139,383      $113,358(2)
President and Chief
Executive Officer

Ronald L. Clements Chief          1999      159,600           --         --               --       745,344(3)
Executive Officer until           1998      318,462       11,354         --               --        18,840
June 30, 1999                     1997      239,154       84,390         --          137,366        14,625

Ronald E. Huff                    1999      180,000           --         --               --      1,019,931(4)
Chief Financial Officer           1998      265,385        9,462         --               --        17,662
until September 3, 1999           1997      208,646       83,192         --          137,366        13,767

Joseph M. Vitale                  1999      180,000       57,416         --           55,000(5)      8,084
Senior Vice President Legal,      1998      186,493       52,525         --               --        14,248
General Counsel and Secretary     1997      168,800       66,627         --           54,946        11,863

Tommy L. Knowles                  1999      172,009       17,201         --           55,000(5)      7,878
Senior Vice President of          1998      175,158        6,244         --               --        14,444
Exploration and Production        1997      167,154       46,563         --           54,946        72,009

Leo A. Schrider                   1999      133,000       13,300         --           55,000(6)      7,635
Senior Vice President of          1998      137,962       12,719         --               --        11,669
Technical Development             1997      128,504       20,065         --           20,000        10,046
</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 payment of $738,060 made under terms of a retirement and
         noncompetition agreement with the named executive officer.

(4)      Includes payment of $1,012,430 made under terms of severance
         arrangement with the named executive officer.

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

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

                                       35
<PAGE>   37
                      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 (1)         Fiscal Year        per Share         Date          Value (2)
----------------             -----------         -----------        ---------         ----          ---------
<S>                         <C>                 <C>                <C>           <C>                <C>
John L. Schwager               139,383             22.40%             $0.01         05/31/09         $27,877
Joseph M. Vitale                55,000              8.84%              0.01         09/30/09          11,000
Tommy L. Knowles                55,000              8.84%              0.01         09/30/09          11,000
Leo A. Schrider                 55,000              8.84%              0.01         09/30/09          11,000
</TABLE>

(1)      Options granted in 1999 and 1997 were 303,491 and 652,624,
         respectively. Options totaling 318,892 were repriced in 1999.
         Refer to 10 Year Option/SAR Repricing table below for additional
         information. These options are exercisable beginning twelve months
         after the date of grant or repricing, with 25% of the shares covered
         thereby becoming exercisable at that time and an additional 12.5%
         becoming exercisable on each successive three month anniversary date.
         The options were granted for a term of ten years, subject to earlier
         termination on cessation of employment.

(2)      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           --     $ --           --         139,383          $   --         $27,876
Ronald L. Clements         --       --       31,168              --           3,428              --
Ronald E. Huff         31,168       --           --              --              --              --
Joseph M. Vitale           --       --           --          55,000              --          11,000
Tommy L. Knowles           --       --           --          55,000              --          11,000
Leo A. Schrider            --       --           --          55,000              --          11,000
</TABLE>

                                       36
<PAGE>   38
<TABLE>
                                             10-YEAR OPTION/SAR REPRICINGS

<CAPTION>
                                                                                                         Number of
                                               Number of                                                 Months of
                                                Shares         Market        Exercise                     Original
                                              Underlying      Price of       Price at                       Term
                               Date          Options/SARs     Stock at        Time of       New          Remaining at
                                of           Repriced or      Time of      Repricing or  Exercise         Date of
           Name              Repricing         Amended      Repricing (1)   Amendment     Price         Repricing (2)
---------------------------  ---------         -------      -------------   ---------     -----         -------------
<S>                          <C>             <C>             <C>           <C>          <C>                <C>
Joseph M. Vitale             10/01/99          54,946          $0.01         $10.82       $0.01              98
Senior Vice President
Legal, General Counsel
and Secretary

Tommy L. Knowles             10/01/99          54,946           0.01          10.82        0.01              98
Senior Vice President of
Exploration and Production

Leo A. Schrider              10/01/99          20,000           0.01          10.82        0.01              98
Senior Vice President of
Technical Development

Duane D. Clark               10/01/99          15,000           0.01          10.82        0.01              98
Vice President of Gas
Marketing

James C. Ewing               10/01/99          15,000           0.01          10.82        0.01              98
Vice President of Human
Resources

Charles P. Faber             10/01/99          25,000           0.01          10.82        0.01              98
Vice President of
Corporate Development

Robert W. Peshek             10/01/99          25,000           0.01          10.82        0.01              98
Vice President of Finance
and Chief Financial Officer
</TABLE>

(1)      Based on information contained in the Stock Option plan options cannot
         be issued for more than fair market value at the time of a grant. Since
         the Company's stock is not actively traded, the Company has determined
         the value of the stock at 10/01/1999 to be $.01 per share.

(2)      Original options were granted on 12/01/97. These options vested 25% per
         year and were valid for a period of ten years or 120 months. Options
         were repriced twenty two months after the original grant date leaving
         98 months remaining from the original grant date.


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.

EMPLOYMENT AND SEVERANCE AGREEMENTS

         The Company has severance agreements with Messrs. Clements, Huff and
Vitale which entitle each of them to receive a lump sum severance payment equal
to 300% of the sum of (i) his respective annual base salary at the highest rate
in effect for any period prior to his employment termination plus (ii) his
highest annual bonus and incentive compensation during the three-year period
preceding a change in control, in the event of the termination of his employment
by the Company other than for "cause" (as defined therein) or his resignation in
response to a substantial reduction in responsibilities, authority, position,
compensation or location of his place of employment prior to June 27, 2000. In
addition, each of them would be entitled to receive an additional payment
sufficient to cover any excise tax imposed by

                                       37
<PAGE>   39
Section 4999 of the Code on the severance payments or other payment considered
"contingent on a change in ownership or control" of the Company within the
meaning of Section 280G of the Code. In connection with the termination of his
employment on September 3, 1999, Mr. Huff received severance pay of $997,050 and
will continue to participate in the Company's employee welfare plans for a
period of three years. Mr. Clements received no severance pay or benefits under
his severance agreement on the termination of his employment because of his
decision to retire voluntarily on June 30, 1999.

         Messrs. Clements and Huff each entered into employment agreements dated
as of June 27, 1997 (the "Employment Agreements") providing for their employment
as Chief Executive Officer and President, respectively, of the Company on an
at-will basis with no fixed or minimum term. Prior to the termination of their
employment, the Employment Agreements provided for an annual base salary of not
less than $300,000 payable to Mr. Clements and $250,000 payable to Mr. Huff.
Messrs. Clements and Huff were each entitled to earn an annual bonus of up to
50% of his annual base salary subject to the attainment of certain goals set by
the Company's Board of Directors. Each of Messrs. Clements and Huff agreed to
continue to hold, and not surrender, certain stock options previously granted to
him under the Company's Stock Option Plan, thereby foregoing the right to
receive $334,220 each in cash upon the surrender of such options on consummation
of the Acquisition. Under the Employment Agreements Messrs. Clements and Huff
were each granted additional options to purchase 31,168 shares of common stock
of the Company constituting 1.25% of the outstanding common stock (on a
fully-diluted basis) at a per share option price of $10.82 which was equivalent
to the price paid by TPG in connection with the Acquisition. The options vest
over a four-year period, with one-fourth (1/4) vesting one year after the date
of grant and the balance at the rate of one-twelfth (1/12) at the end of each
quarter thereafter during the continuation of employment with the Company. The
Employment Agreements provided for certain call options and rights of first
refusal in connection with the shares of common stock obtainable upon the
exercise of stock options.

         In connection with his retirement as Chief Executive Officer and a
director of the Company, Mr. Clements entered into a retirement and
noncompetition agreement with the Company dated as of May 26, 1999 under which
Mr. Clements agreed that, for a period of two (2) years from June 30, 1999, he
will not engage in or be associated with, as a consultant, employer, employee,
director, stockholder, partner, financial backer affiliate or otherwise, the
ownership or operation of any enterprise relating to the exploration, drilling
and/or production of oil or gas in the Appalachian, Michigan or Illinois basins.
In addition, Mr. Clements agreed that during such two-year period, he will not
employ, solicit for employment or endeavor to entice away from employment any
person who is employed by the Company or any of its affiliates. In consideration
of such agreements, the Company agreed to pay Mr. Clements $725,000 in
installments of $350,000 on July 1, 1999, $250,000 on January 3, 2000 and
$125,000 on July 1, 2000, and to continue to provide the same health care and
fringe benefits he was receiving at the time of his retirement for such two-year
period.

         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 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

                                       38
<PAGE>   40
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.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

         During 1999, 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 29,
2000 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)                    89.1%

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%

<CAPTION>
              OFFICERS AND DIRECTORS
              ----------------------
<S>                                                                  <C>                               <C>
William S. Price, III                                                9,353,038 (1)                     89.1%
Henry S. Belden IV                                                      63,360 (2)                         *
John L. Schwager                                                           -0-                           -0-
Ronald L. Clements                                                      35,513 (3)                         *
Ronald E. Huff                                                             -0-                           -0-
Lawrence W. Kellner                                                        -0-                           -0-
Max L. Mardick                                                          39,387 (2)                         *
Tommy L. Knowles                                                           -0-                           -0-
Gareth Roberts                                                             -0-                           -0-
Carter T. Funk                                                          35,000 (2)                         *
David M. Stanton                                                           -0-                           -0-
Leo A. Schrider                                                            -0-                           -0-
Joseph M. Vitale                                                           -0-                           -0-
All directors and executive
   officers (16) as a group                                          9,594,981                         91.4%
</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.

(3)      Includes 31,168 shares subject to stock options exercisable within 60
         days.

                                       40
<PAGE>   42
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         In connection with the Acquisition, 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 Acquisition as compensation for its services as financial
advisor in connection with the Acquisition. 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.

         Messrs. Belden and Mardick have each entered into non-competition
agreements with the Company dated March 27, 1997 (the "Non-Competition
Agreements"), which became effective contemporaneously with consummation of the
Acquisition. Pursuant to the terms of the Non-Competition Agreements, Messrs.
Belden and Mardick have each agreed, for a period of three (3) years from June
27, 1997 that he will not, in any county in the United States in which the
Company does business, directly or indirectly, either for himself or as a member
of a partnership or as a shareholder, investor, agent, associate or consultant
engage in any business in which the Company is engaged immediately prior to June
27, 1997. Messrs. Belden and Mardick have each further agreed that he will not,
directly or indirectly, make any misleading or untrue statement that disparages
or would have the effect of disparaging the Company or any of its affiliates or
employees or of adversely affecting the reputation, business or credit rating of
the Company or any of its affiliates or employees, and that, for a period of
three years from June 27, 1997, he will not, directly or indirectly, interfere
with, or take any action that would have the effect of interfering with, the
contractual and other relationships between the Company or any of its affiliates
and any of its or their employees, customers or suppliers. In consideration of
such agreements, Mr. Belden will receive $2,400,616.44 and Mr. Mardick will
receive $983,711.16 in each case payable in 36 monthly installments.

                                       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)

                                       42
<PAGE>   44

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)

10.1     Credit Agreement dated as of June 27, 1997 by and among the Company,
         each of the Lenders named therein and The Chase Manhattan Bank, as
         Agent --incorporated by reference to Exhibit 10.1 to the Company's
         Registration Statement on Form S-4 (Registration No. 333-33407)

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     Employment Agreement dated as of June 27, 1997 by and between the
         Company and Ronald L. Clements --incorporated by reference to Exhibit
         10.3 to the Company's Registration Statement on Form S-4 (Registration
         No. 333-33407)

10.3(b)* Retirement and noncompetition agreement dated May 26, 1999 by and
         between the Company and Ronald L. Clements

10.4     Employment Agreement dated as of June 27, 1997 by and between the
         Company and Ronald E. Huff --incorporated by reference to Exhibit 10.4
         to the Company's Registration Statement on Form S-4 (Registration No.
         333-33407)

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)

10.6     Form of Severance Agreement between the Company and the following
         officers: Ronald E. Huff, Ronald L. Clements and Joseph M. Vitale--
         incorporated by reference to Exhibit 10.3 to the Company's Quarterly
         Report on Form 10-Q for the quarter ended September 30, 1996

10.7*    Change in Control Severance Pay Plan for Key Employees of the Company
         dated August 12, 1999.

10.8*    Severance Pay Plan for Employees of Belden & Blake Corporation dated
         August 12, 1999.

10.9(a)  1991 Stock Option Plan of the Company--incorporated by reference to
         Exhibit 10.7 to the Company's Registration Statement on Form S-4
         (Registration No. 33-43209)

10.9(b)  1991 Stock Option Plan of the Company (as amended)--incorporated by
         reference to Exhibit 4.1 to the Company's Registration Statement on
         Form S-8 (Registration No. 33-62785)

10.10*   Employment Agreement dated June 1, 1999 and amended November 1, 1999 by
         and between the Company and John L. Schwager.

21*      Subsidiaries of the Registrant

                                       43
<PAGE>   45
27*      Financial Data Schedule

*Filed herewith

         (b)      Reports on Form 8-K

         On December 15, 1999, the Company filed a Current Report on Form 8-K
dated December 15, 1999 relating to the Company's amended revolving credit
agreement and to its semiannual interest payment on its senior subordinated
notes.

         (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 24, 2000                             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>
<CAPTION>
<S>                                             <C>                                <C>
/s/ John L. Schwager                            Director, President                March 24, 2000
-------------------------                       and Chief Executive Officer        --------------
John L. Schwager                                (Principal Executive Officer)      Date



/s/ Robert W. Peshek                            Vice President Finance and         March 24, 2000
-------------------------                       Chief Financial Officer            --------------
Robert W. Peshek                                (Principal Financial and           Date
                                                Accounting Officer)



/s/ Joseph M. Vitale                            Senior Vice President Legal,       March 24, 2000
-------------------------                       General Counsel, Secretary         --------------
Joseph M. Vitale                                and Director                       Date



/s/ Henry S. Belden IV *                        Director                           March 24, 2000
-------------------------                                                          --------------
Henry S. Belden IV                                                                 Date


/s/ Lawrence W. Kellner *                       Director                           March 24, 2000
-------------------------                                                          --------------
Lawrence W. Kellner                                                                Date


/s/ Max L. Mardick *                            Director                           March 24, 2000
-------------------------                                                          --------------
Max L. Mardick                                                                     Date


/s/ William S. Price, III                       Director                           March 24, 2000
-------------------------                                                          --------------
William S. Price, III                                                              Date
</TABLE>

                                       45
<PAGE>   47

<TABLE>
<CAPTION>
<S>                                             <C>                                <C>
/s/ Gareth Roberts                              Director                           March 24, 2000
-------------------------                                                          --------------
Gareth Roberts                                                                     Date


/s/ David M. Stanton *                          Director                           March 24, 2000
-------------------------                                                          --------------
David M. Stanton                                                                   Date



*By: /s/ Joseph M. Vitale                                                          March 24, 2000
     --------------------                                                          --------------
     Attorney-in-Fact                                                              Date
</TABLE>

                                       46
<PAGE>   48
<TABLE>
                                           BELDEN & BLAKE CORPORATION
                                             INDEX TO CONSOLIDATED
                                       FINANCIAL STATEMENTS AND SCHEDULES

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

<CAPTION>
                                                                                                            PAGE
                                                                                                            ----
<S>                                                                                                         <C>
CONSOLIDATED FINANCIAL STATEMENTS
---------------------------------
    Report of Independent Auditors ........................................................................  F-2
    Consolidated Balance Sheets as of December 31, 1999 and 1998 ..........................................  F-3
    Consolidated Statements of Operations:
       Years ended December 31, 1999 and 1998 (Successor Company)
       Six months ended December 31, 1997 (Successor Company)
       Six months ended June 30, 1997 (Predecessor Company) ...............................................  F-4
    Consolidated Statements of Shareholders' Equity (Deficit):
       Years ended December 31, 1999 and 1998 (Successor Company)
       Six months ended December 31, 1997 (Successor Company)
       Six months ended June 30, 1997 (Predecessor Company) ...............................................  F-5
    Consolidated Statements of Cash Flows:
       Years ended December 31, 1999 and 1998 (Successor Company)
       Six months ended December 31, 1997 (Successor Company)
       Six months ended June 30, 1997 (Predecessor Company) ...............................................  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 ("Successor Company") as of December 31, 1999 and 1998, and the
related consolidated statements of operations, shareholders' equity (deficit)
and cash flows for the years ended December 31, 1999 and 1998 and the six month
period ended December 31, 1997 ("Successor periods"). We have also audited the
accompanying consolidated statements of operations, shareholders' equity
(deficit) and cash flows of Belden & Blake Corporation ("Predecessor Company")
for the six month period ended June 30, 1997 ("Predecessor period"). 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, 1999 and 1998 and the consolidated results of their
operations and their cash flows for the Successor periods and the Predecessor
periods in conformity with accounting principles generally accepted in the
United States.


                                                               ERNST & YOUNG LLP


Cleveland, Ohio
March 17, 2000

                                      F-2
<PAGE>   50
<TABLE>
                                 BELDEN & BLAKE CORPORATION
                                CONSOLIDATED BALANCE SHEETS
                             (IN THOUSANDS, EXCEPT SHARE DATA)

<CAPTION>
                                                                          DECEMBER 31,
                                                                   ------------------------
                                                                      1999           1998
                                                                   ---------      ---------
<S>                                                                <C>            <C>
ASSETS
------
CURRENT ASSETS
     Cash and cash equivalents                                     $   4,536      $  10,691
     Accounts receivable, net                                         25,301         33,204
     Inventories                                                       2,106          9,200
     Deferred income taxes                                             2,006          2,449
     Other current assets                                              1,154          3,384
                                                                   ---------      ---------
                TOTAL CURRENT ASSETS                                  35,103         58,928

PROPERTY AND EQUIPMENT, AT COST
     Oil and gas properties (successful efforts method)              534,515        535,837
     Gas gathering systems                                            22,193         22,008
     Land, buildings, machinery and equipment                         24,242         28,551
                                                                   ---------      ---------
                                                                     580,950        586,396
     Less accumulated depreciation, depletion and amortization       280,047        246,689
                                                                   ---------      ---------
                PROPERTY AND EQUIPMENT, NET                          300,903        339,707
OTHER ASSETS                                                          14,689         19,970
                                                                   ---------      ---------
                                                                   $ 350,695      $ 418,605
                                                                   =========      =========

LIABILITIES AND SHAREHOLDERS' DEFICIT
-------------------------------------
CURRENT LIABILITIES
     Accounts payable                                              $   4,132      $   6,458
     Accrued expenses                                                 23,024         29,373
     Current portion of long-term liabilities                         50,979         29,365
                                                                   ---------      ---------
                TOTAL CURRENT LIABILITIES                             78,135         65,196

LONG-TERM LIABILITIES
     Bank and other long-term debt                                    78,161        126,178
     Senior subordinated notes                                       225,000        225,000
     Other                                                               570          3,204
                                                                   ---------      ---------
                                                                     303,731        354,382

DEFERRED INCOME TAXES                                                 20,419         32,041

SHAREHOLDERS' DEFICIT
     Common stock without par value; $.10 stated value
       per share; authorized 58,000,000 shares; issued
       and outstanding 10,260,457 and 10,110,915 shares                1,026          1,011
     Paid in capital                                                 107,609        107,897
     Deficit                                                        (160,225)      (141,922)
                                                                   ---------      ---------
                TOTAL SHAREHOLDERS' DEFICIT                          (51,590)       (33,014)
                                                                   ---------      ---------
                                                                   $ 350,695      $ 418,605
                                                                   =========      =========
</TABLE>

See accompanying notes.

                                       F-3
<PAGE>   51
<TABLE>
                                              BELDEN & BLAKE CORPORATION
                                        CONSOLIDATED STATEMENTS OF OPERATIONS
                                                    (IN THOUSANDS)

<CAPTION>
                                                                                                         | PREDECESSOR
                                                                           SUCCESSOR COMPANY             |   COMPANY
                                                               ----------------------------------------- | -----------
                                                                   YEAR          YEAR        SIX MONTHS  |  SIX MONTHS
                                                                  ENDED         ENDED          ENDED     |    ENDED
                                                               DECEMBER 31,  DECEMBER 31,   DECEMBER 31, |   JUNE 30,
                                                                   1999          1998           1997     |     1997
                                                               ------------  ------------   ------------ |  ----------
<S>                                                            <C>           <C>            <C>          |  <C>
REVENUES                                                                                                 |
    Oil and gas sales                                            $ 79,299      $  87,055      $ 44,165   |   $41,591
    Gas gathering, marketing, and oilfield sales and service       51,443         63,358        38,255   |    36,322
    Other                                                           4,996          4,426         1,706   |     1,484
                                                                 --------      ---------      --------   |   -------
                                                                  135,738        154,839        84,126   |    79,397
EXPENSES                                                                                                 |
    Production expense                                             21,980         23,739        11,338   |    10,158
    Production taxes                                                3,260          2,986         1,525   |     1,647
    Gas gathering, marketing, and oilfield sales and service       46,954         56,813        33,529   |    32,276
    Exploration expense                                             6,442          9,982         5,980   |     4,380
    General and administrative expense                              5,412          4,536         1,813   |     2,445
    Franchise, property and other taxes                               652          1,084           967   |       908
    Depreciation, depletion and amortization                       41,412         68,488        31,694   |    15,366
    Impairment of oil and gas properties                                                                 |
        and other assets                                             --          160,690          --     |      --
    Interest expense                                               34,302         32,903        15,417   |     3,715
    Net loss on sale of subsidiaries and other                                                           |
        nonrecurring expense                                        4,806            373          --     |      --
    Transaction-related expenses                                     --             --            --     |    16,758
                                                                 --------      ---------      --------   |   -------
                                                                  165,220        361,594       102,263   |    87,653
                                                                 --------      ---------      --------   |   -------
                                                                                                         |
LOSS BEFORE INCOME TAXES                                          (29,482)      (206,755)      (18,137)  |    (8,256)
    (Benefit) provision for income taxes                          (11,179)       (76,205)       (6,765)  |     1,617
                                                                 --------      ---------      --------   |   -------
NET LOSS                                                         $(18,303)     $(130,550)     $(11,372)  |   $(9,873)
                                                                 ========      =========      ========   |   =======
</TABLE>

See accompanying notes.

                                       F-4
<PAGE>   52
<TABLE>
                                                    BELDEN & BLAKE CORPORATION
                                     CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
                                                          (IN THOUSANDS)

<CAPTION>
                               SUCCESSOR COMPANY   PREDECESSOR COMPANY
                               -----------------   -------------------                         RETAINED     UNEARNED      TOTAL
                               COMMON     COMMON     COMMON    COMMON   PREFERRED   PAID IN    EARNINGS    RESTRICTED    EQUITY
                               SHARES     STOCK      SHARES    STOCK      STOCK     CAPITAL    (DEFICIT)     STOCK      (DEFICIT)
                               ------     ------    -------   -------   ---------  ---------   ---------   ----------   ---------
<S>                            <C>        <C>       <C>       <C>       <C>        <C>         <C>         <C>          <C>
PREDECESSOR COMPANY:
JANUARY 1, 1997                  --       $ --       11,232   $ 1,123    $ 2,400   $ 128,035   $  27,395      $(35)     $ 158,918

Net loss                                                                                          (9,873)                  (9,873)
Preferred stock redeemed                                                  (2,400)                                          (2,400)
Preferred stock dividend                                                                             (45)                     (45)
Subordinated debentures
  converted to common stock                             275        27                  5,523                                5,550
Stock options exercised and
  surrendered and related
  tax benefit                                             1      --                    1,596                                1,596
Employee stock bonus                                     36         4                    926                                  930
Restricted stock activity                                                                 17                    35             52
Redemption of common stock                          (11,544)   (1,154)              (136,097)    (17,477)                (154,728)
Sale of common stock           10,000      1,000                                     107,230                              108,230

SUCCESSOR COMPANY:
----------------------------------------------------------------------------------------------------------------------------------
JUNE 30, 1997                  10,000      1,000       --        --         --       107,230        --          --        108,230

Net loss                                                                                         (11,372)                 (11,372)
----------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1997              10,000      1,000       --        --         --       107,230     (11,372)       --         96,858

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

Employee stock bonus              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)
==================================================================================================================================
</TABLE>

See accompanying notes.

                                      F-5
<PAGE>   53
<TABLE>
                                                   BELDEN & BLAKE CORPORATION
                                             CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                         (IN THOUSANDS)

<CAPTION>
                                                                                                                  | PREDECESSOR
                                                                                   SUCCESSOR COMPANY              |   COMPANY
                                                                       ------------------------------------------ | -----------
                                                                           YEAR           YEAR        SIX MONTHS  | SIX MONTHS
                                                                          ENDED          ENDED          ENDED     |   ENDED
                                                                       DECEMBER 31,   DECEMBER 31,   DECEMBER 31, |  JUNE 30,
                                                                           1999           1998           1997     |    1997
                                                                       ------------   ------------   ------------ | ----------
<S>                                                                    <C>            <C>            <C>          | <C>
CASH FLOWS FROM OPERATING ACTIVITIES:                                                                             |
    Net loss                                                             $(18,303)     $(130,550)     $(11,372)   | $  (9,873)
    Adjustments to reconcile net loss to net cash                                                                 |
       provided by operating activities:                                                                          |
         Depreciation, depletion and amortization                          41,412         68,488        31,694    |    15,366
         Impairment of oil and gas properties and other assets               --          160,690          --      |      --
         Transaction-related expenses                                        --             --            --      |    15,903
         Exploration expense                                                6,442          9,982         5,980    |     4,380
         Deferred income taxes                                            (11,179)       (75,702)       (6,379)   |     3,125
         Loss on disposal of property and equipment                         1,657            100            51    |       356
         Deferred compensation and stock grants                              (565)           993           380    |     1,756
         Change in operating assets and liabilities, net of                                                       |
            effects of purchases of businesses:                                                                   |
              Accounts receivable and other operating assets                5,814          3,203        (5,280)   |     1,237
              Inventories                                                   2,413           (261)          597    |       112
              Accounts payable and accrued expenses                        (7,867)        (1,689)       (4,064)   |     4,800
                                                                         --------      ---------      --------    | ---------
                 NET CASH PROVIDED BY OPERATING ACTIVITIES                 19,824         35,254        11,607    |    37,162
                                                                                                                  |
CASH FLOWS FROM INVESTING ACTIVITIES:                                                                             |
    Acquisition of businesses, net of cash acquired                          --          (11,827)      (14,276)   |    (9,263)
    Disposition of businesses, net of cash                                  7,887           --            --      |      --
    Proceeds from property and equipment disposals                          3,011          4,082           785    |       704
    Exploration expense                                                    (6,442)        (9,982)       (5,980)   |    (4,380)
    Additions to property and equipment                                    (2,996)       (38,165)      (23,663)   |   (18,419)
    Decrease (Increase) in other assets                                     2,140         (1,294)         (274)   |    (9,496)
                                                                         --------      ---------      --------    | ---------
                 NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES        3,600        (57,186)      (43,408)   |   (40,854)
                                                                                                                  |
CASH FLOWS FROM FINANCING ACTIVITIES:                                                                             |
    Proceeds from revolving line of credit and long-term debt                --             --            --      |    46,000
    Proceeds from new credit agreement                                     21,000         44,000        24,020    |   104,000
    Proceeds from senior subordinated notes                                  --             --            --      |   225,000
    Sale of common stock                                                     --             --            --      |   108,230
    Repayment of long-term debt and other obligations                     (50,582)       (17,929)       (2,989)   |  (140,325)
    Payment to shareholders and optionholders                                --             --            --      |  (312,164)
    Transaction-related expenses                                             --             --            --      |   (15,903)
    Preferred stock redeemed                                                 --             --            --      |    (2,400)
    Preferred stock dividends                                                --             --            --      |       (45)
    Proceeds from sale of common stock and stock options                        3           --            --      |        15
                                                                         --------      ---------      --------    | ---------
                 NET CASH (USED IN) PROVIDED BY                                                                   |
                   FINANCING ACTIVITIES                                   (29,579)        26,071        21,031    |    12,408
                                                                         --------      ---------      --------    | ---------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS                       (6,155)         4,139       (10,770)   |     8,716
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                           10,691          6,552        17,322    |     8,606
                                                                         --------      ---------      --------    | ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD                               $  4,536      $  10,691      $  6,552    | $  17,322
                                                                         ========      =========      ========    | =========
</TABLE>

See accompanying notes.

                                      F-6
<PAGE>   54
                           BELDEN & BLAKE CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)      MERGER
         On March 27, 1997, Belden & Blake Corporation (the "Company") signed a
definitive merger agreement with TPG Partners II, L.P. ("TPG"), a private
investment partnership, pursuant to which TPG and certain other investors
acquired the Company in an all-cash transaction valued at $440 million (the
"Acquisition"). Under the terms of the agreement, TPG and such investors paid
$27 per share for all common shares outstanding plus an additional amount to
redeem certain stock options held by directors and employees. The transaction
was completed on June 27, 1997 and for financial reporting purposes has been
accounted for as a purchase effective June 30, 1997. The Acquisition resulted in
a new basis of accounting reflecting estimated fair values for assets and
liabilities at that date. Accordingly, the financial statements for the periods
subsequent to June 30, 1997 are presented on the Company's new basis of
accounting, while the results of operations for the period ended June 30, 1997
reflects the historical results of the predecessor company. A vertical black
line is presented to separate the financial statements of the predecessor and
successor companies.

         The following table presents the actual results of operations for the
years ended December 31, 1999 and 1998 and the unaudited pro forma results of
operations for the year ended December 31, 1997 as if the Acquisition occurred
at the beginning of 1996 (in thousands):

<TABLE>
<CAPTION>
                                                               Pro Forma
                                     Actual                   (unaudited)
                           --------------------------         -----------
                             1999              1998              1997
                           --------         ---------          --------
<S>                        <C>              <C>                <C>
Total revenues             $135,738         $ 154,839          $163,523
Net loss                    (18,303)         (130,550)          (19,970)
</TABLE>

         The unaudited pro forma information presented above assumes the
transaction-related expenses were incurred prior to the period presented and
does not purport to be indicative of the results that actually would have been
obtained if the Acquisition had been consummated at the beginning of 1996 and is
not intended to be a projection of future results or trends.

         In connection with the Acquisition, the Company entered into a
Transaction Advisory Agreement with TPG pursuant to which TPG received a cash
financial advisory fee of $5.0 million for services as financial advisor in
connection with the Acquisition. The fee is included in the $16.8 million of
transaction-related expenses. TPG 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) entered
into by the successor company.

         Certain former officers entered into non-competition agreements with
the Company dated March 27, 1997, which became effective contemporaneously with
consummation of the Acquisition. These agreements have a term of 36 months and
had a total value of $3.0 million at June 27, 1997. The obligation for these
agreements is included in the balance sheet.

                                      F-7
<PAGE>   55
(2)      BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

BUSINESS
--------
         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, West Virginia, Pennsylvania, New York and Kentucky. 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 1999.

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 debt instruments 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.

         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

                                      F-8
<PAGE>   56
indicated, the costs are charged to expense. During 1998, the Company recorded a
$5.8 million impairment 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.

INTANGIBLE ASSETS
-----------------
         Intangible assets totaling $13.0 million at December 31, 1999, 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."

         Belden & Blake Corporation common stock held in the 401k plan is
subject to variable plan accounting. The changes in share value are reported as
adjustments to compensation expense. The reduction in share value in 1999 and
1998 resulted in a reduction in compensation expense of $858,000 and $403,000,
respectively.

(3)      NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
         In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. ("SFAS") 133, "Accounting for Derivative
Instruments and Hedging

                                      F-9
<PAGE>   57
Activities." SFAS 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS 133, as amended, is effective
for fiscal years beginning after June 15, 2000. On adoption, the provisions of
SFAS 133 must be applied prospectively as the cumulative effect of an accounting
change. The Company has not determined the impact that SFAS 133 will have on its
financial statements and has not determined the timing of or method of adoption
of SFAS 133.

(4)      SALE OF SUBSIDIARIES
         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"). BESCO was the Company's retail natural gas marketing
outlet in Ohio. 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.

(5)      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 (billion cubic feet of natural gas equivalent) net to the Company's
interest at the time of acquisition. The Company also acquired undeveloped
properties and other assets for $4.2 million.

         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 to due
diligence associated with a proposed acquisition by FE Holdings were written-off
to other nonrecurring expense in 1998.

         During 1997, the Company acquired working interests in oil and gas
wells in Ohio, Pennsylvania, West Virginia and Michigan for approximately $13.5
million for the successor company's six months ended December 31, 1997 and $7.8
million for the predecessor company's six months ended June 30, 1997. Estimated
proved developed reserves associated with the wells totaled 32.8 Bcf (billion
cubic feet) of natural gas and 101,000 Bbls (barrels) of oil net to the
Company's interest at the time of the acquisitions.

         The pro forma effects of 1999, 1998 and 1997 (predecessor and successor
periods) acquisitions were not material.

                                      F-10
<PAGE>   58
(6)      OTHER NONRECURRING EXPENSE
         In August 1999, the Company abandoned an acquisition effort and a
proposed public offering of a royalty trust. Approximately $880,000 of costs
associated with these efforts were written off in 1999.

         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.

(7)      DETAILS OF BALANCE SHEETS

<TABLE>
<CAPTION>
                                                              DECEMBER 31,
                                                        -----------------------
                                                          1999           1998
                                                        --------       --------
                                                              (IN THOUSANDS)
<S>                                                      <C>            <C>
          ACCOUNTS RECEIVABLE
               Accounts receivable                      $ 13,280       $ 17,859
               Allowance for doubtful accounts            (1,215)        (1,430)
               Oil and gas production receivable          12,626         16,182
               Current portion of notes receivable           610            593
                                                        --------       --------
                                                        $ 25,301       $ 33,204
                                                        ========       ========
          INVENTORIES
               Oil                                      $  1,552       $  1,710
               Natural gas                                    27            974
               Material, pipe and supplies                   527          6,516
                                                        --------       --------
                                                        $  2,106       $  9,200
                                                        ========       ========
          PROPERTY AND EQUIPMENT, GROSS
            OIL AND GAS PROPERTIES
               Producing properties                     $506,266       $507,652
               Non-producing properties                    7,078          7,040
               Other                                      21,171         21,145
                                                        --------       --------
                                                        $534,515       $535,837
                                                        ========       ========
            LAND, BUILDINGS, MACHINERY AND EQUIPMENT
               Land, buildings and improvements         $  6,592       $  8,540
               Machinery and equipment                    17,650         20,011
                                                        --------       --------
                                                        $ 24,242       $ 28,551
                                                        ========       ========
          ACCRUED EXPENSES
               Accrued expenses                         $  9,500       $ 12,796
               Accrued drilling and completion costs         615          4,217
               Accrued income taxes                          190            241
               Ad valorem and other taxes                  3,733          3,570
               Compensation and related benefits           2,324          2,752
               Undistributed production revenue            6,662          5,797
                                                        --------       --------
                                                        $ 23,024       $ 29,373
                                                        ========       ========
</TABLE>

                                      F-11
<PAGE>   59
(8)      LONG-TERM DEBT
         Long-term debt consists of the following (in thousands):

<TABLE>
<CAPTION>
                                             DECEMBER 31,
                                        ---------------------
                                          1999         1998
                                        --------     --------
<S>                                     <C>          <C>
          Revolving line of credit      $114,000     $154,000
          Term loans                      14,000         --
          Senior subordinated notes      225,000      225,000
          Other                              180          276
                                        --------     --------
                                         353,180      379,276
          Less current portion            50,019       28,098
                                        --------     --------
          Long-term debt                $303,161     $351,178
                                        ========     ========
</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>                                               <C>
                  2002.........................................      104.938%
                  2003.........................................      103.292%
                  2004.........................................      101.646%
                  2005 and thereafter..........................      100.000%
</TABLE>

         Prior to June 15, 2000, the Company may, at its option, on any one or
more occasions, redeem up to 40% of the original aggregate principal amount of
the notes at a redemption price equal to 109.875% of the principal amount, plus
accrued and unpaid interest, if any, on the redemption date, with all or a
portion of net proceeds of public sales of common stock of the Company; provided
that at least 60% of the original aggregate principal amount of the notes
remains outstanding immediately after the occurrence of such redemption; and
provided, further, that such redemption shall occur within 60 days of the date
of the closing of the related sale of common stock of the Company.

         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 also 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 will be available for the

                                      F-12
<PAGE>   60
issuance of letters of credit. The credit agreement is a senior revolving credit
facility which is secured by substantially all of the Company's assets. The
borrowing base is 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 bank in accordance with their standard oil and gas lending practices. If
less than 75% of the borrowing base is utilized, the borrowing base will be
redetermined annually. If more than 75% of the borrowing base is utilized, the
borrowing base will be redetermined semiannually.

         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 the lenders to reduce this deficiency by $14 million on March 22,
1999 and by the remaining $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 of $5 million on the earlier of the receipt of aggregate
proceeds from asset sales totaling $5 million or August 10, 1999 and $5 million
on November 9, 1999, 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. Future borrowing base revisions require approval from all
lenders and any deficiency must be repaid within 30 days of the effective date
of the redetermination. The amended agreement increased the interest rate to
LIBOR (London Interbank Offering 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
provides for a $75 million revolving portion which matures on June 27, 2002 and
a $50 million term portion which matures on March 31, 2000. The borrowing base
on the revolving portion will remain at $75 million until the earlier of (i) the
sale of Peake Energy, Inc. ("Peake") (See Note 21) and (ii) the redetermination
of the borrowing base in the ordinary course, pursuant to the terms of the
existing credit agreement. 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. The amended agreement also increased the interest rate from
LIBOR plus 2.5% to LIBOR plus 3.5% until the $50 million term portion is paid in
full and thereafter a range of LIBOR plus 2.5% to 3.0% based on the percent of
the borrowing base usage. The amendment also replaced certain financial
covenants with a minimum EBITDA (EBITDAX) test. Proceeds from the Peake sale
will be used to repay and permanently reduce the revolving credit commitment by
an amount equal to the proceeds up to $60 million and 25% of the proceeds in
excess of $60 million. The reduction in the revolving credit commitment shall be
applied, first, to the term portion and, second, to the revolving portion.

         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.
The next scheduled borrowing base redetermination is in November 2000.

         At December 31, 1999, the outstanding balance under the credit
agreement was $114 million. This included $64 million under the revolving
portion of the facility and $50 million under the term portion. The outstanding
balances under the agreement incur interest at the Company's choice of several
indexed rates, the most favorable being 9.50% at December 31, 1999. The
Company's $14 million in

                                      F-13
<PAGE>   61
term loans from Chase Manhattan Bank are due on January 1, 2001 with interest
payable at LIBOR plus 2.5%. If the bank group materially reduces the borrowing
base there is no assurance that the Company could meet the required repayment
obligation. The Company expects to be able to meet its 2000 debt service
requirements through internally generated cash flow, the sale of non strategic
assets and additional debt.

         The credit agreement contains a number of covenants that, among other
things, restricts the ability of the Company and its subsidiaries to dispose of
assets, incur additional indebtedness, prepay other indebtedness or amend
certain debt instruments, pay dividends, create liens on assets, enter into sale
and leaseback transactions, make investments, loans or advances, make
acquisitions, engage in mergers or consolidations, change the business conducted
by the Company or its subsidiaries, make capital expenditures or engage in
certain transactions with affiliates and otherwise restrict certain corporate
activities. In addition, under the credit agreement, the Company is required to
maintain specified financial ratios and tests, including minimum interest
coverage ratios and maximum leverage ratios. The agreement requires a minimum
working capital ratio of 1.00 to 1.00. As of December 31, 1999 the Company's
working capital ratio was .45 to 1.00. As part of the May 10, 1999 amendment,
the Company and its lenders have agreed to exclude the current portion of
certain long term debt from this calculation. After making these adjustments the
working capital ratio as of December 31, 1999 was 1.25 to 1.00.

         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. 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 3.5%.

         On April 3, 1997, the Company gave notice of redemption of all of the
outstanding 9.25% convertible subordinated debentures for 104% of face value.
Redemption of these debentures occurred June 10, 1997 when holders of the
debentures elected to convert them into 275,425 shares of common stock in the
predecessor company.

         At December 31, 1999, the aggregate long-term debt maturing in the next
five years is as follows: $50,019,000 (2000); $14,019,000 (2001); $64,019,000
(2002); $19,000 (2003); $4,000 (2004); and $225,100,000 (2005 and thereafter).

(9)      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 $1.9 million, $2.2 million and $1.0 million for the
successor company's years ended December 31, 1999 and 1998 and six months ended
December 31, 1997, respectively, and $1.0 million for the predecessor company's
six months ended June 30, 1997. Future commitments under leasing arrangements
were not significant at December 31, 1999.

                                      F-14
<PAGE>   62
(10)     SHAREHOLDERS' EQUITY
         In November 1998 and 1997, the Company awarded 118,274 and 110,915
shares of successor company common stock, respectively, to employees as profit
sharing and bonuses. These shares were issued in each subsequent year.

         On December 31, 1992, the Company issued 24,000 shares of Class II
Serial Preferred Stock with a stated value of $100 per share. In preference to
shares of predecessor company common stock, each share was entitled to
cumulative cash dividends of $7.50 per year, payable quarterly. The Preferred
Stock was subject to redemption at $100 per share at any time by the Company and
was convertible into predecessor company common stock, at the holder's election,
at any time after five years from the date of issuance at a conversion price of
$15.00 per predecessor company common share. Holders of the Preferred Stock were
entitled to one vote per preferred share. On March 31, 1997, the Company
redeemed all of the outstanding Class II Series A preferred stock for $2.4
million in cash.

(11)     STOCK OPTION PLANS
         In connection with the Acquisition, certain executives of the
predecessor company had agreed that they would not exercise or surrender certain
stock options granted under the Company's 1991 stock option plan having an
aggregate value of $1.8 million at June 27, 1997, based on the intrinsic value
of the options (the difference between the exercise price of the options and a
purchase price of $27 per share). These options were exchanged for 165,083 in
new stock options of the successor company based on the intrinsic value of the
predecessor company's options at the date of the transaction. As of December 31,
1999 there were 133,915 of these options outstanding.

         Under the Company's 1991 employee stock option plan the Company was
authorized to issue up to 1,070,000 shares of common stock to officers and
employees. All options outstanding under the 1991 plan were surrendered for cash
in the Acquisition except for options to purchase 133,915 shares which are
currently 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 1,000,000 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, 1999, options to purchase 622,383 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 shares on every three month anniversary thereafter.

         The Company has a Non-Employee Directors Stock Option Plan authorizing
the issuance of up to 120,000 shares of common stock. The exercise price of
options under the Plan is equal to the fair market value on the date of grant.
Options expire on the tenth anniversary of the grant date. The options become
exercisable on the anniversary of the grant date at a rate of one third of the
shares each year. No options may be granted under this plan and no options were
outstanding at December 31, 1999.

         The Company has elected to follow Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees" (APB 25) 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
303,491 options granted in 1999 and 318,892 options were repriced in 1999 which
had an immaterial effect on compensation expense in 1999.

                                      F-15
<PAGE>   63

         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 1997
and 1999, respectively: risk-free interest rates of 6.1% and 6.2%; volatility
factor of the expected market price of the Company's common stock of near zero;
dividend yield of zero; and a weighted-average expected life of the option of
seven years.

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

         For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The changes in
net loss for the successor company's years ended December 31, 1999 and 1998 and
six months ended December 31, 1997 were not material. The Company's pro forma
information for the predecessor company's six months ended June 30, 1997 was a
net loss of $12.4 million.

         The effects of applying Statement 123 for providing pro forma
disclosures are not indicative of future amounts until the new rules are applied
to all outstanding, nonvested awards.

         Stock option activity under the three plans consisted of the following:

<TABLE>
<CAPTION>
                                                     SUCCESSOR COMPANY      |     PREDECESSOR COMPANY
                                                  ------------------------  |  -------------------------
                                                                  WEIGHTED  |                   WEIGHTED
                                                                  AVERAGE   |                   AVERAGE
                                                  NUMBER OF       EXERCISE  |  NUMBER OF        EXERCISE
                                                   SHARES          PRICE    |   SHARES           PRICE
                                                  ---------       --------  |  ---------        --------
<S>                                               <C>             <C>       |   <C>              <C>
BALANCE AT DECEMBER 31, 1996                                                |   803,500          16.31
     Exercised                                                              |      (937)         16.38
     Surrendered                                                            |  (598,063)         15.61
     Re-quantified and repriced                     165,083        $  .10   |  (204,500)         18.34
     Granted                                        652,624         10.82   |       --
                                                  ---------                 |  --------
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   |
                                                  =========                 |
OPTIONS EXERCISABLE AT DECEMBER 31, 1999            133,915        $  .10   |
                                                  =========
</TABLE>

         The weighted average fair value of options granted during 1999 was
$.50. No options were granted in 1998. The

                                      F-16
<PAGE>   64
weighted average fair value of options granted during 1997 was $1.98. The
exercise price for the options outstanding as of December 31, 1999 ranged from
$.01 to $10.82 per share. At December 31, 1999 the weighted average remaining
contractual life of the outstanding options is 9.3 years.

(12)     TAXES
         The (benefit) provision for income taxes on continuing operations
includes the following (in thousands):

<TABLE>
<CAPTION>
                                                                    | PREDECESSOR
                                       SUCCESSOR COMPANY            |   COMPANY
                            --------------------------------------- | -----------
                                                        SIX MONTHS  | SIX MONTHS
                            YEAR ENDED DECEMBER 31,       ENDED     |   ENDED
                            -----------------------    DECEMBER 31, |  JUNE 30,
                               1999          1998         1997      |    1997
                             --------      --------    ------------ | ----------
<S>                          <C>           <C>         <C>          | <C>
          CURRENT                                                   |
                 Federal     $   --        $   (503)     $  (345)   |  $(1,397)
                 State           --            --            (41)   |     (111)
                             --------      --------      -------    |  -------
                                 --            (503)        (386)   |   (1,508)
          DEFERRED                                                  |
                 Federal      (10,449)      (69,976)      (6,038)   |    2,945
                 State           (730)       (5,726)        (341)   |      180
                             --------      --------      -------    |  -------
                              (11,179)      (75,702)      (6,379)   |    3,125
                             --------      --------      -------    |  -------
                 TOTAL       $(11,179)     $(76,205)     $(6,765)   |  $ 1,617
                             ========      ========      =======    |  =======
</TABLE>

         The effective tax rate for continuing operations differs from the U.S.
federal statutory tax rate as follows:

<TABLE>
<CAPTION>
                                                                                            | PREDECESSOR
                                                                     SUCCESSOR COMPANY      |   COMPANY
                                                              ----------------------------- | -----------
                                                                YEAR ENDED      SIX MONTHS  | SIX MONTHS
                                                               DECEMBER 31,       ENDED     |   ENDED
                                                              --------------   DECEMBER 31, |  JUNE 30,
                                                              1999      1998       1997     |    1997
                                                              ----      ----   ------------ | ----------
<S>                                                           <C>       <C>    <C>          | <C>
          Statutory federal income tax rate                   35.0%     35.0%      35.0%    |    35.0%
          Increases (reductions) in taxes resulting from:                                   |
              State income taxes, net of federal tax                                        |
              benefit                                          2.0       2.0        2.0     |     (.8)
              Nonconventional fuel source tax credits          --        --         --      |    (3.8)
              Transaction-related expenses                     --        --         --      |   (49.9)
              Statutory depletion                              --        --         0.5     |     --
              Other, net                                       0.9      (0.1)      (0.2)    |     --
                                                              ----      ----       ----     |   -----
          Effective income tax rate for the period            37.9%     36.9%      37.3%    |   (19.5)%
                                                              ====      ====       ====     |   =====
</TABLE>

                                      F-17
<PAGE>   65
         Significant components of deferred income tax liabilities and assets
are as follows (in thousands):

<TABLE>
<CAPTION>
                                                        DECEMBER 31,    DECEMBER 31,
                                                            1999           1998
                                                        ------------    ------------
<S>                                                     <C>             <C>
          Deferred income tax liabilities:
               Property and equipment, net                 $48,619        $55,017
               Other, net                                      625            534
                                                           -------        -------
                 Total deferred income tax liabilities      49,244         55,551
          Deferred income tax assets:
               Accrued expenses                              1,446          2,178
               Inventories                                      17             15
               Net operating loss carryforwards             30,014         24,515
               Tax credit carryforwards                        699            744
               Other, net                                      708            483
               Valuation allowance                          (2,053)        (1,976)
                                                           -------        -------
                 Total deferred income tax assets           30,831         25,959
                                                           -------        -------
                 Net deferred income tax liability         $18,413        $29,592
                                                           =======        =======

               Long-term liability                         $20,419        $32,041
               Current asset                                (2,006)        (2,449)
                                                           -------        -------
                 Net deferred income tax liability         $18,413        $29,592
                                                           =======        =======
</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, 1999 relates principally to
certain net operating loss carryforwards which management estimates will expire
before they can be utilized.

         At December 31, 1999, the Company had approximately $81 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 $700,000 which have no expiration date. The Company has
approximately $700,000 of statutory depletion carryforwards, which have no
expiration date.

(13)     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 contributed $845,000,
$938,000 and $749,500 for the successor company's years ended December 31, 1999
and 1998 and six months ended December 31, 1997, respectively, and $588,900 for
the predecessor company's six months ended June 30, 1997 to the profit sharing
plan. The 1999 amount was paid in cash. For the 1998 and 1997 periods 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. Additional
discretionary bonuses are also made.

         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

                                      F-18
<PAGE>   66
contributions which the Company matches $.50 for every $1.00 contributed up to
6% of an employee's annual compensation. Prior to January 1, 1998, the Company
matched $.25 for every $1.00 contributed up to 6% of an employee's annual
compensation. Retirement plan expense amounted to $830,000, $867,000 and
$285,000 for the successor company's years ended December 31, 1999 and 1998 and
six months ended December 31, 1997, respectively, and $266,000 for the
predecessor company's six months ended June 30, 1997.

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

(14)     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.

(15)     SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

<TABLE>
<CAPTION>
                                                                                                          | PREDECESSOR
                                                                          SUCCESSOR COMPANY               |   COMPANY
                                                              ------------------------------------------  | -----------
                                                                                             SIX MONTHS   |  SIX MONTHS
                                                              YEAR ENDED DECEMBER 31,          ENDED      |    ENDED
                                                              -----------------------       DECEMBER 31,  |   JUNE 30,
(IN THOUSANDS)                                                  1999            1998            1997      |    1997
                                                              -------         -------       ------------  |  ----------
<S>                                                           <C>             <C>           <C>           |  <C>
          CASH PAID DURING THE PERIOD FOR:                                                                |
               Interest                                       $34,426         $32,048          $13,867    |    $4,153
               Income taxes, net of refunds                      --            (1,970)          (1,517)   |       288
          NON-CASH INVESTING AND FINANCING ACTIVITIES:                                                    |
               Acquisition of assets in exchange for                                                      |
                  long-term liabilities                           125             415             --      |       792
               Non-compete agreement and related                                                          |
               obligation                                         705            --               --      |      --
               Debentures converted to common stock              --              --               --      |     5,550
</TABLE>

(16)     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 $108 million at
December 31, 1999 based on rates available for similar instruments. The
estimated fair value of interest rate swaps was an unrealized gain of $1.2
million at December 31, 1999 based on current market prices.

         From time to time the Company may enter into a combination of futures
contracts, commodity derivatives and fixed-price physical contracts to manage
its exposure to natural gas price volatility. The Company employs a policy of
hedging gas production sold under New York Mercantile Exchange ("NYMEX") based
contracts by selling NYMEX based commodity derivative contracts which are placed
with major financial institutions that the Company believes are minimal credit
risks. The contracts may take the form of futures contracts, swaps or options.
Under the deferral method, gains and losses on

                                      F-19
<PAGE>   67
these instruments are deferred on the balance sheet and are included as an
adjustment to gas revenue for the production being hedged in the contract month.
The Company incurred pre-tax gains on its hedging activities of $1.2 million in
1999, $1.5 million in 1998 and a loss on its hedging activities of $116,000 in
1997.

         As of December 31, 1999, the Company had hedged 9.1 Bcf of 2000 and
2001 natural gas production at a weighted average NYMEX price of $2.41 per Mcf
(thousand cubic feet) which represented a net unrealized gain of $300,000. On
February 22, 2000, the Company entered into a transaction which effectively
terminated 2.1 Bcf of these hedges. As of February 29, 2000, the Company had
hedges totaling 6.0 Bcf and an estimated net unrealized loss of $2.5 million on
its natural gas hedging activities.

(17)     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>
                                                                              | PREDECESSOR
                                                 SUCCESSOR COMPANY            |   COMPANY
                                     ---------------------------------------- | -----------
                                                                  SIX MONTHS  |  SIX MONTHS
                                     YEAR ENDED DECEMBER 31,        ENDED     |     ENDED
                                     -----------------------     DECEMBER 31, |   JUNE 30,
          (IN THOUSANDS)               1999           1998           1997     |     1997
                                      ------        -------      ------------ |  ----------
<S>                                   <C>           <C>          <C>          |  <C>
          Acquisition costs                                                   |
           Proved properties          $ --          $ 9,194        $13,501    |   $ 9,249
           Unproved properties           855          1,857          1,342    |     1,267
          Developmental costs            186         30,090         21,822    |    11,322
          Exploratory costs            6,442          9,982          5,980    |     4,380
</TABLE>

         The amounts reflected in the above table do not include the effects of
purchase accounting which resulted from the Acquisition. See Note 1.

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 developed reserves have been reviewed by
independent petroleum engineers. The estimates of proved undeveloped reserves
were prepared by the Company's petroleum

                                      F-20
<PAGE>   68
engineers and the December 31, 1998 and 1999 proved undeveloped reserves have
been reviewed by independent petroleum engineers.

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

<TABLE>
<CAPTION>
                                      SUCCESSOR COMPANY               PREDECESSOR COMPANY                      TOTAL
                                  --------------------------      ----------------------------      ---------------------------
                                     OIL             GAS             OIL              GAS              OIL              GAS
                                    (BBLS)          (MCF)           (BBLS)           (MCF)            (BBLS)           (MCF)
                                  ---------      -----------      ----------      ------------      ----------      -----------
<S>                               <C>            <C>              <C>             <C>               <C>             <C>
DECEMBER 31, 1996                                                  7,388,906       288,603,353       7,388,906      288,603,353
Extensions and discoveries          244,242       26,550,917         282,999        12,142,158         527,241       38,693,075
Purchase of reserves in place        78,149       20,093,436          71,905        13,191,547         150,054       33,284,983
Sale of reserves in place           (12,780)        (400,196)        (21,196)         (337,814)        (33,976)        (738,010)
The Acquisition                   6,514,982      276,776,629      (6,514,982)     (276,776,629)
Revisions of previous estimates    (899,930)     (16,909,297)       (826,900)      (24,075,426)     (1,726,830)     (40,984,723)
Production                         (372,651)     (14,466,129)       (380,732)      (12,747,189)       (753,383)     (27,213,318)
                                  ---------      -----------      ----------      ------------      ----------      -----------
DECEMBER 31, 1997                 5,552,012      291,645,360            --                --         5,552,012      291,645,360
Extensions and discoveries          255,101       29,330,826                                           255,101       29,330,826
Purchase of reserves in place        33,899       20,295,868                                            33,899       20,295,868
Sale of reserves in place           (21,209)      (6,939,240)                                          (21,209)      (6,939,240)
Revisions of previous estimates    (808,599)      11,066,042                                          (808,599)      11,066,042
Production                         (768,415)     (30,139,996)                                         (768,415)     (30,139,996)
                                  ---------      -----------      ----------      ------------      ----------      -----------
DECEMBER 31, 1998                 4,242,789      315,258,860            --                --         4,242,789      315,258,860
Extensions and discoveries           12,530          416,442                                            12,530          416,442
Purchase of reserves in place          --               --                                                --               --
Sale of reserves in place           (29,445)        (632,049)                                          (29,445)        (632,049)
Revisions of previous estimates   3,185,892       18,636,407                                         3,185,892       18,636,407
Production                         (713,146)     (26,988,410)                                         (713,146)     (26,988,410)
                                  ---------      -----------      ----------      ------------      ----------      -----------
DECEMBER 31, 1999                 6,698,620      306,691,250            --                --         6,698,620      306,691,250
                                  =========      ===========      ==========      ============      ==========      ===========
PROVED DEVELOPED RESERVES
December 31, 1997                 4,830,163      251,851,000                                         4,830,163      251,851,000
                                  =========      ===========                                         =========      ===========
December 31, 1998                 3,973,772      280,668,600                                         3,973,772      280,668,600
                                  =========      ===========                                         =========      ===========
DECEMBER 31, 1999                 5,897,504      267,941,800                                         5,897,504      267,941,800
                                  =========      ===========                                         =========      ===========
</TABLE>

                                      F-21
<PAGE>   69
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,
                                                         ----------------------------------------
                                                            1999           1998           1997
                                                         ---------      ---------      ---------
                                                                (IN THOUSANDS)
<S>                                                      <C>            <C>            <C>
          Estimated future cash inflows (outflows)
               Revenues from the sale of oil and gas     $ 957,046      $ 818,401      $ 876,464
               Production and development costs           (411,881)      (340,321)      (355,165)
                                                         ---------      ---------      ---------
          Future net cash flows before income taxes        545,165        478,080        521,299
          Future income taxes                             (124,561)      (102,358)      (130,306)
                                                         ---------      ---------      ---------
          Future net cash flows                            420,604        375,722        390,993
          10% timing discount                             (203,716)      (167,059)      (171,273)
                                                         ---------      ---------      ---------
          Standardized measure of discounted
               future net cash flows                     $ 216,888      $ 208,663      $ 219,720
                                                         =========      =========      =========
</TABLE>

                                      F-22
<PAGE>   70
         The principal sources of changes in the standardized measure of future
net cash flows are as follows (the successor and predecessor periods are
combined in 1997 for purposes of this presentation):

<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                         ------------------------------------
                                                           1999          1998          1997
                                                         --------      --------      --------
                                                               (IN THOUSANDS)
<S>                                                      <C>           <C>           <C>
          Beginning of year                              $208,663      $219,720      $259,229
          Sale of oil and gas, net of
              production costs                            (54,059)      (60,330)      (61,088)
          Extensions and discoveries, less
              related estimated future
              development and production costs              1,233        30,821        54,979
          Purchase of reserves in place less
              estimated future production costs              --          10,528        33,233
          Sale of reserves in place less
              estimated future production costs              (578)       (3,373)         (588)
          Revisions of previous quantity estimates         31,128          (673)      (43,111)
          Net changes in prices and production costs       32,836       (30,512)      (73,956)
          Change in income taxes                           (2,729)       24,977        19,618
          Accretion of 10% timing discount                 25,656        29,259        35,596
          Changes in production rates (timing)
              and other                                   (25,262)      (11,754)       (4,192)
                                                         --------      --------      --------
          End of year                                    $216,888      $208,663      $219,720
                                                         ========      ========      ========
</TABLE>

(18)     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
---------------
         No customer accounted for more than 10% of consolidated revenue during
the years ended December 31, 1999 and 1998 and the six months ended June 30,
1997 and December 31, 1997.

                                      F-23
<PAGE>   71
(19)     QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
         The results of operations for the four quarters of 1999 and 1998 are
shown below (in thousands).

<TABLE>
<CAPTION>
                                                   FIRST         SECOND        THIRD        FOURTH
                                                  -------       -------       -------     ---------
<S>                                               <C>           <C>           <C>         <C>
          1999
          ----
          Sales and other operating revenues      $34,253       $33,099       $30,686     $  32,704
          Gross profit                              1,523         1,516         2,297         4,879
          Net loss                                 (4,157)       (4,854)       (7,691)       (1,601)

<CAPTION>
                                                   FIRST         SECOND        THIRD        FOURTH
                                                  -------       -------       -------     ---------
<S>                                               <C>           <C>           <C>         <C>
          1998
          ----
          Sales and other operating revenues      $39,126       $37,614       $34,803     $  38,870
          Gross loss                                 (680)       (3,773)       (3,646)       (4,092)
          Net loss                                 (6,271)       (8,230)       (8,086)     (107,963)(1)
</TABLE>

         (1)  The net loss in the fourth quarter of 1998 includes pre-tax
              impairment losses of $160.7 million. See note 2.

(20)     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 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.

(21)     SUBSEQUENT EVENTS

         On March 17, 2000, the Company sold the stock of Peake, a wholly owned
subsidiary, to North Coast Energy, Inc. ("North Coast"), an independent oil and
gas company, with an effective date of January 1, 2000.  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 million.

         At December 31, 1999, using SEC pricing parameters, Peake had proved
developed reserves of approximately 66.5 Bcfe and proved undeveloped reserves
of approximately 3.7 Bcfe.  Peake's reserves represented 20.2% of the Company's
total proved reserves.

         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.
The next scheduled borrowing base redetermination is in November 2000.


                                      F-24