UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

     (Mark  one)  [X]  Annual  Report  pursuant  to  Section  13 or 15(d) of the
Securities Exchange Act of 1934 For the fiscal year ended December 31, 2001

     [ ]  Transition  Report  pursuant to Section 13 or 15(d) of the  Securities
Exchange Act of 1934 For the transition period from __________ to ___________ .


                           Commission File No. 1-12508

                          MAGNUM HUNTER RESOURCES, INC.
             (Exact name of registrant as specified in its charter)

                                Nevada 87-0462881
                (State or other jurisdiction of (I.R.S. Employer
               incorporation or organization) Identification No.)


           600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039
           --------------------------------------------------------------
               (Address of principal executive offices)        (zip code)


       Registrant's telephone number, including area code: (972) 401-0752

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

     Title of each class        Name of each exchange on which registered
     -------------------        -----------------------------------------
Common Stock ($.002 par value)         American Stock Exchange


     Securities registered under Section 12(g) of the Act: None

     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. [ ]

     As of March 15, 2002,  the  aggregate  market value of voting stock held by
non-affiliates,  computed by reference  to the closing  price as reported by the
American Stock Exchange, was $343,891,333.

     The number of shares outstanding of the registrant's  common stock at March
15, 2002 was 70,065,447.

<PAGE>

                                TABLE OF CONTENTS

                       Securities and Exchange Commission
                           Item Number and Description


                                     PART I
<TABLE>
<CAPTION>
<S>                                                                                                              <C>
Item 1.    Business...............................................................................................1
            The Company...........................................................................................1
            Business Strategy ....................................................................................3
            Properties ...........................................................................................4
            Development and Exploration Activities ...............................................................7
            Gathering and Processing of Gas ......................................................................8
            Marketing of Production ..............................................................................9
            Petroleum Management and Consulting Services ........................................................10
            Competition..........................................................................................10
            Regulation ..........................................................................................10
            Employees ...........................................................................................13
            Facilities ..........................................................................................13
            Risk Factors.........................................................................................14
Item 2.    Description of Properties.............................................................................22
            Oil and Gas Reserves ................................................................................22
            Oil and Gas Production, Prices and Costs ............................................................25
            Drilling Activity ...................................................................................26
            Oil and Gas Wells ...................................................................................27
            Oil and Gas Acreage .................................................................................27
Item 3.    Legal Proceedings.....................................................................................28
Item 4.    Submission of Matters to a Vote of Security Shareholders..............................................28

                                     PART II

Item 5.    Market for Common Equity and Related Stockholder Matters..............................................28
Item 6.    Selected Financial Data...............................................................................29
Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.................32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..............................................47
Item 8.   Financial Statements and Supplementary Data...........................................................F-1
Item 9.    Change in and Disagreements with Accountants on Accounting and Financial Disclosure...................49

                                    PART III

Item 10.  Directors and Executive Officers of the Registrant.....................................................49
Item 11.  Executive Compensation.................................................................................54
Item 12.  Security Ownership of Certain Beneficial Owners and Management.........................................57
Item 13.  Certain Relationships and Related Transactions.........................................................58
          Glossary...............................................................................................59
Item 14.  Exhibits, Financial Statement Schedule and Reports on Form 8-K.........................................61

</TABLE>

<PAGE>

                                     PART I

                SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

     This document includes  "forward-looking  statements" within the meaning of
Section 27A of the  Securities  Act of 1933 and  Section  21E of the  Securities
Exchange Act of 1934. All statements, other than statements of historical facts,
included in this document that address  activities,  events or developments that
we expect,  project,  believe or anticipate  will or may occur in the future are
forward-looking statements. These include such matters as:

     o  benefits,  effects  or results of the  merger  with Prize  Energy  Corp.
("Prize);
     o cost reductions,  operating efficiencies or synergies and the integration
of operations in connection;
     o with the merger with Prize;
     o future stock market valuations;
     o tax and accounting treatment of the merger and the warrants offering;
     o repayment of debt;
     o business strategies;
     o expansion and growth of operations after the merger with Prize; and
     o future operating results and financial condition.

     We have based these  statements on our assumptions and analyses in light of
our experience and perception of historical trends, current conditions, expected
future  developments  and  other  factors  we  believe  are  appropriate  in the
circumstances.  These  statements are subject to a number of assumptions,  risks
and uncertainties, including:

     o general economic and business conditions;
     o prices of crude oil,  natural gas and  natural  gas liquids and  industry
expectations about future prices;
     o the  business  opportunities,  or  lack  of  opportunities,  that  may be
presented to and pursued by us;
     o the ability to integrate our operations with Prize; and
     o changes in laws or regulations.

     These factors are in addition to the risks  described in the "Risk Factors"
and "Management's  Discussion and Analysis of Financial Condition and Results of
Operations"  sections  of this  document.  Most of these  factors are beyond our
control.  We caution you that  forward-looking  statements are not guarantees of
future performance and that actual results or developments may differ materially
from those projected in these statements. You should not place undue reliance on
forward-looking statements. Each forward-looking statement speaks only as of the
date of the  particular  statement,  and we undertake no  obligation to publicly
update or revise any forward-looking statements.

Item 1. Business

The Company

     Magnum Hunter Resources, Inc., a Nevada corporation ("Magnum Hunter" or the
"Company"),  is an  independent  energy  company  engaged  in  the  exploration,
exploitation  and  development,   acquisition  and  operation  of  oil  and  gas
properties  with a geographic  focus in the  Mid-Continent  Region,  the Permian
Basin  and  the  Gulf  of  Mexico/Gulf  Coast.  Management  of the  Company  has
implemented  a business  strategy  that  emphasizes  acquisitions  of long-lived
proved reserves with  significant  exploitation  and  development  opportunities
where the Company  generally could control the operations of the properties.  As
part of this strategy,  from 1996 through 2001, the Company acquired significant
properties  from  Burlington  Resources  Inc.  ("Burlington"),  Spirit Energy 76
("Spirit  76"),  a  business  unit of Union Oil  Company of  California,  Vastar
Resources,  Inc.  ("Vastar") and Mallon  Resources  Corporation  ("Mallon").  In
addition to its focus on selected  exploratory drilling prospects in the Gulf of
Mexico as described  below,  the Company  intends to continue to concentrate its
efforts on additional  producing  property  acquisitions  strategically  located
within its geographic  area of operations.  The Company also intends to continue
to develop its  substantial  inventory of drilling  and  workover  opportunities
located  onshore.  The  Company has  identified  over 358  development  drilling
locations   (including  both  production  and  injection   wells)  and  workover
opportunities  on its properties to which Proved reserves have been  attributed,
substantially all of which are low-risk in-fill drilling opportunities.

<PAGE>

     In 1998,  the Company  acquired an  approximate  40%  beneficial  ownership
interest in TEL Offshore  Trust  ("TEL"),  a trust created under the laws of the
state of Texas.  The principal asset of TEL consists of a 99.99% interest in the
TEL  Offshore  Trust  partnership.  Chevron  USA Inc.  owns the  remaining  .01%
interest in the partnership. The partnership owns an overriding royalty interest
equivalent  to a 25% net  profits  interest  in certain  oil and gas  properties
located  offshore  Louisiana in the shallow waters in the Gulf of Mexico.  As of
March 31, 2002, the Company owned  approximately  36% of the units of beneficial
ownership in TEL.

     Additionally,  the Company owns over 480 miles of gas gathering systems and
a 50% or greater ownership  interest in three natural gas processing plants that
are located adjacent to certain  Company-owned and operated producing properties
located in the states of Texas, Oklahoma and Arkansas.

     At December  31,  2001,  the Company had an interest in 3,241 wells and had
estimated  Proved  reserves  of  378  Bcfe  with  a  PV-10  of  $311.9  million.
Approximately70%  of these  reserves were Proved  developed  reserves:  31% were
attributable to the Mid-Continent  Region,  33% were attributable to the Permian
Basin,  and 36% were  attributable to the Gulf of Mexico/Gulf  Coast region.  At
December 31, 2001, the Company's  Proved reserves had an estimated  Reserve Life
of  approximately  11.3 years and were 66% natural  gas.  The Company  serves as
operator for approximately  70% of its properties,  based on the gross number of
producing wells in which the Company owns an interest and 75% of its properties,
based upon the year-end PV-10 value.

     As a result of its property acquisitions and successful drilling activities
during 2001, the Company has achieved growth as described below:

     o Proved reserves  increased 3% to 378 Bcfe at year- end 2001 from 367 Bcfe
at year-end 2000; and

     o Average daily production increased 22% to 91,292 MMcfe during fiscal 2001
from 74,777 MMcfe in fiscal 2000. The Company had an exit rate of  approximately
100 MMcfe at year-end 2001.

Recent Activities

     Merger with Prize Energy Corp.  On March 15, 2002 we acquired  Prize Energy
Corp., which was merged into one of our wholly-owned  subsidiaries.  Prize was a
publicly  traded  independent  oil  and gas  company  engaged  primarily  in the
acquisition,  enhancement and  exploitation of producing oil and gas properties.
Prize owned oil and gas properties  principally  located in three core operating
areas,  which  were in the  Permian  Basin of West  Texas and  Southeastern  New
Mexico, the onshore Gulf Coast area of Texas and Louisiana and the Mid-Continent
area of  Oklahoma  and the  Texas  Panhandle.  Over 80% of  Prize's  oil and gas
property base was located in Texas.

     The merger  resulted in an exchange of 2.5 shares of Magnum  Hunter  common
stock  and  $5.20 in cash  for  each  share  of  Prize  common  stock,  with the
stockholders of Prize becoming stockholders of Magnum Hunter. As a result of the
merger, we became owned  approximately 52% by our then current  stockholders and
48% by the former stockholders of Prize,  without taking into account subsequent
stock sales and the options and warrants that remained  outstanding  at the time
of the merger.

     In  connection  with our merger with Prize,  we issued $300 million of 9.6%
unsecured  senior  notes  due 2012 and  established  a new  senior  bank  credit
facility  with a  borrowing  base of $300  million  secured by the assets of the
combined company. Proceeds from the senior notes offering and initial borrowings
under the new senior bank credit facility were used to refinance the outstanding
indebtedness  under the existing  senior bank credit  facilities  of both Magnum
Hunter and Prize,  fund the cash  component of the merger  consideration  in the
merger with Prize and pay costs and fees associated with the merger.

Magnum Hunter Warrants Offering.

     We have  distributed  to our  stockholders  of record on January 10,  2002,
warrants to purchase  7,228,457  shares of our common stock at an exercise price
of $15.00 per share and expiring three years from the date of distribution.  The
warrant  distribution  occurred on or about March 21, 2002 and the  warrants are
traded on the American Stock Exchange.  The stockholders and  warrantholders  of
Prize did not receive any of these warrants in the merger or otherwise.

                                        2

<PAGE>

     Recent  Commodity  Hedging  Transactions.   Periodically,   we  enter  into
commodity  price hedging  transactions  to reduce the effects of fluctuations in
crude oil and natural gas prices.  At March 31, 2002,  Magnum  Hunter had 72% of
its natural gas production  and 69% of its crude oil  production  hedged through
December 31, 2002.  None of these hedges were with Enron,  which  recently filed
for bankruptcy.

Business Strategy

     Our overall strategy is to increase our reserves, production, cash flow and
earnings utilizing a properly balanced program of:

     o selective exploration;
     o the exploitation and development of acquired properties; and
     o strategic acquisitions of additional proved reserves.

     The following are key elements of our strategy:

Exploration.

     We plan to continue to participate  in drilling Gulf of Mexico  exploratory
wells in an effort to add shorter-lived, higher output production to our reserve
mix. The continued use of 3-D seismic  information as a tool in our  exploratory
drilling in the Gulf of Mexico will be  significant.  We have  recently  built a
significant inventory of undrilled offshore lease blocks. We plan to continue to
align  ourselves  with other  active Gulf of Mexico  industry  partners who have
similar philosophies and goals with respect to a "fast track" program of placing
new  production  online.  This typically  involves  drilling wells near existing
infrastructure such as production platforms,  facilities and pipelines.  We also
maintain an active onshore  exploration  program primarily  concentrated in West
Texas and Southeastern New Mexico where we have various other operations in core
areas. From time to time, we participate in higher risk new exploration projects
generated by third parties in areas along the Gulf Coast of Texas and Louisiana.

Exploitation and Development of Existing  Properties.

     As a result of the merger with Prize,  we now have a substantial  inventory
of  over  1,000  development/exploitation  projects  which  include  development
drilling, workovers and recompletion opportunities.  We will continue to seek to
maximize the value of our existing  properties  through  development  activities
including   in-fill   drilling,   waterflooding   and  other  enhanced  recovery
techniques.  Typically,  our exploitation  projects do not have significant time
limitations  due  to  the  existing   mineral  acreage  being  held  by  current
production. By operating substantially all of our properties,  our management is
provided  maximum  flexibility with respect to the timing of capital expended to
develop these opportunities.

Property Acquisitions.

     Although we currently  have an  extensive  inventory  of  exploitation  and
development  opportunities,  we will continue to pursue  strategic  acquisitions
which fit our  objectives of increasing  proved  reserves in similar  geographic
regions  that  contain  development  or  exploration   potential  combined  with
maintaining  operating  control.  We plan to continue  to pursue an  acquisition
strategy  of  acquiring  long-lived  assets  where  operating  synergies  may be
obtained and production enhancements, either on the surface or below ground, may
be achieved.

Management of Overhead and Operating Costs.

     We will  continue to emphasize  strict cost  controls in all aspects of our
business and will continue to seek to operate our properties  wherever  possible
utilizing a minimum number of personnel.  By operating  approximately 75% of our
properties  on a PV-10  basis  we will  generally  be  able  to  control  direct
operating and drilling costs as well as to manage the timing of development  and
exploration activities. This operating control also provides greater flexibility
as to the timing  requirements  to fund new  capital  expenditures.  By strictly
controlling  Magnum Hunter's  general and  administrative  expenses,  management
strives to maximize its net operating margin.

                                        3

<PAGE>

     Expansion of Gas Gathering and Processing  Operations.  We have implemented
several  programs to expand and increase  the  efficiency  of our gas  gathering
systems and gas processing plants. We will consider  opportunities to acquire or
develop  additional gas gathering and processing  facilities  that are primarily
associated with our current production.

Properties

     The Company's  major  properties  are located in three core areas:  (i) the
Mid-Continent  Region,  (ii) the Permian Basin and (iii) the Gulf of Mexico/Gulf
Coast.

Mid-Continent Region

     The Company's  properties located in the Mid-Continent region were acquired
principally from Burlington,  Spirit 76 and Vastar.  The Company has received an
engineering   evaluation  from  DeGolyer  and  MacNaughton  ("D&M")  and  Cawley
Gillespie  &  Associates,  Inc.  ("Cawley  Gillespie"),   independent  petroleum
engineers  engaged by the Company to evaluate the Company's  properties,  on the
net reserves in the Mid-Continent Region. According to D&M and Cawley Gillespie,
as of December 31, 2001, the  Mid-Continent  properties  had Proved  reserves of
5.147  MMBbl  of oil  and  109.556  Bcf of  natural  gas,  or on a  Natural  Gas
Equivalent  basis,  140.44 Bcfe. D&M and Cawley Gillespie  further estimated the
PV-10 for the Mid-Continent  properties to be $97.011 million as of December 31,
2001. The Proved reserves are located  principally in the Ardmore Basin in south
central Oklahoma, in the Oklahoma/Texas  panhandle and in Southwestern Arkansas.
Approximately  78% of the  estimated  reserves  are  natural gas and 22% are oil
located on approximately  235,083 net mineral leasehold acres in twelve counties
in Oklahoma,  five  counties in Texas and two  counties in  Arkansas.  Total net
daily  production  from the  Mid-Continent  properties for the month of December
2001 was approximately 24.2 million cubic feet of natural gas production and 944
barrels of oil. The Company's wholly-owned subsidiary, Gruy Petroleum Management
Co.,  is  the  operator  of  approximately  89%  of  the  wells  located  in the
Mid-Continent region.

     The major fields in the  Mid-Continent  Region are the Panoma,  Cumberland,
Walnut Bend and Madill.

     Panoma.  The  Panoma  Properties  currently  consist of  approximately  599
natural gas wells in the West Panhandle,  East Panhandle, and South Erick Fields
along a corridor 66 miles long and 20 miles wide stretching from Beckham County,
Oklahoma  to Gray  County,  Texas.  All wells are less than  2,300 feet deep and
produce natural gas from the Granite Wash and/or Brown Dolomite formations.  For
the month of December 2001, net production  natural gas sales were approximately
9.5  MMcf/d,  which  excludes  liquids  processed  from this  natural gas stream
through the Company's gas processing  facility located adjacent to these fields,
known as the McLean Plant.

     Cumberland. The Cumberland Field is located in Bryan and Marshall Counties,
Oklahoma.  It was  discovered in 1940 and is  productive in multiple  reservoirs
from the Goddard  down to the  Arbuckle  formation.  Depths range from 2,000' to
6,800'. Initially, the field produced oil from the Bromide, McLish and Oil Creek
formations.  These zones were unitized in 1964 for waterflood operations,  which
continue today. The "Shallow Gas" zones include the Sycamore,  Woodford, Hunton,
and Viola.  These formations are  predominantly  gas productive and are produced
commingled.   Development  drilling  plans  exist  for  four  additional  proved
undeveloped  locations  to exploit  the shallow  gas on  160-acre  spacing.  The
shallowest  zone in the  field is the  Goddard,  which is a  channel  sand.  The
Company has an interest in a total of 120 wells,  with working interests varying
from 17% to 100%.  The Company  operates  all but nine of these  wells.  For the
month of December 2001, gross production from the field averaged 5,720 Mcf/d and
183 Bbl/d (or 3,955  Mcf/d  and 127  Bbl/d net to the  Company).  December  2001
production was reduced due to a nine day pipeline shutdown owned and operated by
a third party.

     Walnut Bend. The Walnut Bend Field is located in Cooke County,  Texas.  The
field was  discovered  in the late 1930's and produces oil and gas from numerous
intervals ranging in depth from 2,000' in the Montgomery sands to over 7,000' in
the Ellenburger carbonate. There are currently 104 active producing wells and 34
active injection wells. The Company's working interest ownership in the wells is
approximately  93%. For the month of December 2001,  gross  production  from the
wells  averaged  170  Mcf/d and 756 Bbl/d (or 140 Mcf/d and 617 Bbl/d net to the
Company).

                                        4

<PAGE>

     Madill.  The  Madill  Field is  located  in  Marshall  County  in  Southern
Oklahoma.  The first  production  from this field  occurred in 1906 and produces
primarily gas from various shallow reservoirs,  such as the Sycamore,  Woodford,
Viola and Bromide at depths  ranging from 3,750' to 5,700'.  There are currently
59 active producing wells. The Company's working interest ownership in the wells
varies from 41% to 100%. For the month of December 2001,  gross  production from
the wells  averaged  1,393  Mcf/d and 67 Bbl/d (or 948 Mcf/d and 46 Bbl/d net to
the Company).  December 2001  production  was reduced due to a nine day pipeline
shutdown owned and operated by a third party.

Permian Basin

     The Company  owns  certain oil and gas  properties  consisting  of 25 field
areas in west Texas and 22 field areas in  southeast  New Mexico  (the  "Permian
Basin  Properties").  The primary producing  formations include the Yates, Seven
Rivers and Queen in Lea and Eddy Counties,  New Mexico; the Atoka in the Brunson
Ranch Field in Loving  County,  Texas;  the Clearfork in the Westbrook  Field in
Mitchell County, Texas; and the San Andres in the  Levelland/Slaughter  Field in
Cochran County,  Texas. The Permian Basin Properties include 1,574 producing oil
and  gas  wells  on  approximately  134,212  net  acres.  One of  the  Company's
subsidiaries,  Gruy, serves as operator on approximately 53% of the wells on the
Permian Basin Properties.  Management believes the Permian Basin Properties will
continue to provide  significant  opportunities for exploitation and development
opportunities of both oil and gas through workovers and recompletions,  enhanced
recovery projects and in-fill drilling.  For example, the Company has identified
more  than 102  possible  sites in the  Westbrook  Field  (4.1  MMBbl of  Proved
reserves) and opportunities for tertiary recovery using carbon dioxide injection
in the Levelland-Slaughter Field (1.5 MMBbl of Proved reserves).

     According to D&M and Cawley Gillespie, as of December 31, 2001, the Permian
Basin Properties had Proved reserves of 12.635 MMBbl of oil and 77.9 Bcf of gas,
or on a Natural Gas  Equivalent  basis,  153.72 Bcfe.  D&M and Cawley  Gillespie
further  estimated  the PV-10 for the  Permian  Basin  Properties  to be $102.78
million as of December 31, 2001.

     The   major   fields   in   the   Permian   Basin   are   the    Westbrook,
Levelland/Slaughter and Southeast New Mexico.

     Westbrook.  The Westbrook Field covers 45 square miles of the Permian Basin
in Mitchell County,  Texas and produces from the Clearfork  formation at a depth
of approximately 3,200 feet. The Company owns three principal  properties in the
Westbrook Field, being the Southwest  Westbrook Unit, the Morrison "G" Lease and
the North Westbrook Unit.  There are currently 284 active  producing  wells. The
Company's working interest ownership in the wells varies from 0.02% to 100%. For
the month of December  2001,  gross  production  from the wells  averaged  1,212
Bbl/d.

     Most of the leases and units in the field had waterflood projects initiated
in the 1960's and those  projects are still  active.  The Company has  continued
waterflood  enhancement  operations  on the  Southwest  Westbrook  Unit  and the
Morrison "G" Lease in 2001.

     Levelland/Slaughter. The Levelland and Slaughter Fields consist of 164wells
located in Cochran County, Texas that produce from the San Andres formation at a
depth of 5,000 feet. The Company owns five principal properties in the Levelland
and Slaughter Fields, being the TLB Unit, the Veal Lease, the NW Slaughter Unit,
the Starnes Lease and the Magnum  Levelland Unit.  There are currently 93 active
producing  wells. The Company's  working interest  ownership in the wells varies
from 6% to 100%. For the month of December 2001, gross production from the wells
averaged 306 Mcf/d and 513 Bbl/d (or 84 Mcf/d and 266 Bbl/d net to the Company).

     Discovered  in  the  1930's,   all  five   properties  have  been  actively
waterflooded  since  the  1970's.  While the  projects  are  mature,  additional
drilling and  waterflood  enhancement  opportunities  are  available.  No Proved
undeveloped  reserves  were  assigned  by D&M to either the TLB Unit or the Veal
Lease. Proved undeveloped reserves were assigned by D&M to the NW Slaughter Unit
in contemplation of a carbon dioxide  injection  project which is planned in the
future  for  that  property.  The  operator  of an  adjacent  property  has been
injecting carbon dioxide for a number of years and has enhanced production.

                                        5

<PAGE>

     Southeast  New Mexico  Properties.  The  Southeast  New  Mexico  Properties
consist of approximately 410 wells in Lea and Eddy Counties, New Mexico. The Lea
County properties include the Rhodes, Jalmat,  Monument,  Langlie Mattix, Eumont
and Eunice Fields.  The fields produce from the Yates,  Seven Rivers,  Queen and
other  formations at depths generally  shallower than 3,000 feet.  Additionally,
the Company  owns  interests  in  approximately  33 wells that  produce from the
Morrow formation in Eddy County,  New Mexico where an increased  density program
is ongoing.  The Morrow  formation is found at  approximately  11,500  feet.  We
participated  in the  drilling of 7 wells in 2001 and have  budgeted to drill an
additional  20  wells  in  2002.  For  the  Southeast  New  Mexico   properties,
approximately  37  proved  undeveloped  locations  have been  identified  by the
Company's third-party petroleum engineering consultants.

Gulf of Mexico/Gulf Coast

     The Company owns  properties  both offshore Gulf of Mexico and onshore Gulf
Coast.

     The Company has  received  an  engineering  evaluation  from  DeGolyer  and
MacNaughton on the net reserves in the Gulf of Mexico/Gulf  Coast.  According to
D&M, as of December 31,  2001,  the Gulf of  Mexico/Gulf  Coast  properties  had
Proved  reserves  of 3.818  MMBbl of oil and 61.016 Bcf of natural  gas, or on a
Natural Gas Equivalent  basis,  83.93 Bcfe. D&M further  estimated the PV-10 for
the Gulf of Mexico  properties  to be $112.074  million as of December 31, 2001.
Approximately  73% of the  estimated  reserves  are  natural gas and 27% are oil
located on approximately  170,250 net mineral  leasehold acres.  Total net daily
production from the Gulf of Mexico properties for the month of December 2001 was
approximately  23.2  million  cubic feet of  natural  gas  production  and 1,569
barrels of oil.

     Offshore  Gulf  of  Mexico.   On  March  27,  1998,  the  Company  acquired
approximately 40% beneficial  ownership  interest in TEL Offshore Trust, a trust
created under the laws of the state of Texas pursuant to a cash tender offer for
an aggregate purchase price of approximately $10.4 million.  The principal asset
of TEL  consists of a 99.99%  interest in the TEL  Offshore  Trust  partnership.
Chevron  USA Inc.  owns the  remaining  .01%  interest in the  partnership.  The
partnership owns an overriding royalty interest  equivalent to a 25% net profits
interest in certain oil and gas properties  located  offshore  Louisiana.  As of
March 31, 2002, the Company owned  approximately  36% of the units of beneficial
ownership  in TEL. TEL  produced a total of  approximately  .52 Bcfe in calendar
2001  net to the  Company  and  the  Company  received  distributions  from  the
partnership totaling $2.8 million during 2001.

     The Company entered the Gulf of Mexico as a working interest participant in
new  exploratory  drilling on the shallow water shelf in May 1999. By the end of
2001,  this  program  achieved a result of 34  completed  wells in 39  attempts.
Proved  reserves  have been  assigned in 26  offshore  blocks  representing  the
discoveries. Seventeen of these successes are producing approximately 40 million
cubic feet of natural gas equivalent per day net to the Company as of the end of
March  2002.   Seven  additional  new  discoveries  are  scheduled  to  commence
production  during the remainder of 2002 and will add  substantially to existing
daily net production  rates. The Company currently owns an interest in 87 blocks
in the Gulf of  Mexico  ranging  from  12.5% to 100% and will add to this  lease
inventory  as the Company was the high bidder on 41  additional  lease blocks at
the March 2002 offshore  lease sale. The Company plans to participate in ten new
exploratory  offshore  drilling projects in 2002. Over 470 blocks of 3-D seismic
coverage  are  providing  the  basis  for new  prospect  generation  internally.
Additionally,  alliances  with  other  offshore  operators  provides  access  to
additional high- quality drilling opportunities.

     Onshore Gulf Coast.  Other onshore Gulf Coast properties are located in the
Mossy Grove prospect in Walker County, Texas, the Giddings Field, the First Shot
Field and the Clinton Field. Other than the Clinton Field, which produces from a
vertical well, these properties are typically  producing from horizontal legs of
vertical wells in these fields.

Gas Processing Plants

     McLean  Plant.  In  January  1997,  the  Company  complemented  its  Panoma
acquisition by purchasing a 50% ownership interest in the McLean Gas Plant and a
related  22 mile  products  pipeline.  This  plant is a modern  cryogenic  plant
utilizing  approximately  2,000  horsepower of high speed  compression and a gas
processing  capacity of  approximately  23 million  cubic feet per day.  For the
month of December 2001,  throughput of the plant  averaged  14,725 million cubic
feet per day with processed liquids of 895 barrels per day.

                                        6

<PAGE>

     Madill  Plant.  In  December  1999,  the  Company  acquired  the Madill Gas
Processing  Plant and associated  gathering  system assets from Dynegy Midstream
Services,  Limited Partnership, a wholly-owned subsidiary of Dynegy Inc. The gas
processing  plant and  associated  facilities  are located in Marshall and Bryan
Counties,  Oklahoma and were  acquired in  conjunction  with the  Company's  50%
partner,  Carrera Gas Gathering Co., L.L.C., of Tulsa, Oklahoma who subsequently
paid 50% of the purchase price.  The acquisition  includes over 130 miles of gas
gathering  pipelines.  This modern  cryogenic plant has3,350  horsepower of high
speed  compression and has gas processing  capacity of  approximately 18 million
cubic feet per day.  For the month of  December  2001,  throughput  of the plant
averaged 10.7 million cubic feet per day of natural gas with  processed  liquids
of 480 barrels per day.

     Walker Creek Plant. In conjunction with the Vastar acquisition, the Company
acquired an  approximate  59% ownership  interest and became the operator of the
Walker Creek Plant and associated  gathering system. In 2000, the Company sold a
44.2% interest in the Walker Creek Plant to Mallard Hunter L.P. This facility is
located in southwest Arkansas in Lafayette and Columbia  counties.  This propane
refrigeration  plant utilizes 3,160  horsepower of leased  compression and has a
gas  processing  capacity  of 12 million  cubic  feet per day.  For the month of
December  2001,  throughput of the plant  averaged  6,320 MMcf/d with  processed
liquids of 310 Bbl/d.

Development and Exploration Activities

Overview

     The  Company  presently  intends  to  continue  to  focus  its  efforts  on
exploration, property acquisitions and its substantial inventory of exploitation
and development drilling projects.

     The Company  seeks to minimize  its overhead  and capital  expenditures  by
subcontracting  the drilling,  redrilling  and workover of wells to  independent
drilling  contractors and by outsourcing  other services.  The Company typically
compensates its drilling  subcontractors on a turnkey (fixed price),  footage or
day-rate  basis  depending  on  the  Company's   assessment  of  risk  and  cost
considerations on each individual project.

Development Drilling

     The Company's  development  strategy  focuses on  maximizing  the value and
productivity  of its oil and gas asset base  through  development  drilling  and
enhanced recovery projects.  The Company has budgeted  approximately $55 million
for  exploitation  and development  activities for 2002 with $26 million of such
budget allocated to the Company's proved undeveloped  reserves.  The Company has
identified 358  development  drilling  locations  (including both production and
injection  wells) and workover  opportunities  on its properties to which Proved
reserves have been  attributed.  In exploiting  its  producing  properties,  the
Company relies upon its in-house  technical  staff of petroleum  engineering and
geological  professionals and utilizes the services of outside  consultants on a
selective basis.

     Mid-Continent Region. The Company believes that developmental  drilling can
continue to enhance the value of the Panoma  Properties,  which produce from the
Brown  Dolomite and Granite Wash  formations in the Texas  Panhandle and western
Oklahoma.  The easternmost  fields are developed on 160 acre spacing because the
original spacing of 640 acres proved  inadequate to drain reserves  efficiently.
The  westernmost  field  has now  been  developed  with  approximately  320 acre
spacing,  and future  develop  drilling  will bring the  spacing  down to a more
efficient 160 acres per well.

     The  Cumberland  Field was discovered in 1940 and is productive in multiple
reservoirs  from the Goddard down to the Arbuckle  formation.  Depths range from
2,000' to 6,800'. Initially, the field produced oil from the Bromide, McLish and
Oil  Creek  formations.  These  zones  were  unitized  in  1964  for  waterflood
operations,  which continue today. The "Shallow Gas" zones include the Sycamore,
Woodford,  Goddard,  Hunton,  and Viola.  These formations are predominantly gas
productive  and  are  produced  commingled.  The  Company  has  identified  four
locations  in which  additional  wells  could be drilled  in proved  undeveloped
reserves  to  complete  development  of the  shallow  gas on  160-acre  spacing.
Additional drilling and recompletions are budgeted in 2002.

                                        7

<PAGE>

     Additional Mid-Continent development drilling,  recompletion activities and
improvements  to existing  waterflood  operations  will focus on the Walnut Bend
Field in Cooke County, Texas and the Madill Field in Marshall County, Oklahoma.

     Permian Basin Properties.  In evaluating the Permian Basin Properties,  the
Company has  identified  over 180 drilling  locations  including  production and
injection  wells.  Primary  development  focus will be on the increased  density
drilling opportunities.  Numerous workovers, recompletions and development wells
are targeted for the shallow gas properties in Lea County,  New Mexico.  Further
development of the Westbrook Field in Mitchell County,  Texas began in 2000 when
seven producing wells and five injection wells were drilled.  Approximately  ten
new wells are scheduled to be drilled in the Westbrook Field in 2002.

Exploratory Drilling

     The Company spent $ 37.7 million of its $154.8  million 2001 capital budget
on exploratory drilling and related land and geophysical costs. Fifteen offshore
exploratory  wells were drilled in 2001 of which 13 were  completed as producing
wells providing the Company with a 87% success rate. The most significant change
in strategy  occurred  when the Company  entered the Gulf of Mexico as a working
interest  owner in new  exploratory  drilling on the shallow  water shelf in May
1999.  This new program yielded 34 completions in 39 attempts by the end of 2001
and as the Proved reserves  associated with these new wells are developed,  they
are  projected to add  significant  cash flow.  Production  from its 17 offshore
blocks was  approximately  40 MMcfe/d  net to the Company as of the end of March
2002.  Six new  platforms  scheduled to commence  production  in 2002 should add
substantially  to these levels.  The Company owns an interest ranging from 12.5%
to 100% in 87 offshore blocks and expects to add  significantly to the number of
OCS blocks in 2002 as the Company was the high bidder on 41 additional blocks in
the March 2002 lease sale. An aggressive drilling program will continue in 2002.

     The onshore exploration  program remains active.  Drilling in New Mexico in
2001 and early 2002 has  resulted  in seven new  Morrow  gas wells with  working
interests  ranging from 12.5% to 100%.  Per well  production has ranged from one
million to five  million  cubic feet of natural gas per day.  Forty seven proved
undeveloped  locations  remain to be  drilled  in New  Mexico and over 120 drill
sites are identified as a result of activity in New Mexico.

     In West Texas, 13 consecutive  producing wells have been drilled during the
past  year  in the  Goldsmith  Area.  Occidental  Petroleum  Corporation  is the
operator and the Company owns a 25% - 35% working interest in a 30,000 acre area
of mutual interest.  The latest well tested over 500 Bbl/d (100 Bbl/d net to the
Company).  Twenty two proved undeveloped locations remain to be drilled and over
65 drill sites are identified as a result of activity in the Goldsmith Area.

     New prospects on the Texas and  Louisiana  Gulf Coast area and a continuing
offshore  Gulf of  Mexico  program  should  provide  ample  opportunity  to grow
reserves and production in future years.

Gathering and Processing of Gas

     Hunter Gas Gathering,  Inc. a wholly-owned  subsidiary of the Company, owns
three gas gathering  systems  located in Oklahoma,  Texas and Arkansas,  none of
which are subject to  regulation  by the Federal  Energy  Regulatory  Commission
("FERC"),  and ownership interests in three gas processing plants. Gruy operates
all of the gas gathering systems and one of the gas processing plants.

     Generally,  the gathering systems transport the natural gas from wells to a
common point where it is dehydrated prior to redelivery to downstream pipelines.
In managing its gas  gathering  systems,  the Company has  emphasized  operating
efficiency  and  overhead   management  and  introduced  a  program  which  ties
throughput costs to volume transported rather than to compression capacity.  The
Company  believes that its focus on  volume-based  pricing reduces the potential
financial  impact  of  a  decline  in  actual  throughput.  Since  most  of  the
compression  costs  are not  fixed,  but are tied to  volumes  transported,  the
compression  operator  has an  incentive  to ensure that as much volume is being
transported as possible. The lower the volume transported,  the lower the fee to
the compression operator.

                                        8

<PAGE>

     The Panoma  system,  the largest of the Company's  gas  gathering  systems,
consists of approximately 446 miles of pipeline. The main trunklines run east to
west for  approximately  66 miles with the east end starting in Beckham  County,
Oklahoma and the west end starting in Gray County,  Texas. At December 31, 2001,
gas throughput for the Panoma gas gathering system was approximately 15,618 MMcf
per day. The Panoma gas gathering  system is connected to a third party "header"
system which provides access to all major  interstate  pipelines in the area via
seven pipeline interconnects serving Midwestern, Western and Oklahoma intrastate
markets. The Company,  which operates approximately 599 of the approximately 645
wells connected to the Panoma system,  is also actively seeking to add new wells
to such system through acquisition, development or arrangements with third party
producers.

     Effective January 1997, the Company  purchased a 50% ownership  interest in
the  McLean  Gas  Plant,  a gas  processing  facility  located  adjacent  to the
Company's  Panoma gas  gathering  system.  The purchase  also included a 22 mile
products  pipeline between the McLean Gas Plant and the Koch Pipeline at Lefors,
Texas and all gas and  product  purchase  and sales  agreements  related  to the
plant.  The McLean Gas Plant is a modern  cryogenic gas processing  plant with a
throughput  capacity  of 23.0  MMcf per day.  For the  month of  December  2001,
throughput was  approximately  14,725 MMcf per day with processed liquids of 895
barrels per day. The Company  acquired its 50%  ownership  interest in the plant
from Carrera Gas Company, L.L.C.  ("Carrera") of Tulsa, Oklahoma, which owns the
remaining 50% of the plant and operates the facility on behalf of the Company.

     In December 1999, the Company  acquired the Madill Gas Processing Plant and
associated  gathering  system  assets from Dynegy  Midstream  Services,  Limited
Partnership,  a wholly-owned  subsidiary of Dynegy Inc. The gas processing plant
and associated  facilities are located in Marshall and Bryan Counties,  Oklahoma
and were acquired in conjunction  with the Company's 50% partner,  Carrera.  The
acquisition  includes  over 130 miles of gas  gathering  pipelines.  This modern
cryogenic  plant has 3,350  horsepower  of high  speed  compression  and has gas
processing  capacity of  approximately  18 million  cubic feet per day.  For the
month of December 2001,  throughput of the plant was  approximately  10,730 MMcf
per day of natural gas with processed liquids of 480 barrels per day.

     In  conjunction   with  the  Vastar   acquisition,   the  Company  acquired
approximately 59% ownership interest and became the operator of the Walker Creek
Plant  and  associated  gathering  system.  In 2000,  the  Company  sold a 44.2%
interest in the Walker  Creek  Plant to Mallard  Hunter  L.P.  This  facility is
located in southwest Arkansas in Lafayette and Columbia  counties.  This propane
refrigeration  plant utilizes 3,160 horsepower leased  compression and has a gas
processing  capacity of 12 million cubic feet per day. For the month of December
2001,  throughput  of the plant was  approximately  6,320 MMcf/d with  processed
liquids of 310 Bbl/d.

Marketing of Production

     The Company  markets all of its gas  production as well as gas it purchases
from third  parties to gas marketing  firms or end-users  either on (i) the spot
market under  contracts of less than one year at  prevailing  spot market prices
(approximately  75% of our  volume) or (ii) at market  responsive  prices  under
multi-year  contracts  (approximately 25% of our volume).  Marketing gas for its
own  account  exposes the Company to the  attendant  commodities  risk which the
Company  attempts to mitigate  through  various  financial  hedges.  The Company
normally  sells its own oil under  month-to-month  contracts  with a variety  of
crude oil purchasers.  Oil is usually sold for the Company's own account through
the services of Enmark Services,  a marketing agent in Dallas,  Texas. While the
Company has historically  been able to sell oil above posted prices,  it is also
exposed to the  commodities  risk  inherent in  short-term  contracts  which the
Company attempts to mitigate through various financial hedges.  For a discussion
of the Company's hedging activities,  see "Management's  Discussion and Analysis
of  Financial  Condition  and  Results of  Operations  -  Liquidity  and Capital
Resources  -  Hedging  Activity"  and  Note  13 to  the  Company's  Consolidated
Financial Statements.

     In December  1997,  Hunter Gas  Gathering,  Inc.  acquired a thirty percent
(30%) membership interest in NGTS, LLC, a subsidiary of Natural Gas Transmission
Services,  Inc. NGTS is a Dallas-based natural gas marketing and trading company
with  operations  concentrated in the western  two-thirds of the country.  As of
December 31, 2001, NGTS marketed  approximately 26% of the Company's natural gas
under short term contracts. The balance of the Company's

                                        9

<PAGE>

     production   is   marketed    through   other   marketing    companies   or
gatherer/processors.

     The market for oil and  natural  gas  produced  by the  Company  depends on
factors  beyond its control,  including  the extent of domestic  production  and
imports of oil and  natural  gas,  the  proximity  and  capacity  of natural gas
pipelines  and other  transportation  facilities,  weather,  demand  for oil and
natural gas, the  marketing  of  competitive  fuels and the effects of state and
federal  regulation.  The oil and natural gas industry  also competes with other
industries  in  supplying  the  energy  and  fuel  requirements  of  industrial,
commercial and individual consumers.

Petroleum Management and Consulting Services

     The Company acquired Gruy in December 1995. Gruy, which conducts operations
for both the Company and third parties,  has over a 45-year  history of managing
properties for financial institutions,  bankruptcy trustees, estates, individual
investors, trusts and independent oil and gas companies. Gruy provides drilling,
completion and other well-site  services;  advice  regarding  environmental  and
other regulatory compliance;  receipt and disbursement functions, expert witness
testimony and other managerial services and petroleum engineering services. Gruy
manages,  operates and provides  consulting  services on oil and gas properties,
gathering systems and processing plants located in Texas, Oklahoma, Mississippi,
Louisiana,  New  Mexico  and  Kansas.  Gruy  is an  important  component  of the
Company's acquisition program. As the operator of wells for third parties and as
a  provider  of  consulting  services  for the  energy  industry,  Gruy is often
uniquely able to identify attractive acquisition opportunities.

     For additional  information on the Company's business segments, see Note 16
to the Company's consolidated financial statements.

Competition

     The oil and gas industry is highly competitive.  Competitors of the Company
include  major  oil  companies,  other  independent  oil and gas  concerns,  and
individual  producers and operators,  many of which have  substantially  greater
financial  resources and larger staffs and facilities than those of the Company.
In addition, the Company frequently encounters competition in the acquisition of
oil and gas  properties  and gas gathering  systems,  and in its  management and
consulting business.  The principal means of such competition are the amount and
terms of the consideration offered. The principal means of such competition with
respect  to the sale of oil and gas  production  are  product  availability  and
price. The price at which the Company's products may be sold will continue to be
affected by a number of factors,  including the price of alternate fuels such as
oil,  natural gas, nuclear power,  hydroelectric  power and coal and competition
among various gas producers and marketers.

Regulation

General Federal and State Regulation

     There have been,  and continue to be,  numerous  federal and state laws and
regulations  governing  the oil and gas  industry  that  are  often  changed  in
response to the current political or economic environment.  Compliance with this
regulatory  burden is often  difficult  and  costly  and may  carry  substantial
penalties for  noncompliance.  The following are some specific  regulations that
may affect the Company. The Company cannot predict the impact of these or future
legislative or regulatory initiatives.

Regulation of Natural Gas and Oil Exploration and Production

     The Company's  operations are subject to various types of regulation at the
federal,  state and local levels. Such regulation includes requiring permits for
drilling wells,  maintaining  bonding  requirements in order to drill or operate
wells and  regulating  the location of wells,  the method of drilling and casing
wells,  the  surface  use and  restoration  of  properties  upon which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids used in
connection with

                                       10

<PAGE>

     operations.   The  Company's   operations   are  also  subject  to  various
conservation  laws and regulations.  These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in and the  unitization  or  pooling  of oil and gas  properties.  In
addition, state conservation laws establish maximum rates of production from oil
and gas  wells,  generally  prohibit  the  venting  or flaring of gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and gas the Company can produce from its
wells and may limit the number of wells or the  locations  at which the  Company
can drill.  The  regulatory  burden on the oil and gas  industry  increases  the
Company's costs of doing business and, consequently,  affects its profitability.
Inasmuch  as such laws and  regulations  are  frequently  expanded,  amended and
reinterpreted,  the  Company is unable to predict  the future  cost or impact of
complying with such regulations.

Federal Regulation of Sales Prices and Transportation

     Currently,  there are no  federal,  state or local laws that  regulate  the
price for sales of natural gas,  NGLs,  crude oil or  condensate by the Company.
However,  the rates charged and terms and  conditions for the movement of gas in
interstate  commerce  through certain  intrastate  pipelines and production area
hubs are  subject  to  regulation  under  the  Natural  Gas  Policy  Act of 1978
("NGPA").  Pipeline and hub  construction  activities  are, to a limited extent,
also subject to  regulations  under the Natural Gas Act of 1938  ("NGA").  While
these controls do not apply directly to the Company, their effect on natural gas
markets can be significant in terms of  competition  and cost of  transportation
services. Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress,  FERC,  state  regulatory
bodies and the courts.  The Company cannot predict when or if any such proposals
might become  effective and their effect,  if any, on the Company's  operations.
Historically,  the natural gas industry has been heavily  regulated;  therefore,
there is no  assurance  that the less  stringent  regulatory  approach  recently
pursued by FERC,  Congress and the states will  continue  indefinitely  into the
future.

Gathering Regulations

     State regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances,  nondiscriminatory  take requirements.
Such regulation has not generally been applied against gatherers of natural gas,
although  natural gas gathering may receive greater  regulatory  scrutiny in the
future.  Federal,  State or Indian Leases The  Company's  operations on federal,
state or  Indian  oil and gas  leases  are  subject  to  numerous  restrictions,
including nondiscrimination statutes. Such operations must be conducted pursuant
to certain on-site  security  regulations  and other permits and  authorizations
issued by the Bureau of Land Management,  Minerals  Management Service and other
agencies.

Environmental Regulation

     The  Company's  exploration,  development,  and  production of oil and gas,
including its operation of saltwater  injection and disposal wells,  are subject
to various federal,  state and local  environmental  laws and regulations.  Such
laws and regulations can increase the costs of planning,  designing,  installing
and operating oil and gas wells. The Company's  domestic  activities are subject
to a variety of environmental  laws and  regulations,  including but not limited
to, the Oil  Pollution  Act of 1990  ("OPA"),  the Clean Water Act ("CWA"),  the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
the Resource Conservation and Recovery Act ("RCRA"),  the Clean Air Act ("CAA"),
and  the  Safe  Drinking  Water  Act  ("SDWA"),  as well  as  state  regulations
promulgated  under  comparable  state  statutes.  The Company also is subject to
regulations  governing the handling,  transportation,  storage,  and disposal of
naturally  occurring  radioactive  materials  that are  found in its oil and gas
operations.   Civil  and  criminal  fines  and  penalties  may  be  imposed  for
non-compliance  with these  environmental  laws and  regulations.  Additionally,
these  laws  and  regulations  require  the  acquisition  of  permits  or  other
governmental  authorizations  before undertaking  certain  activities,  limit or
prohibit  other  activities  because of protected  areas or species,  and impose
substantial liabilities for cleanup of pollution.

                                       11

<PAGE>

     Under the OPA, a release of oil into water or other areas designated by the
statute  could  result in the Company  being held  responsible  for the costs of
remediating such a release,  certain OPA specified damages, and natural resource
damages.  The extent of that liability  could be extensive,  as set forth in the
statute,  depending  on the nature of the  release.  A release of oil in harmful
quantities or other  materials  into water or other  specified  areas could also
result in the  Company  being  held  responsible  under the CWA for the costs of
remediation, and civil and criminal fines and penalties.

     CERCLA and comparable state statutes,  also known as "Superfund"  laws, can
impose joint and several and retroactive  liability,  without regard to fault or
the  legality of the  original  conduct,  on certain  classes of persons for the
release of a "hazardous  substance" into the environment.  In practice,  cleanup
costs are usually  allocated  among  various  responsible  parties.  Potentially
liable parties include site owners or operators,  past owners or operators under
certain conditions,  and entities that arrange for the disposal or treatment of,
or  transport  hazardous  substances  found at the  site.  Although  CERCLA,  as
amended,  currently exempts petroleum,  including but not limited to, crude oil,
gas and natural gas liquids  from the  definition  of hazardous  substance,  the
Company's operations may involve the use or handling of other materials that may
be classified as hazardous substances under CERCLA. Furthermore, there can be no
assurance that the exemption will be preserved in future  amendments of the act,
if any.

     RCRA and comparable state and local  requirements  impose standards for the
management,  including  treatment,  storage,  and disposal of both hazardous and
nonhazardous  solid wastes.  The Company  generates  hazardous and  nonhazardous
solid  waste in  connection  with its  routine  operations.  From  time to time,
proposals  have been made that  would  reclassify  certain  oil and gas  wastes,
including wastes generated during drilling,  production and pipeline operations,
as "hazardous  wastes" under RCRA which would make such solid wastes  subject to
much more stringent handling,  transportation,  storage,  disposal, and clean-up
requirements.  This development could have a significant impact on the Company's
operating  costs.  While state laws vary on this  issue,  state  initiatives  to
further regulate oil and gas wastes could have a similar impact.

     Because  oil  and  gas  exploration  and  production,  and  possibly  other
activities,  have been conducted at some of the Company's properties by previous
owners and  operators,  materials  from these  operations  remain on some of the
properties and in some instances require  remediation.  In addition,  in certain
instances  the Company has agreed to indemnify  sellers of producing  properties
from whom the Company has acquired  reserves  against  certain  liabilities  for
environmental claims associated with such properties. While the Company does not
believe that costs to be incurred by the Company for compliance and  remediating
previously or currently owned or operated properties will be material, there can
be no guarantee that such costs will not result in material expenditures.

     Additionally,   in  the  course  of  the  Company's  routine  oil  and  gas
operations,  surface spills and leaks,  including  casing leaks, of oil or other
materials   occur,   and  the  Company  incurs  costs  for  waste  handling  and
environmental compliance.  Moreover, the Company is able to control directly the
operations  of only those  wells for which it acts as the  operator.  Management
believes  that  the  Company  is  in  substantial   compliance  with  applicable
environmental laws and regulations.

     It is not anticipated  that the Company will be required in the near future
to  expend   amounts  that  are  material  in  relation  to  its  total  capital
expenditures  program  by  reason of  environmental  laws and  regulations,  but
inasmuch as such laws and  regulations  are frequently  changed,  the Company is
unable to predict the  ultimate  cost of  compliance.  There can be no assurance
that more stringent laws and regulations  protecting the environment will not be
adopted or that the  Company  will not  otherwise  incur  material  expenses  in
connection with environmental laws and regulations in the future.

                                       12

<PAGE>

Employees

     At December 31, 2001,  the Company had 105 full-time  employees of which 13
were management, 36 were administrative and 56 were field personnel. None of the
Company's  employees  are  represented  by a  union.  Management  considers  its
relations with employees to be good.

Facilities

     The Company  occupies  approximately  23,386 square feet of office space at
600 East Las Colinas Boulevard,  Suite 1100,  Irving,  Texas, under a lease that
expires in October 2004. The Company owns field offices and production  yards in
Shamrock and Gainesville,  Texas, Cumberland, Oklahoma and Taylor, Arkansas. The
Company also leases  field  production  offices in Midland and  Abilene,  Texas,
Hobbs, New Mexico and Oklahoma City and Madill, Oklahoma.

                                       13

<PAGE>

                                  RISK FACTORS

RISKS RELATED TO SUBSTANTIAL LEVERAGE

We have a significant amount of debt.

In  connection  with our  merger  with  Prize,  we issued  $300  million of 9.6%
unsecured  senior notes due 2012 and  established  a new credit  facility with a
borrowing  base of $300 million  secured by the assets of the combined  company.
Proceeds  from the senior  notes  offering and  borrowings  under the new credit
facility were used to refinance the outstanding  indebtedness under the existing
senior  credit  facilities  of both  Magnum  Hunter  and  Prize,  fund  the cash
component of the  consideration  in the merger with Prize and pay costs and fees
associated  with the merger.  As a result of the merger,  the combination of our
outstanding  10.00%  senior notes due 2007,  our new issuance of the 9.6% senior
notes due 2012 and our new senior bank credit facility, created outstanding long
term debt of approximately  $634.9 million as of March 31, 2002. Because we must
dedicate a substantial  portion of our cash flow from  operations to the payment
of  interest on our debt,  that  portion of our cash flow is not  available  for
other  purposes.  The  covenants  contained  in our new credit  facility and the
indentures  relating to our two outstanding issues of senior notes require us to
meet  financial  tests and limit our  ability to borrow  additional  funds or to
acquire or dispose of assets.  Also, our ability to obtain additional  financing
in the future may be impaired by our  substantial  leverage.  Additionally,  the
senior, as opposed to subordinated,  status of our 10% senior notes due 2007 and
our 9.6% senior notes due 2012, our high debt to equity ratio, and the pledge of
substantially  all of our assets as collateral for our new credit facility will,
for the  foreseeable  future,  make it  difficult  for us to  obtain  additional
financing on an  unsecured  basis,  or to obtain  secured  financing  other than
"purchase money" indebtedness  collateralized by the acquired assets.

We may not be able to meet our capital requirements.

     We will need to continue to make substantial  capital  expenditures for the
acquisition,  enhancement,  exploitation  and  production of oil and natural gas
reserves.   Without   successful   enhancement,   exploitation  and  acquisition
activities,  our  reserves  and  revenues  will decline over time due to natural
depletion.  The Company's oil and natural gas capital  expenditures for the year
2002  are  budgeted  at $115  million,  which  the  Company  intends  to use for
enhancement,  exploitation  and exploration  drilling  activities.  We intend to
finance our capital  expenditures,  other than  significant  acquisitions,  from
internally  generated funds provided by operations and borrowings  under our new
credit   facility.   The  timing  of  most  of  our  capital   expenditures   is
discretionary,  with no long-term capital commitments.  Consequently,  we have a
significant  degree of  flexibility  to adjust  the  amounts  and  timing of our
capital expenditures as circumstances may warrant. However, in the long term, if
our cash flow from operations and availability under our new credit facility are
not  sufficient to satisfy  capital  expenditure  requirements,  there can be no
assurance that additional debt or equity financing will be available to allow us
to fund our continued growth.

     Our new credit  facility  and the  indentures  governing  our senior  notes
impose  restrictions  on us that may limit the  discretion of our  management in
operating  our  business  that,  in turn,  could impair our ability to repay our
obligations under the notes.

     Our new credit  facility  and the  indentures  governing  our senior  notes
contain various restrictive covenants that limit our management's  discretion in
operating our business.  In particular,  these  covenants  limit our ability to,
among other things:

     o incur additional debt;
     o make restricted  payments  (including  paying  dividends on, redeeming or
repurchasing our capital stock);
     o make certain investments or acquisitions;

                                       14

<PAGE>

     o grant liens on assets;
     o sell our assets;
     o engage  in  transactions  with  affiliates;  and
     o merge, consolidate or transfer substantially all of our assets.

     Under some  circumstances,  including if we fail to meet certain  financial
tests, the indentures  governing our senior notes prohibit us from borrowing the
full amount of availability under our new credit facility.

     Our new credit  facility also requires us to maintain  specified  financial
ratios and satisfy some financial  tests.  Our ability to maintain or meet these
financial  ratios  and  tests may be  affected  by events  beyond  our  control,
including  changes in general  economic and business  conditions,  and we cannot
assure  you that we will  maintain  or meet  these  ratios and tests or that the
lenders  under the new  credit  facility  will  waive any  failure to meet these
ratios or tests. A breach of any of these  covenants could result in an event of
default under the new credit facility, in which case, the lenders could elect to
declare all amounts borrowed under the new senior bank credit facility, together
with unpaid accrued interest, to be immediately due and payable and to terminate
all commitments under the new senior bank credit facility.

RISKS RELATING TO THE OIL AND GAS INDUSTRY

A decrease in oil and natural gas prices will adversely affect our
financial results.

     Our  revenues,  profitability  and the  carrying  value  of our oil and gas
properties,  including  the  properties  we  acquired  in the merger with Prize,
depend  substantially upon prevailing prices of, and demand for, oil and gas and
the costs of acquiring,  finding, developing and producing reserves. Oil and gas
prices  also  substantially  affect our  ability to  maintain  or  increase  our
borrowing  capacity,  to repay  current  or future  indebtedness,  and to obtain
additional  capital on attractive terms.  Historically,  the markets for oil and
gas have been  volatile and are likely to continue to be volatile in the future.
Prices for oil and gas fluctuate widely in response to:

     o relatively minor changes in the supply of, and demand for, oil and gas;
     o market uncertainty both domestically and worldwide; and
     o a variety of additional factors, all of which are beyond our control.

     These factors include domestic and foreign political conditions,  the price
and availability of domestic and imported oil and gas, the level of consumer and
industrial demand, weather, domestic and foreign government relations, the price
and availability of alternative fuels and overall economic conditions. Also, our
ability  to  market  our  production  depends  in part  upon  the  availability,
proximity  and  capacity  of  gathering   systems,   pipelines  and   processing
facilities.  Volatility in oil and gas prices could affect our ability to market
our production through such systems, pipelines or facilities. Currently, we sell
substantially all our natural gas production to gas marketing firms or end users
either on the spot market on a  month-to-month  basis at prevailing  spot market
prices or under long-term contracts based on current spot market prices.

     Under the full cost accounting  method,  we are required to take a non-cash
charge against  earnings if capitalized  costs of  acquisition,  exploration and
development,  net of depletion,  depreciation  and  amortization,  less deferred
income taxes,  exceed the present value of our proved  reserves and the lower of
cost or fair  value of  unproved  properties  after  income  tax  effects.  Once
incurred,  a write-down of oil and gas  properties is not  reversible at a later
date even if oil and gas prices increase.

                                       15

<PAGE>

     At December  31,  2000,  NYMEX prices were $26.80 per Bbl for oil and $9.78
per Mcf for gas. At December 31, 2001, NYMEX prices were $19.78 per Bbl for oil,
a decline of 26% from year-end 2000, and $2.72 per Mcf for gas, a decline of 72%
from  year-end  2000.  Our  capitalized  costs  exceeded  the  PV-10  limitation
utilizing  commodity  prices in effect at December  31, 2001 under the full cost
method of  accounting.  However,  no writedown for impairment of our oil and gas
properties is required, due to higher oil and gas prices that have been recorded
in the market subsequent to December 31, 2001.

You should not place undue reliance on our reserve data because they are
estimates.

     This document  contains  estimates of Magnum  Hunter's oil and gas reserves
and the  future  net cash  flows that were  prepared  by  independent  petroleum
consultants as of December 31, 2001. There are numerous  uncertainties  inherent
in  estimating  quantities  of proved  reserves  of oil and  natural  gas and in
projecting   future  rates  of   production   and  the  timing  of   development
expenditures,  including many factors beyond our control.  The estimates in this
document rely on various assumptions,  including, for example,  constant oil and
gas prices,  operating  expenses,  capital  expenditures and the availability of
funds,  and are therefore  inherently  imprecise  indications of future net cash
flows.  Actual  future  production,   cash  flows,  taxes,  operating  expenses,
development  expenditures and quantities of recoverable oil and gas reserves may
vary substantially from those assumed in the estimates. Any significant variance
in these assumptions could materially affect the estimated quantity and value of
reserves.

     You should not construe the present value of proved reserves referred to in
this document as the current  market value of the estimated  proved  reserves of
oil and natural gas attributable to our properties.  We have based the estimated
discounted  future net cash flows from  proved  reserves  generally  on year-end
prices and costs, but actual future prices and costs may vary significantly. The
following factors may also affect actual future net cash flows:

     o the timing of both production and related expenses;
     o changes in consumption levels; and
     o governmental regulations or taxation.

     In addition,  the  calculation  of the present value of the future net cash
flows uses a 10% discount rate,  which is not necessarily  the most  appropriate
discount  rate  based on  interest  rates in effect  from time to time and risks
associated   with  our  reserves  or  the  oil  and  gas  industry  in  general.
Furthermore,  we may need to revise our  reserves  downward or upward based upon
actual  production,  results of future  development and exploration,  supply and
demand for oil and natural gas,  prevailing oil and natural gas prices and other
factors, many of which are beyond our control.

Maintaining reserves and revenues in the future depends on successful
exploration and development.

     Our future success  depends upon our ability to find or acquire  additional
oil and gas reserves that are economically  recoverable.  Unless we successfully
explore or develop or acquire properties containing proved reserves,  our proved
reserves will generally decline as we produce them due to natural depletion. The
decline rate varies depending upon reservoir  characteristics and other factors.
Our future oil and gas reserves and production,  and,  therefore,  cash flow and
income,  depend greatly upon our success in exploiting our current  reserves and
acquiring or finding additional reserves.  We cannot assure you that our planned
development  projects  and  acquisition  activities  will result in  significant
additional  reserves  or that we will  successfully  drill  productive  wells at
economic returns to replace our current and future production.

                                       16

<PAGE>


Our operations are subject to delays and cost overruns, and our activities may
not be profitable.

     We intend to  increase  our  exploration  activities  and to  continue  our
development   activities.   Exploratory   drilling  and,  to  a  lesser  extent,
developmental drilling of oil and gas reserves involve a high degree of risk. We
have expanded, and plan to increase our capital expenditures on, our exploration
efforts,  including offshore exploration,  which involve a higher degree of risk
than our  development  activities.  It is  possible  that we will not obtain any
commercial  production  or that  drilling and  completion  costs will exceed the
value of production.  The cost of drilling,  completing  and operating  wells is
often uncertain. Numerous factors, including title problems, weather conditions,
compliance  with  governmental  requirements  and  shortages  or  delays  in the
delivery  of  equipment,  may  curtail,  delay or  cancel  drilling  operations.
Furthermore,  completion of a well does not assure a profit on the investment or
a complete recovery of drilling, completion and operating costs.

We conduct waterflood projects and other secondary recovery operations.

     Secondary recovery operations involve certain risks,  especially the use of
waterflooding  techniques.  Our  inventory  of  development  prospects  includes
waterflood  projects.  With  respect to our  properties  located in the  Permian
Basin, we have identified  significant potential expenditures related to further
developing  existing  waterfloods.  Waterflooding  involves  significant capital
expenditures  and  uncertainty as to the total amount of  recoverable  secondary
reserves. In waterflood operations,  there is generally a time delay between the
initiation of water injection into a formation  containing  hydrocarbons and any
increase in production.  The operating cost per unit of production of waterflood
projects is generally  higher during the initial  phases of such projects due to
the purchase of injection water and related production  enhancement costs. Costs
are also higher during the later stages of the life of the project as production
naturally  declines.  The degree of success,  if any, of any secondary  recovery
program  depends on a large number of factors,  including  the amount of primary
production,  the porosity and permeability of the formation, the technique used,
the location of injection  wells and the spacing of both producing and injection
wells.

We hedge our oil and gas production.

     Periodically,  we have  entered  into  hedging  transactions  to reduce the
effects of fluctuations in crude oil and natural gas prices.  At March 31, 2002,
Magnum  Hunter had 72% of its  natural gas  production  and 69% of its crude oil
production  hedged  through  December 31, 2002.  The hedging  activities  of the
combined  company,  while  intended to reduce  sensitivity  to changes in market
prices of oil and gas, are subject to a number of risks  including  instances in
which  we or the  counterparties  to our  hedging  contracts  fail  to  perform.
Additionally, the fixed price sales and hedging contracts limit the benefits the
combined company will realize if actual prices rise above the contract prices.

Our operations are subject to many laws and regulations.

     The oil and gas industry is heavily regulated.  Extensive  federal,  state,
local and  foreign  laws and  regulations  relating to the  exploration  for and
development,  production,  gathering  and  marketing  of oil and gas  affect our
operations.  Some of the regulations  set forth standards for discharge  permits
for drilling  operations,  drilling  and  abandonment  bonds or other  financial
responsibility  requirements,  reports  concerning  operations,  the  spacing of
wells,  unitization  and pooling of properties and taxation.  From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting  the  rate of flow of oil and  gas  wells  below  actual  production
capacity to conserve supplies of oil and gas.

     Numerous  environmental laws, including but not limited to, those governing
the management of waste, the protection of water and air quality,  the discharge
of materials into the environment,  and the  preservation of natural  resources,
impact and influence  our  operations.  If we fail to comply with  environmental
laws regarding the discharge of oil, gas, or other  materials into the air, soil
or water we may be subject to  liabilities  to the government and third parties,
including  civil and criminal  penalties.  These  regulations  may require us to
incur  costs to  remedy  the  discharge.  Laws and  regulations  protecting  the
environment  have  become  more  stringent  in recent  years,  and may,  in some
circumstances,

                                       17

<PAGE>

     result in liability for  environmental  damage  regardless of negligence or
fault. New laws or regulations,  or modifications of or new  interpretations  of
existing laws and regulations, may increase substantially the cost of compliance
or adversely  affect our oil and gas  operations and financial  condition.  From
time to time,  we have  agreed to  indemnify  sellers  of  producing  properties
against  some  liabilities  for  environmental   claims  associated  with  these
properties.  Material indemnity claims may also arise with respect to properties
acquired by or from us.  Additionally,  as a result of the merger with Prize, we
are now responsible for any environmental  liabilities Prize may have had in the
past or which may occur in the  future  from these  properties.  While we do not
anticipate incurring material costs in connection with environmental  compliance
and remediation, we cannot guarantee that we will not incur material costs.

Marketability of our oil and natural gas production may be affected by factors
beyond our control.

     The marketability of our production  depends in part upon the availability,
proximity  and  capacity  of  natural  gas  gathering  systems,   pipelines  and
processing  facilities.  Most of our natural gas is delivered  through gathering
systems and pipelines  that we do not own.  Federal and state  regulation of oil
and natural gas production and transportation,  tax and energy policies, changes
in supply and demand and general economic  conditions all could adversely affect
our ability to produce and market our oil and natural gas.

Our acquisitions involve certain risks.

     We have  grown  primarily  through  acquisitions  and  intend  to  continue
acquiring oil and gas  properties in the future.  Although we review and analyze
the properties that we acquire,  such reviews are subject to  uncertainties.  It
generally is not possible to review in detail every individual property involved
in an  acquisition.  Ordinarily,  we  focus  our  review  on  the  higher-valued
properties.  However,  even a detailed  review of all properties and records may
not reveal  existing or  potential  problems.  Economics  dictate that we cannot
become  sufficiently  familiar  with all the  properties  to assess  fully their
deficiencies  and  capabilities.  We do not always conduct  inspections on every
well. Even when we do inspect a specific well, we cannot always detect potential
problems, such as mechanical integrity of equipment and environmental conditions
that may require significant remedial expenditures.

     As the  merger  with  Prize  demonstrates,  we  have  begun  to  focus  our
acquisition  efforts on larger packages of oil and gas properties.  Acquisitions
of larger oil and gas properties may involve  substantially higher costs and may
pose additional issues regarding operations and management. We cannot assure you
that we will be able to successfully integrate all of the oil and gas properties
that  we  acquire  into  our   operations  or  that  we  will  achieve   desired
profitability objectives.

We are subject to substantial competition.

     We encounter substantial competition in acquiring properties,  drilling for
new reserves,  marketing oil and gas,  securing trained  personnel and operating
our  properties.  Many  competitors  have  financial  and other  resources  that
substantially   exceed  our  resources.   Our   competitors   in   acquisitions,
development, exploration and production include major oil companies, natural gas
utilities,  independent  power  producers,  numerous  independents  who are both
public and private,  individual  proprietors and others.  Our competitors may be
able to pay more for desirable  leases and may be able to evaluate,  bid for and
purchase a greater  number of  properties  or  prospects  than our  financial or
personnel resources will permit.

Our business may be adversely affected if we lose our key personnel.

     We depend greatly upon three key  individuals  within our management  team:
Gary C. Evans, Richard R. Frazier and Charles R. Erwin. The loss of the services
of any of these individuals could materially impact our operations.

                                       18

<PAGE>

RISKS ASSOCIATED WITH OUR MERGER WITH PRIZE

We may not achieve the expected benefits of the merger.

     The merger was  intended  to achieve  specific  goals.  The  likelihood  of
achieving  those  goals  represented  the  subjective  judgment  of  our  senior
management  and board of directors.  Some of those goals may not be achieved or,
if achieved,  may not be achieved in the time frame in which they were expected.
Whether the combined  company will actually realize these  anticipated  benefits
depends on future  events and  circumstances  beyond the control of the combined
company, including the following:

     o A  decline  in  economic  conditions  in  general  or in the  oil and gas
industry  in  particular  could cause our  combined  company to fail to meet the
expectations of our board of directors for revenue, earnings and cash flow.

     o Differing  opinions of securities  analysts and  investors  regarding the
prospects for our combined company's business and our future financial condition
could reduce the likelihood  that our combined  company will enjoy the hoped-for
increase  in stock  market  valuation  multiples  relative  to the stock  market
valuation multiples of smaller competitors.

     o The other risk factors discussed below may prevent the achievement of the
believed advantages of the merger.

     Because  of these and  other  factors,  it is  possible  that our  combined
company will not realize some or all of the expected benefits of the merger.

We may face difficulties in integrating the operations of Magnum Hunter
and Prize.

     Before the merger,  Magnum  Hunter and Prize  operated  separately.  Magnum
Hunter's management team has no experience in running the combined business.  We
may not be able to integrate  all of the  operations  of Magnum Hunter and Prize
within  the  time  frame  anticipated  and  without  an  unexpected  loss of key
employees,  customers or suppliers, a loss of revenues, an increase in operating
or other costs or other difficulties. In addition, we may not be able to realize
all of the operating  efficiencies,  synergies,  cost savings or other  benefits
originally  anticipated from the merger. Any unexpected costs or delays incurred
in connection with the integration could have an adverse effect on our business,
results of operations or financial condition.

As a result of the merger with Prize, our risk profile is different from that of
Magnum Hunter and Prize before the merger.

     We were  relatively  more  active in onshore  exploration  and in  offshore
exploration and production than Prize, which did not engage in these activities.
As a result, the combined company will have a different risk profile than either
company had before the merger.

     The combined company's oil and gas business involves a variety of operating
risks,  including  unexpected  formations or pressures,  uncontrollable flows of
oil,  gas,  brine or well fluids  into the  environment  (including  groundwater
contamination), blowouts, fires, explosions, pollution, marine hazards and other
risks,  any of which  could cause  personal  injuries,  loss of life,  damage to
properties and substantial losses. Although we carry, and will continue to carry
insurance at levels that we believe are reasonable, we will not be fully insured
against all risks. We will not carry business  interruption  insurance except on
rare occasions.  Losses and liabilities  arising from uninsured or under-insured
events could materially affect the combined  company's  financial  condition and
operations.

                                       19

<PAGE>

The price of our common stock may decline as a result of the merger with Prize.

     The  number  of  issued  shares of Magnum  Hunter  common  stock  increased
substantially  as a result of the merger with Prize,  from 35,972,484  shares on
March 1, 2002 to  70,065,447  shares  as of March  15,  2002.  If  holders  of a
significant  number of these new shares  elect not to retain their  shares,  the
market  price of our  common  stock may vary  sharply  or  decline  for  reasons
unrelated to the financial performance of the combined company.

RISKS RELATED TO MAGNUM HUNTER COMMON STOCK

     The market  price of our common stock and our ability to raise equity could
be  adversely  affected by sales of  substantial  amounts of common stock in the
public market or the perception that such sales could occur.

     A  substantial  number of our  shares are  issuable  upon the  exercise  of
options and warrants.  A substantial number of shares will be available for sale
by our  management  and their  affiliates  under Rule 144 who  collectively  own
approximately 35% of our outstanding stock as of March 15, 2002.

     In addition,  we will have a  significant  number of shares that are freely
transferable  without  restriction.  We had  approximately  70,065,447 shares of
common stock issued and outstanding as of March 15, 2002. The  possibility  that
substantial  amounts  of  common  stock  may be sold in the  public  market  may
adversely  affect  prevailing  and future market prices for our common stock and
could impair our ability to raise capital through the sale of equity  securities
in the future.

We have never paid cash dividends on our common stock.

     We have not  previously  paid any cash dividends on our common stock and we
do not anticipate  paying cash dividends on our common stock in the  foreseeable
future. We intend to reinvest all available funds for the development and growth
of our  business.  In  addition,  our new  credit  facility  and the  indentures
governing  our 10%  senior  notes due 2007 and our 9.6%  senior  notes due 2012,
restrict the payment of cash dividends on some types of securities.

We have outstanding preferred stock and have the ability to issue more.

     Our common stock is  subordinate  to all  outstanding  classes of preferred
stock in the payment of dividends and other  distributions  made with respect to
the common stock,  including  distributions  upon  liquidation or dissolution of
Magnum  Hunter.  Our board of directors is  authorized to issue up to 10,000,000
shares of preferred stock without first obtaining stockholder  approval,  except
in limited circumstances.  We have previously issued several series of preferred
stock.  Although only the 1996 Series A Convertible Preferred Stock is currently
outstanding  and is presently owned 100% by a wholly-owned  subsidiary,  we have
the ability to resale such securities to a third party. If we designate or issue
other series of preferred stock, it will create additional  securities that will
have dividend and  liquidation  preferences  over the common stock.  If we issue
convertible  preferred  stock,  a subsequent  conversion  may dilute the current
common stockholders' interest.

                                       20

<PAGE>

Anti-takeover provisions may affect your rights as a stockholder.

     Our articles of incorporation and bylaws and Nevada law include  provisions
that may  encourage  persons  considering  unsolicited  tender  offers  or other
unilateral  takeover  proposals to negotiate with our board of directors  rather
than  pursue   non-negotiated   takeover  attempts.   These  provisions  include
authorized   "blank   check"   preferred   stock,   restrictions,   under   some
circumstances, on business combinations with stockholders who own 10% or more of
our common stock and restrictions,  under some circumstances, on a stockholder's
ability to vote the shares of our common stock it owns when it crosses specified
thresholds of ownership.  Our ability to issue preferred stock may also delay or
prevent a change in control of Magnum Hunter without further  stockholder action
and may adversely affect the rights and powers,  including voting rights, of the
holders of common  stock.  Under some  circumstances,  the issuance of preferred
stock could depress the market price of our common stock.

     In addition,  in January 1998, our Board of Directors adopted a stockholder
rights plan. Under the stockholder  rights plan, the rights initially  represent
the  right to  purchase  one  one-hundredth  of a share of 1998  Series A Junior
Participating   Preferred  Stock  for  $35.00  per  share.   The  rights  become
exercisable only if a person or a group acquires or commences a tender offer for
15% or more of our common stock, a so-called "acquiring person." The stockholder
rights plan was amended so that Natural Gas Partners V, L.P., one of the Selling
Stockholders,  would not be considered  an  "acquiring  person" by reason of the
merger with Prize.  Until these rights  become  exercisable,  they attach to and
trade with our common stock. The rights issued under the stockholder rights plan
expire January 20, 2008.

     In addition,  a change of control, as defined under the indentures relating
to our senior notes, would entitle the holders of those notes to put those notes
to us under the indentures  and would entitle the lenders to accelerate  payment
of outstanding  indebtedness under our new credit facility. Both of these events
could  discourage  takeover  attempts by making such attempts more expensive and
requiring greater capital resources.

                                       21

<PAGE>

Item 2. Description of Properties

Oil and Gas Reserves

General

     All  information  set forth in this Form 10-K  regarding  estimated  Proved
reserves, related estimated future net cash flows and PV-10 of the Company's oil
and gas interests is taken from reports prepared by:

     (a)  DeGolyer  and  MacNaughton  of Dallas,  Texas and Cawley  Gillespie  &
Associates, Inc. of Fort Worth, Texas, both independent petroleum engineers with
respect to the  Company's  interests  at  December  31,  2001 (using oil and gas
prices in effect at December 31, 2001),

     (b) Ryder Scott Company of Houston,  Texas,  DeGolyer and  MacNaughton  and
Cawley Gillespie & Associates,  Inc., all independent  petroleum  engineers with
respect to the  Company's  interests  at  December  31,  2000 (using oil and gas
prices in effect at December 31, 2000), and

     (c) Ryder Scott  Company and Pollard,  Gore and Harrison of Austin,  Texas,
both independent  petroleum engineers with respect to the Company's interests at
December 31, 1999 (using oil and gas prices in effect at December 31, 1999).

     The  estimates of these  independent  petroleum  engineers  were based upon
their review of production histories and other geological,  economic,  ownership
and engineering data provided by the Company.

     PV-10 is the present value of Proved  reserves  which is an estimate of the
discounted  future  net cash  flows  from each of the  Company's  properties  at
December 31, 2001,  or as otherwise  indicated.  Net cash flow is defined as net
revenues less, after deducting  production and ad valorem taxes,  future capital
costs and operating  expenses,  but before  deducting  federal income taxes. The
future net cash flows have been discounted at an annual rate of 10% to determine
their "present value." The present value is shown to indicate the effect of time
on the value of the revenue stream and should not be construed as being the fair
market value of the properties.  Estimates have been made using constant oil and
gas prices and  operating  costs,  as of  December  31,  2001,  or as  otherwise
indicated.

     The estimates of future net cash flows from Proved reserves and their PV-10
are made  using  oil and gas  sales  prices  in  effect  as of the dates of such
estimates  and are held  constant  throughout  the life of the  properties.  The
Company's  estimates  of Proved  reserves,  future net cash flows and PV-10 were
estimated  using the following  weighted  average  prices,  before  deduction of
production taxes:

                       Prices used in Reserve Reports at December 31,
                   -----------------------------------------------------
                          2001              2000              1999
                   -----------------------------------------------------
Gas (per Mcf)......       $2.53             $9.28             $2.25
Oil (per Bbl)......      $17.19            $25.59            $24.03

     All reserves are evaluated at contract  temperature  and pressure which can
affect the measurement of gas reserves.  Operating costs,  development costs and
certain production related and ad valorem taxes were deducted in arriving at the
estimated  future net cash flows.  No provision was made for income  taxes.  The
estimates   following  this  section  set  forth   reserves   considered  to  be
economically  recoverable under normal operating methods and existing conditions
at the prices and operating costs  prevailing at the dates indicated  above. The
estimates of the PV-10 from future net cash flows  differ from the  standardized
measure  of  discounted  future  net cash  flows  set  forth in the notes to the
Consolidated  Financial  Statements of the Company,  which is  calculated  after
provision  for  future  income  taxes.  There  can be no  assurance  that  these
estimates  are  accurate  predictions  of future net cash flows from oil and gas
reserves or their present value.

                                       22

<PAGE>

     Proved reserves are estimates of oil and gas to be recovered in the future.
Reservoir  engineering  is a  subjective  process  of  estimating  the  sizes of
underground  accumulations  of oil and gas that  cannot be  measured in an exact
way.  The  accuracy  of any  reserve  estimates  is a function of the quality of
available data and of engineering  and geological  interpretation  and judgment.
Reserve  reports of other  engineers  might  differ from the  reports  contained
herein.  Results of drilling,  testing, and production subsequent to the date of
the estimate may justify  revision of such estimate.  Future prices received for
the sale of oil and gas will likely be  different  from those used in  preparing
these reports.  The amounts and timing of future operating and development costs
may also  differ  from those  used.  Accordingly,  reserve  estimates  are often
different from the quantities of oil and gas that are ultimately recovered.

     Except for the effect of changes in oil and gas prices,  no major discovery
or other  favorable  or adverse  event is believed to have caused a  significant
change in these  estimates of the Company's  Proved  reserves since December 31,
2001.  No  estimates  of Proved  reserves  of oil and gas have been filed by the
Company  with,  or included  in any report to, any United  States  authority  or
agency  (other than the  Securities  and Exchange  Commission)  since January 1,
2001.

                                       23

<PAGE>

Company Reserves

     The following tables set forth the estimated Proved reserves of oil and gas
of the Company and the PV-10  thereof on an actual  basis at December  31, 2001,
2000 and 1999.

                Estimated Proved Oil and Natural Gas Reserves (a)

                                                  At December 31,
                                    --------------------------------------------
                                        2001            2000          1999
                                    --------------------------------------------
Net gas reserves (Mcf):
     Proved developed...............  188,413,106    179,697,015  184,954,732
     Proved undeveloped.............   60,066,682     53,511,550   45,044,794
                                    --------------------------------------------
       Total proved gas reserves....  248,479,788    233,208,565  229,999,526
                                    ============================================

Net oil reserves (Bbl):
    (including condensate and NGL)
     Proved developed...............   12,959,569     13,923,380   16,299,585
     Proved undeveloped.............    8,641,555      8,380,082    9,234,165
                                    --------------------------------------------

       Total proved oil reserves....   21,601,124     22,303,462   25,533,750
                                    ============================================

Total Proved Reserves (Mcfe)........  378,086,532    367,029,337  383,202,026
                                    ============================================

                     Estimated PV-10 of Proved Reserves (a)

                                                      At December 31,
                                 -----------------------------------------------
                                        2001              2000          1999
                                 -----------------------------------------------
Estimated PV-10 (b) :
 Proved developed.............  $  264,930,820   $  829,688,640   $  282,481,193
 Proved undeveloped ..........      46,939,305      269,843,116       87,609,991
                                 -----------------------------------------------
   Proved Reserves PV-10 (c)..  $  311,870,125   $1,099,526,756   $  370,091,184
                                 ===============================================

     ------------  (a) Based upon reserve  reports at December 31, 2001 prepared
by D&M and, Cawley Gillespie,  at December 31, 2000 prepared by Ryder Scott, D&M
and Cawley Gillespie and at December 31, 1999 prepared by Ryder Scott and PG&H.

     (b) PV-10 differs from the  standardized  measure of discounted  future net
cash flows set forth in the notes to the  Consolidated  Financial  Statements of
the Company, which is calculated after provision for future income taxes.

     (c) The standardized measure of discounted future net cash flows related to
proved oil and gas reserves at December 31, 2001,  2000 and 1999,  respectively,
were as follows: $305,693,000, $804,923,000 and $315,616,000.

                                       24

<PAGE>

       Significant Properties

     On December 31, 2001, 100% of the Company's Proved reserves on a Bcfe basis
were located in the Mid-  Continent  Area, the Permian Basin Region and the Gulf
of Mexico/Gulf  Coast. On such date, the Company's  properties  included working
interests in 3,241 gross (1,835 net) productive oil and gas wells.

     The  following  table sets forth  summary  information  with respect to the
Company's estimated Proved reserves of oil and gas at December 31, 2001.
<TABLE>
<CAPTION>
<S>                                    <C>              <C>          <C>           <C>             <C>
                                               PV-10 (a)                           Proved Reserves
                                     ------------------------------------------------------------------------------
                                                                                                    Natural Gas
                                           Amount         % of          Oil             Gas          Equivalent
                                       (in thousands)     Total        (Bbl)           (Mcf)           (Bcfe)
                                     -------------------------------------------- --------------- ---------------
Mid-Continent Area (b)...............       $    97,011    31%           5,147,280    109,556,265      140.44
Permian Basin Region (b).............           102,785    33%          12,635,526     77,907,306      153.72
Gulf Coast/Gulf of Mexico (b) .......           112,074    36%           3,818,318     61,016,217       83.93
                                     ------------------------------------------------------------------------------
       Total ........................       $   311,870   100%          21,601,124    248,479,788      378.09
                                     ------------------------------------------------------------------------------
</TABLE>

----------
     (a) PV-10 differs from the  standardized  measure of discounted  future net
cash flows set forth in the notes to the  Consolidated  Financial  Statements of
the Company,  which is calculated  after provision for future income taxes.

     (b) Based on reserve  reports at  December  31,  2001  prepared  by D&M and
Cawley Gillespie.

Oil and Gas Production, Prices and Costs

     The following table shows the  approximate  net production  attributable to
the  Company's  oil and gas  interests,  the average sales price and the average
production expense  attributable to the Company's oil and gas production for the
periods  indicated.  Production  and sales  information  relating to  properties
acquired  or  disposed  of is  reflected  in this  table only since or up to the
closing  date of  their  respective  acquisition  or sale  and  may  affect  the
comparability of the data between the periods presented.
<TABLE>
<CAPTION>
<S>                                                   <C>               <C>                <C>
                                                                  Year Ended December 31,
                                                          2001             2000              1999
                                                   --------------------------------------------------------
Oil and gas production:
  Oil (Mbbl)......................................              1,410           1,298             1,307
  Gas (MMcf)......................................             24,861          19,579            19,026
  Natural Gas Equivalents (MMcfe).................             33,322          27,368            26,868
Average sales price (a):
  Before Hedge Contracts:
     Oil (per Bbl)................................      $       23.64     $     28.91       $     17.55
     Gas (per Mcf)................................               3.82            4.08              2.16
     Natural Gas Equivalents (per Mcfe)...........               4.13            4.28              2.38
  After Hedge Contracts:
     Oil (per Bbl)................................      $       24.53     $     22.95       $     15.01
     Gas (per Mcf)................................               3.96            3.90              2.16
     Natural Gas Equivalents (per Mcfe)...........               3.99            3.88              2.26
Oil and gas production lifting costs (per Mcfe) ..      $        0.61     $     0 .60       $      0.57
Production taxes and other costs (per Mcfe) (b)...      $        0.39     $     0 .46       $      0.30

</TABLE>

----------
     (a) Before deduction of production taxes and net of hedging results.

     (b) Includes ad valorem taxes,  insurance,  bonds, company overhead and net
profits interest.

                                       25

<PAGE>

Drilling Activity

     The  following  table sets  forth the  results  of the  Company's  drilling
activities during the three fiscal years ended December 31, 2001, 2000 and 1999.

<TABLE>
<CAPTION>
<S>          <C>                  <C>         <C>                 <C>                <C>              <C>               <C>
                                               Gross Wells (a)                                     Net Wells (b)
    Year         Type of Well       Total      Producing (c)       Dry (d)            Total            Producing (c)    Dry (d)
    ----         ------------       -----      -------------       -------            -----            -------------    -------
    2001       Exploratory
                 Texas                2              1                1                 1.3                     1          0.3
                 Oklahoma             0              0                0                   0                     0            0
                 New Mexico           3              3                0                1.37                  1.37            0
                 Other               10              8                2                4.31                  3.68         0.71
               Development
                 Texas               64             64                0               13.48                 13.48            0
                 Oklahoma             3              2                1                0.89                  0.39          0.5
                 New Mexico          13             13                0                7.69                  7.69            0
                 Other                7              6                1                3.05                  2.80         0.25

    2000       Exploratory
                 Texas               13             12                1                2.82                  2.51         0.31
                 Oklahoma             1              1                0                0.25                  0.25            0
                 New Mexico           6              6                0                2.23                  2.23            0
                 Other               16             15                1                6.12                  5.63         0.50
               Development
                 Texas               47             47                0               23.10                 23.10            0
                 Oklahoma             1              1                0                0.50                  0.50            0
                 New Mexico           2              2                0                1.18                  1.18            0
                 Other                2              2                0                0.33                  0.33            0

    1999       Exploratory
                 Texas                6              5                1                2.77                  2.46         0.31
                 Oklahoma             1              1                0                0.18                  0.18            0
                 New Mexico           0              0                0                   0                     0            0
                 Other                7              5                2                2.38                  1.88         0.50
               Development
                 Texas               10             10                0                9.14                  9.14            0
                 Oklahoma             3              1                2                3.00                  1.00            2
                 New Mexico           3              3                0                2.34                  2.34            0
                 Other                1              1                0                0.25                  0.25            0
</TABLE>
----------

     (a) The  number  of gross  wells is the  total  number  of wells in which a
working  interest  is owned.  Fluid  injection  wells for  waterflood  and other
enhanced recovery projects are not included as gross wells.
     (b) The  number of net  wells is the sum of  fractional  working  interests
owned in gross wells expressed as whole numbers and fractions thereof.
     (c) A producing  well is an  exploratory  or  development  well found to be
capable of  producing  either  oil or gas in  sufficient  quantities  to justify
completion as an oil or gas well.
     (d) A dry  well  is an  exploratory  or  development  well  that  is  not a
producing well.

                                       26

<PAGE>

Oil and Gas Wells

     The  following  table sets forth the number of oil and natural gas wells in
which the Company had a working  interest at  December  31,  2001.  All of these
wells are located in the United States.

<TABLE>
<CAPTION>
                                                               Productive Wells
                                                            As of December 31, 2001
<S>                           <C>           <C>            <C>           <C>            <C>           <C>
                                            Gross (a)                                    Net (b)
Location                        Oil             Gas          Total           Oil            Gas           Total
--------                        ---             ---          -----           ---            ---           -----

Texas......................    1,487            736          2,223         597.30         526.43       1,123.73
Offshore Texas ............        0              4              4              0              1              1
Oklahoma...................      120            270            390         107.68         182.57         290.25
Mississippi................        1              0              1              1              0              1
New Mexico.................      201            353            554         132.53          17.34         149.87
Offshore Louisiana.........        0             44             44              0          20.72          20.72
Arkansas...................       25              0             25          15.23              0          15.23
                           --------------------------------------------------------------------------------------
         Total.............    1,834          1,407          3,241         853.75         981.30       1,835.05
</TABLE>

----------

       (a)   The number of gross wells is the total number of wells in which a
             working interest is owned. Well counts include wells with multiple
             completions.
       (b)   The number of net wells is the sum of fractional working interests
             owned in gross wells expressed as whole numbers and fractions
             thereof.

Oil and Gas Acreage

     The following  table  summarizes  the Company's  developed and  undeveloped
leasehold acreage at December 31, 2001.

<TABLE>
<CAPTION>
<S>                              <C>                    <C>              <C>                 <C>
                                               Developed                              Undeveloped
                                               ---------                              -----------
                                    Gross (a)             Net (b)          Gross (a)            Net (b)
                                    ---------             -------          ---------            -------
Offshore..................          174,044              71,816             240,346             112,328
Texas.....................          268,600             217,490              73,150              26,100
Oklahoma..................          102,500              73,496               6,600              19,259
Mississippi...............              528                 452                   0                   0
New Mexico................           56,517              44,800                   0                   0
Louisiana.................                0                   0               4,160               1,000
                          -------------------------------------------------------------------------------
      Total ..............          602,189             408,054             324,256             158,687
                          ===============================================================================
</TABLE>

----------

     (a) The  number  of gross  acres is the  total  number  of acres in which a
working interest is owned.

     (b) The  number of net  acres is the sum of  fractional  working  interests
owned in gross acres expressed as whole numbers and fractions thereof.

     Substantially  all  of  the  Company's   interests  are  leasehold  working
interests  or  overriding  royalty  interests  (as  opposed  to  mineral  or fee
interests)  under  standard  onshore oil and gas leases.  As is customary in the
industry, the

                                       27

<PAGE>

     Company  generally  acquires  oil and gas acreage  without any  warranty of
title except as to claims made by, through or under the transferor. Although the
Company has title  examined by a landman or title  attorney prior to acquisition
of mineral  acreage in those  cases in which the  economic  significance  of the
acreage  justifies  the cost,  there can be no  assurance  that  losses will not
result from title defects or from defects in the assignment of leasehold rights.
In certain  instances,  title  opinions may not be obtained if, in the Company's
judgment, it would be uneconomical or impractical to do so.

Item 3. Legal Proceedings.

     No legal  proceedings  are pending other than ordinary  routine  litigation
incidental to the Company's  business,  the outcome of which management believes
will not have a material adverse effect on the Company.

Item 4. Submission of Matters to a Vote of Security Holders.

     The Company had no matters  requiring a vote of security holders during the
fourth quarter of 2001.

                                     PART II

Item 5. Market for Common Equity and Related Stockholder Matters.

     Our common stock is listed on the American  Stock Exchange under the symbol
"MHR." The  following  table  shows the  quarterly  high and low sales price per
share and the average daily trading  volume for our common stock for the periods
indicated.

                                                               Average Daily
                                                               Trading Volume
                                    High          Low            (Shares)
2001
   First Quarter ..............    $ 13.90     $  10.11           128,456
   Second Quarter..............    $ 12.48     $   8.11           128,842
   Third Quarter ..............    $  9.69     $   7.70           108,418
   Fourth Quarter..............    $ 11.30     $   7.53           129,426
2000
   First Quarter ..............    $  4.06     $   2.56            34,688
   Second Quarter..............    $  6.63     $   3.38            45,703
   Third Quarter ..............    $  9.13     $   5.88            80,593
   Fourth Quarter .............    $ 10.81     $   6.50           106,183


     On April 10, 2002 the last  reported  sale price of our common stock on the
American  Stock Exchange was $7.59 per share.  As of April 11, 2002,  there were
3,279 record holders of Magnum Hunter common stock.

     The Company has not previously  paid any cash dividends on its Common Stock
and does not anticipate  paying dividends on its Common Stock in the foreseeable
future. It is the present intention of management to utilize all available funds
for the development and growth of the Company's business activities. The Company
may not pay any  dividends on Common Stock unless and until all dividend  rights
on  outstanding  Preferred  Stock have been  satisfied.  The Company's  existing
credit  facility  restricts  the  payment  of cash  dividends  on the  Company's
securities.

                                       28

<PAGE>

Item 6. Selected Financial Data

     The selected  historical  financial data sets forth our summary  historical
consolidated  financial  data as of and for the years ended  December  31, 2001,
2000, 1999, 1998 and 1997, which have been derived from the audited consolidated
financial  statements and notes thereto.  The selected historical financial data
is  qualified  in its  entirety  by,  and  should  be read in  conjunction  with
"Management's  Discussion  and  Analysis of Financial  Condition  and Results of
Operations"  and  the  financial  statements  and  the  notes  thereto  included
elsewhere  in  this  Form  10-K.  For  additional  information  relating  to our
operations, see "Business" and "Properties." Certain reclassifications have been
made to the selected historical financial data of the prior years, as well as to
certain quarterly financial data, to conform with the current presentation.  All
data is in thousands, except per share data.

<TABLE>
<CAPTION>
<S>                                                   <C>          <C>            <C>          <C>               <C>
                                                        1997           1998           1999          2000             2001
                                                      --------       --------      ---------      --------         ---------
Income Statement Data:
Total operating revenues..........................    $ 48,834       $ 51,400       $ 69,626       $127,510         $152,806
Total operating costs and expenses (a)............      38,833         94,414         54,514         77,181          104,755
                                                       -------       --------       --------       --------         --------

Operating profit (loss)...........................      10,001        (43,014)        15,112         50,329           48,051
Provision for impairment of investment (b)........         -              -              -              -             (7,123)
Income (loss) before extraordinary loss...........      (2,128)       (47,080)        (6,826)        22,260           13,820
Extraordinary loss from early extinguishment
  of debt, net of taxes ..........................      (1,384)             -              -              -             (304)
Net Income (loss) ................................      (3,512)       (47,080)        (6,826)        22,260           13,516
Dividends applicable to preferred shares (c)......        (875)          (875)        (4,509)        (9,708)             -
Income (loss) applicable to common shares.........    $ (4,387)      $(47,955)      $(11,335)      $ 12,552         $ 13,516
Income (loss) per common share before
 extraordinary item
   Basic (c)......................................    $  (0.21)      $  (2.27)      $  (0.57)      $   0.60         $   0.40
   Diluted (c)....................................    $  (0.21)      $  (2.27)      $  (0.57)      $   0.51         $   0.37
Income (loss) per common share after
 extraordinary item
   Basic (c)......................................    $  (0.30)      $  (2.27)      $  (0.57)      $   0.60         $   0.39
   Diluted (c)....................................    $  (0.30)      $  (2.27)      $  (0.57)      $   0.51         $   0.36

Other Data:
EBITDA (d)........................................    $ 22,740       $ 22,112       $ 37,538       $ 76,362         $ 92,333
Capital expenditures (e)..........................    $160,059       $ 70,187       $ 59,968       $ 64,311         $204,370
Cash flow from operations.........................    $  5,652       $ 13,688       $ 17,435       $ 49,466         $104,074
</TABLE>

--------

     (a) Includes in 1998 the non-cash  write-down of $42.745 million of oil and
gas properties in the full-cost  pool due to the ceiling test  limitation and in
2001 a provision for loss of $3.156 million related to the Enron bankruptcy.

     (b) Includes in 2001 a provision for $2.142  million for the  impairment of
available-for-sale  equity  securities  deemed by management to have suffered an
other than temporary  impairment.  The impairment was determined  using a quoted
market price at December 31, 2001 of $0.86 per share. The Company had previously
reported losses in accumulated other comprehensive  income of $507,000 ($466,000
net of income tax benefit)  through December 31, 2000. Also included in 2001 was
an impairment  provision of $4.981  million due to the bankruptcy of a privately
held company in which Magnum  Hunter owned a minority  interest and had invested
$4.528 million in equity securities and $453 thousand in secured loans.

     (c) Includes the effect in the year 2000 of the payment of $5.5 million fee
paid upon redemption of $25.0 million  (liquidation value) of the Company's 1999
Series A 8%  Convertible  preferred  stock.  The fee was  treated as a dividend,
reducing  income per common  share,  basic and  diluted,  by $0.26 per share and
$0.17 per share, respectively, for the year 2000.

     (d) EBITDA is defined as income  (loss)  before  income  taxes and minority
interest,  plus the sum of  depletion  and  depreciation,  provision  for  asset
impairment,  and  interest  expense.  EBITDA  is not a  measure  of cash flow as
determined by generally accepted accounting principles. The Company has included
information  concerning  EBITDA  because  EBITDA  is a measure  used by  certain
investors  in  determining  the  Company's  historical  ability to  service  its
indebtedness.  EBITDA  should not be considered  as an  alternative  to, or more
meaningful  than,  net income or cash flows as  determined  in  accordance  with
generally  accepted  accounting  principles  or as an indicator of the Company's
operating  performance  or  liquidity.  This  measure may not be  comparable  to
similarly titled measures reported by other companies.

                                       29

<PAGE>

     (e) Capital expenditures include cash expended for acquisitions plus normal
additions  to  oil  and  natural  gas   properties   and  other  fixed   assets.
Additionally,  the year  2000  amount  includes  the cost of  property  acquired
through the issuance of common stock with a fair market value of $3.481  million
on the acquisition date.

<TABLE>
<CAPTION>
<S>                                                  <C>            <C>           <C>            <C>           <C>
                                                       1997           1998           1999           2000          2001
                                                    -----------    -----------    -----------    -----------   -----------
Balance Sheet Data:
Property, plant and equipment, net.................   $ 221,259      $ 228,436      $ 265,195      $ 260,532      $ 419,837
Total assets.......................................     251,069        265,724        304,022        315,612        454,385
Total debt (a).....................................     161,543        231,020        234,806        191,139        288,583
Stockholders' equity...............................   $  72,152      $  19,697      $  51,552      $  93,416      $ 117,974

</TABLE>

-----------

     (a) Consists of current notes payable and long-term debt, including current
maturities of long-term debt, and excluding  production  payment  liabilities of
$743 thousand,  $633 thousand, $460 thousand, $359 thousand and $203 thousand as
of December 31, 1997,  1998, 1999, 2000 and 2001,  respectively.  As of December
31, 2000 and 1999,  $20.6 million and $41.8 million,  respectively,  of the debt
was non-recourse to the Company.

     The following table sets forth  unaudited  summary  financial  results on a
quarterly basis for the two most recent years.

<TABLE>
<CAPTION>
<S>                                                  <C>             <C>              <C>             <C>
                                                                                 2001
                                                   ----------------------------------------------------------------
                                                       First           Second           Third           Fourth
                                                   --------------  ---------------  --------------  ---------------
Revenues...........................................    $   50,754       $   39,930      $   33,571       $   28,551
Depreciation, depletion and amortization...........         7,415            9,686          12,218           14,680
Net Operating Profit (Loss)........................        26,030           15,233           7,911           (1,123)
Provision for impairment of investment (a).........             -                -               -           (7,123)
Net Income (Loss)..................................        14,028            6,275           1,971           (8,758)
Income (Loss) per common share, basic (b)..........    $     0.41       $     0.18      $     0.06       $    (0.25)
Income (Loss) per common share, diluted (b)........    $     0.37       $     0.17      $     0.05       $    (0.25)
</TABLE>

<TABLE>
<CAPTION>
<S>                                                  <C>             <C>              <C>             <C>

                                                                                 2000
                                                   ----------------------------------------------------------------
                                                       First           Second           Third           Fourth
                                                   --------------  ---------------  --------------  ---------------
Revenues...........................................    $   25,393       $   28,286      $   30,689       $   43,142
Depreciation, depletion and amortization...........         5,971            5,566           5,398            8,621
Net Operating Profit...............................         8,139           10,847          13,244           18,099
Net Income.........................................         1,580            3,528           4,874           12,278
Income per common share, basic (c).................    $     0.02       $     0.13      $     0.20       $     0.24
Income per common share, diluted (c)...............    $     0.02       $     0.12      $     0.15       $     0.19

</TABLE>

     (a) Includes in 2001 a provision for $2.142  million for the  impairment of
available-for-sale  equity  securities  deemed by management to have suffered an
other than temporary  impairment.  The Company had previously reported losses in
accumulated other  comprehensive  income of $507,000 ($466,000 net of income tax
benefit)  through  December 31, 2000.  Also  included in 2001 was an  impairment
provision of $4.981 million due to the bankruptcy of a privately held company in
which Magnum Hunter owned a minority interest and had invested $4.528 million in
equity securities and $453 thousand in secured loans.

                                       30

<PAGE>

     (b) Loss per common  share for the fourth  quarter of 2001 was the same for
basic and diluted due to the exclusion of warrants and options whose effect were
anti-dilutive.

     (c) Includes  the effect in the fourth  quarter of 2000 of the payment of a
$5.5 million fee paid upon redemption of $25 million  (liquidation value) of the
Company's 1999 Series A 8% Convertible preferred stock. The fee was treated as a
dividend, reducing income per common share, basic and diluted by $0.22 per share
and $0.15 per share, respectively, for the fourth quarter of 2000.

                                       31

<PAGE>

     Item 7.  Management  Discussion  and  Analysis of Financial  Condition  and
Results of Operations

Results of Operations

     The following  discussion and analysis  should be read in conjunction  with
the Company's  consolidated  financial  statements and the notes associated with
them contained elsewhere in this report. This discussion should not be construed
to imply that the results  discussed herein will  necessarily  continue into the
future or that any conclusion  reached herein will  necessarily be indicative of
actual operating results in the future. Such discussion represents only the best
present assessment by management of the Company.

     The Company's results of operations have been significantly affected by our
success in  acquiring  oil and gas  properties  and our  ability to  maintain or
increase oil and natural gas production  through  exploration  and  exploitation
activities.  Fluctuations in oil and gas prices have also significantly affected
the results of operations.

     On  December  31,  1998,  the Company  through its newly  formed 100% owned
subsidiary,  Bluebird,  acquired from Spirit Energy 76 ("Spirit 76") natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
in the total amount of $25 million.  The effective date of the  acquisition  was
December  31,  1998.  As part of the  capitalization  of  Bluebird,  the Company
contributed 1,840,271 units of TEL Offshore Trust. Bluebird, as an "unrestricted
subsidiary" as defined under certain credit  agreements,  is neither a guarantor
of the Company's 10% Senior Notes due 2007 nor can it be included in determining
compliance  with  certain   financial   covenants  under  the  Company's  credit
agreements.

     On June 8, 1999, the Company and Bluebird acquired oil and gas reserves and
related  assets from Vastar  including  interests in 476 wells, a gas processing
plant and two gas gathering systems located in the states of Texas, Oklahoma and
Arkansas  in the  total  amount  of $32.5  million.  The  effective  date of the
acquisition was April 1, 1999.

     On  December  1, 1999  Bluebird  acquired a 50%  ownership  interest in the
Madill gas processing plant and associated  gathering system located in Marshall
and Bryan counties,  Oklahoma in the total amount of $8.4 million. The effective
date of the acquisition was November 1, 1999.

     Effective  September  1,  2000 the  Company  acquired  a 5.5%  net  profits
interest in the Panoma production and gas gathering  facilities for $3.5 million
of the  Company's  restricted  common stock.  By acquiring  this  interest,  the
Company  lowered  its lease  operating  expense,  increased  oil field  services
income, and reduced a permanent burden on this property.

     Effective  April 1, 2000 the Company  exchanged  interests with another oil
and gas company in certain  onshore oil  producing  properties  for interests in
certain  offshore oil and gas producing  properties  and  production  facilities
located in the Gulf of Mexico in a tax free like-kind exchange.  The transaction
did not have a material  effect on reported  production in 2000, but the Company
gained significantly increased exposure in an offshore area of interest where it
continues to conduct active exploration and development activities.

     During  2000,  we  realized  proceeds  of  $43.8  million  from the sale of
non-core oil and gas and other properties,  of which approximately $11.6 million
was attributable to Bluebird.

     Effective  July 1, 2001, the Company  acquired  proved and unproved oil and
gas properties located in Southeast New Mexico totaling  approximately 41.8 Bcfe
of  reserves  for  $31.6  million,  net  of  purchase  price  adjustments.   The
transaction had an effective date of July 1, 2001.

     On December  18,  2001,  the Company  announced a merger with Prize  Energy
Corp.  (Prize),  an independent oil and gas development and production  company.
The merger was completed on March 15, 2002. The  transaction  has been accounted
for as a purchase of Prize by the Company in accordance  with the  provisions of
FAS 141. Under the terms of the merger,  the Company has  distributed 2.5 shares
of  common  stock  plus  $5.20 in cash for each  Prize  share  outstanding.  The
following  summary,  prepared  on a pro forma  basis,  presents  the  results of
operations for the years ended December 31, 2001 and 2000 as if the acquisitions
had  occurred  as of the  beginning  of the  respective  years.  The  pro  forma
information   includes  the  effects  of  adjustments   for  interest   expense,
depreciation, depletion and amortization, and income taxes:

                                       32

<PAGE>

<TABLE>
<CAPTION>
<S>                                                    <C>                      <C>

                                                                      (Unaudited)
                                                              2001                   2000
                                                       --------------------------------------------
                                                       (in thousands, except for per share amounts)
                                                       --------------------------------------------
Revenue..............................................    $      334,873            $    276,999
Total Operating Costs and Expenses...................          (224,138)               (172,320)
                                                        --------------------    -------------------
Operating Profit.....................................           110,735                 104,679
Interest Expense and Other...........................           (52,680)                (48,178)
                                                        --------------------    -------------------
Income before Tax....................................            58,055                  56,501
Provision for Income Tax.............................           (21,792)                (17,429)
Extraordinary loss from early extinguishment of debt.              (304)                      -
                                                        --------------------    -------------------
Net Income...........................................            35,959                  39,072
Dividends Applicable to Preferred Stock..............                 -                 (10,167)
                                                        --------------------    -------------------
Net Income Applicable to Common Stock................            35,959                  28,905
                                                        ====================    ===================
Net Income Per Common Share
   Basic.............................................    $         0.52            $       0.53
                                                        ====================    ===================
   Diluted...........................................    $         0.50            $       0.50
                                                        ====================    ===================

</TABLE>

     The following table sets forth certain  information with respect to our oil
and gas operations and our gas gathering, marketing and processing operations:

<TABLE>
<CAPTION>
<S>                                              <C>             <C>              <C>
                                                                Years Ended
                                                   2001            2000             1999
Oil and Gas Operations                          -----------------------------------------------
-----------------------------------------------
Production:
   Oil (MBbls).................................        1,410           1,298            1,307
   Gas (MMcf)..................................       24,861          19,579           19,026
   Oil and Gas (MMcfe).........................       33,322          27,368           26,868
   Equivalent Daily Rate (MMcfe/day)...........         91.3            74.8             73.6


Average Sale Prices (after hedging)
   Oil (per Bbl)...............................    $   24.53       $   22.95        $   15.01
   Gas (per Mcf)...............................         3.96            3.90             2.16
   Oil and Gas (per Mcfe)......................         3.99            3.88             2.26
Effect of hedging activities (per Mcfe)........         0.14           (0.41)           (0.12)
Lease Operating Expense (per Mcfe)
   Lifting costs...............................         0.61            0.60             0.57
   Production tax and other costs..............         0.39            0.46             0.30
Gross margin (per Mcfe)........................    $    2.99       $    2.82        $    1.39

Gas Gathering, Marketing and
   Processing Operations
-----------------------------------------------
Throughput Volumes (Mcf per day)
   Gathering...................................       16,139          16,639           18,536
   Processing..................................       13,257          16,506           21,510
Gross margin (in thousands)....................
   Gathering (per Mcf throughput)..............         0.04            0.18             0.14
   Processing (per Mcf throughput).............         0.27            0.50             0.16

</TABLE>

                                       33

<PAGE>

Period to Period Comparisons
For the Years Ended December 31, 2001 and 2000

     We reported  net income of $13.5  million for the year ended  December  31,
2001 as compared to net income of $22.3  million for the same period in 2000,  a
decrease of 39%. The 2001 period results  include a loss on Enron related assets
of $3.2 million, a provision for impairment of investments of $7.1 million,  and
an extraordinary loss from early extinguishment of debt of $304 thousand, net of
tax benefits,  from the  repurchase of $10.5 million of the Company's 10% Senior
Notes.  Total  operating  revenues  increased 20% to $152.8 million in 2001 from
$127.5  million in 2000 and  operating  profit  decreased 5% to $48.0 million in
2001 from $50.3 million in 2000. A 3% increase in the price received for oil and
gas sold (on a thousand cubic feet equivalent,  or Mcfe, basis), combined with a
22% increase in oil and gas production (on a million cubic feet  equivalent,  or
MMcfe,  basis)  in our  oil and  gas  exploration  and  production  segment  was
primarily   responsible   for  the   improvement   in  revenues,   while  higher
depreciation, depletion and amortization expense and the Enron related loss were
primarily  responsible for the increase in operating costs and expenses.  Income
applicable  to common  shares was $13.5  million in the 2001 period versus $12.6
million in the 2000 period,  an increase of 8%. Income per common  share-diluted
was $0.36 per share in the 2001 period compared to $0.51 per  share-diluted,  in
the 2000 period, a decrease of 29% due to a 13% increase in diluted shares.  The
effect of the extraordinary  loss in the 2001 period was $0.01 per share,  basic
and diluted. No dividends were recorded in the 2001 period due to the conversion
of  $25.0  million  (liquidation  value)  of our 1999  Series  A 8%  Convertible
preferred stock on January 1, 2001 into  approximately 4.8 million shares of our
common stock. We had previously  redeemed $25.0 million  (liquidation  value) of
the 1999 Series A 8% Convertible preferred stock in December,  2000 and Bluebird
acquired  100%  of our  $10.0  million  (liquidation  value)  in 1996  Series  A
Convertible preferred stock during 2000.

Oil and Gas Operations:

     For the year ended  December 31, 2001,  we reported oil  production  of 1.4
MMbbls (million barrels) and gas production of 24,861 MMcf (million cubic feet),
which represents an increase of 9% in oil and an increase of 27% in gas produced
from the  comparable  period in 2000.  Our  reported  equivalent  daily  rate of
production  on a million cubic feet per day basis  (MMcfe/day)  increased 22% to
91.3 MMcfe/day in the 2001 period from 74.8 Mmcfe/day in the 2000 period.  These
increases  were  primarily  the result of the  success of our  drilling  program
offsetting normal production declines.

     Prices  realized in the 2001 period  averaged  $24.53 per barrel of oil and
$3.96 per Mcf of gas. This  represents a 3% increase on a thousand cubic feet of
gas  equivalent  (Mcfe) basis over the 2000 period  average  realized  prices of
$22.95  per  barrel of oil and $3.90 per Mcf of gas.  The unit  prices  realized
include the effects of hedging.  During the 2001 period,  hedging  increased the
average  price we received for oil by $0.89 per barrel and the average  price we
received for gas by $0.14 per Mcf. Excluding the effects of hedging,  oil prices
declined 18% and natural gas prices  declined 6% in 2001 from those  received in
2000.

     As a result of higher realized prices and higher production levels, oil and
gas  revenues  increased  25% to $133.0  million in the 2001 period  compared to
$106.1 million in the 2000 period.

     For the 2001 period,  oil and gas production  lifting  costs,  on a unit of
production  basis, were $0.61 per Mcfe as compared to $0.60 per Mcfe in the 2000
period, an increase of 2%. Production tax and other costs were $0.39 per Mcfe in
the 2001 period compared to $0.46 per Mcfe in the 2000 period, a decline of 15%,
principally due to lower production  taxes.  Lower production taxes are a result
of lower oil and gas prices before the effect of hedge  transactions  and higher
production levels in the Gulf of Mexico on which no production taxes are levied.

     Gross  margin  for oil and gas  operations  for the 2001  period  was $99.7
million,  or $2.99 per Mcfe, compared to $77.1 million, or $2.82 per Mcfe in the
2000 period, an increase of 6% on a per unit of production basis, primarily as a
result of higher oil and gas prices  realized and the increase in our daily unit
production rate.

                                       34

<PAGE>

Gathering, Marketing and Processing Operations:

     For the year ended December 31, 2001, our gathering systems  throughput was
16.1  MMcf per day  versus  16.6  MMcf per day for the same  period  in 2000,  a
decline  of 3% due  to  normal  production  declines  behind  the  systems.  Gas
processing  throughput was 13.3 MMcf per day in 2001 versus 16.5 MMcf per day in
2000, a decrease of 20%. Our reported  processing  throughput in the 2001 period
was reduced due to (i) the sale in  September  2000 of a  substantial  ownership
interest  in oil  and gas  properties  supplying  one of our  plants,  (ii)  the
voluntary  shutdown of two gas processing  plants for approximately 1 1/2 months
of the 2001  period  due to  adverse  processing  economics  as a result of high
natural gas prices and (iii) normal production declines on properties  supplying
the plants.

     Revenues from  gathering,  marketing and processing  decreased 11% to $17.9
million in 2001  versus  $20.0  million in 2000,  primarily  due to a decline in
natural gas liquids prices and a decrease in throughput. Operating costs for the
gathering,  marketing and  processing  segment  increased 3% to $16.1 million in
2001 from $15.7 million in 2000.

     The gross margin realized from gathering, marketing and processing for 2001
was $1.8  million  versus $4.3  million in 2000,  a decrease  of 59%.  Gathering
margin was $0.04 per Mcf  gathered in 2001 versus $0.18 per Mcf in 2000 due to a
decrease  in  marketing  spreads  and  losses  incurred  on  pipeline  imbalance
positions. Processing margin was $0.27 per Mcf in 2001 compared to $0.50 per Mcf
in 2000 due to less  favorable  processing  economics  because of the decline in
natural  gas  liquids  prices  and the  temporary  shutdown  of two plants for a
portion of the 2001 period.

Oil Field Management Services Operations:

     Revenues from oil field  management  services were $1.8 million in the 2001
period  versus  $1.4  million in the 2000  period due to higher  management  and
operations  services  fees  charged  to third  parties,  primarily  on  offshore
operations. Operating costs increased to $1.3 million in 2001 from $903 thousand
in 2000 due to higher  costs for labor and  overhead.  The gross margin for this
segment in 2001 was $551  thousand  versus $545 thousand in 2000, an increase of
1%.

Other Income and Expenses:

     Depreciation  and  depletion  expense was $44.0  million in the 2001 period
versus  $25.6  million  in the 2000  period,  an  increase  of 72% due to higher
production  levels and higher unit costs.  Depreciation and depletion on oil and
gas  properties  was $1.28 per Mcfe in 2001 versus $0.89 per Mcfe in 2000.  This
44%  increase in the  equivalent  unit cost was due  primarily to an increase in
development costs associated with our exploration efforts in the Gulf of Mexico.

     General and  administrative  expense for 2001 increased 13% to $6.9 million
from $6.1 million in 2000. The principal  cause of this increase was an increase
in  salary,  benefits  and  retirement  plan  expenses  and an  increase  in the
Company's  overall headcount  associated with its increased  activity level. The
number of  personnel  employed by the Company at fiscal  year-end  2000 and 2001
were 95 and 105,  respectively.  We recorded  equity in earnings of affiliate of
$1.1 million in 2001 versus income of $1.3 million in 2000, a 17% decrease,  due
to decreased  net earnings  from gas  marketing  operations of the Company's 30%
owned affiliate. Other income was $283 thousand for 2001 versus $477 thousand in
2000, a 41% decrease, due to a reduction in interest income.

     We made  provision  for a $3.2 million loss on assets  associated  with the
Enron Corp. bankruptcy in the 2001 period. Of the total loss provision recorded,
approximately  $2.5  million was related to  accounts  receivable  for Enron for
physical gas sales and  approximately  $701 thousand was related to a receivable
from a natural gas commodity hedge in which Enron was the counterparty.

                                       35

<PAGE>

     The Company  had equity and debt  investments  in a  privately  held entity
which  declared  bankruptcy  subsequent to December 31, 2001,  and for which the
Company  provided an  impairment  charge  against  earnings  of $5.0  million at
December   31,   2001.   Additionally,   the  Company  had  an   investment   in
available-for-sale  securities of another entity of $2.8 million at December 31,
2001.  Because of the  deteriorating  financial  condition of this  entity,  the
Company reported an other than temporary  impairment of $2.1 million as a charge
against  earnings at December 31, 2001,  based on the entity's  reported  market
value on that date.

     Interest  expense was $19.9 million for 2001 versus $22.3 million for 2000,
a decrease of 11%.  During the 2001 period,  the interest  rate on our primarily
LIBOR-based  bank  debt was 6.3%  versus  9.1% in 2000,  a decline  of 31%.  The
weighted  average daily  balance of bank debt  increased 17% to $93.3 million in
2001 from $79.7  million in 2000.  We also  benefitted in the 2001 period by the
repurchase of $10.5 million of our 10% Senior Notes in June,  2001. In addition,
interest  expense was reduced in the 2001 period by $744 thousand as a result of
interest rate derivatives versus an increase in interest expense of $13 thousand
from interest rate derivatives in the 2000 period.

     We recorded a total  provision  for income tax  expense of $8.6  million in
2001 versus $7.6 million in 2000,  an increase of 14%. We made no  adjustment to
the valuation  allowance charged against deferred tax assets in the 2001 period,
whereas  the  2000  period  benefitted  from a  $3.9  million  reduction  in the
valuation allowance charged against deferred tax assets.

     There were no dividends  applicable to preferred  stock in 2001 as compared
to $9.7 million for the 2000 period.  The elimination of the dividend was due to
the purchase,  redemption  and  conversion  of all of the Company's  outstanding
dividend paying preferred stock not controlled by wholly-owned entities.

For the Years Ended December 31, 2000 and 1999

     We reported  record net income of $22.3 million for the year ended December
31,  2000 versus a net loss of $6.8  million for the same period in 1999.  Total
operating  revenues  increased  83%  to  $127.5  million  and  operating  profit
increased  233% to $50.3  million in 2000. A 72% increase in the price  received
for oil and gas sold (on a thousand  cubic  feet  equivalent,  or Mcfe,  basis),
combined with a 2% increase in oil and gas  production  (on a million cubic feet
equivalent,  or MMcfe,  basis)  in our oil and gas  exploration  and  production
segment  was  primarily   responsible  for  these  results.   We  also  reported
significant  increases  in revenues  and gross  operating  margins  from our gas
gathering,  marketing and  processing  and oil field  services  segments in 2000
compared to 1999 due to improved product prices and processing  economics and an
increase in customers  for whom we are  providing  operations  services.  Income
applicable to common  shares was $12.6 million in 2000 versus a loss  applicable
to common shares of $11.3  million in 1999.  Income per common share - basic was
$0.60 per share and  income per  common  share - diluted  was $0.51 per share in
2000 compared to a loss  applicable  to common  shares of $0.57 per share,  both
basic and diluted,  in 1999.  Income per share in 2000  includes the effect of a
$5.5  million   non-recurring   fee  paid  upon   redemption  of  $25.0  million
(liquidation value) of our 1999 Series A 8% Convertible preferred stock. The fee
was treated as a dividend,  which  reduced  income per common  share,  basic and
diluted,  by $0.26 per share and  $0.17 per  share,  respectively,  for the year
2000.

Oil and Gas Operations:

     For the year 2000,  we reported  oil  production  of 1,298 Mbbls  (thousand
barrels)  and  gas  production  of  19,579  MMcf  (million  cubic  feet),  which
represents  a decline of 1% in oil and an  increase of 3% in gas  produced  from
1999. Our reported  equivalent  daily rate of production on a million cubic feet
per day basis  (MMcfe/day)  increased 2% to 74.8 MMcfe/day in 2000. The reported
production  in 2000 was  impacted  by the sale of certain  non-core  oil and gas
properties  which  took  effect  in  June  and  September  2000.  Excluding  the
production of these properties from both periods,  our underlying oil production
increased 13% and our underlying  gas production  increased 11% in 2000 compared
to 1999,with the underlying  equivalent daily rate of production  increasing 11%
to 68.5 MMcfe/day .

                                       36

<PAGE>

     These  increases  were the  result  of a full year of  production  from the
properties acquired from Vastar being included in 2000 as well as the success of
our drilling program offsetting normal production declines.

     The  increase  in oil  and  gas  prices  was the  most  significant  factor
affecting the increase in net income in 2000.  Prices  realized in 2000 averaged
$22.95  per  barrel  of oil and  $3.90  per Mcf of gas.  This  represents  a 72%
increase  on a thousand  cubic  feet of gas  equivalent  (Mcfe)  basis over 1999
average  realized  prices of $15.01  per barrel of oil and $2.16 per Mcf of gas.
The unit prices realized include the effects of commodity hedging.

     From time to time,  we enter into various  commodity  hedging  contracts in
order to reduce our exposure to the possibility of declining oil and gas prices.
During 2000,  commodity hedging reduced the average price we received for oil by
$5.96 per barrel and for gas by $0.18 per Mcf. During 2000, we had approximately
19% of our  natural  gas  production  and  73% of  our  oil  production  hedged.
Beginning  January 1, 2000 we had  approximately 14% of our expected natural gas
production  hedged for 2001 at a weighted average price using cost-less  collars
of $4.50 to $6.15 per Mcf and we had approximately 45% of our expected crude oil
production  for the first six months of 2001 hedged at a weighted  average price
using cost-less collars of $25.00 to $34.73 per barrel.

     Primarily  as a result  of higher  realized  prices,  oil and gas  revenues
increased 75% to $106.1 million in 2000 compared to $60.7 million in 1999.

     Lease  operating  expenses  consist of two  components,  lifting  costs and
production tax and other costs. For 2000, lifting costs, on a unit of production
basis, were $0.60 per Mcfe as compared to $0.57 per Mcfe in 1999, an increase of
5%.  This  increase in lifting  costs per unit was due to a general  increase in
costs of labor, materials and field services stimulated by higher prices for oil
and  natural  gas.  Production  tax and other  costs were $0.46 per Mcfe in 2000
compared to $0.30 per Mcfe in 1999, an increase of 53%. This was principally due
to an increase of $0.10 per Mcfe in  production  taxes,  which are a function of
higher oil and gas prices,  and an increase in company  overhead  charged to oil
and gas operations of $0.04 per Mcfe due principally to higher labor and benefit
costs.

     Our gross  margin for oil and gas  operations  (oil and gas  revenues  less
lease  operating  expenses)  for 2000 was  $77.1  million,  or $2.82  per  Mcfe,
compared to $37.1  million,  or $1.39 per Mcfe in 1999, an increase of 102% on a
per unit of  production  basis,  primarily  as a result  of  higher  oil and gas
prices.

Gathering, Marketing and Processing Operations:

     For 2000, our gathering system throughput was 16.6 MMcf per day versus 18.5
MMcf per day in 1999, a decline of 10% due to the sale of a gathering  system in
June 1999 and to normal  production  declines behind the system.  Gas processing
throughput  was 16.5 MMcf per day in 2000  versus  21.5 MMcf per day in 1999,  a
decrease of 23%. During  December 1999, we completed  recoupment of our original
investment  in the  McLean  gas  processing  plant.  As a  result,  our share of
operating income and plant  throughput  reverted to 50% from the 100% applicable
during the recoupment period.  The decline in reported  throughput at McLean was
partially  offset  by  our  acquisition  of a 50%  interest  in the  Madill  gas
processing  plant in December  1999.  Also,  our reported  throughput at another
plant was reduced  beginning June 2000 due to the sale of an interest in oil and
gas properties supplying the plant.

     Revenues from gathering,  marketing and processing  increased 144% to $20.0
million in 2000 versus $8.2 million in 1999. Of this increase,  $8.4 million was
due to the  acquisition  of the Madill plant.  Also,  we received  significantly
higher prices for natural gas and plant  products sold in 2000 compared to 1999.
Natural  gas prices  increased  85% while the price  received  for  natural  gas
liquids  increased  62%.  The effect of price  increases  was seen at the McLean
plant,  where our  revenues  declined  only 14%  despite  the 50% decline in our
operating interest due to reversion.

     Operating  costs  for  the  gathering,  marketing  and  processing  segment
increased 166% to $15.7 million in 2000 from $5.9 million in 1999. A substantial
portion of this increase was due to the acquisition of the Madill plant. Our

                                       37

<PAGE>

     net  share of costs at the  McLean  plant  declined  only 19%  despite  the
reversion to a 50% operating interest due to higher natural gas prices affecting
the cost of plant  throughput.  Higher natural gas prices also affected the cost
of gas marketed.

     The gross margin realized from gathering, marketing and processing for 2000
was $4.3  million  versus $2.3  million in 1999,  an increase of 87%.  Gathering
margin  was $0.18 per Mcf in 2000  versus  $0.14 in 1999 due to an  increase  in
marketing spreads. Processing margin was $0.50 per Mcf in 2000 compared to $0.16
per Mcf in 1999 due to higher  prices for plant  products and better  processing
economics.

Oil Field Services Operations:

     Revenues  from oil field  services  were $1.4  million in 2000  versus $768
thousand in 1999 due to an increase in customers for whom we provided operations
services.  Operating costs increased to $903 thousand in 2000 from $350 thousand
in 1999 due to higher  costs for labor and  overhead.  The gross margin for this
segment in 2000 was $545  thousand  versus $418 thousand in 1999, an increase of
30%.

Other Income and Expenses:

     Depreciation  and depletion  expense was $25.6 million in 2000 versus $22.1
million in 1999.  Depreciation and depletion on oil and gas properties was $0.89
per  Mcfe in 2000  versus  $0.79  per Mcfe in 1999.  This  13%  increase  in the
equivalent unit cost was due to an increase in development costs associated with
our  exploration  efforts in the Gulf of Mexico.  Depreciation  expense  for the
gathering,  marketing and processing  segment increased by $230 thousand in 2000
due to the Madill plant acquisition.

     For 2000, we recorded a gain on sale of $28 thousand  versus a gain on sale
of $272 thousand in 1999.  The gain on sale in both periods  relates to the sale
of property other than oil and gas properties. Since we use the full cost method
of  accounting  for oil and gas  properties,  proceeds  from  the  sale of those
properties  are applied to the full cost pool and no gain or loss is recognized.
General and administrative  expense for 2000 increased 110% to $6.1 million from
$2.9 million in 1999.  The  principal  cause of this increase was a $3.1 million
increase in salary,  benefits and retirement plan expenses as a result of higher
headcount,   year-end  incentive  bonuses,   and  ESOP  expense  resulting  from
appreciation  in the Company's  stock price.  The  difference  between the stock
value on the  contribution  date and the  stock  value  when  purchased  must be
expensed at the date the contribution is made to the ESOP. We recorded equity in
earnings of affiliate of $1.3 million in 2000 versus a loss of $103  thousand in
1999.  This  increase  was due to  increased  net  earnings  from gas  marketing
operations of the affiliate. Other income was $477 thousand for 2000 versus $354
thousand in 1999. The increase was caused by an increase in interest income.

     Interest  expense was $22.3 million for 2000 versus $22.1 million for 1999.
During  most of 2000,  the  interest  rate on our  LIBOR-based  bank debt and an
interest  rate swap were higher  than in 1999.  This was offset by a decrease in
outstanding  LIBOR-based  bank debt in the latter  part of 2000 due to  reducing
debt from cash raised from the sale of non-core oil and gas  properties  and the
exercise of warrants and options for our common stock.

     We recorded a total  provision  for income tax  expense of $7.6  million in
2000  versus  none in 1999.  The year 2000  provision  included a $234  thousand
current provision due to alternative minimum tax regulations.  The provision for
deferred income tax expense of $7.3 million in 2000 reflects a reduction of $3.9
million in the valuation  allowance  charged  against our deferred tax asset. We
made this reduction in the valuation  allowance in 2000 after  consideration  of
current production levels,  current expectations regarding near-term oil and gas
prices,  current commodity hedging positions,  anticipated capital expenditures,
the  estimated  reversal  of  book  and  tax  temporary  differences,  available
tax-planning  strategies and expectations  regarding future taxable income.  The
valuation  allowance  reduces the  deferred  tax asset to an amount that is more
likely than not to be realized  based on the factors  previously  discussed.  No
income tax benefit was provided in 1999 because of  uncertainty  at that time in
our ability to realize  additional  tax benefits on our net operating  losses in
the future.

                                       38

<PAGE>

     Dividends  applicable to preferred  stock were $9.7 million for 2000 versus
$4.5 million in 1999.  The dividends in 2000  included the $5.5 million  premium
(non-recurring) on redemption of $25.0 million  (liquidation  value) of our 1999
Series A 8% Convertible preferred stock.

Liquidity and Capital Resources

     CASH FLOW AND WORKING  CAPITAL.  Net cash provided by operating  activities
during 2001, 2000 and 1999 was $104.1 million,  $49.5 million and $17.4 million,
respectively.  The substantial increase in our operating cash flows in 2001 over
2000 and 2000 over 1999 is  primarily  the result of higher net realized oil and
gas prices and higher production levels. In the 2001 period compared to the 2000
period,  a  reduction  in trade  accounts  receivable  and an  increase in trade
accounts payable balances also contributed to increased operating cash flows.

     Our net working  capital  position  at  December  31, 2001 was a deficit of
$23.6 million. On that date, we had available $5.0 million under our senior bank
credit  facility.  Several items  contributed to the deficit in working capital,
including a delay in obtaining $11.2 million of sale and leaseback  financing of
offshore  production  platforms  until  January  2002,  the $3.2 million loss we
sustained  as a  result  of  the  Enron  bankruptcy,  and  the  postponement  of
negotiations for the expected $5.4 million sale of certain assets, also a result
of uncertainty in the  marketplace  caused by Enron.  We also cancelled plans to
sell an interest in a recent Gulf of Mexico discovery for $10 million because of
falling  oil and gas prices in the fourth  quarter  of 2001 and  general  market
uncertainties.  Subsequent  to  December  31,  2001,  several  actions  taken by
management  eliminated  this deficit in working  capital.  See "Magnum  Hunter's
Liquidity and Capital  Resources"  later in this  discussion for a more complete
description of these actions.

     INVESTING  ACTIVITIES.  Net cash used in  investing  activities  was $204.0
million in the 2001  period.  We made  capital  expenditures  of $204.4  million
during 2001. Our capital  expenditures are discussed in further detail below. We
received a distribution  of $1.6 million from NGTS, LLC, a 30% owned natural gas
marketing affiliate which we account for under the equity method.  Additionally,
we made an  investment  in  another  10% owned  company  of $2.5  million.  This
affiliate  is  accounted  for as an  investment.  We  realized  proceeds of $1.1
million from sale of assets,  received  payments on promissory  notes receivable
totaling $70 thousand and had a decrease in deposits of $50 thousand  during the
2001 period.

     In the 2000  period,  net  cash  used in  investing  activities  was  $20.0
million,  which  included  proceeds from asset sales of $43.8  million,  capital
expenditures  of $60.8  million,  a loan made for $1.4 million,  repayments on a
loan of $1.0 million and investment in unconsolidated affiliate of $2.6 million.

     In 1999, net cash used in investing  activities  was $58.5  million,  which
included  proceeds from asset sales of $1.5 million and capital  expenditures of
$60.0 million.

     FINANCING ACTIVITIES.  Net cash provided by financing activities was $102.7
million in 2001. We borrowed  $262.5  million under our senior bank credit lines
and $4.0 million through vendor provided financing for offshore construction. We
repaid  borrowings  under our senior bank credit lines by $158.6  million,  made
payments of $180 thousand on production  payment and other loans and repurchased
$10.5  million  principal  value of our 10% Senior  Notes on the open market for
$10.8  million.  We received  $5.8  million in cash from the  issuance of common
stock.  Cash  dividends paid were $169 thousand in 2001. Due to the repayment of
Bluebird's  bank debt,  its cash is no longer  restricted,  which  provided $1.8
million in cash. We paid $956 thousand for fees related to financing activities,
made a loan to stockholder of $300 thousand,  received  repayment of stockholder
loans of $360  thousand,  made a loan to the ESOP of $898  thousand,  received a
loan repayment from the ESOP of $1.1 million,  and purchased  treasury stock for
$1.0  million.  With  respect to the ESOP,  and as required  under  Statement of
Position  93-6  "Employers'  Accounting  for Employee  Stock  Ownership  Plans,"
compensation  expense  is  recorded  for  shares  committed  to be  released  to
employees based on the fair market value of those shares when they are committed
to be

                                       39

<PAGE>

     released.  The  difference  between  cost and the fair market  value of the
committed  to be  released  shares is recorded  in  additional  paid-in-capital.
Unreleased shares held by the ESOP are excluded from the calculation of earnings
per share.

     In the 2000  period,  net  cash  used in  financing  activities  was  $31.0
million.  We  borrowed a total of $101.1  million  under our senior  bank credit
lines of which $11.5 million was attributable to Bluebird.  We repaid borrowings
under our senior bank credit lines by $144.8 million, of which $32.7 million was
attributable to Bluebird. We received $60.0 million in cash from the issuance of
common and preferred stock, net of offering costs. We paid $534 thousand of fees
related  to  financing  activities.  We spent  $25.0  million to redeem our 1999
Series A preferred  stock,  while  Bluebird  also spent $10.5 million to acquire
Magnum Hunter preferred and common stock. Cash dividends paid were $10.2 million
in 2000. We loaned the ESOP $1.6 million to purchase our common stock.  Bluebird
had a net decrease in cash of $325 thousand.

     In 1999, net cash provided by financing  activities  was $37.7 million.  We
borrowed a total of $106.8 million under our senior bank credit lines,  of which
$46.3  million was  attributable  to Bluebird.  We repaid  borrowings  under our
senior  bank  credit  lines by  $103.2  million,  of  which  $30.5  million  was
attributable  to  Bluebird.  We realized  proceeds  from  issuance of common and
preferred  stock of $46.3  million,  net of  offering  costs.  We also paid fees
related to financing  activities of $1.6  million,  paid a short term note of $2
million,  loaned the ESOP $759  thousand,  loaned a shareholder  $123  thousand,
purchased  treasury stock for $1.7 million and paid preferred  dividends of $4.2
million. Bluebird had a net increase in cash of $1.7 million.

     BLUEBIRD'S  CAPITAL  RESOURCES.  On May 17, 2001,  Bluebird sold all of its
proved and unproved oil and gas  properties,  except for its  investment  in Tel
Offshore  Trust,  and all of its  pipelines  and other fixed  asset  property to
Magnum Hunter Production, Inc., for $17.7 million in cash and $10 million of our
1996 Series A Convertible  preferred stock.  Bluebird used the cash to repay and
retire  its $17.7  million  of debt  under its  senior  bank  credit  line.  The
effective date of the sale was May 1, 2001. On June 25, 2001, Bluebird purchased
$4.7 million face value of Magnum Hunter Resources, Inc. 10% Senior Notes on the
open market.  Bluebird  remains an unrestricted  subsidiary  under the Company's
senior bank credit  agreement.  At December  31,  2001,  Bluebird had no capital
spending  plans  or  commitments  and no  remaining  debt  or  interest  payment
requirements.

     MAGNUM HUNTER'S LIQUIDITY AND CAPITAL RESOURCES.  The following  discussion
of Magnum Hunter's  capital  resources  refers to the Company and its affiliates
other than Bluebird,  whose capital  resources were discussed  separately above.
Internally  generated cash flow and the borrowing capacity under its senior bank
credit line are the Company's major sources of liquidity. From time to time, the
Company may also sell oil and gas properties in order to increase liquidity.  In
addition,  the Company may use other sources of capital,  including the issuance
of  additional  debt  securities  or  equity  securities,  as  sources  to  fund
acquisitions or other specific needs. In the past, the Company has accessed both
public and private capital markets to provide liquidity for specific  activities
and general corporate purposes.

     In December  2000,  the Company used $10.0 million in cash to purchase 100%
of its 1996 Series A Convertible preferred stock outstanding from Bluebird. This
preferred stock was held by another 100% owned  affiliate for possible  re-issue
at a later  date.  Also in  December  2000,  the  Company  spent  $30.5  million
(including a $5.5 million  redemption  premium) to redeem 50% of its outstanding
1999 Series A 8% Convertible preferred stock. In January, 2001 the remaining 50%
of this  preferred  stock was  converted by the holder to the  Company's  common
stock at the conversion  price of $5.25 per share. As a result of the redemption
of its 1999 Series A 8%  Convertible  preferred  stock,  the Company  saved $4.0
million in annual dividend payments. In May 2001, the Company reissued the $10.0
million  of its 1996  Series  A  Convertible  preferred  stock  to  Bluebird  in
connection  with the  acquisition  of  Bluebird's  oil and gas  properties.  The
Company  will make  dividend  payments of $875  thousand  annually to  Bluebird,
however, such payments are eliminated under consolidated financial reporting.

                                       40

<PAGE>

     On May 17,  2001,  the  Company  closed on a new $225  million  Senior Bank
Credit Facility, of which $160 million was available under the borrowing base at
December  31,  2001.  The credit  agreement  provides for both "LIBOR" and "Base
Rate" (Prime) interest rate options.  This new credit facility  consolidated and
replaced  both the Company's  and  Bluebird's  previous  credit  facilities.  At
December  31,  2001,  borrowings  under this line were $155.0  million,  leaving
availability of $5.0 million on that date versus a deficit in working capital of
$27.4 million (excluding Bluebird). As described below, the Company entered into
several  courses  of action to  remedy  this  working  capital  shortfall.  On a
semiannual basis, the borrowing base is redetermined by the banks based on their
review of the  Company's oil and gas reserves.  If the  outstanding  senior bank
debt exceeds the redetermined borrowing base, the Company must repay the excess.

    On  December 5, 2001,  the Company  announced  that a  distribution  of one
warrant for every five shares of common stock owned on January 10,  2002.  These
warrants were  distributed on March 21, 2002.  Each new warrant will entitle the
holder to purchase one share of common  stock at $15.  The warrants  will expire
three years from the date of distribution.

     On January 15, 2002, the Company entered into a sale-leaseback  transaction
on  three  newly  constructed   offshore  production  platforms  and  associated
pipelines that were recently placed into service.  The Company  received a total
of $11.2  million in new funding which was used for general  corporate  purposes
including a voluntary  reduction  under the Company's  corporate  bank revolving
credit  facility.  The  production  platforms  are being leased from a syndicate
group  of  lenders  over a term  of  three  years  and at a  cost  of  funds  of
approximately 5.30% per annum, based on current interest rates. This transaction
will be accounted for as a capital lease.

     On March 15, 2002, the Company  amended and restated its Senior Bank Credit
Facility (the facility) in conjunction  with the merger with Prize.  The amended
facility  provides for total  borrowings of $500 million,  up from $225 million,
and raises the borrowing base limit from $160 million to $300 million.  On March
15, 2002,  the Company  borrowed  $185.6 million  against the facility,  leaving
$114.4  million of excess  credit line for working  capital and other  corporate
purposes.

     On March 15, 2002, the Company also  completed a private  placement of $300
million of Senior Notes (the  private  placement)  due 2012 that are  unsecured.
Interest  on the  Senior  Notes bear an annual  rate of 9.6% due  semi-annually,
commencing September 15, 2002.

     With the funds  provided by the new facility  and the private  placement of
Senior Notes, the Company repaid  indebtedness  under its old credit facility of
$155.7 million,  repaid debt under Prize's  previous credit  agreement of $246.8
million, funded the cash component of the merger consideration of $70.9 million,
and paid other fees and  expenses  related to the merger,  facility  and private
placement of  approximately  $12.2 million.  In connection  with the merger with
Prize,  the  Company  issued  34,062,963  shares  of its  common  stock to Prize
shareholders, increasing its total shares outstanding by 96%. Also in connection
with the merger with Prize, 11,811,073 Prize warrants remain outstanding and are
exercisable  at $9.12 for up to a total of  4,218,241  shares  of the  Company's
common stock.  These  warrants  expire in November 2002.  Additionally,  150,000
Prize warrants remain  outstanding and are exercisable at $6.38 for up to 53,573
shares of the Company's common stock. These warrants expire in June 2002.

     The Company's  internally  generated cash flow, results of operations,  and
financing for its operations are dependent on oil and gas prices.  To the extent
that oil and gas prices  decline,  the Company's  earnings and cash flows may be
adversely affected.

     CAPITAL  EXPENDITURES.  For the year ended December 31, 2001, the Company's
total  capital  expenditures  for  property,  plant and  equipment  were  $204.4
million.  The following  summarizes the Company's  capital  expenditures by cost
component (in millions):

                                       41

<PAGE>

<TABLE>
<CAPTION>
<S>                        <C>                <C>              <C>             <C>
                                 Oil & Gas Properties
                            ------------------------------       Other
                              Unproved          Proved          Property          Total
                            -------------    -------------    ------------    -------------
Acquisition Costs             $      12.2       $     36.1        $    1.3       $     49.6
Exploration Costs                     4.1             33.6               -             37.7
Development Costs                       -            117.1               -            117.1
                            -------------    -------------    ------------    -------------
Total                         $      16.3       $    186.8        $    1.3       $    204.4

</TABLE>

     Acquisition  costs  include $4.8 million for unproved and $26.8 million for
proved  reserves in the Mallon  acquisition and $5.8 million for the purchase of
additional  proved  reserves in South  Timbalier  block 264. As of December  31,
2001,  the  Company  had  total  unproved  oil and gas  property  costs of $18.7
million,  consisting  of $14.7  million of property  acquisition  costs and $4.0
million of exploration costs.

     For the year 2002, the Company has budgeted  approximately $115 million for
exploration  and  development  activities,  including  $40 million on properties
acquired in the Prize merger.  We anticipate  that the 2002 capital  expenditure
budget  will  be  funded  by cash  flow  from  operations  and  credit  facility
utilization.  The Company is not contractually  obligated to proceed with any of
its material budgeted capital expenditures.  The amount and allocation of future
capital  expenditures  will depend on a number of factors  that are not entirely
within the Company's control or ability to forecast, including drilling results,
oilfield costs, and changes in oil and gas prices.  As a result,  actual capital
expenditures may vary significantly from current expectations.

     In the normal course of business, the Company reviews opportunities for the
possible  acquisition  of oil and gas reserves and activities  related  thereto.
When  potential  acquisition   opportunities  are  deemed  consistent  with  the
Company's growth  strategy,  bids or offers in amounts and with terms acceptable
to the Company may be submitted. It is uncertain whether any such bids or offers
which may be submitted by the Company  from time to time will be  acceptable  to
the sellers. In the event of a future significant  acquisition,  the Company may
require  additional  financing  in  connection  therewith.  The Company does not
budget for acquisition expenditures.

     CONTRACTUAL OBLIGATIONS AND COMMERCIAL  COMMITMENTS.  We have the following
contractual obligations as of December 31, 2001:

<TABLE>
<CAPTION>
<S>                                  <C>               <C>                 <C>                  <C>               <C>
                                                              Payments Due by Period (in thousands)
Contractual Obligations                 Total            Less than 1         1 - 3 Years         4 - 5 Years       After 5 Years
                                                             Year
-------------------------------    ----------------    ----------------    ---------------     ---------------    ---------------
Long-Term Debt                         $    284,539        $         73        $   155,000        $    129,466          $     -
Notes Payable                                 4,044               4,044                -                   -                  -
Operating Leases                              3,732               1,037              2,576                 119                -
                                   ----------------    ----------------    ---------------     ---------------    ---------------
Total Contractual Obligations          $    292,315        $      5,154        $   157,576        $    129,585          $     -

</TABLE>

     We have commercial commitments in the form of guarantees on a several basis
to trade  creditors  of our 30% owned  affiliate,  NGTS,  LLC.  The total amount
committed as of December 31, 2001 is  $11,040,000.  The guarantees  expire up to
one year from the dates of original issuance.

                                       42

<PAGE>

Critical Accounting Policies and Other

     Our  financial  statements  are  prepared  in  accordance  with  accounting
principles  generally  accepted in the United  States of America.  The  reported
financial results and disclosures were determined using  significant  accounting
policies,  practices and estimates as described  below.  We believe the reported
financial  results are reliable and that the  ultimate  actual  results will not
differ significantly from those reported.

     The accompanying  consolidated financial statements include the accounts of
the Company and its subsidiaries.  The Company  consolidates on a pro rata basis
its  approximately  39%, as of at December 31,  2001,  ownership of TEL Offshore
Trust.  The Company  accounts for its  investment in NGTS,  LLC under the equity
method.  All  significant  intercompany  transactions  and  balances  have  been
eliminated  in   consolidation.   Certain  items  in  prior  periods  have  been
reclassified to conform with the current presentation.

     The Company is a holding  company with no significant  assets or operations
other than its investments in its subsidiaries. The wholly-owned subsidiaries of
the  Company,  except  for  Bluebird  Energy,  Inc.  ("Bluebird"),   are  direct
guarantors of the Company's 10% senior notes and have fully and  unconditionally
guaranteed the notes on a joint and several basis.  The guarantors  comprise all
of the direct and indirect  subsidiaries  of the Company (other than  Bluebird),
and  the  Company  has  presented  separate  condensed  consolidating  financial
statements  and other  disclosures  concerning  each guarantor and Bluebird (See
Note 17 to the Consolidated  Financial  Statements).  There is no restriction on
the ability of consolidated or unconsolidated  subsidiaries to transfer funds to
the Company in the form of cash dividends,  and,  except for Bluebird,  loans or
advances.

Oil and Gas Properties

     The Company uses the full cost method of accounting  for its  investment in
oil and gas properties.  Under the full cost method of accounting,  all costs of
acquisition,  exploration  and  development  of oil and gas proved  reserves are
capitalized into a "full cost pool" on a  country-by-country  basis as incurred,
and  properties  in the pool are  depleted and charged to  operations  using the
unit-of-production  method  based on the ratio of  current  production  to total
proved oil and gas reserves,  as determined by independent  petroleum engineers.
To the extent  that such  capitalized  costs (net of  accumulated  depreciation,
depletion and  amortization)  less deferred  taxes exceed the PV-10 of estimated
future  net cash  flow from  proved  reserves  of oil and gas,  and the lower of
unamortized cost or fair value of unproved  properties after income tax effects,
such excess costs are charged to operations. Once incurred, a write- down of oil
and gas  properties is not  reversible at a later date even if oil or gas prices
subsequently  increase.  The  Company's  capitalized  costs  exceeded  the PV-10
limitation  utilizing  prices in effect at  December  31,  2001 by $76  million.
However, no writedown for impairment of oil and gas properties was required as a
result of the  increase in oil and gas prices  subsequent  to December 31, 2001.
Significant  downward revisions of quantity  estimates,  declines in oil and gas
prices,  higher operating costs or additional capital costs which are not offset
by incremental increases in oil and gas reserves or other factors could possibly
result in a write-down for impairment of oil and gas properties in the future.

     Reserve  engineering  is a  subjective  process  that is  dependent  on the
quality of available data and on engineering and geological  interpretation  and
judgment.  Reserve  estimates  are  subject  to change  over time as  additional
information becomes available.

Revenue Recognition

     Revenues are recognized when title to the product  transfers to purchasers.
We follow the "sales  method" of accounting  for revenue for oil and natural gas
production,  so  that we  recognize  sales  revenue  on all  production  sold to
purchasers,  regardless of whether the sales are  proportionate to our ownership
in the property. A receivable or liability is recognized only to the extent that
we have an imbalance on a specific property greater than the expected  remaining
proved reserves.  Ultimate  revenues from the sales of oil and gas production is
not known with certainty

                                       43

<PAGE>

     until up to three months after production and title transfer occur. Current
revenues are accrued based on our  expectation  of actual  deliveries and actual
prices received.

Inflation and Changes in Prices

     The results of operations  and cash flow of the Company have been, and will
continue to be,  affected by the  volatility  in oil and gas prices.  Should the
Company  experience  a  significant  increase  in oil  and  gas  prices  that is
sustained  over a prolonged  period,  it would expect that there would also be a
corresponding  increase in oil and gas finding costs,  lease acquisition  costs,
and operating expenses.

     The Company  markets  oil and gas for its own  account,  which  exposes the
Company  to  the  attendant  commodities  risk.  A  significant  portion  of the
Company's gas production is currently sold to a 30% owned affiliate,  NGTS, LLC,
or  end-users  either  (i) on the  spot  market  on a  month-to-month  basis  at
prevailing spot market prices or (ii) under long-term contracts based on current
spot market  prices.  The Company  normally  sells its oil under  month-to-month
contracts to a variety of purchasers.

Hedging

     Periodically the Company enters into futures,  options,  and swap contracts
to reduce the adverse  effects of  fluctuations  in crude oil and gas prices and
interest  rates.  It is the  policy of the  Company  to not enter  into any such
commodity hedging  arrangements  which cause the Company's  aggregate  commodity
hedge position to exceed 75% of the oil and gas production  during the projected
next 12 months.  We also utilize financial  derivative  instruments to hedge the
risk  associated  with interest on our  outstanding  debt.  Generally,  the cash
settlement of all  derivative  instruments is recognized as income or expense in
the  period  in which  the  hedged  transaction  is  recognized.  The  Company's
accounting of the fair value of derivative instruments is discussed below.

New Accounting Standards

     Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative  Instruments and Hedging  Activities"  (SFAS No. 133), as extended by
SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000),  was effective
for the Company beginning  January 1, 2001. SFAS No. 133 establishes  accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of derivatives in the balance sheet and the measurement of those
instruments at fair value.  Derivative  instruments  that are not hedges must be
adjusted to the fair value through net income  (loss).  Under the  provisions of
SFAS 133,  changes in the fair  value of  derivative  instruments  that are fair
value hedges are offset against  changes in the fair value of the hedged assets,
liabilities, or firm commitments, through net income (loss). Changes in the fair
value of  derivative  instruments  that are cash-flow  hedges are  recognized in
other  comprehensive  income  (loss)  until  such time as the  hedged  items are
recognized  in  net  income  (loss).   Ineffective   portions  of  a  derivative
instrument's  change in fair  value are  immediately  recognized  in net  income
(loss).

     The Company was  obligated to four crude oil  derivatives,  one natural gas
derivative,  and one interest rate  derivative  on January 1, 2001.  The Company
determined that the interest rate derivative did not qualify for hedge treatment
as defined  within  SFAS No.  133.  The crude oil and  natural  gas  derivatives
qualified as cash-flow hedges.

     At January 1, 2001,  all  derivatives  within the Company  were  identified
pursuant to SFAS No. 133 requirements,  and the Company  designated,  documented
and assessed all hedging  relationships.  Adoption of this  accounting  standard
resulted in the  recognition  of $179 thousand of a derivative  asset related to
the interest rate  derivative and an increase in the carrying value of long-term
debt with recourse of $179 thousand.  In June,  2001 the Company  terminated its
position in this  derivative.  For the year ended December 31, 2001, the Company
recognized a gain of $980  thousand as a reduction of interest  expense for this
derivative.

                                       44

<PAGE>

     With respect to the cash-flow hedges, at the accounting change  transition,
the Company  recorded a derivative  asset of $648 thousand  related to the crude
oil derivatives with a cumulative effect increase to other comprehensive  income
of $403  thousand  (net of income  taxes)  and a  derivative  liability  of $3.5
million related to the natural gas derivatives with a cumulative effect decrease
to other comprehensive income of $2.2 million (net of income taxes).

     In May,  2001, the Company  entered into  additional  costless  collars for
crude oil for the periods July 2001 through December 2001. In August,  2001, the
Company  entered  into a swap  transaction  for  natural  gas  for  the  periods
September   2001  through   November  2001  and  interest  rate  swaps  (receive
variable/pay fixed) on $50 million of its variable rate bank debt for the period
August 2001 through August 2003.  These crude oil, natural gas and interest rate
derivatives qualify as cash flow hedges.

     At December 31,  2001,  the Company had no crude oil  derivatives,  and its
natural  gas  derivatives  had a fair  value  of  $3.6  million,  recognized  as
derivative  assets of $5.1 million and  derivative  liabilities of $1.5 million.
The  Company  recognized  a  liability  of $1.0  million  on its  interest  rate
derivatives. For the year ended December 31, 2001, the income statement includes
a gain of $1.3  million  related  to the crude oil  derivatives,  a gain of $3.4
million  related to the natural gas  derivatives  and a loss of $204 thousand on
interest  rate   derivatives,   net  of  amounts   reclassified   out  of  other
comprehensive  income.  The Company expects that the remaining  balance in other
comprehensive  income  related to the natural gas  derivatives  at December  31,
2001, will be reclassified  into the income  statement  within the next eighteen
months and for the interest rate derivatives, within the next twenty months.

Recently Issued Statements

     SFAS No. 141 - SFAS No. 141, "Business Combinations",  is effective for the
Company  beginning  July 1, 2001.  SFAS No. 141 requires the use of the purchase
method of accounting  for business  combinations  initiated and completed  after
June 30, 2001 and eliminates  the use of the  pooling-of-interests  method.  The
adoption  of SFAS  No.  141 as of July 1,  2001 did not  have an  impact  on our
consolidated financial statements.

     SFAS No. 142 - SFAS No. 142, "Goodwill and Other Intangible  Assets",  will
be effective for the Company  beginning  January 1, 2002. SFAS No. 142 requires,
among other things,  the discontinuance of goodwill  amortization.  Any goodwill
resulting from acquisitions completed after June 30, 2001 will not be amortized.

     In addition,  SFAS No. 142 requires the Company to complete a  transitional
goodwill  impairment  test  within  six  months  from the date of  adoption  and
establishes a new method of testing goodwill that could reduce the fair value of
a reporting unit below its carrying value.  Any goodwill  impairment loss during
the transition period will be recognized as the cumulative effect of a change in
accounting principle. Subsequent impairments will be recorded in operations. The
adoption  of SFAS No.  142 will not have a material  impact on our  consolidated
financial statements.

     SFAS No. 143 - SFAS No. 143, "Accounting for Asset Retirement Obligations",
will be  effective  for the  Company  beginning  January 1,  2003.  SFAS No. 143
requires the recognition of a fair value liability for any retirement obligation
associated with long-lived assets. The offset to any liability recorded is added
to the recorded asset where the additional  amount is depreciated  over the same
period  as  the  long-lived  asset  for  which  the  retirement   obligation  is
established.  SFAS No. 143 also requires additional  disclosures.  We are in the
process of evaluating the impact of the provisions of SFAS No. 143.

     SFAS No. 144 - SFAS No. 144,  "Accounting for the Impairment or Disposal of
Long-Lived Assets", will be effective for the Company beginning January 1, 2002.
SFAS No. 144  establishes  a single  accounting  model,  based on the  framework
established in SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets
and for  Long-Lived  Assets to Be  Disposed  Of",  for  long-lived  assets to be
disposed of by sale and resolves  significant  implementation  issues related to
SFAS No. 121. We are in the process of evaluating  the impact of the  provisions
of SFAS No. 144.

                                       45

<PAGE>

Off Balance Sheet Arrangements

     We have no off balance  sheet  arrangements,  special  purpose  entities or
financing partnerships.  We have agreed to provide guarantees on a several basis
to trade  creditors of our 30% owned  affiliate,  NGTS,  LLC. The upper limit of
liability we have agreed to guarantee is $15 million.  At December 31, 2001, the
aggregate amount of our guarantees for NGTS, LLC was $11,040,000.

     The Company  had equity and debt  investments  in a  privately  held entity
which  declared  bankruptcy  subsequent to December 31, 2001,  and for which the
Company  provided an  impairment  charge  against  earnings  of $5.0  million at
December 31, 2001. The Company is not  responsible for any debts of this entity.
The Company had an investment in available-for-sale securities of another entity
of $2.8  million at December 31, 2001.  Because of the  deteriorating  financial
condition  of  this  entity,  the  Company  reported  an  other  than  temporary
impairment  of $2.1 million as a charge  against  earnings at December 31, 2001.
The Company is not responsible for any debts of this entity.

Other

     Our  hedging   activity  has   resulted  in  gas  revenue   that   reflects
approximately  60% of our gas  sales  volumes  realized  at  fixed  prices.  The
remainder of our hydrocarbon volumes are sold at market prices. Future commodity
price declines will negatively  impact future income and cash flow to the extent
of any production sold at market prices.  These declines could ultimately affect
the  quantity of proved oil and gas  reserves  and cost center  ceiling  values.
These results,  individually or collectively,  could result in bank debt default
and/or debt acceleration, restrict our ability to attract qualified personnel or
cause further industry consolidation.  There are no requirements from any of the
Company's lenders to hedge our products.

     Our  domestic   operations  are   concentrated  in  the   southwestern  and
midcontinent  regions of the United  States and shallow water region of the Gulf
of Mexico offshore Texas and Louisiana.  We currently have no operations outside
of the  United  States of  America.  We  currently  have  eighteen  wells  which
individually   produce  1.5  MMcfe  per  day  or  greater,  but  these  are  not
concentrated in any one field. We have no individual fields in which disruptions
could reduce our financial results.

     FORWARD-LOOKING STATEMENTS. This Form 10-K and the information incorporated
by reference  contain  statements that constitute  "forward-looking  statements"
within the meaning of Section 27A of the  Securities  Act and Section 21E of the
Securities Exchange Act. The words "expect", "project",  "estimate",  "believe",
"anticipate",  "intend",  "budget",  "plan",  "forecast",  "predict"  and  other
similar expressions are intended to identify forward- looking statements.  These
statements  appear in a number of places and include  statements  regarding  our
plans,  beliefs,  or current  expectations,  including the plans,  beliefs,  and
expectations of our officers and directors.

     When considering any forward-looking statement, you should keep in mind the
risk factors that could cause our actual results to differ materially from those
contained in any forward-looking  statement.  Important factors that could cause
actual results to differ materially from those in the forward-looking statements
herein include the timing and extent of changes in commodity  prices for oil and
gas, operating risks and other risk factors as described in our Annual Report on
Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the
assumptions  that  support  our   forward-looking   statements  are  based  upon
information  that  is  currently   available  and  is  subject  to  change.   We
specifically  disclaim all  responsibility  to publicly  update any  information
contained in a forward- looking  statement or any  forward-looking  statement in
its entirety and  therefore  disclaim any resulting  liability  for  potentially
related damages.

     All  forward-looking  statements  attributable to Magnum Hunter  Resources,
Inc. are expressly qualified in their entirety by this cautionary statement.

                                       46

<PAGE>

Item 7A. Qualitative and Quantitative Disclosure About Market Risk

     The Company's  operations are exposed to market risks primarily as a result
of changes in  commodity  prices and  interest  rates.  The Company does not use
derivative financial instruments for speculative or trading purposes.

     Energy swap agreements.  The Company produces,  purchases,  and sells crude
oil,  natural  gas,  condensate,  and  natural  gas  liquids.  As a result,  the
Company's  financial  results can be  significantly  impacted as these commodity
prices fluctuate  widely in response to changing market forces.  The Company has
previously  engaged in oil and gas hedging activities and intends to continue to
consider  various  hedging  arrangements  to realize  commodity  prices which it
considers  favorable and to reduce  volatility.  The Company  engages in futures
contracts with certain of its oil and gas production  through various  contracts
("Swap  Agreements").  The primary  objective of these  activities is to protect
against significant decreases in price during the term of the hedge.

     The Swap  Agreements  provide for separate  contracts  tied to the New York
Mercantile  Exchange ("NYMEX") light sweet crude oil and the Inside FERC natural
gas index price  posting  ("Index").  The Company has  contracts  which  contain
specific  contracted  prices  ("Swaps")  that are settled  monthly  based on the
differences  between the contract prices and the specified Index prices for each
month applied to the related contract  volumes.  To the extent the Index exceeds
the contract price, the Company pays the spread,  and to the extent the contract
price exceeds the Index price, the Company receives the spread. In addition, the
Company has combined  contracts which have agreed upon price floors and ceilings
("Costless  Collars").  To the  extent  the Index  price  exceeds  the  contract
ceiling,  the  Company  pays the spread  between the ceiling and the Index price
applied to the  related  contract  volumes.  To the extent  the  contract  floor
exceeds the Index,  the Company  receives the spread  between the contract floor
and the Index price applied to the related contract volumes.

     To the extent the Company  receives the spread  between the contract  floor
and the Index  price  applied to related  contract  volumes,  the  Company has a
credit risk in the event of nonperformance of the counterparty to the agreement.
The Company does not anticipate any material impact to its results of operations
as a result of nonperformance by such parties.

     At December 31, 2001, the Company had the following open contracts:


            Type           Volume/Day       Duration         Wtd. Avg. Price
          -----------     ------------    ------------      ------------------
Gas
-------
          Swap......      60,000 MMBtu   Jan 02 - Dec 02        $ 2.87
          Swap......      50,000 MMBtu   Jan 03 - Jun 03        $ 2.88

     Based on future market prices at December 31, 2001,  the fair value of open
contracts  to the  Company  was a net asset of $3.6  million.  If future  market
prices were to increase 10% from those in effect at December 31, 2001,  the fair
value  of open  contracts  to the  Company  would  decrease  in  value  to a net
liability  of $4.5  million.  If future  market  prices were to decline 10% from
those in effect at December  31, 2001,  the fair value of the open  contracts to
the Company would increase to a net asset of $11.6 million.

     The  Company  currently  intends  to  commit  no more than 75% of its daily
production on a Bcfe basis to such  arrangements at any point in time. A portion
of the  Company's  oil and  natural  gas  production  will be  subject  to price
fluctuations unless the Company enters into additional hedging transactions.

                                       47

<PAGE>

Interest Rate Swaps

     On June 30, 1999, the Company entered into two interest rate swaps in order
to shift a  portion  of the  fixed  rate bond debt to  floating  rate  debt,  to
capitalize on what was perceived as a market  overreaction  to pending  interest
rate increases by the Federal  Reserve,  and to effectively  lower interest rate
expense over the following  twelve months.  On June 1, 2000, one of the interest
rate swaps terminated.  The Company  terminated the remaining interest rate swap
in June, 2001.

     On August 9, 2001,  the Company  entered  into two  interest  rate swaps in
order to shift a portion of its variable rate bank debt to fixed rate debt.  The
following table reflects the terms of these swaps.

<TABLE>
<CAPTION>
<S>                                  <C>                      <C>                    <C>                     <C>
             Type                     Notional Amount          Termination Date         Pay Rate              Receive Rate
            ------                    ---------------          ----------------      --------------         ----------------
  Pay Fixed/Receive Variable            $50,000,000                8/23/03            4.25 % Fixed              3 month
                                                                                                               LIBOR rate
                                                                                                             currently 2.195%
</TABLE>

     The rate the Company  receives  will be reset every three months to exactly
match  the  rate  the  Company  will pay on  $50.0  million  of its  outstanding
LIBOR-based bank debt.

     Based on future market prices at December 31, 2001,  the fair value of open
interest rate swap contracts to the Company was a liability of $1.0 million.  If
future  market  rates were to increase  10% from those in effect at December 31,
2001,  the fair value of open  contracts to the Company  would be a liability of
$864  thousand.  If future market rates were to decline 10% from those in effect
at December 31, 2001,  the fair value of the open contracts to the Company would
be a liability of $1.2 million.

Fixed and Variable Debt.

     The Company uses fixed and  variable  debt to  partially  finance  budgeted
expenditures.  These  agreements  expose the Company to market  risk  related to
changes in interest rates.

     The following  table  presents the carrying and fair value of the Company's
debt along with average  interest  rates.  Fair values are calculated as the net
present value of the expected cash flows of the  financial  instruments,  except
for the fixed rate senior  notes,  which are valued at their last  traded  value
before December 31, 2001.

<TABLE>
<CAPTION>
<S>                                <C>        <C>          <C>           <C>         <C>         <C>

     Expected Maturity Dates
         (in thousands)               2002        2003      2004-2006      2007        Total      Fair Value
                                    ---------  ----------   ----------   ---------   ----------   -----------
Variable Rate Debt:
Bank Debt with Recourse (a)......   $      -    $ 155,000    $     -      $    -      $ 155,000    $ 155,000
Fixed Rate Debt:
Senior Notes (b).................   $      -    $     -      $     -      $129,466    $ 129,466    $ 130,113
Other............................   $      73   $     -      $     -      $    -      $      73    $      73
Notes Payable - Current (c)......   $   4,044   $     -      $     -      $    -      $   4,044    $   4,044
</TABLE>

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

     (a) The weighted  average  interest  rate on the bank debt with recourse at
         December 31, 2001 is 4.71%.
     (b) The interest rate on the senior notes is a fixed 10%.
     (c) The interest rate on notes payable - current is a fixed 7%.

                                       48

<PAGE>

Item 8. Consolidated Financial Statements and Unaudited Supplemental Information


                   Index to Consolidated Financial Statements
<TABLE>
<CAPTION>
<S>                                                                                                       <C>

                                                                                                           Page

     Independent Auditors' Report...........................................................................F-1

     Financial Statements:
             Consolidated Balance Sheets at December 31, 2001and 2000.......................................F-2

            Consolidated Statements of Operations and Comprehensive Income for the
                     Years Ended December 31, 2001, 2000 and 1999...........................................F-3

             Consolidated Statements of Stockholders' Equity for the
                      Years Ended December 31, 2001, 2000 and 1999..........................................F-4

             Consolidated Statements of Cash Flows for the Years
                      Ended December 31, 2001, 2000 and 1999................................................F-5

     Notes to Consolidated Financial Statements.............................................................F-6

     Supplemental Information (Unaudited)..................................................................F-30

</TABLE>


                                       ii

<PAGE>

                          INDEPENDENT AUDITORS' REPORT



Board of Directors and Stockholders
Magnum Hunter Resources, Inc.

     We have  audited the  accompanying  consolidated  balance  sheets of Magnum
Hunter  Resources,  Inc. and Subsidiaries as of December 31, 2001, and 2000, and
the related  consolidated  statements of operations  and  comprehensive  income,
stockholders'  equity,  and cash flows for each of the three years in the period
ended  December  31,  2001.  These  consolidated  financial  statements  are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

     We conducted our audits in accordance  with  auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

     In our opinion,  the consolidated  financial  statements  referred to above
present  fairly,  in all material  respects,  the  financial  position of Magnum
Hunter  Resources,  Inc. and  Subsidiaries as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2001, in conformity with accounting  principles
generally accepted in the United States of America.



Deloitte & Touche LLP


Dallas, Texas
March 22, 2002


                                       F-1

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                            (in thousands of dollars)
<TABLE>
<CAPTION>
<S>                                                                             <C>                      <C>
                                                                                      December 31,        December 31,
                                                                                          2001                2000
                                                                                --------------------------------------------
                                     ASSETS

Current Assets
     Cash and cash equivalents..................................................$           2,755        $        9
     Restricted cash ..........................................................                 -             1,820
     Accounts receivable
          Trade, net of allowance of $3,264 and $50, respectively...............           14,251            30,442
          Due from affiliates...................................................              235               107
     Notes receivable from affiliate............................................              300               377
     Current portion of long-term notes receivable, net of allowance of $1,170..                -                50
     Income tax refund receivable...............................................              300                 -
     Derivative assets, current.................................................            5,045                 -
     Prepaid and other..........................................................            2,220             2,033
                                                                                --------------------------------------------
           Total Current Assets.................................................           25,106            34,838
                                                                                --------------------------------------------
Property, Plant, and Equipment
     Oil and gas properties, full cost method
           Unproved.............................................................           18,653             5,534
           Proved...............................................................          556,766           367,822
     Pipelines..................................................................           12,642            12,581
     Other property.............................................................            3,640             2,459
                                                                                --------------------------------------------
     Total Property, Plant and Equipment........................................          591,701           388,396
           Accumulated depreciation, depletion, amortization and impairment.....         (171,864)         (127,864)
                                                                                --------------------------------------------
     Net Property, Plant and Equipment..........................................          419,837           260,532
                                                                                --------------------------------------------
Other Assets
     Deposits and other assets..................................................            4,420             6,570
     Investment in unconsolidated affiliates, net of allowance
       of $453 and $0, respectively.............................................            5,022             8,054
     Deferred tax asset ........................................................                -             5,618
                                                                                --------------------------------------------
     Total Assets.............................................................. $         454,385        $  315,612
                                                                               =============================================
                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
     Trade payables and accrued liabilities.....................................$          41,446        $   27,094
     Dividends payable..........................................................                -               169
     Suspended revenue payable..................................................            2,154             3,201
     Derivative liabilities, current............................................              996                 -
     Current income taxes payable...............................................                -               234
     Current maturities of long-term debt, with recourse........................               73                19
     Notes payable..............................................................            4,044                 -
                                                                                --------------------------------------------
           Total Current Liabilities............................................           48,713            30,717
                                                                                --------------------------------------------
Long-Term Liabilities
     Long-term debt, with recourse, less current maturities.....................          284,466           170,520
     Long-term debt, non recourse, less current maturities......................                -            20,600
     Production payment liability...............................................              203               359
     Derivative liabilities, noncurrent.........................................            1,531                 -
     Deferred income taxes payable..............................................            1,498                 -
Commitments and Contingencies (Note 11)
Stockholders' Equity
     Preferred stock - $.001 par value; 10,000,000 shares authorized, 216,000
       designated as Series A; 80,000 issued and outstanding, liquidation
       amount $0................................................................                -                 -
       1,000,000 designated as 1996 Series A Convertible; 1,000,000 purchased
        and held for remarketing by subsidiary, liquidation amount $10,000,000..                1                 1
       50,000 designated as 1999 Series A 8% Convertible; none and 25,000
        issued and outstanding, respectively,  liquidation amount $0 and
        $25,000,000, respectively...............................................                -                 -
     Common Stock - $.002 par value; 100,000,000 shares authorized,
       36,588,097 and 30,705,398 shares issued, respectively....................               73                61
     Additional paid-in capital.................................................          157,836           148,580
     Accumulated other comprehensive income (loss)..............................            1,632              (466)
     Accumulated deficit........................................................          (36,636)          (50,152)
     Receivable from stockholder................................................             (442)             (442)
     Unearned common stock in ESOP, at cost (468,652 and 680,282 shares,
      respectively).............................................................           (2,576)           (2,780)
                                                                                --------------------------------------------
                                                                                          119,888            94,802
     Treasury stock, at cost (441,813 and 455,063 shares of common stock,
      respectively).............................................................           (1,914)           (1,386)
                                                                                --------------------------------------------
     Total Stockholders' Equity.................................................          117,974            93,416
                                                                                --------------------------------------------
     Total Liabilities and Stockholders' Equity.................................$         454,385        $  315,612
                                                                                ============================================

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

                 Magnum Hunter Resources, Inc. and Subsidiaries
         Consolidated Statements of Operations and Comprehensive Income
        (in thousands of dollars, except for share and per share amounts)
<TABLE>
<CAPTION>
<S>                                                             <C>              <C>             <C>
                                                                             For the Years Ended
                                                                                 December 31,
                                                              -----------------------------------------------------
                                                                      2001             2000            1999
                                                              -----------------------------------------------------
Operating Revenues:
   Oil and gas sales..........................................  $      133,083   $      106,052  $       60,673
   Gas gathering, marketing and processing....................          17,895           20,010           8,185
   Oil field services.........................................           1,828            1,448             768
                                                              -----------------------------------------------------
         Total Operating Revenues.............................         152,806          127,510          69,626
                                                              -----------------------------------------------------
Operating Costs and Expenses:
   Oil and gas production lifting costs.......................          20,388           16,401          15,431
   Production taxes and other costs...........................          12,994           12,558           8,144
   Gas gathering, marketing and processing....................          16,101           15,685           5,870
   Oil field services.........................................           1,277              903             350
   Depreciation, depletion and amortization...................          43,999           25,556          22,072
   Gains on sale of assets....................................             (58)             (28)           (272)
      Loss on Enron related assets............................           3,156                -               -
   General and administrative.................................           6,898            6,106           2,919
                                                              -----------------------------------------------------
         Total Operating Costs and Expenses...................         104,755           77,181          54,514
                                                              -----------------------------------------------------
Operating Profit..............................................          48,051           50,329          15,112
   Equity in earnings (loss) of affiliate.....................           1,085            1,307           (103)
   Other income...............................................             283              477             354
      Provision for impairment of investments.................          (7,123)               -               -
      Minority interest in subsidiary loss....................               -                -             (86)
   Interest expense...........................................         (19,868)         (22,298)        (22,103)
                                                              -----------------------------------------------------
Income (loss) before income tax...............................          22,428           29,815         (6,826)
   Provision for income tax expense
      Current.................................................            (178)            (234)              -
      Deferred................................................          (8,430)          (7,321)              -
                                                              -----------------------------------------------------
         Total provision for income tax expense...............          (8,608)          (7,555)              -
                                                              -----------------------------------------------------
Income (Loss) Before Extraordinary Loss.......................          13,820           22,260          (6,826)
      Extraordinary loss from early extinguishment of debt,
          net of income tax benefit of $186...................            (304)               -               -
                                                              -----------------------------------------------------
Net Income (Loss).............................................          13,516           22,260          (6,826)
   Dividends Applicable to Preferred Stock....................               -           (9,708)         (4,509)
                                                              -----------------------------------------------------
Income (Loss) Applicable to Common Shares.....................  $       13,516   $       12,552  $      (11,335)
                                                              =====================================================
Comprehensive Income (Loss):
     Net Income (Loss)........................................  $       13,516   $       22,260  $       (6,826)
     Other Comprehensive Income (Loss), net of tax
     Cumulative effect on prior years of a change in
      accounting principle....................................          (1,757)               -               -
   Gain on derivatives........................................           3,536                -               -
   Reclassification adjustment related to derivative assets...            (147)               -               -
   Unrealized Gain (Loss) on investments......................             466            1,247           (405)
                                                              -----------------------------------------------------
Comprehensive Income (Loss)...................................  $       15,614   $       23,507  $      (7,231)
                                                              =====================================================
Income (Loss) per Common Share - Basic
   Income (Loss) Before Extraordinary Loss....................  $         0.40   $         0.60  $       (0.57)
   Extraordinary Loss.........................................           (0.01)               -              -
                                                              -----------------------------------------------------
Income (Loss) per Common Share - Basic                          $         0.39   $         0.60  $       (0.57)
                                                              =====================================================
Income (Loss) per Common Share - Diluted
   Income (Loss) Before Extraordinary Loss....................  $         0.37   $         0.51  $       (0.57)
   Extraordinary Loss.........................................           (0.01)               -              -
                                                              -----------------------------------------------------
Income (Loss) per Common Share - Diluted                        $         0.36   $         0.51  $       (0.57)
                                                              =====================================================
Common Shares Used in Per Share Calculation
   Basic .....................................................      34,819,614       20,856,854     19,743,738
                                                              =====================================================
   Diluted ...................................................      37,108,976       32,834,270     19,743,738
                                                              =====================================================

              The accompanying  notes are an integral part of these consolidated financial statements.
</TABLE>

<PAGE>

                 Magnum Hunter Resources, Inc. and Subsidiaries
                 Consolidated Statements of Stockholders' Equity
             For the Periods Ended December 31, 2001, 2000 and 1999
                             (dollars in thousands)

<TABLE>
<CAPTION>
<S>                                                 <C>          <C>       <C>          <C>     <C>          <C>         <C>
                                                                                                                         Additional
                                                        Preferred Stock        Common Stock         Treasury Stock        Paid-In
                                                     Shares       Amount    Shares       Amount  Shares       Amount      Capital
                                                     ------------------------------------------------------------------------------
Balance at December 31, 1998.......................  1,080,000    $    1    21,738,320   $   43  (1,054,507)  $ (1,909)   $  80,032
  Issuance of 1999 Series A preferred, net of
    offering costs.................................    50,000          -                                                     46,260
  Fees paid on issuance of warrants................                                                                            (133)
  Common Stock contributed to 401(k) plan .........                                                  41,115          -          123
  Exercise of employees' common stock options .....                                                 102,145          -           74
  Costs associated with release of shares from ESOP                                                                              (2)
  Purchase of treasury stock ......................                                                (601,472)    (1,722)
  Dividends declared on preferred stock ...........                                                                          (4,509)
  Net loss ........................................
  Unrealized loss on investment ...................
  Loan to stockholder..............................
  Unearned shares in ESOP..........................
                                                   --------------------------------------------------------------------------------
Balance at December 31, 1999.......................  1,130,000    $    1    21,738,320   $   43  (1,512,719)  $ (3,631)   $ 121,845
  Purchase of 1996 Series A preferred by subsidiary                                                                         (10,035)
  Redemption of 1999 Series A 8% convertible
    preferred stock................................    (25,000)                                                             (25,000)
  Purchase of treasury stock.......................                                                (129,032)      (500)
  Exercise of employees' common stock options......                            528,942        1     127,450         77        2,335
  Exercise of warrants, net of expenses............                          8,438,136       17     702,272      1,588       55,952
  Issuance of common stock for property............                                                 356,966      1,080        2,401
  Costs associated with release of shares from ESOP                                                                             672
  Deferred tax benefit on exercise of employee
    stock options..................................                                                                410
  Net income.......................................
  Dividends on preferred stock.....................
  Unrealized gain on investment....................
  Repayment of stockholder loan....................
  Unearned shares in ESOP..........................
                                                   --------------------------------------------------------------------------------
Balance at December 31, 2000.......................  1,105,000    $    1    30,705,398$      61    (455,063)  $ (1,386)   $ 148,580
  Conversion of 1999 Series A 8% convertible
    preferred stock................................    (25,000)              4,761,904       10                                 (10)
  Exercise of employees' common stock options......                          1,068,316        2      56,300        171        4,692
  Deferred tax benefit on exercise of employee
    stock options..................................                                                              2,350
  Common stock contributed to 401(k) plan and other                             52,479        -                                 151
  Issuance of common stock from treasury...........                                                  72,900        316          418
  Purchase of treasury stock.......................                                                (115,950)    (1,015)
  Net income.......................................
  Cumulative effect on prior years of a change in
    accounting principle...........................
  Gain on hedges...................................
  Reclassification adjustment related to
    derivative assets..............................
  Unrealized gain on investments...................
  Employee salary deferrals to ESOP................                                                                           1,655
  Loan to ESOP.....................................
                                                   --------------------------------------------------------------------------------
Balance at December 31, 2001.......................  1,080,000    $    1    36,588,097   $   73    (441,813)  $ (1,914)   $ 157,836
                                                   ================================================================================
</TABLE>

<TABLE>
<CAPTION>
<S>                                                     <C>                <C>           <C>            <C>          <C>
                                                         Accumulated Other                Receivable     Unearned Shares in
                                                          Comprehensive     Accumulated      from               ESOP
                                                          Income (Loss)       Deficit     Stockholder    Shares       Amount
                                                       -------------------------------------------------------------------------
Balance at December 31, 1998.......................       $   (1,308)       $  (55,734)    $   (672)    (250,423)     $  (756)
  Issuance of 1999 Series A preferred, net of
    offering costs.................................
  Fees paid on issuance of warrants................
  Common Stock contributed to 401(k) plan .........
  Exercise of employees' common stock options .....
  Costs associated with release of shares from ESOP
  Purchase of treasury stock ......................
  Dividends declared on preferred stock ...........
  Net loss ........................................                             (6,826)
  Unrealized loss on investment ...................             (405)
  Loan to stockholder..............................                                             (123)
  Unearned shares in ESOP..........................                                                     (287,092)        (882)
                                                       -------------------------------------------------------------------------
Balance at December 31, 1999.......................       $   (1,713)       $  (62,560)    $    (795)   (537,515)     $(1,638)
  Purchase of 1996 Series A preferred by subsidiary
  Redemption of 1999 Series A 8% convertible
    preferred stock................................
  Purchase of treasury stock.......................
  Exercise of employees' common stock options......
  Exercise of warrants, net of expenses............
  Issuance of common stock for property............
  Costs associated with release of shares from ESOP
  Deferred tax benefit on exercise of employee
    stock options..................................
  Net income.......................................                             22,260
  Dividends on preferred stock.....................                             (9,852)
  Unrealized gain on investment....................            1,247
  Repayment of stockholder loan....................                                              353
  Unearned shares in ESOP..........................                                                     (142,767)      (1,142)
                                                       -------------------------------------------------------------------------
Balance at December 31, 2000.......................       $     (466)       $  (50,152)    $    (442)   (680,282)     $(2,780)
  Conversion of 1999 Series A 8% convertible
    preferred stock................................
  Exercise of employees' common stock options......
  Deferred tax benefit on exercise of employee
    stock options..................................
  Common stock contributed to 401(k) plan and other
  Issuance of common stock from treasury...........
  Purchase of treasury stock.......................
  Net income.......................................                             13,516
  Cumulative effect on prior years of a change in
    accounting principle...........................           (1,757)
  Gain on hedges...................................            3,536
  Reclassification adjustment related to
    derivative assets..............................             (147)
  Unrealized gain on investments...................              466
  Employee salary deferrals to ESOP................                                                      317,080        1,102
  Loan to ESOP.....................................                                                     (105,450)        (898)
                                                       -------------------------------------------------------------------------
Balance at December 31, 2001.......................       $    1,632        $  (36,636)    $    (442)   (468,652)     $(2,576)
                                                       =========================================================================

   The accompanying  notes are an integral part of these consolidated financial statements.
</TABLE>
                                      F-4
<PAGE>

                 Magnum Hunter Resources, Inc. and Subsidiaries
                      Consolidated Statements of Cash Flows
                                 (in thousands)
<TABLE>
<CAPTION>
<S>                                                                                 <C>              <C>              <C>
                                                                                                For the Years Ended
                                                                                                    December 31,
                                                                                   -------------------------------------------------
                                                                                          2001            2000           1999
                                                                                   -------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
  Net income (loss).............................................................     $    13,516      $    22,260     $    (6,826)
  Adjustments to reconcile net income (loss) to cash
    provided by operating activities
        Extraordinary loss......................................................             304                -               -
        Depreciation, depletion and amortization................................          43,999           25,556          22,072
        Impairment of investments...............................................           7,123                -               -
        Amortization of financing fees..........................................           1,192            1,318           2,091
        Increase in allowance for doubtful accounts.............................           3,214              464               -
        Deferred income taxes...................................................           8,430            7,321               -
        Equity in (income) loss of unconsolidated affiliate.....................          (1,085)          (1,307)            103
        Minority interest expense...............................................               -                -              86
        Cost of shares released from ESOP suspense..............................               -              448             151
        Excess of fair value over cost of shares released from ESOP suspense....           1,655              672              (2)
        Gain on sale of assets..................................................             (58)             (28)           (272)
        Change in fair value of derivatives.....................................             162                -               -
        Changes in certain assets and liabilities
                Accounts and notes receivable...................................          12,849          (20,378)         (4,660)
                Other current assets............................................            (187)            (737)            281
                Accounts payable and accrued liabilities........................          13,494           13,827           4,411
                Current income taxes payable....................................            (534)             234               -
                Minority interest liability.....................................               -             (184)              -
                                                                                   -------------------------------------------------
  Net Cash Provided By Operating Activities.....................................         104,074           49,466          17,435
                                                                                   -------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Proceeds from sale of assets..................................................           1,124           43,770           1,499
  Additions to property and equipment...........................................        (204,370)         (60,830)        (59,968)
  Decrease in deposits and other assets.........................................              50                -               -
  Loan made for promissory note receivable......................................               -           (1,370)              -
  Payments received on promissory note receivable ..............................              70            1,012               -
  Distribution from unconsolidated affiliate....................................           1,590                -               -
  Investment in unconsolidated affiliate........................................          (2,453)          (2,590)              -
                                                                                   -------------------------------------------------
  Net Cash Used In Investing Activities.........................................        (203,989)         (20,008)        (58,469)
                                                                                   -------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from the issuance of long-term debt, note payable, and
    production payment..........................................................         266,524          101,056         106,800
  Fees paid related to financing activities.....................................            (956)            (534)         (1,603)
  Payments of principal on long-term debt and production payment................        (169,557)        (144,824)       (103,186)
  Payment of short-term notes payable ..........................................               -                -          (2,000)
  Receipts from short-term notes receivable ....................................             360                -               -
  Loan repaid by (made to) stockholder..........................................            (300)             353            (123)
  Loan to ESOP..................................................................            (898)          (1,590)           (759)
  Loan repaid from ESOP.........................................................           1,102                -               -
  Payment of fees on issuance of warrants and preferred stock...................               -                -            (133)
  Proceeds from issuance of common and preferred stock, net of offering costs...           5,750           59,970          46,334
  Purchase of 1996 Series A preferred stock by subsidiary.......................               -          (10,035)              -
  Redemption of 1999 Series A preferred stock...................................               -          (25,000)              -
  Purchase of treasury stock ...................................................          (1,015)            (500)         (1,722)
  Decrease (increase) in restricted cash for payment of notes payable ..........           1,820              325          (1,686)
  Dividends paid................................................................            (169)         (10,235)         (4,176)
                                                                                   -------------------------------------------------
  Net Cash Provided By (Used In) Financing Activities...........................         102,661          (31,014)         37,746
                                                                                   -------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................           2,746           (1,556)         (3,288)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR..................................               9            1,565           4,853
                                                                                   -------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR........................................     $     2,755      $         9     $     1,565
                                                                                   =================================================

      The  accompanying  notes  are an  integral  part of these consolidated financial statements.
</TABLE>
                                       F-5

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations

     Magnum Hunter Resources,  Inc. (the "Company"),  is incorporated  under the
laws of the state of Nevada. The Company and its subsidiaries are engaged in the
acquisition, operation and development of oil and gas properties, the gathering,
processing,  transmission,  and marketing of natural gas and natural gas liquids
and  providing  management  and  advisory  consulting  services  on oil  and gas
properties for third  parties.  In conjunction  with the above  activities,  the
Company owns and operates oil and gas properties in six states, predominantly in
the Southwest  region of the United  States.  In addition,  the Company owns and
operates  two  gathering  systems  located  in Texas  and  Oklahoma  and owns an
interest in three natural gas processing  plants located in Texas,  Oklahoma and
Arkansas.

Consolidation

     The accompanying  consolidated financial statements include the accounts of
the Company and its existing  wholly-owned  subsidiaries,  Bluebird Energy, Inc.
("Bluebird"),  Gruy Petroleum Management Company ("Gruy"), Hunter Gas Gathering,
Inc.,  Inesco  Corporation,  Magnum  Hunter  Production,  Inc.,  Midland  Hunter
Petroleum  Limited  Liability  Company and SPL Gas  Marketing,  Inc. The Company
consolidates on a pro rata basis its approximately 39% ownership of TEL Offshore
Trust.  The Company  accounts for its  investment in NGTS,  LLC under the equity
method.  All  significant  intercompany  accounts  and  transactions  have  been
eliminated in  consolidation.  Certain  reclassifications  have been made to the
consolidated  financial statements of the prior year to conform with the current
presentation.

     The Company is a holding  company with no significant  assets or operations
other than its investments in its subsidiaries. The wholly-owned subsidiaries of
the Company,  except for  Bluebird,  are direct  Guarantors of the Company's 10%
Senior Notes and have fully and unconditionally  guaranteed the Notes on a joint
and  several  basis.  The  Guarantors  comprise  all of the direct and  indirect
subsidiaries of the Company (other than Bluebird), and the Company has presented
separate  condensed  consolidating  financial  statements and other  disclosures
concerning each Guarantor and Bluebird (See Note 17). There is no restriction on
the ability of consolidated or unconsolidated  subsidiaries to transfer funds to
the Company in the form of cash dividends,  and,  except for Bluebird,  loans or
advances.

     Bluebird  was formed in December  1998.  As part of the  capitalization  of
Bluebird,  the Company  contributed to Bluebird  1,840,271 units of TEL Offshore
Trust. Bluebird, as an "unrestricted subsidiary" as defined under certain credit
agreements,  is neither a guarantor of the  Company's  10% Senior Notes due 2007
nor  can  it be  included  in  determining  compliance  with  certain  financial
covenants under the Company's credit agreements.

Cash and Cash Equivalents

     The Company  considers all highly liquid debt instruments  purchased with a
maturity of three  months or less to be cash  equivalents.  The Company has cash
deposits in excess of federally insured limits.

Restricted Cash

     Prior  to May,  2001,  the cash  balance  of  Bluebird  was  classified  as
restricted cash as a result of a credit agreement  entered into between Bluebird
and certain banks. Under this credit agreement,  cash funds of Bluebird were not
permitted  to be  commingled  with Magnum  Hunter or its other  subsidiaries  or
affiliates  and could not be  dividended or loaned to Magnum Hunter or its other
subsidiaries  or  affiliates,  but were  required to be used to satisfy the cash
requirements  of  Bluebird,  including  the  payment of  Bluebird's  outstanding
borrowings.  During May 2001,  Bluebird  sold certain oil and gas  properties to
Magnum Hunter  Production,  Inc. and used a portion of the proceeds  received to
repay all outstanding debt and to terminate the credit agreement.

                                       F-6

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Investments

     The  Company  follows  accounting  procedures  according  to  Statement  of
Financial   Accounting  Standards  ("SFAS")  No.  115,  Accounting  for  Certain
Investments  in Debt and  Equity  Securities.  Under this  standard,  the equity
securities  held by the Company that have readily  determinable  fair values are
classified as current or non-current assets, available-for-sale and are measured
at fair value. Unrealized gains and losses for these investments are reported as
comprehensive  income and  included  as a separate  component  of  stockholders'
equity.  Realized  gains  and  losses  are  calculated  based  on  the  specific
identification method.

     At December 31, 2000,  the  Company's  available-for-sale  securities  were
classified as non-current  assets and included in deposits and other assets. The
securities had a cost basis of $2,762,000,  gross unrealized  losses reported in
accumulated other  comprehensive  income of $507,000 ($466,000 net of income tax
benefit) and had a fair market value of  $2,255,000  based on the quoted  market
price.  At December 31, 2001,  the Company  determined  that the  securities had
suffered an other than  temporary  impairment  as a result of the  deteriorating
financial  condition of the entity and a steadily  declining market value of the
securities.  As a result, at December 31, 2001, the Company reported a provision
for impairment of  investments of $2,142,000 as a charge against  earnings and a
reclassification in accumulated other comprehensive income of $507,000 ($466,000
net of income tax).

     During  2000,  the  Company  acquired a minority  ownership  interest  in a
privately  held  entity  that  provides  remote data  collection  and  web-based
monitoring  services for the company and other entities  operating in the energy
industry.  The total  invested by the Company in 2000 was $2.5 million,  and the
investment was carried at cost on the balance sheet at December 31, 2000. During
2001, the Company made an additional  equity investment of $2 million as well as
secured loans totaling  $453,000,  including accrued  interest.  At December 31,
2001, the Company's total equity investment of $4,528,000  represented less than
10% of the entity's  common  equity.  As a result of the  entity's  inability to
obtain additional  anticipated equity financing from third parties at the end of
2001,  the entity  subsequently  declared  bankruptcy.  The  Company  reported a
provision for  impairment  of  investments  of  $4,981,000  as a charge  against
earnings at December 31, 2001.

ESOP

     As required  under  Statement of Position 93-6  "Employers'  Accounting for
Employee Stock  Ownership  Plans,"  compensation  expense is recorded for shares
committed  to be released to  employees  based on the fair market value of those
shares when they are committed to be released.  The difference  between cost and
the fair market  value of the  committed  to be  released  shares is recorded in
additional paid-in-capital. Unreleased shares held by the ESOP are excluded from
the calculation of earnings per share.

Suspended Revenues

     Suspended  revenue  interests  represent oil and gas sales payable to third
parties largely on properties  operated by the Company.  The Company distributes
such  amounts  to third  parties  upon  receipt  of  signed  division  orders or
resolution of other legal matters.

Oil and Gas Producing Operations

     Magnum Hunter  follows the full-cost  method of accounting  for oil and gas
properties. Accordingly, all costs associated with acquisition,  exploration and
development of oil and gas reserves,  including directly related overhead costs,
are capitalized. Internal costs that directly relate to acquisition, exploration
and development  activities that were  capitalized  totaled $600,000 for each of
the years ended December 31, 2001, 2000 and 1999,  respectively.  The balance of
capitalized  costs  included  in oil and gas  properties  for  the  years  ended
December  31,  2001 and  2000  were  $3,279,000  and  $2,679,000,  respectively.
Management  believes  that the basis it uses to determine the amount of internal
costs capitalized is appropriate.

     All capitalized  costs of oil and gas  properties,  including the estimated
future  costs  to  develop  proved  reserves  and  estimated  dismantlement  and
abandonment   costs,   net   of   salvage   values,   are   amortized   on   the
unit-of-production  method using  estimates of proved  reserves.  Costs directly
associated  with the  acquisition  and  evaluation  of unproved  properties  are
excluded from the amortization base until the related  properties are evaluated.
Such unproved  properties  are assessed for impairment at least annually and any
provision for  impairment is  transferred  to the full-cost  amortization  base.
Sales of oil and gas properties,  including consideration received from sales or
transfers  of  properties  in  connection  with   partnerships,   joint  venture
operations or drilling  arrangements,  are credited to the full-cost pool unless
the sale would have a significant effect on the amortization  rate.  Abandonment
of properties is accounted  for as an  adjustment to  capitalized  costs with no
loss recognized.

                                       F-7

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     A summary of the unproved  properties  excluded from oil and gas properties
being  amortized  at December 31, 2001 and 2000,  respectively,  and the year in
which they were incurred follows:


                                               December 31, 2001
                                                  Incurred In
                                                (in thousands)
                             ------------------------------------------------
                               1998    1999     2000     2001       Total
                               ----    ----     ----    -------    -------
Property Acquisition Costs... $  513   $1,464  $ 360    $12,226     $14,563
Exploration Costs............      -        -      -      4,090       4,090
                             ------------------------------------------------
     Total................... $  513   $1,464  $ 360    $16,316     $18,653
                             ================================================

                                            December 31, 2000
                                               Incurred In
                                             (in thousands)
                           -------------------------------------------------
                             Prior    1998      1999     2000      Total
                             -----    ----      ----    ------   --------
Property Acquisition Costs..  $  -    $ 1,397   $1,485  $1,080   $3,962
Exploration Costs...........     -          -        -   1,572    1,572
                           -------------------------------------------------
     Total..................  $  -    $ 1,397   $1,485  $2,652   $5,534
                           =================================================

     Costs are transferred into the amortization base on an ongoing basis as the
projects  are  evaluated  and proved  reserves  are  established  or  impairment
determined.  Pending  determination of proved reserves attributable to the above
costs, the Company cannot assess the future impact on the amortization rate.

     The  capitalized  costs are subject to a "ceiling  test,"  which  generally
limits such costs less  accumulated  amortization  and related  deferred  income
taxes to the  aggregate of the  estimated  present  value of future net revenues
from proved  reserves  discounted at ten percent  based on current  economic and
operating  conditions less income tax effects related to the differences between
the  book and tax  basis  of the oil and gas  properties.  The  ceiling  test is
performed on a quarterly basis. At December 31, 2001, the Company's  capitalized
costs of its oil and gas properties  exceeded the PV-10  limitation using prices
in effect at December  31,  2001 by  $75,984,000.  However,  no  write-down  for
impairment of oil and gas properties was required as a result of the increase in
oil and gas prices  subsequent to December 31, 2001. The Company  experienced no
impairment in 2000 or 1999.

     All costs  relating  to  production  activities  are  charged to expense as
incurred.

     Amortization  expense per thousand cubic feet  equivalent was $1.28,  $0.89
and $0.79 for the years ended December 31, 2001, 2000 and 1999, respectively.

Derivative Instruments

     The Company's  product price and interest hedging  activities are described
in Note 13 to the consolidated  financial  statements.  Periodically the Company
enters into futures,  options,  and swap contracts to reduce the adverse effects
of  fluctuations  in crude oil and gas prices on anticipated  future oil and gas
production.  It is the  policy  of  the  Company  to not  enter  into  any  such
arrangements which cause the Company's aggregate hedge position to exceed 75% of
the oil and gas production  during the projected next 12 months. We also utilize
financial  derivative  instruments to hedge the risk associated with interest on
our  outstanding  debt.  Generally,   the  cash  settlement  of  all  derivative
instruments is recognized as income or expense in the period in which the hedged
transaction is recognized.

     Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative  Instruments and Hedging  Activities"  (SFAS No. 133), as extended by
SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000),  was effective
for the Company beginning  January 1, 2001. SFAS No. 133 establishes  accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of derivatives in the balance sheet and the measurement of those
instruments at fair value.  Derivative  instruments  that are not hedges must be
adjusted to the fair value through net income  (loss).  Under the  provisions of
SFAS 133,  changes in the fair  value of  derivative  instruments  that are fair
value hedges are offset against  changes in the fair value of the hedged assets,
liabilities, or firm commitments, through net income (loss). Changes in the fair
value of  derivative  instruments  that are cash-flow  hedges are  recognized in
other

                                       F-8

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     comprehensive  income  (loss)  until  such  time as the  hedged  items  are
recognized  in  net  income  (loss).   Ineffective   portions  of  a  derivative
instrument's  change in fair  value are  immediately  recognized  in net  income
(loss).

     The Company was  obligated to four crude oil  derivatives,  one natural gas
derivative,  and one interest rate  derivative  on January 1, 2001.  The Company
determined that the interest rate derivative did not qualify for hedge treatment
as defined  within  SFAS No.  133.  The crude oil and  natural  gas  derivatives
qualified as cash-flow hedges.

     At January 1, 2001,  all  derivatives  within the Company  were  identified
pursuant to SFAS No. 133 requirements,  and the Company  designated,  documented
and assessed all hedging  relationships.  Adoption of this  accounting  standard
resulted in the  recognition  of $179 thousand of a derivative  asset related to
the interest rate  derivative and an increase in the carrying value of long-term
debt with recourse of $179 thousand.  In June,  2001 the Company  terminated its
position in this  derivative.  For the year ended December 31, 2001, the Company
recognized a gain of $980  thousand as a reduction of interest  expense for this
derivative.

     With respect to the cash-flow hedges, at the accounting change  transition,
the Company  recorded a derivative  asset of $648 thousand  related to the crude
oil derivatives with a cumulative effect increase to other comprehensive  income
of $403  thousand  (net of income  taxes)  and a  derivative  liability  of $3.5
million related to the natural gas derivatives with a cumulative effect decrease
to other comprehensive income of $2.2 million (net of income taxes).

     In May,  2001, the Company  entered into  additional  costless  collars for
crude oil for the periods July 2001 through December 2001. In August,  2001, the
Company  entered  into a swap  transaction  for  natural  gas  for  the  periods
September   2001  through   November  2001  and  interest  rate  swaps  (receive
variable/pay fixed) on $50 million of its variable rate bank debt for the period
August 2001 through August 2003.  These crude oil, natural gas and interest rate
derivatives qualify as cash flow hedges.

     At December 31,  2001,  the Company had no crude oil  derivatives,  and its
natural  gas  derivatives  had a fair  value  of  $3.6  million,  recognized  as
derivative  assets of $5.1 million and  derivative  liabilities of $1.5 million.
The  Company  recognized  a  liability  of $1.0  million  on its  interest  rate
derivatives. For the year ended December 31, 2001, the income statement includes
a gain of $1.3  million  related  to the crude oil  derivatives,  a gain of $3.4
million  related to the natural gas  derivatives  and a loss of $204 thousand on
interest  rate   derivatives,   net  of  amounts   reclassified   out  of  other
comprehensive  income.  The Company expects that the remaining  balance in other
comprehensive income related to the natural gas derivatives at December 31, 2001
will be reclassified  into the income  statement within the next eighteen months
and for the interest rate derivatives within the next twenty months.

Pipelines and Processing Plant

     Pipelines  and  processing  plant  are  carried  at cost.  Depreciation  is
provided  using the  straight-line  method over an  estimated  useful life of 15
years.  Gain or loss on  retirement  or sale or other  disposition  of assets is
included  in results of  operations  in the period of  disposition.  The Company
reviews  the  carrying  value  of  pipelines  and  processing  plant  and  other
long-lived  assets  (other  than oil and gas  assets  accounted  for  under  the
full-cost method) for impairment whenever events and circumstances indicate that
the carrying value of an asset may not be recoverable  from the estimated future
cash flows  expected to result from its use and eventual  disposition.  In cases
where the  undiscounted  expected  future cash flows are less than the  carrying
value, an impairment loss is recognized equal to an amount by which the carrying
value exceeds the fair value of assets.

Other Property

     Other property and equipment are carried at cost.  Depreciation is provided
using the straight-line  method over estimated useful lives ranging from five to
ten years.  Gain or loss on retirement or sale or other disposition of assets is
included in results of operations in the period of disposition.

Other Oil and Gas Related Services

     Other oil and gas related  services consist largely of fees earned from the
Company's  operation of oil and gas properties for third parties.  Such fees are
recognized in the month the service is provided.

     Magnum Hunter does not recognize  income in connection with drilling,  well
service or other services provided in connection with

                                       F-9

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     oil and gas  properties  in which the Company  holds an  ownership or other
economic interest to the extent of the Company's interest. Any proceeds received
for services  performed  that are not  recognized  as income are credited to the
full cost pool.

Income Taxes

     The Company files a consolidated  federal  income tax return.  Income taxes
are  provided  for the tax effects of  transactions  reported  in the  financial
statements  and consist of taxes  currently due, if any, plus net deferred taxes
related primarily to differences between the basis of assets and liabilities for
financial  and  income  tax  reporting.  Deferred  tax  assets  and  liabilities
represent the future tax return  consequences  of those  differences  which will
either be taxable or deductible when the assets and liabilities are recovered or
settled.  Deferred tax assets include  recognition of operating  losses that are
available to offset future  taxable income and tax credits that are available to
offset  future  income  taxes.  Valuation  allowances  are  recognized  to limit
recognition  of deferred tax assets where  appropriate.  Such  allowances may be
reversed when  circumstances  provide evidence that the deferred tax assets will
more likely than not be realized.

New Accounting Standards

     SFAS No. 141 - SFAS No. 141, "Business Combinations",  is effective for the
Company  beginning  July 1, 2001.  SFAS No. 141 requires the use of the purchase
method of accounting  for business  combinations  initiated and completed  after
June 30, 2001 and eliminates the use of the  pooling-of-interests  method. As of
July 1,  2001,  the  adoption  of SFAS  No.  141 did not have an  impact  on the
Company's consolidated financial statements.

     SFAS No. 142 - SFAS No. 142, "Goodwill and Other Intangible  Assets",  will
be effective for the Company  beginning  January 1, 2002. SFAS No. 142 requires,
among other things,  the discontinuance of goodwill  amortization.  Any goodwill
resulting from acquisitions completed after June 30, 2001 will not be amortized.

     In addition,  SFAS No. 142 requires the Company to complete a  transitional
goodwill  impairment  test  within  six  months  from the date of  adoption  and
establishes a new method of testing goodwill that could reduce the fair value of
a reporting unit below its carrying value.  Any goodwill  impairment loss during
the transition period will be recognized as the cumulative effect of a change in
accounting principle. Subsequent impairments will be recorded in operations. The
adoption  of SFAS  No.  142 will not have a  material  impact  on the  Company's
consolidated financial statements.

     SFAS No. 143 - SFAS No. 143, "Accounting for Asset Retirement Obligations",
will be  effective  for the  Company  beginning  January 1,  2003.  SFAS No. 143
requires the recognition of a fair value liability for any retirement obligation
associated  with long- lived  assets.  The offset to any  liability  recorded is
added to the recorded asset where the additional  amount is depreciated over the
same  period as the  long-lived  asset for which the  retirement  obligation  is
established.  SFAS No. 143 also requires additional disclosures.  The Company is
in the process of evaluating the impact of the provisions of SFAS No. 143.

     SFAS No. 144 - SFAS No. 144,  "Accounting for the Impairment or Disposal of
Long-Lived Assets", will be effective for the Company beginning January 1, 2002.
SFAS No. 144  establishes  a single  accounting  model,  based on the  framework
established in SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets
and for  Long-Lived  Assets to Be  Disposed  Of",  for  long-lived  assets to be
disposed of by sale and resolves  significant  implementation  issues related to
SFAS No.  121.  The Company is in the  process of  evaluating  the impact of the
provisions of SFAS No. 144.

Income or Loss Per Common Share

     Basic net income or loss per common  share is computed by dividing  the net
income or loss  attributable  to common  stockholders  by the  weighted  average
number of shares of common  stock  outstanding  during the  period.  Diluted net
income or loss per  common  share is  calculated  in the same  manner,  but also
considers the impact to net income and common shares for the potential  dilution
from  stock  options,  stock  warrants  and any  other  outstanding  convertible
securities.

     The following table reconciles the numerators and denominators  used in the
computations of both basic and diluted EPS as

                                      F-10

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     required by SFAS No. 128, "Earnings per Share":


<TABLE>
<CAPTION>
<S>                              <C>          <C>        <C>     <C>        <C>           <C>      <C>          <C>       <C>
                                       For the Year Ended                For the Year Ended                For the Year Ended
                                        December 31, 2001                 December 31, 2000                 December 31, 1999
                               -----------------------------------------------------------------------------------------------------
                                                            Per                              Per                               Per
                                  Income        Shares     Share    Income      Shares      Share      Loss       Shares      Share
                                (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount  (Numerator) (Denominator)  Amount
                                ----------------------------------------------------------------------------------------------------
Income (Loss) before
     Extraordinary Item........  $13,820,000  34,819,614  $0.40 $22,260,000    20,856,854 $1.07  $ (6,826,000)   19,743,738  $(0.34)
Net Income (Loss)..............     (304,000)             (0.01)          -                   -            -                      -
     Less: Preferred Stock
       dividends...............  $13,516,000                    $22,260,000                      $ (6,826,000)
Net Income (Loss)..............                                 $22,260,000                      $ (6,826,000)
     Less: Preferred Stock
           dividends...........            -                  -  (9,708,000)              $(0.47)  (4,509,000)               $(0.23)
                                ----------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available to
     common stockholders.......  $13,516,000  34,819,614  $0.39  12,552,000    20,856,854 $0.60   (11,335,000)   19,743,738  $(0.57)
Effect of dilutive securities
   Warrants....................                  212,512                  -       571,623                   -             -
   Options.....................                2,076,850                  -     1,247,063                   -             -
   Convertible preferred stock.                        -          4,312,000    10,158,730                   -             -
Diluted EPS
Income (Loss) available to
     common stockholders and   -----------------------------------------------------------------------------------------------------
     assumed conversions......   $13,516,000  37,108,976  $0.36 $16,864,000    32,834,270 $0.51  $(11,335,000)   19,743,738  $(0.57)
                               =====================================================================================================
     Add back: Extraordinary
       Item..................       (304,000)             (0.01)          -                   -             -                     -
                               ----------------------------------------------------------------------------------------------------
Income (Loss) before
     Extraordinary Item......    $13,820,000              $0.37 $16,864,000               $0.51  $(11,335,000)               $(0.57)
                               =====================================================================================================
</TABLE>

     For the year ended  December 31,  2001,  basic and diluted EPS includes the
effect of an extraordinary  loss from early  extinguishment of debt of $304,000,
or $(.01) per share.

     At December 31, 2001,  the Company had  outstanding  644,749  warrants at a
weighted  average  price of $6.75 per  share,  5,217,584  options  at a weighted
average  exercise  price of $6.22  per  share,  and no  outstanding  convertible
preferred stock. Warrants totaling 432,237 shares and options totaling 3,140,734
shares were excluded from the diluted net income per share  computation  in 2001
as the exercise price exceeded the average market price of the Company's  common
stock.

     At December 31, 2000,  the Company had  outstanding  644,749  warrants at a
weighted  average  price of $6.75 per  share,  4,702,400  options  at a weighted
average  exercise price of $4.97 per share, and 25,000 shares of preferred stock
convertible to common stock at a weighted average  conversion price of $5.25 per
share.  Warrants  totaling 73,126 shares and options  totaling  3,455,337 shares
were excluded from the diluted net income per share  computation  in 2000 as the
exercise price exceeded the average market price of the Company's common stock.

     At December 31, 1999, the Company had outstanding  10,583,149 warrants at a
weighted  average  price of $6.49 per  share,  3,866,092  options  at a weighted
average  exercise  price of $3.57 per share,  and 1,050,000  shares of preferred
stock  convertible  to common stock at a weighted  average  conversion  price of
$5.25 per share. The warrants,  options and preferred stock were not included in
the computation of diluted earnings per share in 1999 since the Company incurred
a net loss for the year and any effect would have been anti-dilutive.

Revenue Recognition

     Revenues are recognized when title to the product  transfers to purchasers.
The Company  follows the "sales  method" of  accounting  for revenue for oil and
natural gas  production,  so that sales revenue is recognized on all  production
sold to  purchasers,  regardless of whether the sales are  proportionate  to the
Company's  ownership in the  property.  A receivable  or liability is recognized
only to the extent that we have an imbalance on a specific property greater than
the expected remaining proved reserves.  Ultimate revenues from the sales of oil
and gas  production is not known with  certainty  until up to three months after
production  and title  transfer  occur.  Current  revenues are accrued  based on
expectations of actual deliveries and actual prices received.

                                      F-11

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Inflation and Changes in Prices

     The results of operations  and cash flow of the Company have been, and will
continue to be,  affected by the  volatility  in oil and gas prices.  Should the
Company  experience  a  significant  increase  in oil  and  gas  prices  that is
sustained  over a prolonged  period,  it would expect that there would also be a
corresponding  increase in oil and gas finding costs,  lease acquisition  costs,
and operating expenses.

     The Company  markets  oil and gas for its own  account,  which  exposes the
Company  to  the  attendant  commodities  risk.  A  significant  portion  of the
Company's gas production is currently sold to a 30% owned affiliate,  NGTS, LLC,
or  end-users  either  (i) on the  spot  market  on a  month-to-month  basis  at
prevailing spot market prices or (ii) under long-term contracts based on current
spot market  prices.  The Company  normally  sells its oil under  month-to-month
contracts to a variety of purchasers.

Use of Estimates and Certain Significant Estimates

     The  preparation of the Company's  financial  statements in conformity with
accounting  principles  generally  accepted  in the  United  States  of  America
requires the Company's  management to make estimates and assumptions that affect
the amounts  reported in these  financial  statements  and  accompanying  notes.
Actual results could differ from those  estimates.  Significant  assumptions are
required in the  valuation  of proved oil and gas  reserves,  which as described
above may affect the amount at which oil and gas properties are recorded.  It is
at least  reasonably  possible those estimates could be revised in the near term
and those revisions could be material.

Treasury Stock

     The  Company  may  repurchase  shares of common  stock in stock  repurchase
programs.  The Company's  repurchases  of shares of common stock are recorded as
Treasury Stock at cost and result in a reduction of Stockholders'  Equity.  When
treasury shares are reissued,  the Company uses a first-in  first-out method and
the difference  between  repurchase  cost and reissuance  price is treated as an
adjustment to paid-in capital.

NOTE 2 -- ACQUISITIONS AND DISPOSITIONS

     On June 10, 1999, the Company and Bluebird  acquired from Vastar Resources,
Inc.,  interest  in oil  and  gas  reserves  producing  from  476  wells,  a gas
processing  plant and two gas gathering  systems located in the states of Texas,
Oklahoma and Arkansas for a purchase price of $32.5 million after purchase price
adjustments. The effective date of the transaction was April 1, 1999.

     On December  1, 1999,  Bluebird  acquired a 50%  interest in the Madill Gas
Processing  Plant and  associated  gas  gathering  system from Dynegy Inc. for a
purchase price of $4.1 million after purchase price  adjustments.  The effective
date of the transaction was November 1, 1999.

     The following summary,  prepared on a pro forma basis, presents the results
of  operations  for the year  ended  December  31,  1999 as if the  acquisitions
occurred as of the beginning of the year. The pro forma information includes the
effects  of  adjustments  for  increased  general  and  administrative  expense,
interest expense, depreciation, depletion and income taxes:

                                                             (Unaudited)
                                                      --------------------------
                                                      (in thousands, except for
                                                         per share amounts)
                                                      --------------------------
Revenue..............................................     $       73,104
Net Income (Loss) Applicable to Common Stock.........            (12,022)
Net Income (Loss) Per Common Share
  Basic..............................................     $        (0.61)
  Diluted............................................     $        (0.61)

     Effective  September  1,  2000 the  Company  acquired  a 5.5%  net  profits
interest in the Panoma production and gas gathering  facilities for $3.5 million
of the  Company's  restricted  common stock.  By acquiring  this  interest,  the
Company  lowered its lease  operating  expense and increased oil field  services
income.

                                      F-12

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     Effective April 1, 2000 the Company exchanged  interests in certain onshore
oil producing properties for interests in certain offshore oil and gas producing
properties and production facilities located in the Gulf of Mexico in a tax free
like-kind  exchange.  The transaction did not have a material effect on reported
production in 2000, but the Company gained  significantly  increased exposure in
an  offshore  area of  interest  where it has been  conducting  exploration  and
development activities.

     During 2000, the Company  realized  proceeds of $43.8 million from the sale
of  non-core  oil and gas and other  properties,  of which  approximately  $11.6
million was attributable to Bluebird.

     Effective July 1, 2001, the Company  acquired proved oil and gas properties
located in Southeast New Mexico totaling approximately 41.8 Bcfe of reserves for
$31.6  million,  net of  purchase  price  adjustments.  The  transaction  had an
effective date of July 1, 2001.

NOTE 3 -- NOTES RECEIVABLE

     At December 31, 2000, the balance of a note receivable, net of allowance of
$1,170,000,  was $50,000. During 2001, the Company received a payment of $50,000
to apply against this note.

NOTE 4 -- RELATED PARTY TRANSACTIONS

     In conjunction with the acquisition of Hunter in December 1995, the Company
assumed  a note  receivable  with a  balance  of  $379,321  from an  owner in an
affiliated  limited  liability  company.  The note  provides  for interest at 10
percent and had a due date of December  31,  2000.  The note was not paid by the
due date,  and the Company has commenced  legal  proceedings in order to recover
the amount due. The note is secured by interest in a real estate joint venture.

     At December  31, 2001 and 2000,  the  Company's  note  receivable  from the
Magnum  Hunter   Employee  Stock   Ownership  Plan  (ESOP)  was  $2,576,000  and
$2,780,000,  respectively.  The  purpose  of the  loan is to  allow  the ESOP to
purchase Magnum Hunter  Resources  common stock on the open market.  The loan is
interest  free,  due December 31, 2004 and is secured by shares of the Company's
common stock which have not been earned by participants in the ESOP. At December
31, 2001 and 2000,  the number of unearned  shares in the ESOP were  468,652 and
680,282,  respectively.  The unearned shares and their  corresponding costs were
reflected on the  consolidated  balance  sheets of the Company as  reductions to
stockholders' equity.

     During 1998, the Company's Board of Directors authorized the acquisition of
certain shares of a publicly  traded oil and gas company from Mr. Gary C. Evans,
President and Chief Executive  Officer of the Company,  at Mr. Evans' cost basis
in such shares of stock for purposes of a long-term investment.  The shares were
purchased for a total of $442,019.  The Company has the right to cause Mr. Evans
to repurchase the shares back from the Company at the equivalent  price that the
Company  purchased the shares from Mr. Evans.  The value paid for the shares was
in excess of the publicly traded value of the shares on the acquisition  date by
$159,481.  For accounting purposes, the purchase price of the shares was treated
as  a  receivable  from  stockholder  and  has  been  shown  as a  reduction  to
stockholders' equity at December 31, 2001, 2000 and 1999.

     During December 1998, the Company's Board of Directors authorized a loan of
up to $300,000 be made available to Mr. Evans, as part of his 1998  compensation
package and to exercise  certain  stock  options.  A total of $230,000 was drawn
under the loan and was  outstanding at December 31, 1998.  During the year ended
December 31, 1999,  the Company  advanced an additional  $188,000 and was repaid
$65,000,  leaving a balance due the  Company,  including  accrued  interest,  of
$371,860 at December 31, 1999,  which was  authorized by the Board of Directors.
The  unpaid  principal  amount  of  these  loans  was  classified  as a loan  to
stockholder  at December 31, 1999 and 1998 and as a reduction  to  stockholders'
equity.  On January 7, 2000,  Mr. Evans repaid  $225,000 on the loan,  leaving a
principal balance of $146,860.  On April 17, 2000 Mr. Evans re-borrowed $100,000
under this loan, and on August 18, 2000, he repaid $258,731,  including  accrued
interest, bringing the balance to zero. On December 28, 2000, Mr. Evans borrowed
$294,938,  which was the balance  owed to the  Company on December  31, 2000 and
included in notes  receivable  from  affiliate.  On January 15, 2001,  Mr. Evans
repaid $295,261,  including accrued  interest,  bringing the balance to zero. On
April 16, 2001, the Company loaned Mr. Evans $300,000, under an authorization by
the Board of Directors,  on a note with an interest rate of 10% and due December
31,  2001.  At year end,  this loan was  classified  as a note  receivable  from
affiliate.  Subsequent to year end, Mr. Evans repaid $328,931, including accrued
interest, bringing the principal and interest balance to zero.

                                      F-13

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     On November 28, 2000, Mr. Matthew C. Lutz,  then the Chairman and Executive
Vice  President  of the  Company,  borrowed  $65,000  from the Company  with the
approval of the Board of  Directors.  On January 15,  2001,  Mr. Lutz repaid the
loan, including accrued interest.

NOTE 5 -- DEBT

     Notes payable and long-term debt at December 31, 2001 and 2000 consisted of
the following:

<TABLE>
<CAPTION>
<S>                                                                           <C>                 <C>
                                                                                    2001          2000
                                                                                      (in thousands)
                                                                            ----------------------------------
Notes Payable:
Note payable to vendor, due January 31, 2002, interest at 7% payable
    on due date (a)........................................................     $  2,532         $     -
Note payable to vendor, due February 28, 2002, interest at 7% payable
on due date (a)............................................................        1,512               -
                                                                           ------------------------------------
               Total Notes Payable.........................................     $  4,044         $     -
                                                                           ====================================
Long-Term Debt, with recourse to the Company:

Banks
Revolving promissory note, collateralized by pipeline and oil and gas
  properties, due April 30, 2003 (effective rate of 4.7% and 8.5% at
       December 31, 2001 and 2000, respectively) (b).......................     $155,000         $  30,500
Other
Senior notes, unsecured, due June 1, 2007, interest at 10% payable
  semi-annually on June 1 and December 1...................................      140,000           140,000

   Less: Notes re-purchased and held in treasury                                 (10,534)              -
                                                                           ------------------------------------
      Net Senior notes outstanding                                               129,466           140,000
                                                                           ------------------------------------

Other......................................................................           73                39
                                                                           ------------------------------------
              Total Long-Term Debt, with recourse                               $284,539         $ 170,539
                                                                                     73                 19
                 Less Current Portion...................................... -----------------------------------
         Long-Term Debt, with recourse.....................................     $284,466         $ 170,520
                                                                           ====================================
Long-Term Debt, non recourse to the Company:

Banks
Revolving promissory note, collateralized by pipeline and oil and gas properties
  and 1,840,270 units of TEL Offshore Trust, due June 7,
  2002   (effective rate of 9.48% at December 31, 2000) (c)................     $    -           $  20,600
                                                                             -----------------  ---------------
         Total Long-Term Debt, non recourse................................     $    -           $  20,600
                                                                             ==================  ==============
</TABLE>

                                      F-14

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     Maturities  of long-term  debt based on  contractual  requirements  for the
years ending December 31, are as follows:

                                         (in thousands)
2002..................................              73
2003..................................         155,000
2004 to 2006..........................               -
2007..................................         129,466
                                      ------------------
         Total........................       $ 284,539
                                      ==================

     (a) The due dates on the notes payable to vendors was extended to March 15,
2002. On that date, both notes were paid off.

     (b) The  revolving  promissory  note to the  banks is a  borrowing  under a
$225,000,000  line  of  credit  on  which  there  existed  a  borrowing  base of
$160,000,000  at December 31, 2001. The level of the borrowing base is dependent
on the valuation of the assets  pledged,  primarily oil and gas reserve  values.
The line of credit includes  covenants,  the most  restrictive of which requires
maintenance of a current ratio, interest coverage ratio, and tangible net worth,
as specified in the loan  agreement.  The bank group must approve all  dividends
paid on common stock. The credit  agreement  provides for both "LIBOR" and "Base
Rate" (Prime) interest rate options.  At December 31, 2001, the amounts borrowed
at these rates were:

                                                (in thousands)
LIBOR + 2.5% (total of 4.64%)................    $     145,000
Base Rate (Prime) + 1.0% (total of 5.75%)....           10,000
                                             --------------------
       Total.................................    $     155,000
                                             ====================

     (c) The  revolving  promissory  note to the  banks  was  borrowing  under a
$75,000,000  line  of  credit  on  which  there  existed  a  borrowing  base  of
$42,000,000  at December 31, 2000. The level of the borrowing base was dependent
on the valuation of the assets pledged,  primarily oil and gas reserves, natural
gas processing  plants,  and units of Tel Offshore  Trust.  On May 17, 2001, the
loan  under  this line of credit  was  repaid in full and the line of credit was
terminated.

NOTE 6 -- PRODUCTION PAYMENT LIABILITY

     In  November,   1996,  the  Company  entered  into  a  production   payment
conveyance.  The Company  received a production  payment  amount of $750,000 and
agreed to make royalty payments of up to 50% of the monthly net revenue proceeds
received  from  certain  oil and gas  properties.  The  balance  owed  under the
conveyance   was   $203,000   and  $359,000  at  December  31,  2001  and  2000,
respectively.  The  production  payment bears  interest at the rate of 13.5% per
annum and is non-recourse to the Company.

NOTE 7 -- INCOME TAXES

     The Company  accounts  for income  taxes in  accordance  with SFAS No. 109,
"Accounting for Income Taxes",  which requires the recognition of a liability or
asset,  net of a valuation  allowance,  for the deferred tax consequences of all
temporary  differences  between the tax bases and the reported amounts of assets
and liabilities, and for the future benefit of operating loss carryforwards. The
following is a reconciliation of income tax expense reported in the statement of
operations:

<TABLE>
<CAPTION>
<S>                                                     <C>                     <C>              <C>

                                                               2001              2000              1999
                                                                            (in thousands)
                                                        -----------------------------------------------------
Income tax expense (benefit) at statutory rates......... $       7,850          $   10,191        $ (2,352)
State tax expense (benefit).............................           818                 829            (193)
Increase in operating loss and other carryovers.........          (493)                  -               -
Change in valuation allowance...........................             -              (3,875)          2,315
Other...................................................           433                 410             230
                                                        -----------------------------------------------------
       Tax expense...................................... $       8,608          $    7,555        $      -
                                                        =====================================================
</TABLE>

                                      F-15

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     The tax effects of significant  temporary differences and carryforwards are
as follows:

<TABLE>
<CAPTION>
<S>                                                                    <C>                          <C>
                                                                                      December 31,
                                                                       --------------------------------------------
                                                                             2001                       2000
                                                                                     (in thousands)
                                                                       --------------------------------------------
Property and equipment, including intangible drilling costs...........   $    (38,005)               $  (18,855)

Derivative instruments................................................           (995)                      -
Other.................................................................            (41)                      -
                                                                      ---------------------------------------------
         Total deferred tax liability.................................   $     (39,041)              $  (18,855)
Allowance for doubtful accounts.......................................           3,125                      577
Reserves..............................................................              33                       33
Depletion carryforwards...............................................           1,003                      510
Alternative minimum tax credit........................................              98                      234
Employee stock options................................................           2,350                      -
Operating loss and other carryforwards................................          38,034                   30,219
                                                                       --------------------------------------------
         Total deferred tax assets....................................          44,643                   31,573
                                                                       --------------------------------------------
Valuation allowance...................................................          (7,100)                  (7,100)
                                                                       --------------------------------------------
         Net Deferred Tax Asset (Liability)...........................   $      (1,498)              $    5,618
                                                                      =============================================

</TABLE>

     The Company and its subsidiaries  have net operating loss  carryforwards of
approximately  $105,912,000  that expire, if unused, in years 2009 through 2021.
Current tax laws and  regulations  relating to  specified  changes in  ownership
limit  the  utilization  of the  Company's  net  operating  loss and tax  credit
carryforwards. A change in ownership of greater than 50% of a corporation within
a three year period causes the annual limitations to be placed in effect. Such a
change is deemed  to have  occurred  February  3,  1999 in  connection  with the
purchase of preferred stock by ONEOK Resources  Company,  which has subsequently
been either redeemed or converted to common stock. Approximately $556,000 of the
net  operating  losses are  subject to a  limitation  of  $556,000  per year and
$50,857,000 are subject to a limitation of $7,850,000 per year. In addition, the
Company has depletion  carryforwards of $2,648,000 with no expiration  period. A
valuation  allowance  reduces  deferred taxes based on the criteria set forth in
SFAS 109.

NOTE 8 -- STOCKHOLDERS' EQUITY

Preferred Stock

     Shares  of  preferred  stock  may be  issued  in  such  series,  with  such
designations,  preferences, stated values, rights, qualifications or limitations
as determined  solely by the Board of  Directors.  Of the  10,000,000  shares of
$.001 par value  preferred  stock the Company is  authorized  to issue,  216,000
shares have been  designated as Series A Preferred  Stock,1,000,000  shares have
been  designated as 1996 Series A Convertible  Preferred Stock and 50,000 shares
have been  designated as 1999 Series A 8%  Convertible  Preferred  Stock.  Thus,
8,734,000  preferred  shares have been authorized for issuance but have not been
issued  nor have the  rights  of these  preferred  shares  been  designated.  No
dividends can be paid on the common stock until the dividend requirements of the
preferred  shares  have  been  satisfied.  The  preferred  shareholders  are not
entitled to vote except on those  matters in which the consent of the holders of
preferred stock is  specifically  required by Nevada law. If the Company were to
liquidate  prior to payment of the full dividend  requirements  on the preferred
stock,  the  preferred  stock would receive a  liquidation  preference  from the
liquidation  proceeds.  On  liquidation,  holders of all series of the preferred
stock would be entitled to receive the par value, $.001 per share, in preference
to the common stock shareholders.

     Dividend   payments   and   preferential   rights  to  Series  A  preferred
shareholders  are tied to wells  that  have  been  plugged  and  abandoned.  The
liquidation value of the Series A Preferred Stock is $216.

     On December 23, 1996, the Company issued  1,000,000  shares of new Series A
preferred  stock,  known as the 1996 Series A Convertible  Preferred Stock, in a
private placement, resulting in net proceeds to the Company after offering costs
of $9,280,000.  Dividends of $438,000 and $875,000 and were declared in 2000 and
1999,  respectively.  On  June  30,  2000  the  holders  of the  1996  Series  A
Convertible  Preferred  stock  agreed  to  exchange  the  convertible  preferred
securities  for 900,000  warrants to purchase  restricted  common  shares of the
Company's  stock at an exercise price of $5.25 per share with an expiration date
of June 3, 2003 and payment of $10,000,000. The convertible preferred shares are
currently listed as issued but held by Bluebird as of December 31, 2001.

                                      F-16

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     On February 3, 1999, the Company sold 50,000 shares of its 1999 Series A 8%
Convertible  Preferred  Stock  for  $50  million  in a  private  placement.  The
Preferred Stock had a liquidation  value of $50 million and was convertible into
the Company's Common Stock at $5.25 per share.  Dividends on the Preferred Stock
were  payable  in cash at the  rate of 8% per  annum  and were  cumulative.  The
Company used the net proceeds from the transaction, approximately $46.3 million,
to repay senior bank debt.  Dividends of $3,874,000 and $3,634,000 were declared
in 2000 and 1999,  respectively.  $169,000  of the 2000  dividends  were paid in
January 2001.  On December 7, 2000,  the Company  redeemed  25,000 shares of the
Preferred stock for a cash payment of  $30,540,000,  which included a redemption
premium  of  $5,540,000.  The  redemption  premium  was  included  in  dividends
applicable  to  preferred  stock  in the  Company's  consolidated  statement  of
operations and comprehensive income in 2000.

Warrants

     The  following  is a summary  of warrant  activity  for the  periods  ended
December 31, 2001, 2000 and 1999:
<TABLE>
<CAPTION>
<S>                            <C>             <C>             <C>           <C>              <C>              <C>
                                           2001                           2000                           1999
                             ------------------------------------------------------------------------------------------------
                               Number of         Weighted      Number of         Weighted      Number of       Weighted
                               Warrants          Average       Warrants          Average        Warrants        Average
                                              Exercise Price                  Exercise Price                  Exercise Price
                             -------------- ------------------------------- -------------------------------------------------
Outstanding - Beginning of          644,749       $       6.75   10,608,150      $        6.49      156,000      $      4.62
Year
Issued                                    -                         900,000               5.25   10,512,150             6.50
Exercised                                 -                     (9,413,136)               6.37            -
Redeemed                                  -                     (1,429,264)               0.01            -
Expired                                   -                        (21,000)                  -      (60,000)                -
                             -------------- ------------------------------- -------------------------------------------------
Outstanding - End of Year           644,749      $        6.75      644,749      $        6.75   10,608,150       $      6.49

</TABLE>

     The new warrants in 1999 were issued in  connection  with a  redemption  of
1996  Series A  Convertible  Preferred  Stock and 1999  Series A 8%  Convertible
Stock.

     The new warrants in 2000 were issued in  connection  with a  redemption  of
1996 Series A Convertible Preferred Stock.

     On November  27, 2000,  the Board of  Directors  allowed a total of 644,749
warrants  held by certain key  officers and  directors  of the Company,  with an
exercise price of $6.50 per share and an expiration date of June 30, 2000, to be
exchanged  for an equal number of new warrants  with an exercise  price of $6.75
per share  expiring on December 31, 2003. The exercise price of the new warrants
was fair market value on the date of the new grant.

     On  December 5, 2001,  the Company  announced  that a  distribution  of one
warrant for every five shares of common stock owned on January 10,  2002.  These
warrants were  distributed on March 21, 2002.  Each new warrant will entitle the
holder to purchase one share of common  stock at $15.  The warrants  will expire
three years from the date of distribution.

Common Stock

     The Company has a Shareholder Rights Plan, under which the Rights initially
represent  the right to purchase one  one-hundredth  of a share of 1998 Series A
Junior  Participating  Preferred  Stock for  $35.00 per one  one-hundredth  of a
share.  The Rights become  exercisable  only if a person or a group  acquires or
commences a tender offer for 15% or more of the Company's  common  stock.  Until
they  become  exercisable,  the Rights  attach to and trade  with the  Company's
common stock. The Rights expire January 20, 2008.

     On February 17, 1999, the Company  revised its previously  announced  stock
repurchase program to spend up to $4 million without a share limitation.  During
1999,  the  Company  repurchased  601,472  shares of its  common  stock for $1.7
million. Additionally

                                      F-17

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     in 1999,  41,115 shares of the Company's  common stock were  contributed to
the 401(k)  plan,  102,145  shares were issued upon  exercise of employee  stock
options,  338,900  shares  were  purchased  by the ESOP and 51,808  shares  were
released by the ESOP to participants.

     In April 2000, the Company announced a stock repurchase program whereby the
Company or its affiliates  were  authorized to repurchase up to an additional 5%
of the Company's  outstanding  common  stock.  In May 2000,  Bluebird  purchased
129,032  shares of the Company's  common stock for  approximately  $500,000.  On
December 22, 2000 the Company acquired a 5.5% net profits interest in the Panoma
properties  and gas  gathering  system for  $3,480,418  through the  issuance of
356,966 of  restricted  common  stock.  Additionally  in 2000,  shares  totaling
656,392 were issued upon exercise of employee  stock options for net proceeds of
$2,413,336;  shares  totaling  9,140,408  were issued upon  exercise of warrants
(including  177,272  shares  issued in a cashless  exercise  and 164,946  shares
exercised  by the  Company's  ESOP)  for net  proceeds  of  $57,556,569;  shares
totaling  118,916 were purchased by the ESOP (other than the 164,946 obtained by
exercise of warrants) for $519,948; and shares totaling 141,095 were released by
the ESOP to participants.

     Effective  January  1,  2001,  the holder of the  Company's  remaining  $25
million principal amount of Magnum Hunter 1999 Series A 8% convertible preferred
stock  converted  into 4,761,904  common  shares.  On June 11, 2001, the Company
announced a stock  repurchase  program to repurchase up to one million shares of
the Company's common stock.  Through December 31, 2001, Bluebird had repurchased
115,950 shares under this program for $1,015,000.  Additionally in 2001,  shares
totaling  1,124,616  were issued upon exercise of employee stock options for net
proceeds of $4,865,000; shares totaling 52,479 were contributed to the Company's
401(K) plan;  shares  totaling 72,900 were issued to the public for net proceeds
of $734,000;  shares totaling 317,080 were released by the KSOP to participants;
$1,094,000 of KSOP loans were repaid to the Company;  and the Company loaned the
KSOP $890,000 to purchase 105,450 shares.

NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION

     During 2001,  the Company  contributed  52,479 shares valued at $151,000 to
the Company's 401(K) plan. In accordance with SFAS 115, the Company wrote-up the
carrying costs of its marketable  investments by $507,000 ($466,000 after income
tax expense).  Interest paid on the Company's  outstanding  indebtedness  during
2001 was $19,037,000. Tax paid in 2001 was $716,000.

     During  2000,  the  Company  purchased  oil and gas  properties  by issuing
356,966  restricted common shares valued at $3,480,418.  In accordance with SFAS
115, the Company  wrote-up the carrying costs of its  marketable  investments by
$2,006,986 ($1,246,840 after income tax expense). Interest paid on the Company's
outstanding indebtedness during 2000 was $21,661,000.  The Company paid no taxes
in 2000.

     During 1999,  the Company  contributed  41,115 shares valued at $123,000 to
the Company's  401(k) plan. In accordance  with SFAS 115, the Company wrote down
the carrying costs of its marketable  investments by $617,000.  Interest paid on
the Company's outstanding indebtedness during 1999 was $19,773,000.  The Company
paid no taxes in 1999.

NOTE 10 -- ENVIRONMENTAL ISSUES

     Being engaged in the oil and gas exploration and development business,  the
Company  may  become   subject  to  certain   liabilities   as  they  relate  to
environmental  clean  up  of  well  sites  or  other  environmental  restoration
procedures as they relate to the drilling of oil and gas wells and the operation
thereof.  In the Company's  acquisition  of existing or previously  drilled well
bores, the Company may not be aware of what environmental  safeguards were taken
at the time such  wells  were  drilled  or during  the time that such wells were
operated.  Should it be determined  that a liability  exists with respect to any
environmental  clean-up or  restoration,  the liability to cure such a violation
would most likely fall upon the Company.  In certain  acquisitions,  the Company
has received  contractual  warranties  that no such violations  exist,  while in
other acquisitions, the Company has waived its rights to pursue a claim for such
violations  from the selling party.  No claim has been made nor has a claim been
asserted,  nor is the Company aware of the  existence of any material  liability
which the  Company  may  have,  as it  relates  to any  environmental  clean-up,
restoration or the violation of any rules or regulations relating thereto.

                                      F-18

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 11 -- COMMITMENTS AND CONTINGENCIES

     The Company  has  certain  lease  agreements  for the use of office  space,
office equipment,  and vehicles. The office space lease extends through November
2005 with an option to renew the lease for a three year term. The various office
equipment  leases  extend until 2004.  The various  vehicle  leases extend until
2006. The leases have been  classified as operating  leases.  The following is a
schedule by years of future minimum lease payments  required under the operating
lease agreements:


Year Ended December 31:
2002...................................          $1,037,425
2003...................................             949,484
2004...................................             890,714
2005...................................             735,318
2006...................................             119,035
Thereafter.............................                   -
                                       --------------------
 Total Minimum Payments Required.......          $3,731,976
                                       ====================

     Rental  expense was  $582,305,  $717,636 and $367,000,  for 2001,  2000 and
1999, respectively.

     The Company's  existing  Revolving Loan Agreement with certain banks permit
guarantees of NGTS,  LLC's  indebtedness,  not to exceed  $4,000,000,  and trade
payables  or letters of credit for the  purchase of natural gas not to exceed an
aggregate  of  $15,000,000  on behalf of NGTS,  LLC. As of December 31, 2001 and
2000, there was no NGTS, LLC debt outstanding that the Company guaranteed.

NOTE 12 -- FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK

     Financial  instruments  that  subject the  Company to credit  risk  consist
principally of accounts and notes receivable. The receivables are primarily from
companies in the oil and gas business or from  individual oil and gas investors.
These parties are primarily  located in the  Southwestern  regions of the United
States.  No single  receivable is considered to be  sufficiently  material as to
constitute a concentration. During the year ended December 31, 2001, the Company
provided an addition  to the  allowance  for  doubtful  accounts of  $3,214,000,
including  $3,156,000  related to Enron. The Company does not ordinarily require
collateral,  but in the case of receivables  for joint  operations,  the Company
often has the ability to offset amounts due against the  participant's  share of
production  from the related  property.  The Company  believes the allowance for
doubtful accounts at December 31, 2001 is adequate.

     To the extent the Company  receives the spread  between the contract  floor
and the Index  price  applied to related  contract  volumes,  the  Company has a
credit risk in the event of nonperformance of the counterparty to the agreement.
The Company does not anticipate any material impact to its results of operations
as a result of nonperformance by such parties.

     Management  estimates  the market  values of notes  receivable  and payable
based on expected  cash flows.  At December  31, 2001 and 2000,  the Company had
provided a reserve for the carrying value of a note receivable of $1,170,000 and
$790,000,  respectively.  After establishing this reserve,  management  believes
those market values  approximate  carrying values at December 31, 2001 and 2000.
The market values of equity  investments  are based upon quoted prices (see Note
1). At December 31, 2001,  the fair value of the Company's debt was equal to its
carrying  value,  except  for the 10%  Senior  Notes.  The fair value of the 10%
Senior Notes was $130,113,000.

NOTE 13 -- COMMODITY DERIVATIVES AND HEDGING ACTIVITIES

Crude Oil and Natural Gas Hedges

     Periodically,  the Company enters into futures, options, and swap contracts
to mitigate the effects of significant fluctuations in crude oil and gas prices.
At December 31, 2001, the Company had the following open contracts:


           Type          Volume/Day           Duration         Wtd. Avg. Price
       -------------   ----------------    --------------    ------------------
Gas
------
       Swap.......        60,000 MMBtu     Jan 02 - Dec 02         $ 2.87
       Swap.......        50,000 MMBtu     Jan 03 - Jun 03         $ 2.88

                                      F-19

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     Based on future market prices at December 31, 2001,  the fair value of open
contracts to the Company was a net asset of $3.6 million.

     Net  gains  (losses)  related  to  crude  oil and  natural  gas  derivative
transactions  for the  years  ended  December  31,  2001,  2000  and  1999  were
$4,629,000, $(11,179,000) and $(3,232,000), respectively.

Interest Rate Swaps

     On June 30, 1999, the Company entered into two interest rate swaps in order
to shift a  portion  of its  fixed  rate bond debt to  floating  rate  debt,  to
capitalize on what was perceived as a market  overreaction  to pending  interest
rate increases by the Federal  Reserve,  and to effectively  lower interest rate
expense over the following  twelve months.  On June 1, 2000, one of the interest
rate swaps terminated.  The Company  terminated the remaining interest rate swap
in June, 2001.

     On August 9, 2001,  the Company  entered  into two  interest  rate swaps in
order to shift a portion of its variable rate bank debt to fixed rate debt.  The
following table reflects the terms of these swaps.

<TABLE>
<CAPTION>
<S>                                 <C>                      <C>                    <C>                   <C>

             Type                   Notional Amount          Termination Date        Pay Rate             Receive Rate
            ------                  ---------------          ----------------        --------             ------------
  Pay Fixed/Receive Variable          $50,000,000                8/23/03            4.25 % Fixed             3 month
                                                                                                           LIBOR rate
                                                                                                         currently 2.195%

</TABLE>

     The rate the Company  receives  will be reset every three months to exactly
match  the  rate  the  Company  will pay on  $50.0  million  of its  outstanding
LIBOR-based bank debt.

     The Company's  total fixed rate debt  outstanding  at December 31, 2001 was
approximately $129.5 million.

     Based on future  market rates at December 31, 2001,  the fair value of open
contracts to the Company was a liability of $1.0 million.

     Net gains (losses) related to interest rate derivative transactions for the
years ended  December  31, 2001,  2000 and 1999 were  $744,000,  $(13,000),  and
$209,000, respectively.

NOTE 14 -- STOCK COMPENSATION PLANS

     The  Company  has three  stock  compensation  plans for its  employees  and
directors, (i) the Magnum Hunter Resources 401(k) Employee Stock Ownership Plan,
(the "KSOP"), (ii) the Magnum Hunter Resources, Inc. 1996 Incentive Stock Option
Plan (the "1996 Option Plan"), and (iii) the Magnum Hunter Resources,  Inc. 2001
Incentive Stock Option Plan (the "2001 Option Plan").  In addition,  the Company
has made non-incentive stock option grants in 2001, 2000 and 1999.

KSOP

     The Company  established an ESOP and a related trust in 1996 as a long-term
benefit  for its  employees.  On January 1, 2001,  the ESOP was merged  with the
401(k) plan to form the KSOP. Under terms of the KSOP, eligible participants may
choose to make elective deferred  contributions of not less than 1% or more than
15% of their annual compensation, limited in combination with the 401(k) plan to
the  maximum   allowable  per  year  by  the  Internal  Revenue  Code.   Company
contributions  to the  KSOP are made on a  discretionary  basis.  It is also the
Company's intent to invest all  contributions in the Company's Common Stock. All
employees  who have  reached  the age of 21 and with  one  year of  service  are
eligible to  participate  in the plan.  Shares  purchased by the KSOP with loans
from the  Company are  released to  participants  as Company  contributions  and
participant  salary  deferrals  are made and the related  loans are repaid.  The
Company has no repurchase obligations with respect to released shares.


                                      F-20

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     During 1999,  the Company  loaned the KSOP  $1,030,365 to purchase  338,900
shares of the  Company's  Common Stock on the open market at an average price of
$3.04 per share. At December 31, 1999, the Company  contributed  $150,782 to the
KSOP as a discretionary  contribution  under the plan. The KSOP then repaid that
portion  of its  outstanding  loan  from the  Company  and  51,808  shares  were
allocated among the plan participants.

     During 2000,  the Company  loaned the KSOP  $1,592,098 to purchase  118,916
shares of the  Company's  common stock on the open market at an average price of
$4.37 per share and to exercise  164,946 warrants at a price of $6.50 per share.
On  December  8,  2000,  the  Company  contributed  $448,454  to the  KSOP  as a
discretionary  contribution under the plan. The KSOP then repaid that portion of
its  outstanding  loan from the Company and shares were allocated among the plan
participants.

     During  2001,  the Company  loaned the KSOP  $890,095  to purchase  105,450
shares of the  Company's  common stock on the open market at an average price of
$8.44 per share.  During 2001,  employees purchased 346,084 shares of the KSOP's
unreleased shares of $3.18 per share through salary deferrals and transfers from
the 401(k). Employer purchases totaled $1,100,651,  which the KSOP used to repay
that portion of its outstanding  loan from the Company,  and 346,084 shares were
allocated  among the Plan  participants.  The loan is  interest  free and is due
December 31, 2004.  The loan was secured by 468,652 shares and 680,282 shares of
the Company's common stock at December 31, 2001 and 2000, respectively.

     As required  under  Statement of Position 93-6  "Employers'  Accounting for
Employee Stock  Ownership  Plans,"  compensation  expense is recorded for shares
committed  to be released to  employees  based on the fair market value of those
shares when they are committed to be released.  The difference  between cost and
the fair market  value of the  committed  to be  released  shares is recorded in
additional paid-in-capital. Unreleased shares held by the KSOP are excluded from
the calculation of earnings per share.

     The KSOP shares are summarized as follows:


                                                    December 31,
                                             2001                   2000
                                 -------------------------------------------
Allocated shares                            573,416                 256,336
Unreleased shares                           468,652                 680,282
                                         ----------             -----------
  Total ESOP shares                       1,042,068                 936,618
                                         ==========             ===========
Fair value of unreleased shares         $ 3,889,812             $ 8,163,384

     The ESOP expense for the years ending  December 31, 2001, 2000 and 1999 was
$1,655,835, $1,119,942 and $148,948, respectively.

Stock Option Plans

Incentive Stock Option Plan

     The Company  established  this plan beginning April 1, 1996. It is governed
by Section 422 of the Internal Revenue Code, and Section 16(b) of the Securities
Exchange  Act of 1934.  This stock  option plan covers  1,200,000  shares of the
Company's common stock. Eligibility is limited to employees and directors of the
Company and its  subsidiaries.  The actual  selection of grantees is made by the
Board of  Directors.  The term of the  individual  option  grants,  while at the
discretion of the Board,  has  historically  been for a term of five years.  All
options  granted in 1996 were fully vested and  exercisable  when  granted.  The
exercise price was fair market value at the date of each grant.

                                      F-21

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Non-Incentive Stock Option Grants

     During 1999, the Board granted  1,306,650 new stock options to employees at
an  average  price of $2.69  per  share,  of which  108,000  were  fully  vested
immediately and the remaining  1,198,650 stock options vested 20% at the date of
grant,  with the balance  vesting an additional 20% per year on the  anniversary
date over the next four  years.  Additionally,  the  expiration  date of 300,000
options previously granted to two former officers of Magnum Petroleum,  Inc. was
modified to extend the expiration date from January 5, 2000 to January 5, 2002.

     During 2000, the Board granted  1,536,000 new stock options to employees at
a weighted average price of $7.89 per share, all of which vested 20% at the date
of grant, with the balance vesting an additional 20% per year on the anniversary
date over the next four years,  and with a weighted  average  term of 9.9 years.
The exercise price was the fair market value on the date of grant.

     During 2001, the Board granted  1,655,500 new stock options to employees at
a weighted  average price of $8.48 per share, of which 20% vested at the date of
grant,  with the balance  vesting an additional 20% per year on the  anniversary
date over the next four years,  with a weighted  average term of 9.9 years.  The
exercise price was the fair market value on the date of the grant.

     The following is a summary of stock option activity under the Option Plans:

<TABLE>
<CAPTION>
<S>                                 <C>          <C>               <C>          <C>               <C>           <C>
                                                2001                       2000                           1999
                                   ------------------------------------------------------------------------------------------
                                                     Weighted                       Weighted                      Weighted
                                       Number of     Average          Number of     Average         Number of     Average
                                       Warrants   Exercise Price      Warrants   Exercise Price     Warrants   Exercise Price
                                   -------------------------------------------------------------------------------------------
Outstanding - Beginning of Year....    4,702,400    $     4.97        3,866,092   $     3.57        2,661,587    $     3.90
Granted............................    1,655,500          8.48        1,536,000         7.89        1,306,650          2.69
Exercised..........................   (1,124,616)         4.33         (656,392)        3.67         (102,145)          .76
Cancelled..........................      (15,700)         6.59          (43,300)        3.32                -             -
                                   ------------------------------------------------------------------------------------------
Outstanding - End of Year..........    5,217,584    $     6.22        4,702,400   $     4.97        3,866,092    $     3.57
                                       =========    ==========        =========   ==========        =========    ==========
Exercisable - End of Year..........    2,531,724    $     5.14        2,730,460   $     4.31        2,787,172    $     3.94
                                       =========    ==========        =========   ==========        =========    ==========
</TABLE>

     The  following is a summary of stock  options  outstanding  at December 31,
2001:

<TABLE>
<CAPTION>
<S>                                    <C>                    <C>                    <C>
                                                                  Weighted
                                                                   Average
                                           Number of              Remaining
                                            Options           Contractual Life             Number of
Exercise Price                            Outstanding              (Years)            Exercisable Options
----------------------------------------------------------------------------------------------------------------
$      2.50..........................        1,083,450               3.0                      617,290
       3.4375........................            6,000               3.2                          -
       3.75..........................          881,034               1.0                      881,034
       5.25..........................           80,000               2.1                       80,000
       5.375.........................            5,000               0.3                        5,000
       6.625.........................           20,000               3.6                        7,400
       6.6875........................            2,400               3.6                          600
       7.9375........................        1,536,700               8.9                      611,800
       8.44..........................        1,538,000               9.9                      307,600
       8.50..........................           20,000               9.7                        4,000
       9.3125........................           20,000               3.9                        8,000
       11.08.........................           20,000               8.9                        8,000
       12.00.........................            5,000               4.1                        1,000
                                      --------------------------------------------------------------------------
                                             5,217,584               6.5                    2,531,724
                                      ==========================================================================

</TABLE>

     The Company  adopted  the  disclosures  only  portion of SFAS No. 123 as it
continues to follow the  provisions of APB No. 25, which is the intrinsic  value
method of accounting for stock-based compensation.

                                      F-22

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     On a pro forma basis, the effect of stock based  compensation  (options and
warrants) had the Company adopted Statement No. 123 is as follows:

<TABLE>
<CAPTION>
<S>                                                         <C>                 <C>                    <C>
                                                                              Year Ended December 31,
                                                                    2001               2000                1999
                                                             ---------------------------------------------------------
Net Income (Loss) Applicable to Common Stock:
  As reported...........................................           $ 13,516,000      $  12,552,000      $ (11,335,000)
  Pro Forma................................................           8,311,000          6,800,000        (13,313,000)
Basic Earnings (Loss) per Share:
  As reported, after extraordinary loss....................        $        .39      $        0.60      $       (0.57)
  Pro Forma................................................                 .24               0.33              (0.67)
Diluted Earnings (Loss) per Share:
  As reported, after extraordinary loss....................        $        .37      $        0.51      $       (0.57)
  Pro Forma................................................                 .23               0.30              (0.67)
Weighted average grant date fair value.....................        $  8,379,000      $   9,259,000      $   1,978,000

</TABLE>

     The Company estimated the fair value of each stock based grant (options and
warrants)  using  the  Black-Scholes  option  pricing  method  while  using  the
following weighted average assumptions:

                                     2001          2000         1999
                                -------------------------------------------

Risk-free interest rate.........     4.39%          5.75%        5.875%
Expected life...................     7.4 years      7.4 years    4.4 years
Expected volatility.............     52.6%          56.0%        53.0%
Dividend yield..................      -              -            -

NOTE 15 -- EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND
  CHANGE-IN-CONTROL ARRANGEMENTS

     Mr. Gary C. Evans,  Mr. Richard R. Frazier,  Mr. Chris Tong, Mr. R. Douglas
Cronk and Mr. Charles R. Erwin each have employment agreements with the Company.
Mr. Evans' agreement  terminates  January 1, 2006 and continues  thereafter on a
year to year  basis and  provides  for a salary  of  $300,000  per annum  unless
increased by the Board.  Mr.  Evans'  salary for the year 2002 is $375,000.  Mr.
Frazier's  agreement  terminates  January 1, 2006 and continues  thereafter on a
year to year  basis and  provides  for a salary  of  $175,000  per annum  unless
increased by the Board. Mr. Frazier's salary for the year 2002 is $205,000.  Mr.
Tong's agreement  terminates January 1, 2004 and continues  thereafter on a year
to year basis and provides  for a salary of $160,000 per annum unless  increased
by the Board.  Mr.  Tong's  salary for the year 2002 is  $175,000.  Mr.  Cronk's
agreement  terminates January 1, 2004 and continues thereafter on a year to year
basis and provides  for a salary of $122,500  per annum unless  increased by the
Board. Mr. Cronk's salary for the year 2002 is $150,000.  Mr. Erwin's  agreement
terminates January 1, 2004 and continues  thereafter on a year to year basis and
provides for a salary of $105,000 per annum unless  increased by the Board.  Mr.
Erwin's salary for the year 2002 is $155,000. All of the agreements provide that
the same benefits  supplied to other Company employees shall be available to the
employee. The employment agreements also contain, among other things,  covenants
by the employee that in the event of  termination,  he will not compete with the
Company in certain geographical areas or hire any employees of the Company for a
period of two years after cessation of employment.

     In  addition,  all  of the  agreements  contain  a  provision  that  upon a
change-in-control  of the Company and the  employee's  position is terminated or
the  employee  leaves for "good  cause",  the  employee  is entitled to receive,
immediately in one lump sum, certain compensation.  In the case of Mr. Evans and
Mr. Frazier,  the employee shall receive three times the employee's base salary,
bonus for the last fiscal year and any other compensation received by him in the
last fiscal year. In the case of Mr. Tong, Mr. Cronk and Mr. Erwin, the employee
shall receive the employee's base salary, bonus for the last fiscal year and any
other  compensation  received by him in the last fiscal year  multiplied by two.
Also, any medical, dental and group life insurance covering the employee and his

                                      F-23

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     dependents  shall  continue  until the  earlier of (i) 12 months  after the
change-in-control  or (ii) the date the employee  becomes a  participant  in the
group insurance benefit program of a new employer.  The Company also has key man
life insurance on Mr. Evans in the amount of $12,000,000.

NOTE 16 - SEGMENT DATA

     The Company has three reportable  segments.  The Exploration and Production
segment is engaged in exploratory drilling and acquisition, production, and sale
of crude oil,  condensate,  and natural gas. The Gas  Gathering,  Marketing  and
Processing  segment is engaged in the gathering and  compression  of natural gas
from the wellhead,  the purchase and resale of natural gas which it gathers, and
the processing of natural gas liquids. The Oil Field Services segment is engaged
in the managing and operation of producing oil and gas  properties  for interest
owners.

     The Company's  reportable  segments are strategic business units that offer
different  products  and  services.  They are managed  separately  because  each
business requires different technology and marketing strategies. The Exploration
and Production  segment has six geographic  areas that are  aggregated.  The Gas
Gathering,  Marketing and Processing  segment includes the activities of the two
gathering  systems  and  three  natural  gas  liquids  processing  plants in two
geographic  areas that are  aggregated.  The Oil Field Services  segment has six
geographic  areas that are aggregated.  The reason for aggregating the segments,
in  each  case,  was  due to the  similarity  in  nature  of the  products,  the
production processes, the type of customers, the method of distribution, and the
regulatory environments.

     The accounting  policies of the segments are the same as those described in
Note 1 - Summary of  Significant  Accounting  Policies.  The  Company  evaluates
performance  based on profit or loss from  operations  before income taxes.  The
accounting  for  intersegment  sales  and  transfers  is done as if the sales or
transfers were to third parties, that is, at current market prices.

     Segment data for the three years ended December 31, 2001, 2000 and 1999 are
as follows (in thousands):

<TABLE>
<CAPTION>
<S>                                     <C>             <C>              <C>         <C>         <C>           <C>
                                                        Gas Gathering,
                                         Exploration &    Marketing &    Oil Field
                  2001:                    Production     Processing      Services    All Other  Elimination  Consolidated
                  -----               ---------------------------------------------------------------------------------------
Revenue from external customers.........   $    133,083   $17,895         $   1,828   $      -   $      -      $   152,806
Intersegment revenues....................             -    19,253             6,233          -    (25,486)               -
Depreciation, depletion, amortization and
impairment...............................        42,703       883               394         19                      43,999
Segment profit (loss)..................          56,998       725            (2,851)    (6,821)                     48,051
Equity earnings (losses) of affiliates...                                                1,085                       1,085
Interest expense.........................                                              (19,868)                    (19,868)
Provision for non-cash impairment of
investments..............................                                               (7,123)                     (7,123)
Other income.............................                                                  283                         283
                                                                                                              -------------------
Income before income taxes...............                                                                      $    22,428
Current income tax provision.............                                                 (178)                       (178)
Deferred income tax provision............                                               (8,430)                     (8,430)
Extraordinary loss.......................                                                 (304)                       (304)
                                                                                                              -------------------
Net income...............................                                                                      $    13,516
                                                                                                              ===================
Capital expenditures (net of asset sales)  $    202,063   $    61         $     326   $    855   $             $   203,305

</TABLE>

                                                              F-24

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

<TABLE>
<CAPTION>
<S>                                      <C>           <C>               <C>         <C>         <C>          <C>
                                                        Gas Gathering,
                                         Exploration &    Marketing &    Oil Field
                  2000:                    Production     Processing      Services    All Other  Elimination  Consolidated
                  -----                ---------------------------------------------------------------------------------------
Revenue from external customers.........    $   106,052     $  20,010     $  1,448     $      -    $      -     $   127,510
Intersegment revenues....................             -        20,218        6,128                  (26,346)              -
Depreciation, depletion, amortization and
impairment...............................        24,350           876          304           26                      25,556
Segment profit (loss)..................          52,743         3,422       (1,274)      (4,562)                     50,329
Equity earnings (losses) of affiliates...                                                 1,307                       1,307
Interest expense.........................                                               (22,298)                    (22,298)
Other income.............................                                                   477                         477
                                                                                                             -----------------
Income before income taxes...............                                                                       $     29,815
Current income tax provision.............                                                  (234)                        (234)
Deferred income tax provision............                                                (7,321)                      (7,321)
                                                                                                             -----------------
Net income...............................                                                                       $     22,260
                                                                                                             =================
Capital expenditures (net of asset sales)   $    20,279     $     119     $    495     $      -                 $     20,893

</TABLE>

<TABLE>
<CAPTION>
<S>                                       <C>           <C>              <C>         <C>         <C>         <C>
                                                         Gas Gathering,
                                          Exploration &   Marketing &    Oil Field
                  1999:                    Production      Processing     Services    All Other  Elimination  Consolidated
                  -----                ---------------------------------------------------------------------------------------
Revenue from external customers.........    $  60,673      $   8,185      $    768      $      -  $       -   $      69,626
Intersegment revenues....................           -         14,135         6,164             -    (20,299)              -
Depreciation, depletion, amortization and
impairment...............................      21,176            646           233            17                     22,072
Segment profit (loss)..................        15,960          1,858          (605)       (2,101)                    15,112
Equity earnings (losses) of affiliates...                                                   (103)                      (103)
Interest expense.........................                                                (22,103)                   (22,103)
Other income.............................                                                    354                        354
                                                                                                             -----------------
Loss before income taxes.................                                                      -              $      (6,740)
Deferred income tax benefit..............                                                      -                          -
Minority interest........................                                                    (86)                       (86)
                                                                                                              -----------------
Net loss.................................                                                                     $      (6,826)
                                                                                                              =================
Capital expenditures (net of asset sales)   $  54,877      $   3,331      $    410      $      -              $      58,618

</TABLE>

<TABLE>
<CAPTION>
<S>                                      <C>             <C>                <C>         <C>        <C>           <C>
                                                          Gas Gathering,
                                           Exploration &    Marketing &     Oil Field
                                            Production      Processing       Services    All Other  Elimination   Consolidated
                                          -------------------------------------------------------------------------------------
As of December 31, 2001
Segment assets............................ $     423,018   $       15,884    $   8,675    $  6,808                 $   454,385
Equity subsidiary investments.............                                                   5,022                       5,022

As of December 31, 2000
Segment assets............................ $     270,195   $       20,561    $  16,154    $  8,702                 $   315,612
Equity subsidiary investments.............                                                   8,054                       8,054

</TABLE>

                                      F-25

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 17 -- CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

     The   Company   and  its   subsidiaries,   except   Bluebird   and  certain
inconsequential  subsidiaries (Inesco Corporation,  SPL Gas Marketing,  Inc. and
Midland Hunter Petroleum Limited Liability Company) are direct Guarantors of the
Company's  10% Senior Notes and have fully and  unconditionally  guaranteed  the
Notes on a joint and several  basis.  Bluebird  was formed in December  1998 and
first reported  results of operations in fiscal 1999. In addition to not being a
guarantor  of  the  Company's  10%  Senior  Notes,  it  cannot  be  included  in
determining  compliance  with certain  financial  covenants  under the Company's
credit agreements.  Management has determined that separate financial statements
relating  to  the   Guarantors   are  not  material  to   investors.   Condensed
consolidating balance sheets for Magnum Hunter Resources,  Inc. and subsidiaries
as of December  31,  2001and  2000 and  condensed  consolidating  statements  of
operations and cash flows for the years ended  December 31, 2001,  2000 and 1999
are as follows:

                 Magnum Hunter Resources, Inc. and Subsidiaries
                     Condensed Consolidating Balance Sheets

<TABLE>
<CAPTION>
<S>                                           <C>                   <C>               <C>            <C>

                                December 31, 2001
-----------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                          And Guarantor Subs    (Non Guarantor)    Eliminations     Consolidated
--------------------
ASSETS
Current assets..............................  $   21,196                $  3,910        $         -     $    25,106
Property and equipment
  (using full cost accounting)..............     412,720                   7,117                  -         419,837
Investment in subsidiaries
 (equity method)............................      14,963                       -            (14,963)              -
Investment in Parent........................           -                  15,750            (15,750)              -
Other assets................................       9,442                       -                  -           9,442
                                            ----------------------------------------------------------------------------
   Total Assets.............................  $  458,321                $ 26,777        $   (30,713)    $   454,385
                                            ============================================================================
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.........................  $   48,561                $    152        $         -     $    48,713
Long-term liabilities.......................     280,736                  11,662             (4,700)        287,698
Shareholders' equity........................     129,024                  14,963            (26,013)        117,974
                                            ----------------------------------------------------------------------------
  Total Liabilities and Stockholders' Equity  $  458,321                $ 26,777        $   (30,713)    $   454,385
                                            ============================================================================
</TABLE>


<TABLE>
<CAPTION>
<S>                                           <C>                   <C>               <C>            <C>

                                December 31, 2000
-----------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                          And Guarantor Subs    (Non Guarantor)    Eliminations     Consolidated
--------------------
ASSETS
Current assets..............................    $  33,556            $    6,894        $   (5,612)      $    34,838
Property and equipment
  (using full cost accounting)..............      208,115                52,417                 -           260,532
Investment in subsidiaries
 (equity method)............................       25,574                     -           (25,574)                -
Other assets................................       27,173                   319            (7,250)           20,242
                                            ----------------------------------------------------------------------------
   Total Assets.............................    $ 294,418            $   59,630        $  (38,436)      $   315,612
                                            ============================================================================
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.........................    $  30,123            $    6,206        $   (5,612)      $    30,717
Long-term liabilities.......................      170,879                27,850            (7,250)          191,479
Shareholders' equity........................       93,416                25,574           (25,574)           93,416
                                            ----------------------------------------------------------------------------
  Total Liabilities and Stockholders' Equity    $ 294,418            $   59,630        $  (38,436)      $   315,612
                                            ============================================================================
</TABLE>

                                      F-26

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

<TABLE>
<CAPTION>

            Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Statement of Operations

<S>                                       <C>                     <C>              <C>               <C>
                          Year Ended December 31, 2001
-----------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                         And Guarantor Subs     (Non Guarantor)   Eliminations     Consolidated
--------------------                       ----------------------------------------------------------------------------
Revenues.................................       $      128,572      $     24,445      $    (211)         $  152,806
Expenses...................................            118,265            12,324           (211)            130,378
                                           ----------------------------------------------------------------------------
Income (loss) before                                    10,307            12,121              -              22,428
 Equity in net earnings of subsidiaries....              7,530                 -         (7,530)                  -
                                           ----------------------------------------------------------------------------
Income (loss) before income taxes..........             17,837            12,121         (7,530)             22,428
Income tax provision.......................             (4,017)           (4,591)             -              (8,608)
                                           ----------------------------------------------------------------------------
Income before extraordinary loss...........             13,820                                               13,820
Extraordinary Loss.........................               (304)                                                (304)
  Net Income (Loss)........................     $       13,516      $      7,530      $  (7,530)         $   13,516
                                           ============================================================================
</TABLE>


<TABLE>
<CAPTION>
<S>                                        <C>                    <C>               <C>             <C>
                          Year Ended December 31, 2000
-----------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                         And Guarantor Subs     (Non Guarantor)   Eliminations     Consolidated
--------------------                       ----------------------------------------------------------------------------
Revenues...................................  $       83,048        $    44,772        $   (310)       $   127,510
Expenses...................................          72,375             25,250              70             97,695
                                           ---------------------------------------------------------------------------
Income (loss) before                                 10,673             19,522            (380)            29,815
 Equity in net earnings of subsidiaries....          12,272                  -         (12,272)                 -
                                           ---------------------------------------------------------------------------
Income (loss) before income taxes..........          22,945             19,522         (12,652)            29,815
Income tax provision.......................            (305)            (7,250)              -             (7,555)
                                           ---------------------------------------------------------------------------
  Net Income (Loss)........................  $       22,640        $    12,272        $(12,652)       $    22,260
                                           ===========================================================================
</TABLE>

<TABLE>
<CAPTION>
<S>                                        <C>                    <C>               <C>             <C>
                          Year Ended December 31, 1999
-----------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                         And Guarantor Subs     (Non Guarantor)   Eliminations     Consolidated
--------------------                       ----------------------------------------------------------------------------
Revenues...................................  $         53,189       $     16,847     $    (410)         $   69,626
Expenses...................................            62,184             14,678          (410)             76,452
                                           ----------------------------------------------------------------------------
Income (loss) before                                   (8,995)             2,169             -              (6,826)
 Equity in net earnings of subsidiaries....             2,169                  -        (2,169)                  -
                                           ----------------------------------------------------------------------------
Income (loss) before income taxes..........           (6,826)              2,169        (2,169)             (6,826)
Income tax provision.......................               -                    -             -                   -
                                           ----------------------------------------------------------------------------
  Net Income (Loss)........................  $       (6,826)        $      2,169     $  (2,169)         $   (6,826)
                                           ============================================================================
</TABLE>



                                      F-27

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)


<TABLE>
<CAPTION>
            Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Statement of Cash Flows

                          Year Ended December 31, 2001
<S>                                         <C>                  <C>              <C>            <C>
                                                Magnum Hunter         Bluebird                     Magnum Hunter
                                               Resources, Inc.      Energy, Inc.                  Resources, Inc.
Amounts in Thousands                         And Guarantor Subs   (Non Guarantor)  Eliminations    Consolidated
-------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities.........   $  89,712           $   14,362       $      -          $104,074
Cash flow used by investing activities......    (225,745)              40,334        (18,578)         (203,989)
Cash flow used by financing activities......     138,574              (54,491)        18,578           102,661
                                            -----------------------------------------------------------------------
Net increase (decrease) in cash.............       2,541                  205              -             2,746
Cash at beginning of period.................      (1,811)               1,820              -                 9
                                            -----------------------------------------------------------------------
Cash at end of period.......................   $     730           $    2,025       $      -          $  2,755
                                            =======================================================================
</TABLE>


                          Year Ended December 31, 2000
<TABLE>
<CAPTION>
<S>                                         <C>                   <C>             <C>            <C>
                                                Magnum Hunter         Bluebird                     Magnum Hunter
                                               Resources, Inc.      Energy, Inc.                  Resources, Inc.
Amounts in Thousands                         And Guarantor Subs   (Non Guarantor)  Eliminations    Consolidated
-----------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities.........    $    21,909         $  27,557       $     -        $   49,466
Cash flow used by investing activities......        (13,501)           (6,507)            -           (20,008)
Cash flow used by financing activities......         (9,964)          (21,375)          325           (31,014)
                                            ---------------------------------------------------------------------------
Net increase (decrease) in cash.............         (1,556)             (325)          325            (1,556)
Cash at beginning of period.................          1,565             2,145        (2,145)            1,565
                                            ---------------------------------------------------------------------------
Cash at end of period.......................    $         9         $   1,820       $(1,820)       $        9
                                            ===========================================================================
</TABLE>

                          Year Ended December 31, 1999

<TABLE>
<CAPTION>
<S>                                         <C>                   <C>             <C>            <C>
                                                Magnum Hunter         Bluebird                     Magnum Hunter
                                               Resources, Inc.      Energy, Inc.                  Resources, Inc.
Amounts in Thousands                         And Guarantor Subs   (Non Guarantor)  Eliminations    Consolidated
---------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities.........   $      6,202         $     11,233   $       -       $     17,435
Cash flow used by investing activities......        (34,668)             (25,209)      1,408            (58,469)
Cash flow used by financing activities......         25,178               15,662      (3,094)            37,746
                                            -------------------------------------------------------------------------
Net increase (decrease) in cash.............         (3,288)               1,686      (1,686)            (3,288)
Cash at beginning of period.................          4,853                  459        (459)             4,853
                                            -------------------------------------------------------------------------
Cash at end of period.......................   $      1,565         $      2,145   $  (2,145)      $      1,565
                                            =========================================================================
</TABLE>


NOTE 18 - SUBSEQUENT EVENTS

     On January 15, 2002, the Company entered into a sale-leaseback  transaction
on  three  newly  constructed   offshore  production  platforms  and  associated
pipelines that were recently placed into service.  The Company  received a total
of $11.2  million in new funding which was used for general  corporate  purposes
including a voluntary  reduction  under the Company's  corporate  bank revolving
credit  facility.  The  production  platforms  are being leased from a syndicate
group  of  lenders  over a term  of  three  years  and at a  cost  of  funds  of
approximately  5.30% per annum, based on current interest rates. The transaction
will be accounted for as a capital lease.

     On March 15, 2002,  the Company merged with Prize Energy  Corp.(Prize),  an
independent oil and gas development and production company.  The transaction was
accounted  for as a  purchase  of Prize by the  Company in  accordance  with the
provisions of FAS 141.  Under the terms of the merger,  the Company  distributed
2.5 shares of

                                      F-28

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     common stock plus $5.20 in cash for each Prize  Energy  share  outstanding.
The following  table  summarizes  the total assumed  purchase  price and related
preliminary  allocation to the net assets acquired (in  thousands).  The Company
has not completed a final allocation of the purchase price to the fair values of
the assets and liabilities of Prize and the related business  integration  plan.
The Company  expects that the ultimate  purchase  price  allocation  may include
additional  adjustments to the fair values of assets and the carrying  values of
certain liabilities.  Accordingly,  to the extebt that such assessments indicate
that the fair values of the assets and liabilities differ from their preliminary
purchase price  allocation,  such differences would adjust the amounts allocated
to the  assets  and  liabilities  and would  change  the  amounts  allocated  to
goodwill.

<TABLE>
<CAPTION>
<S>                                                                         <C>

Total Purchase Price:
  Fair Value of 34,062,963 shares of Magnum Hunter common stock              $      256,153
    issued based on a price of $7.52 per share at March 15, 2002
    (assuming exercise of outstanding Prize stock options).............
  Cash consideration...................................................              70,851
  Fair value of Prize warrants.........................................               5,568
  Severance payments...................................................               8,000
  Estimated Magnum Hunter transaction related costs....................               1,400
                                                                           ----------------
     Total.............................................................      $      341,972
                                                                           ================
Net Preliminary Purchase Price Allocation:
  Net purchase price...................................................      $      341,972
  Historical net assets acquired.......................................            (162,970)
                                                                           ----------------
  Excess purchase price................................................             179,002
  Adjustment of proved oil and gas properties to fair value............             (26,230)
  Adjustment of unproved oil and gas properties to fair value..........            (113,000)
  Write-off of historical Prize deferred financing costs...............               2,300
  Additional deferred income taxes.....................................              48,787
                                                                           ----------------
     Excess purchase price allocated to goodwill.......................      $       90,859
                                                                           ================
</TABLE>

     The following summary,  prepared on a pro forma basis, presents the results
of  operations  for  the  years  ended  December  31,  2001  and  2000 as if the
acquisition of Prize occurred as of the beginning of the respective  years.  The
pro forma information  includes the effects of adjustments for interest expense,
depreciation, depletion and amortization, and income taxes:

<TABLE>
<CAPTION>
<S>                                                   <C>                       <C>
                                                                      (Unaudited)
                                                      -----------------------------------------------
                                                              2001                      2000
                                                      (in thousands, except for per share amounts)
                                                      -----------------------------------------------
Revenue..............................................    $          334,873        $        276,999
Total Operating Costs and Expenses...................              (224,138)               (172,320)
                                                        --------------------    -------------------
Operating Profit.....................................               110,735                 104,679
Interest Expense and Other...........................               (52,680)                (48,178)
                                                        --------------------    -------------------
Income before Tax....................................                58,055                  56,501
Provision for Income Tax.............................               (21,792)                (17,429)
Extraordinary loss from early extinguishment of debt.                  (304)                    -
                                                        --------------------    -------------------
Net Income...........................................                35,959                  39,072
Dividends Applicable to Preferred Stock..............                   -                   (10,167)
                                                        --------------------    -------------------
Net Income Applicable to Common Stock................                35,959                  28,905
                                                        ====================    ===================
Net Income Per Common Share
   Basic.............................................    $             0.52        $           0.53
                                                        ====================    ===================
   Diluted...........................................    $             0.50        $           0.50
                                                        ====================    ===================
</TABLE>

     The Company  amended and  restated  its Senior  Bank Credit  Facility  (the
facility)  in  conjunction  with the merger  with Prize.  The  amended  facility
provides for total borrowings of $500 million, up from $225 million,  and raises
the  borrowing  base limit from $160  million to $300  million.  After March 15,
2002, the facility was used to retire  outstanding  indebtedness under the Prize
commercial  bank  credit  facility,  fund  the  cash  component  of  the  merger
consideration  payable to the Prize shareholders,  pay costs associated with the
merger, and for general corporate purposes.

     On March 15, 2002, the Company also  completed a private  placement of $300
million of unsecured Senior Notes due 2012. Interest on the Senior Notes bear an
annual rate of 9.6% due semi-annually, commencing September 15, 2002.

     On  December 5, 2001,  the Company  announced  that a  distribution  of one
warrant for every five shares of common stock owned on January 10,  2002.  These
warrants were  distributed on March 21, 2002.  Each new warrant will entitle the
holder to purchase one share of common  stock at $15.  The warrants  will expire
three years from the date of distribution.

                                      F-29

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
          SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
                                   (Unaudited)


     Proved oil and gas reserves consist of those estimated  quantities of crude
oil,  natural gas and natural gas liquids that geological and  engineering  data
demonstrate  with  reasonable  certainty to be  recoverable in future years from
known  reservoirs  under  existing  economic and  operating  conditions.  Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

     Estimates of petroleum reserves have been made by independent engineers and
Company  employees.  These estimates include reserves in which the Company holds
an economic  interest  under  production-sharing  and other  types of  operating
agreements.  These estimates do not include probable or possible  reserves.  The
estimated net interests in Proved Reserves are based upon subjective engineering
judgments and may be affected by the  limitations  inherent in such  estimation.
The  process  of  estimating  reserves  is  subject  to  continual  revision  as
additional  information  becomes  available  as a result of  drilling,  testing,
reservoir  studies and production  history.  There can be no assurance that such
estimates will not be materially revised in subsequent periods. The revisions of
previous  estimates of the Company's  proved oil and gas reserves were primarily
due to changes in  commodity  prices at December  31,  1999,  2000 and 2001 that
impacted  whether such reserves  were  economically  recoverable.  The impact of
price  changes  disproportionately  affects  the  Company's  long life  reserves
because of the more gradual decline curve of the applicable production.

     Estimated  quantities of proved oil and gas reserves of the Company were as
follows:

                                                                  Gas
                                                Oil            (Thousand
                                             (Barrels)        Cubic Feet)
                                      --------------------------------------

December 31, 1999
  Proved Reserves.....................       25,534,000       230,000,000
  Proved developed reserves...........       16,300,000       184,955,000
December 31, 2000
  Proved Reserves.....................       22,303,000       233,208,000
  Proved developed reserves...........       13,923,000       179,697,000
December 31, 2001
  Proved Reserves.....................       21,601,000       248,480,000
  Proved developed reserves...........       12,960,000       188,413,000

                                      F-30

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
   SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
                                   (Unaudited)

     The changes in Proved  Reserves for the years ended December 31, 1999, 2000
and 2001 were as follows:


                                                            Gas
                                             Oil         (Thousand
                                          (Barrels)     Cubic Feet)
                                        -----------------------------------
Reserves at December 31, 1998...........    17,349,000     219,060,000
Purchase of minerals-in-place...........     3,123,000      15,990,000
Sale of minerals-in-place...............      (21,000)       (197,000)
Extensions and discoveries..............       164,000       6,068,000
Production..............................   (1,311,000)    (19,041,000)
Revisions of estimates..................     6,230,000       8,120,000
                                        -----------------------------------
Reserves at December 31, 1999...........    25,534,000     230,000,000
Purchase of minerals-in-place...........         1,000       2,203,000
Sale of minerals-in-place...............   (3,095,000)    (21,966,000)
Extensions and discoveries..............     1,777,000      35,009,000
Production..............................   (1,298,000)    (19,579,000)
Revisions of estimates..................     (616,000)       7,541,000
                                        -----------------------------------
Reserves at December 31, 2000...........    22,303,000     233,208,000
                                        -----------------------------------
Purchase of minerals-in-place...........     1,794,000      25,349,000
Sale of minerals-in-place...............      (67,000)       (577,000)
Extensions and discoveries..............     1,178,000      27,088,000
Production..............................   (1,410,000)    (24,864,000)
Revisions of estimates..................   (2,197,000)    (11,724,000)
                                        -----------------------------------
Reserves at December 31, 2001...........    21,601,000     248,480,000
                                        -----------------------------------

     The  aggregate  amounts  of  capitalized  costs  relating  to oil  and  gas
producing  activities  and  the  related  accumulated  depreciation,  depletion,
amortization  and  impairment  as of December  31,  2001,  2000 and 1999 were as
follows:

<TABLE>
<CAPTION>
<S>                                                            <C>               <C>               <C>
                                                                     2001             2000              1999
                                                               ----------------------------------------------------
Unproved oil and gas properties................................ $    18,653,000    $    5,534,000     $   3,567,000
Proved properties..............................................     556,766,000       367,822,000       349,510,000
                                                               ----------------------------------------------------
Gross Capitalized Costs........................................     575,419,000       373,356,000       353,077,000
Accumulated depreciation, depletion, amortization and impairment   (167,487,000)     (124,720,000)     (100,370,000)
                                                               ----------------------------------------------------
          Net Capitalized Costs................................ $   407,932,000    $  248,636,000     $ 252,707,000
                                                               ====================================================
</TABLE>

     Costs incurred in oil and gas producing  activities,  both  capitalized and
expensed,  during  the years  ended  December  31,  2001,  2000 and 1999 were as
follows:

<TABLE>
<CAPTION>
<S>                                        <C>             <C>              <C>
                                                2001            2000            1999
                                           -----------------------------------------------
Property acquisition costs
  Proved properties........................ $   36,069,000  $   7,806,000    $ 34,478,000
  Unproved properties......................     12,226,000      1,080,000       1,912,000
Exploration costs..........................     37,711,000     32,521,000       6,835,000
Development costs..........................    117,107,000     22,234,000      12,176,000
                                           -----------------------------------------------
          Total Costs Incurred............. $  203,113,000  $  63,641,000    $ 55,401,000
                                           ===============================================
</TABLE>

                                      F-31

<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
   SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
                                   (Unaudited)

     Results of operations  from oil and gas producing  activities for the years
ended December 31, 2001, 2000 and 1999 were as follows:

<TABLE>
<CAPTION>
<S>                                                                   <C>               <C>               <C>
                                                                             2001             2000               1999
                                                                      -------------------------------------------------
Oil and gas production revenue........................................ $  133,083,000   $ 106,052,000     $ 60,673,493
Production costs......................................................    (33,382,000)    (28,959,000)     (23,575,241)
Depreciation, depletion, amortization and impairment..................    (42,703,000)    (24,350,000)     (21,176,428)
Income taxes..........................................................    (19,949,000)    (18,460,000)      (5,572,638)
                                                                      -------------------------------------------------
          Results of Operations for Producing Activities               $   37,049,000   $  34,283,000     $ 10,349,186
                                                                      =================================================
</TABLE>

       The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 2001, 2000 and 1999 were
as follows:

<TABLE>
<CAPTION>
<S>                                                                   <C>               <C>               <C>
                                                                             2001             2000               1999
                                                                    ------------------------------------------------------
Future cash inflows.............................................      $ 998,101,000      $ 2,685,776,000  $ 1,102,673,000
Future development costs........................................        (94,950,000)         (84,158,000)     (52,600,000)
Future production costs.........................................       (367,526,000)        (559,596,000)    (362,365,000)
                                                                    ------------------------------------------------------
Future net cash flows, before income tax........................        535,625,000        2,042,022,000      687,708,000
Future income taxes.............................................        (28,299,000)        (607,407,000)    (131,500,000)
                                                                    ------------------------------------------------------
Future Net Cash Flows...........................................        507,326,000        1,434,615,000      556,208,000
10% annual discount.............................................       (201,633,000)        (629,692,000)    (240,592,000)
                                                                    ------------------------------------------------------
    Standardized Measure of Discounted Future Net Cash Flows (a)      $ 305,693,000      $   804,923,000  $   315,616,000
                                                                    ======================================================
</TABLE>

     The primary  changes in the  standardized  measure of discounted  estimated
future net cash flows for the years ended December 31, 2001,  2000 and 1999 were
as follows:

<TABLE>
<CAPTION>
<S>                                                                <C>               <C>               <C>
                                                                        2001             2000               1999
                                                                ------------------------------------------------------
Purchases of minerals-in-place.................................     $  35,257,000      $  16,040,000    $  45,321,000
Sales of minerals-in-place.....................................        (2,614,000)       (33,981,000)        (168,000)
Extensions, discoveries and improved recovery, less related costs      33,623,000        208,966,000        8,398,000
Sales of oil and gas produced, net of production costs.........       (99,701,000)       (77,093,000)     (37,098,000)
Development costs incurred during the period...................       117,107,000         22,231,000       12,176,000
Revision of prior estimates:
  Net change in prices and costs...............................      (858,125,000)       552,634,000      118,271,000
  Change in quantity estimates.................................       (88,279,000)         1,524,000       36,937,000
Accretion of discount..........................................        80,492,000         31,562,000       17,615,000
Net change in income taxes.....................................       283,010,000       (232,576,000)     (61,984,000)
                                                               -------------------------------------------------------
                 Net Change....................................     $(499,230,000)     $ 489,307,000    $ 139,468,000
                                                               =======================================================
</TABLE>

     Estimated  future cash inflows are computed by applying  year-end prices of
oil  and  gas to  year-end  quantities  of  Proved  Reserves.  Estimated  future
development and production  costs are determined by estimating the  expenditures
to be incurred in  developing  and  producing the proved oil and gas reserves at
the end of the year,  based on  year-end  costs  and  assuming  continuation  of
existing economic conditions.  Estimated future income tax expense is calculated
by applying  year-end  statutory tax rates to estimated  future pre-tax net cash
flows  related  to  proved  oil and gas  reserves,  less  the tax  basis  of the
properties involved.

     The  assumptions  used  to  compute  the  standardized  measure  are  those
prescribed  by the  Financial  Accounting  Standards  Board and as such,  do not
necessarily reflect the Company's  expectations of actual revenues to be derived
from those reserves nor their present  worth.  The  limitations  inherent in the
reserve quantity  estimation  process are equally applicable to the standardized
measure  computations  since  these  estimates  are the basis for the  valuation
process.

                                      F-32

<PAGE>

Item 9. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure.

     None.

                                    PART III

Item 10. Directors, Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act

     The following table sets forth the directors,  executive officers and other
significant employees of the Company,  their ages, and all offices and positions
with  the  Company.  Each  director  is  elected  for a  period  of one year and
thereafter serves until his successor is duly elected by the stockholders of the
Company and qualifies.

<TABLE>
<CAPTION>
<S>                               <C>       <C>
 Name                             Age       Title
Gary C. Evans...................  44        Chairman, President and Chief Executive Officer
Richard R. Frazier..............  55        President and Chief Operating Officer of Magnum Hunter
                                            Production, Inc. and Gruy
Chris Tong......................  45        Senior Vice President and Chief Financial Officer
R. Douglas Cronk ...............  55        Senior Vice President of Operations of Magnum Hunter Production, Inc.
                                            and Gruy
Morgan F. Johnston..............  41        Vice President, General Counsel and Secretary
David S. Krueger................  52        Vice President and Chief Accounting Officer
Michael P. McInerney ...........  60        Vice President, Corporate Development & Investor Relations
Charles R. Erwin................  55        Senior Vice President of Exploration of Magnum Hunter Production, Inc.
                                            and Gruy
Gregory L. Jessup...............  48        Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits..............  50        Vice President and Controller
Craig Knight....................  45        Vice President of Operations of Hunter Gas Gathering, Inc.
Earl Krieg, Jr. ................  48        Vice President of Engineering of Magnum Hunter Production, Inc. and
                                            Gruy
Gerald W. Bolfing...............  73        Director
Jerry Box.......................  63        Director
Robert Kelley...................  56        Director
Jim Kneale......................  50        Director
James R. Latimer, III...........  55        Director
Matthew C. Lutz.................  68        Director
John H. Trescot, Jr.............  77        Director
James E. Upfield................  81        Director
</TABLE>

     Gary C.  Evans has  served as  President,  Chief  Executive  Officer  and a
director of Magnum Hunter  Resources,  Inc. since December 1995 and Chairman and
Chief  Executive  Officer of all of the Magnum Hunter  subsidiaries  since their
formation or  acquisition.  In 1985, Mr. Evans formed the  predecessor  company,
Hunter  Resources,  Inc., that was merged into and formed Magnum Hunter some ten
years later.  From 1981 to 1985,  Mr. Evans was  associated  with the Mercantile
Bank of Canada where he held various  positions  including  Vice  President  and
Manager of the Energy Division of the Southwestern  United States.  From 1978 to
1981,  he served in various  capacities  with  National  Bank of  Commerce  (now
BancTexas,  N.A.) including Credit Manager and Credit Officer.  Mr. Evans serves
on the Board of Directors of Novavax,  Inc., an American Stock  Exchange  listed
pharmaceutical  company.  He  additionally  serves on the board of three private
Texas-based companies that Magnum Hunter owns various minority interests in,

                                       49

<PAGE>

     including(i)  Swanson Consulting  Services,  Inc., a geological  consulting
firm;  (ii)  NGTS,  LLC,  a natural  gas  marketing  company  and  (iii)  Aurion
Technologies,  Inc., a company that provides  web-enabled  automation to the oil
and natural gas industry.  He also serves as a Trustee of TEL Offshore Trust, an
OTC listed oil and gas trust of which  Magnum  Hunter  owns an  approximate  36%
interest.

                                    Officers

     Richard R. Frazier has served as President and Chief  Operating  Officer of
Magnum Hunter  Production,  Inc. and Gruy since January 1994. From 1977 to 1993,
Mr. Frazier was employed by Edisto Resources  Corporation in Dallas,  serving as
Executive Vice President  Exploration and Production from 1983 to 1993, where he
had overall responsibility for its property acquisition,  exploration, drilling,
production,  gas marketing and  engineering  functions.  From 1972 to 1976,  Mr.
Frazier served as District Production Superintendent and Petroleum Engineer with
HNG Oil Company (now Enron Oil & Gas Company) in Midland,  Texas.  Mr. Frazier's
initial  employment,  from 1968 to 1971, was with Amerada Hess  Corporation as a
petroleum  engineer  involved in numerous  projects in Oklahoma  and Texas.  Mr.
Frazier  graduated  in 1970 from the  University  of Tulsa  with a  Bachelor  of
Science  Degree  in  Petroleum  Engineering.  He  is a  registered  Professional
Engineer in Texas and a member of the Society of  Petroleum  Engineers  and many
other professional organizations.

     Chris Tong has served as Senior Vice President and Chief Financial  Officer
since August 1997. Previously,  Mr. Tong was Senior Vice President of Finance of
Tejas Acadian  Holding Company and its  subsidiaries  including Tejas Gas Corp.,
Acadian  Gas  Corporation  and  Transok,  Inc.,  all of which were  wholly-owned
subsidiaries of Tejas Gas  Corporation.  In January 1998,  Tejas Gas Corporation
was acquired by Shell Oil. Mr. Tong held these  positions since August 1996, and
served in other treasury positions with Tejas beginning August 1989. He was also
responsible for managing Tejas' property and liability  insurance.  From 1980 to
1989,  Mr.  Tong  served in various  energy  lending  capacities  with  Canadian
Imperial Bank of Commerce,  Post Oak Bank, and Bankers Trust Company in Houston,
Texas.  Prior to his  banking  career,  Mr.  Tong also  served  over a year with
Superior Oil Company as a Reservoir Engineering  Assistant.  Mr. Tong is a summa
cum laude graduate of the University of  Southwestern  Louisiana with a Bachelor
of Arts degree in Economics and a minor in Mathematics.

     R.  Douglas  Cronk has served as Senior Vice  President of  Operations  for
Magnum Hunter  Production,  Inc. and Gruy since December 1998. He served as Vice
President of Operations  for the two companies  since May 1996 at which time the
Company  acquired  from Mr. Cronk  Rampart  Petroleum,  Inc.,  based in Abilene,
Texas. Rampart had been an active operating and exploration company in the north
central and west Texas region since 1983. Prior to the formation of Rampart, Mr.
Cronk  was  an  independent  oil  and  gas  consultant  in  Houston,  Texas  for
approximately  two years.  From 1974 to 1981,  Mr. Cronk held various  positions
with subsidiaries of Deutsch Corporation of Tulsa, Oklahoma, including Southland
Drilling  and  Production  where  he  became  Vice  President  of  Drilling  and
Production.  Mr. Cronk is a Chemical  Engineer  graduate from the  University of
Tulsa.

     Charles R. Erwin has served as Senior Vice  President  of  Exploration  for
Magnum Hunter  Production,  Inc. and Gruy  Petroleum  Management  Co. since July
2000. He became Vice President of Exploration for Magnum Hunter Production, Inc.
and Gruy Petroleum Management Co. in January 2000. Mr. Erwin initially served as
Manager of Exploration for Gruy Petroleum  Management Co. beginning May of 1999.
Mr.  Erwin  received a Masters in Geology  from the  University  of  Wisconsin -
Milwaukee. He has 27 years experience in the oil and gas industry. Prior to Gruy
Petroleum  Management Co., Mr. Erwin worked for Enserch Exploration for 22 years
holding  various  positions   including   Exploration   Manager  -  East  Texas,
Exploration  Manager - Texas and Louisiana  Gulf Coast and Director  Exploration
Offshore and International.

     Morgan F. Johnston has served as Vice  President and General  Counsel since
April  1997 and has served as the  Company's  Secretary  since May 1, 1996.  Mr.
Johnston  was in private  practice  as a sole  practitioner  from May 1, 1996 to
April 1, 1997,  specializing in corporate and securities law. From February 1994
to May 1996,  Mr.  Johnston  served  as  general  counsel  for  Millennia,  Inc.
(formerly known as SOI Industries, Inc.) and Digital Communications

                                       50

<PAGE>

     Technology  Corporation,  two American Stock Exchange listed companies.  He
also  served  as  general  counsel  to  Halter  Capital  Corporation,  a private
consulting  firm from August 1991 to May 1996. For the two years prior to August
1991 he was  securities  counsel  for Motel 6 L.P.,  a New York  Stock  Exchange
listed company.  Mr. Johnston  graduated cum laude from Texas Tech Law School in
May 1986 and was also a member of the Texas Tech Law  Review.  He is licensed to
practice law in the State of Texas.

     David S. Krueger has served as Vice President and Chief Accounting  Officer
of the Company since January 1997. Mr.  Krueger acted as Vice  President-Finance
of Cimarron Gas Holding Co., a gas processing and natural gas liquids  marketing
company in Tulsa,  Oklahoma,  from April 1992 until  January  1997. He served as
Vice  President/  Controller  of American  Central Gas  Companies,  Inc.,  a gas
gathering, processing and marketing company from May 1988 until April 1992. From
1974 to 1986, Mr. Krueger served in various managerial  capacities for Southland
Energy  Corporation.  From 1971 to 1973, Mr. Krueger was a staff accountant with
Arthur Andersen LLP. Mr. Krueger, a certified public accountant,  graduated from
the  University of Arkansas with a B.S./B.A.  degree in Business  Administration
and earned his M.B.A. from the University of Tulsa.

     Michael P. McInerney has served as Vice President,  Corporate Development &
Investor  Relations  of the Company  since  October  1997.  Prior to joining the
Company,  Mr. McInerney owned Energy Advisors,  Inc., an energy consulting firm,
from June 1993 until  October 1997.  Mr.  McInerney was employed from 1981 until
June 1993 by Triton Energy Corporation, an independent energy company, where his
responsibilities   included  investor  relations,   acquisitions  and  corporate
planning.  Before joining Triton Energy  Corporation,  Mr. McInerney served nine
years in various financial  management positions with American Natural Resources
Company,  a  gas  transmission  and  distribution  corporation.   Mr.  McInerney
graduated from the University of Michigan with a B.B.A.

     Gregory  L.  Jessup  has been  Vice  President  of Land for  Magnum  Hunter
Production,  Inc., a wholly-owned subsidiary of the Company and Gruy since April
17, 1998.  Mr.  Jessup  joined the Company as Land Manager on May 1, 1997.  From
1982  until  joining  the  Company,  Mr.  Jessup  served as Land  Manager of Ken
Petroleum  Corporation of Dallas managing its Land and Regulatory  Department as
well as managing  its crude oil  marketing  business.  During his tenure as Land
Manager, Mr. Jessup has been actively involved in all phases of land operations,
including  negotiations,  acquisitions,  and administration.  Mr. Jessup holds a
Bachelor  of  Business  Administration  degree in  Management  from  Texas  Tech
University and is a Certified Professional Landman.

     David M.  Keglovits  has served as Vice  President  and  Controller  of the
Company and its subsidiaries  since 1999. Prior to 1999. Mr. Keglovits served as
Vice President and Controller of Gruy. Mr.  Keglovits  joined Gruy in March 1977
as an  accountant  before  holding the  positions  of Assistant  Controller  and
Controller.  From December 1974 to December 1976, Mr.  Keglovits was employed by
Bell  Helicopter  International  in its financial  management  office in Tehran,
Iran.  Mr.  Keglovits was graduated  with honors from the University of Texas at
Austin with a B.B.A. in Accounting.

     Craig  Knight has served as Vice  President  of  Operations  for Hunter Gas
Gathering,  Inc.  since March 1998.  Prior to joining the Company Mr. Knight was
employed by MidCon Corp.  and its affiliates  since 1979 in various  capacities.
From 1995 to his departure  from MidCon he served as the Sr.  Business  Manager,
Gathering and Processing for MidCon Gas Products Corp. where he managed MidCon's
gathering and  processing  activities in the Panhandle and Permian Basin regions
of Texas. From 1992 -1994, he served as an account manager of the Electric Power
Sector  Start-up Group for MidCon Gas Services Corp and as Manager - West Region
for MidCon  Marketing Corp. Mr. Knight graduated from Texas Tech University with
a B.S. in Engineering Technology with Construction  Specialty.  He also received
his M.B.A. in Executive Programs from University of Houston in 1989.

     Earl  Krieg  has  served  as  Manager  of  Engineering  for Gruy  Petroleum
Management Co. since May of 1999. Mr. Krieg became Vice President of Engineering
for Magnum  Hunter  Production,  Inc.  and Gruy in January  2000.  Mr. Krieg was
employed  by The Wiser Oil  Company  for the five  years  prior to  joining  the
Company in various  capacities  including  Manager of Operations  and Manager of
Secondary  Recovery.  Mr.  Krieg has 26 years  experience  in various  reservoir
engineering, operations, acquisitions and management roles with Chevron, General
Crude, Edisto and most recently The Wiser Oil Company. Mr. Krieg is a Registered
Professional  Engineer in Texas and was an officer in the  Society of  Petroleum
Evaluation  Engineers in 1989. Mr. Krieg  graduated from Texas A&M University in
1975 with a B.S. degree in petroleum engineering.

                                       51

<PAGE>

                                    Directors

     Gerald W. Bolfing has been a director of Magnum Hunter since December 1995.
Mr. Bolfing was appointed a director of Hunter  Resources,  Inc. in August 1993.
He is an  investor  in the oil and gas  business  and a past  officer  of one of
Hunter's  former  subsidiaries.  From 1962 to 1980, Mr. Bolfing was a partner in
Bolfing Food Stores in Waco, Texas. Mr. Bolfing was involved in American Service
Company  in  Atlanta,  Georgia  from 1964 to 1965,  and was  active  with  Cable
Advertising  Systems,  Inc. of  Kerrville,  Texas from 1978 to 1981. He joined a
Hunter  subsidiary  in the well  servicing  business  in 1981 where he  remained
active until its  divestiture  in 1992. Mr. Bolfing is on the board of directors
of Capital Marketing Corporation of Hurst, Texas.

     Jerry Box has served as a director of Magnum Hunter since March 1999.  From
February  1998 to March 1999,  he served in the position of president  and chief
operating  officer and as a director of Oryx Energy  Company,  now owned by Kerr
McGee  Corporation.  From December 1995 to February  1998, he was executive vice
president  and chief  operating  officer of Oryx.  From  December  1994  through
November 1995, he served as executive vice president, exploration and production
of Oryx.  Previously,  he served  as  senior  vice  president,  exploration  and
production  of Oryx.  Mr.  Box  attended  Louisiana  Tech  University,  where he
received B.S. and M.S. degrees in geology, and is also a graduate of the Program
for Management Development at the Harvard University Graduate School of Business
Administration. Mr. Box served as an officer in the U. S. Air Force from 1961 to
1966. Mr. Box is a former member of the Policy Committee of the U. S. Department
of the Interior's  Outer  Continental  Shelf Advisory  Board,  past chairman and
vice-chairman  of  the  American  Petroleum   Institute's   Exploration  Affairs
subcommittee,  a former  president of the Dallas  Petroleum Club and a member of
the Independent Petroleum Association of America.

     Robert Kelley was a director of Prize from May 2001 until the merger. He is
currently  president of Kellco Investments Inc., a private  investment  company.
From 1986  through  October  2000,  Mr.  Kelley  served as  president  and chief
executive officer of Noble Affiliates,  Inc., an independent energy company with
domestic and  international  exploration  and production  operations.  From 1992
through  April  2001,  Mr.  Kelley also served as chairman of the board of Noble
Affiliates,  and he was a director of Noble  Affiliates  from 1986 through April
2001. He held various financial and operational  positions with Noble Affiliates
and its  subsidiaries  from 1975 until his election as  president  in 1986.  Mr.
Kelley also serves as a director of OGE Energy Corp., the parent company of OG&E
Electric Services,  Oklahoma's largest electric utility; Enogex, Inc., a natural
gas pipeline,  processing and energy marketing business; Lone Star Technologies,
Inc., a leading  manufacturer  of oilfield  tubular  products;  and  Continental
Resources,  Inc., a privately held  exploration  and  production  company active
primarily in the Rocky Mountain and Mid-Continent  regions of the United States.
Mr. Kelley  received his B.B.A from the  University of Oklahoma in 1973 and is a
certified public accountant.

     Jim Kneale has served as a director of Magnum Hunter since  September 2000.
Mr. Kneale is currently employed by ONEOK, Inc., as senior vice president, chief
financial  officer and  treasurer  and has been such since  January  2001. He is
responsible for the finance, tax and accounting, internal audit and risk control
functions for ONEOK.  Mr. Kneale joined ONEOK in 1981 as vice president of ONEOK
Drilling Company. He became vice president of Energy Companies of ONEOK later in
1981 and was named  vice  president  of  accounting  for  Oklahoma  Natural  Gas
Company, a division of ONEOK, Inc., in 1992. Mr. Kneale became vice president of
the Tulsa  District of Oklahoma  Natural Gas in 1994,  vice  president for ONEOK
Resources in 1996, and president of Oklahoma Natural Gas in 1997. He was elected
to the chief financial  officer  position in 1999. Mr. Kneale is a member of the
American  Institute of Certified Public  Accountants and the Oklahoma Society of
CPAs.  Mr. Kneale serves on the board of directors of the YMCA of Greater Tulsa,
the Tulsa Boys' Home, Tulsa Community College Foundation, and the Advisory Board
of the Oklahoma  Blood  Institute.  A certified  public  accountant,  Mr. Kneale
received his accounting degree from West Texas A&M University in 1973.

     James R.  Latimer,  III was a director of Prize from October 2000 until the
merger.  Over the past eight years,  Mr. Latimer has been the chairman and chief
executive   officer  of  Explore  Horizons,   Incorporated,   a  privately  held
exploration  and  production  company based in Dallas,  Texas.  Previously,  Mr.
Latimer was co-head of the regional office of what is now The Prudential Capital
Group in  Dallas,  Texas,  which  handled  energy  and other  financing  for The
Prudential  Insurance Company.  In addition,  Mr. Latimer's prior experience has
included senior executive positions with several

                                       52

<PAGE>

     private  energy  companies,  consulting  with the firm of  McKinsey  & Co.,
service as an officer in the United  States  Army  Signal  Corps.,  and  several
directorships.  Mr.  Latimer  received  a B.A.  degree  in  economics  from Yale
University and an M.B.A. from Harvard  University.  He is a Chartered  Financial
Analyst.

     Matthew C. Lutz  retired as chairman of Magnum  Hunter on September 1, 2001
after  having  served  in that  capacity  since  March  1997  and  after  having
previously  served as vice chairman of Magnum Hunter from December 1995 to March
1997.  Mr. Lutz also  previously  served as executive  vice  president of Magnum
Hunter from December  1995 to September  2001.  Mr. Lutz held similar  positions
with Hunter  Resources,  Inc. from September 1993 until October 1996.  From 1984
through 1992, Mr. Lutz was senior vice  president of exploration  and a director
of Enserch Exploration,  Inc., with responsibility for its worldwide oil and gas
exploration and development program. Prior to joining Enserch, Mr. Lutz spent 28
years with Getty Oil Company. He advanced through several technical, supervisory
and  managerial  positions  which gave him  various  responsibilities  including
exploration,   production,  lease  acquisition,   administration  and  financial
planning.

     John H.  Trescot,  Jr. has served as a director of Magnum Hunter since June
1997. Mr. Trescot is the principal of AWA Management  Corporation,  a consulting
firm  specializing  in financial  evaluations for companies and entities such as
the Overseas Private Investment Corp. Mr. Trescot began his professional  career
as an engineer with Shell Oil Company.  Later,  Mr. Trescot joined Hudson Pulp &
Paper Corp.  (now a part of  Georgia-Pacific  Corp.) where he served 19 years in
various positions in woodlands and pulp and paper,  advancing to the position of
senior vice president for its Southern Operations.  Mr. Trescot then became vice
president of The Charter  Company,  a multi-  billion  dollar  corporation  with
operations in oil, communications and insurance. In 1979, Mr. Trescot became the
chief  executive  officer of JARI,  a timber,  pulp and mining  operation in the
Amazon Basin of Brazil. During 1982-89, while he was the chief executive officer
of TOT Drilling Corp.,  TOT drilled many deep wells in West Texas and New Mexico
for major and  independent  oil companies.  Mr. Trescot  received his BME degree
from Clemson University and his M.B.A. from Harvard University.

     James E. Upfield has served as a director of Magnum  Hunter since  December
1995. Mr. Upfield was appointed a director of Hunter Resources,  Inc., in August
1992. Mr. Upfield is chairman of Temtex Industries, Inc., a public company based
in Dallas,  Texas, that produces consumer hard goods and building materials.  In
1969, Mr. Upfield served on a select  Presidential  Committee  overseeing postal
operations of the United States of America. He later accepted the responsibility
for the Dallas region, which encompassed Texas and Louisiana. From 1959 to 1967,
Mr. Upfield was president of Baifield  Industries,  Inc. and its predecessor,  a
company he founded in 1949 which  merged  with  Baifield in 1963.  Baifield  was
engaged in prime  government  contracts for military  systems and sub-systems in
the production of high-strength, light-weight metal products.

                                       53

<PAGE>

Item 11.          Executive Compensation.

     The  following  table  contains   information  with  respect  to  all  cash
compensation  paid or accrued by the Company  during the past three fiscal years
to the Company's Chief Executive Officer and each person serving as an executive
officer of the Company on December 31, 2001.

<TABLE>
<CAPTION>
<S>                         <C>     <C>        <C>          <C>              <C>        <C>        <C>         <C>
                                                                                 Long Term Compensation
                                     Annual Compensation                      Awards               Payout
           (a)               (b)      (c)         (d)            (e)            (f)       (g)        (h)           (i)
          Name,                                                 Other                    Number
        Principal                                               Annual      Restricted  Options      LTP        All Other
         Position           Year     Salary      Bonus     Compensation (a)    Stock      SARs     Payouts    Compensation
         --------           ----     ------      -----     -------------       -----      ----     -------    ------------
Gary C. Evans               2001    $350,000   $425,000        $ 7,500           -         -          -        $20,627 (b)
Chairman, President and     2000    $300,000   $400,000        $ 7,500           -         -          -        $19,933 (b)
CEO                         1999    $250,000   $250,000        $ 7,500           -         -          -        $19,342 (b)

Richard R. Frazier          2001    $190,000   $150,000        $ 6,000           -         -          -             -
President of                2000    $175,000   $125,000        $ 6,000           -         -          -             -
Magnum Hunter               1999    $150,000   $ 75,000        $ 4,200           -         -          -             -
Production, Inc.

Chris Tong                  2001    $165,000   $100,000        $ 6,000           -         -          -             -
Senior Vice President &     2000    $160,000   $ 65,000        $ 6,000           -         -          -             -
Chief Financial Officer     1999    $150,000   $ 35,000        $ 6,000           -         -          -             -

R. Douglas Cronk            2001    $138,000   $ 75,000        $ 6,000           -         -          -             -
Senior V.P. of Magnum       2000    $122,500   $ 65,000        $ 6,000           -         -          -             -
Hunter Production, Inc.     1999    $115,000   $ 25,000        $ 4,200           -         -          -             -

Charles R. Erwin (c)        2001    $145,000   $125,000        $ 6,000           -         -          -             -
Senior V.P. of Magnum       2000    $113,423   $125,000        $ 5,100           -         -          -             -
Hunter Production, Inc.     1999    $ 90,000    $ 7,500           -              -         -          -             -
</TABLE>

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

     (a)  Other  compensation  consists  of a  vehicle  allowance  paid  to  the
employee.
     (b) Mr. Evans receives compensation for acting as an individual Trustee for
the TEL Offshore Trust.
     (c) Mr. Erwin was hired in May 1999.

                                       54

<PAGE>

                      Option/SAR Grants in Last Fiscal Year

<TABLE>
<CAPTION>
<S>                  <C>           <C>                <C>             <C>        <C>                <C>         <C>
                                                                                                                Alternative to
                                                                                 Potential realizable value at   (f) and (g):
                                                                                  assumed annual rates of stock   grant date
                               Individual Grants                                  price appreciation for option termvalue
-------------------------------------------------------------------------------- -----------------------------  -------------
       Name            Number of    Percent of total  Exercise or base  Expiration      5% ($)         10% ($)      Grant date
                       securities     options/SARs    price ($/Sh)        date                                     present value
                       underlying      granted to                                                                     $
                      Options/SARs    employees in
                       granted (#)    fiscal year
        (a)               (b)             (c)            (d)             (e)            (f)            (g)           (f) *
-------------------  -------------- --------------- --------------   ------------ --------------- -------------  -------------
Gary C. Evans               300,000      19.0%          $8.44          12/12/11                                     $1,518,000
Richard R. Frazier          125,000       7.9%          $8.44          12/12/11                                        632,500
Charles R. Erwin            100,000       6.3%          $8.44          12/12/11                                        506,000
R. Douglas Cronk             75,000       4.7%          $8.44          12/12/11                                        379,500
Chris Tong                   75,000       4.7%          $8.44          12/12/11                                        379,500
</TABLE>

     * The Company used the  Black-Scholes  method to determine the value of the
option grants.

<TABLE>
<CAPTION>
                 Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values

<S>                    <C>                      <C>              <C>                     <C>
                                                                  Number of securities    Value of unexercised in-
                                                                 underlying unexercised    the-money options/SARs
                                                                  options/SARs at fiscal   at fiscal year-end ($)
                                                                       year-end (#)

                         Shares acquired on         Value              Exercisable/              Exercisable/
         Name               exercise (#)         Realized ($)          unexercisable            unexercisable

          (a)                    (b)                 (c)                    (d)                      (e)
---------------------------------------------------------------- ---------------------------------------------------
   Gary C. Evans               150,000             $570,000         330,000 / 420,000       $913,500 / $645,250
   Richard R. Frazier          100,000             $393,000         240,000 / 210,000       $904,500 / $311,750
   Charles R. Erwin               -                   -              68,000 / 148,000       $ 60,900 / $ 68,150
   R. Douglas Cronk             76,666             $525,579          91,334 / 112,000       $304,819 / $138,475
   Chris Tong                   11,800             $ 74,398         202,200 / 108,000       $820,790 / $136,300
</TABLE>

     Compensation of Directors

     The Company has nine individuals who serve as directors, eight of which are
independent. One director receives compensation with respect to his services and
in his  capacities  as an  executive  officer of the Company  and no  additional
compensation  has  historically  been paid for his  services to the Company as a
director.  The other eight  directors of the Company  were not  employees of the
Company at December 31, 2001 and receive no  compensation  for their services as
directors  other  than as  stated  below.  For  fiscal  year  2001,  independent
directors  received a $15,000  retainer for being a board member and in addition
received $1,500 per meeting attended and $500 per committee meeting attended. In
addition,  for the fiscal year 2001 each independent  director was granted stock
options to acquire  15,000 shares of the  Company's  common stock at an exercise
price not less than the market price

                                       55

<PAGE>



of the common stock on the date of grant. For fiscal year 2002, independent
directors will receive a $15,000 retainer (pro-rated) for being a board member
and in addition will receive $1,500 per meeting attended and $500 per committee
meeting attended. Other than the compensation stated herein, the Company has not
entered into any arrangement, including consulting contracts, in consideration
of the director's service on the board.

     Employment  Contracts and  Termination of Employment and  Change-in-Control
Arrangements

     Mr. Gary C. Evans,  Mr. Richard R. Frazier,  Mr. Chris Tong, Mr. R. Douglas
Cronk and Mr. Charles R. Erwin each have employment agreements with the Company.
Mr. Evans' agreement  terminates  January 1, 2006 and continues  thereafter on a
year to year  basis and  provides  for a salary  of  $300,000  per annum  unless
increased by the Board.  Mr.  Evans'  salary for the year 2002 is $375,000.  Mr.
Frazier's  agreement  terminates  January 1, 2006 and continues  thereafter on a
year to year  basis and  provides  for a salary  of  $175,000  per annum  unless
increased by the Board. Mr. Frazier's salary for the year 2002 is $205,000.  Mr.
Tong's agreement  terminates January 1, 2004 and continues  thereafter on a year
to year basis and provides  for a salary of $160,000 per annum unless  increased
by the Board.  Mr.  Tong's  salary for the year 2002 is  $175,000.  Mr.  Cronk's
agreement  terminates January 1, 2004 and continues thereafter on a year to year
basis and provides  for a salary of $122,500  per annum unless  increased by the
Board. Mr. Cronk's salary for the year 2002 is $150,000.  Mr. Erwin's  agreement
terminates January 1, 2004 and continues  thereafter on a year to year basis and
provides for a salary of $105,000 per annum unless  increased by the Board.  Mr.
Erwin's salary for the year 2002 is $155,000. All of the agreements provide that
the same benefits  supplied to other Company employees shall be available to the
employee. The employment agreements also contain, among other things,  covenants
by the employee that in the event of  termination,  he will not compete with the
Company in certain geographical areas or hire any employees of the Company for a
period of two years after cessation of employment.

     In  addition,  all  of the  agreements  contain  a  provision  that  upon a
change-in-control  of the Company and the  employee's  position is terminated or
the  employee  leaves for "good  cause",  the  employee  is entitled to receive,
immediately in one lump sum, certain compensation.  In the case of Mr. Evans and
Mr. Frazier,  the employee shall receive three times the employee's base salary,
bonus for the last fiscal year and any other compensation received by him in the
last fiscal year. In the case of Mr. Tong, Mr. Cronk and Mr. Erwin, the employee
shall receive the employee's base salary, bonus for the last fiscal year and any
other  compensation  received by him in the last fiscal year  multiplied by two.
Also, any medical, dental and group life insurance covering the employee and his
dependents  shall  continue  until  the  earlier  of (i)  12  months  after  the
change-in-control  or (ii) the date the employee  becomes a  participant  in the
group insurance benefit program of a new employer.  The Company also has key man
life insurance on Mr. Evans in the amount of $12,000,000.

                                       56

<PAGE>

Item 12. Security Ownership of Certain Beneficial Owners and Management.

     The following  table sets forth certain  information  as of March 15, 2002,
regarding  the share  ownership  of the Company by (i) each person  known to the
Company to be the beneficial owner of more than 5% of the outstanding  shares of
Common Stock of the  Company,  (ii) each  director,  (iii) the  Company's  Chief
Executive Officer and the four other most highly compensated  executive officers
of the Company, and (iv) all directors and executive officers of the Company, as
a group.  None of the directors or executive  officers named below,  as of march
15, 2002, owned any shares of the Company's Series A Preferred Stock or its 1996
Series A Convertible  Preferred  Stock. The business address of each officer and
director  listed  below is:  c/o Magnum  Hunter  Resources,  Inc.,  600 East Las
Colinas Blvd., Suite 1100, Irving, Texas 75039.

<TABLE>
<CAPTION>
<S>                                                                              <C>                <C>
                                                                                     Common Stock
                                                                                   Beneficially Owned
                                                                                  Number of            Percent
                             Name                                                  Shares            of Class (m)
Directors and Executive Officers
       Gary C. Evans ..........................................                  3,026,073 (a)           4.3%
       Richard R. Frazier......................................                    363,115 (b)              *
       Chris Tong..............................................                    210,133 (c)              *
       R. Douglas Cronk .......................................                    145,102 (d)              *
       Charles R. Erwin........................................                     68,000 (e)              *
       Gerald W. Bolfing.......................................                    467,349 (f)              *
       Jerry Box...............................................                     48,335 (g)              *
       Robert Kelley...........................................                      7,195                  *
       Jim Kneale .............................................                     10,000 (h)              *
       James R. Latimer, III ..................................                      2,195                  *
       Matthew C. Lutz.........................................                    746,729 (i)              *
       John H. Trescot, Jr.....................................                   120,056  (j)              *
       James E. Upfield.......................................                     142,392 (k)              *
       All directors and executive officers as a group
       (13 persons)............................................                  5,356,674               7.4%
Beneficial owners of 5 percent or more
(excluding persons named above)
       ONEOK Resources Company
       100 W. Fifth Street
       Tulsa, OK 74103-4298 ...................................                  7,936,507              11.3%
       Natural Gas Partners V, L.P.
       125 E. John Carpenter Freeway, Suite 600
       Irving, TX 75062........................................                 13,417,052 (l)          19.1%
</TABLE>

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

     * Less than one percent.

     (a) Includes  330,000  shares of common stock issuable upon the exercise of
certain  currently  exercisable  options.  Also  includes  494,921  common stock
purchase warrants which are currently  exercisable.  Also includes 17,024 shares
held in the name of Jacquelyn Evelyn Enterprises, Inc., a corporation whose sole
shareholder  is Mr.  Evans' wife.  Mr.  Evans  disclaims  any  ownership in such
securities other than those in which he has an economic interest.
     (b) Includes  240,000  shares of common stock issuable upon the exercise of
certain currently exercisable options.
     (c) Includes  196,200  shares of common stock issuable upon the exercise of
certain currently exercisable options.

                                       57

<PAGE>

     (d) Includes  91,334  shares of common stock  issuable upon the exercise of
certain currently exercisable options.
     (e) Includes  68,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.
     (f) Includes  15,000  shares of common stock  issuable upon the exercise of
certain  currently  exercisable  options.  Also  includes  84,339  common  stock
purchase warrants which are currently exercisable.
     (g) Includes  31,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.
     (h) Includes  9,000 shares of common  stock  issuable  upon the exercise of
certain currently exercisable options.
     (i) Includes  523,000  shares of common stock issuable upon the exercise of
certain  currently  exercisable  options.  Also  includes  49,641  common  stock
purchase warrants which are currently exercisable.
     (j) Includes  11,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.
     (k) Includes  11,000  shares of common stock  issuable upon the exercise of
certain  currently  exercisable  options.  Also  includes  15,848  common  stock
purchase warrants which are currently exercisable.
     (l) Based on Schedule  13G filed by Natural  Gas  Partners V, L.P. on March
15, 2002.
     (m) Percentage is calculated on the number of shares outstanding plus those
shares deemed outstanding under Rule 13d-3(d)(1) under the Exchange Act.


Item 13. Certain Relationships and Related Transactions.

     The  Company's  Board of  Directors  authorized a loan of up to $371,860 be
made available to Gary C. Evans,  President and Chief  Executive  Officer of the
Company,  as  part of his  compensation  package.  The  balance  outstanding  at
December 31, 1999 was $371,860 and bears interest at 10%. On January 7, 2000 Mr.
Evans repaid $225,000 on the loan,  leaving a principal balance of $146,860.  On
April 17, 2000 Mr. Evans re-borrowed $100,000 under this loan, and on August 18,
2000 he repaid $258,731,  including  accrued  interest,  bringing the balance to
zero. On December 28, 2000 Mr. Evans  borrowed  $294,938,  which was the balance
owed to the Company on December 31, 2000 and included in notes  receivable  from
affiliate.  On January 15, 2001 Mr. Evans  repaid  $295,261,  including  accrued
interest,  bringing the balance to zero. On April 16, 2001,  Mr. Evans  borrowed
$300,000 pursuant to a loan approved by the Company's Board of Directors for the
payment of deferred  income taxes.  Subsequent  to December 31, 2001,  Mr. Evans
repaid the loan in full,  including  accrued  interest,  bringing the balance to
zero.

     On November 28, 2000,  Mr.  Matthew C. Lutz,  Chairman and  Executive  Vice
President of the Company, borrowed $65,000 from the Company with the approval of
the Board of Directors. On January 15, 2001, Mr. Lutz repaid the loan, including
accrued interest.

     During 1998, the Company  acquired  certain shares of a publicly traded oil
and gas company  from Mr. Gary C. Evans at Mr.  Evans' cost basis in such shares
of stock. The shares were purchased for a total of $442,019. The Company has the
right through December 31, 2002 to cause Mr. Evans to repurchase the shares back
from the Company at the equivalent  price that the Company  purchased the shares
from Mr. Evans.

                                       58

<PAGE>

                                    GLOSSARY

As used in this document:

     "Mcf" means thousand cubic feet;
     "MMcf" means million cubic feet;
     "Bcf" means billion cubic feet;
     "Bbl" means barrel;
     "MBbls" means thousand barrels;
     "MMBbls" means million barrels;
     "BOE" means barrel of oil equivalent;
     "MMBOE" means million barrels of oil equivalent
     "Btu" or  "British  Thermal  Unit" means the  quantity of heat  required to
raise the temperature of one pound of water by one degree Fahrenheit;
     "MMBtu" means million British Thermal Units;
     "Mcfe" means thousand cubic feet of natural gas equivalent;
     "MMcfe" means million cubic feet of natural gas equivalent; and
     "Bcfe" means billion cubic feet of natural gas equivalent.

     Natural gas equivalents and crude oil equivalents are determined  using the
ratio of six Mcf of natural gas to one Bbl of crude oil,  condensate  or natural
gas liquids. All estimates of reserves,  unless otherwise noted, are reported on
a "net" basis. Information regarding production, acreage and numbers of wells is
set forth on a gross basis, unless otherwise noted.

     "Proved  reserves" means the estimated  quantitie of crude oil, natural gas
and natural gas liquids which  geological and engineering  data demonstrate with
reasonable  certainty to be  recoverable  in future years from known  reservoirs
under existing economic and operating  conditions,  i.e., prices and costs as of
the date the  estimate  is made.  Prices  include  consideration  of  changes in
existing  prices  provided  only  by  contractual   arrangements,   but  not  on
escalations based upon future conditions.

     (i) Reservoirs are considered proved if economic producibility is supported
by  either  actual  production  or  conclusive  formation  test.  The  area of a
reservoir considered proved includes

     (A) that  portion  delineated  by drilling  and  defined by gas-oil  and/or
oil-water contacts, if any; and

     (B) the immediately  adjoining  portions not yet drilled,  but which can be
reasonably  judged  as  economically   productive  on  the  basis  of  available
geological  and  engineering  data.  In the  absence  of  information  on  fluid
contacts,  the lowest known structural  occurrence of hydrocarbons  controls the
lower proved limit of the reservoir.

     (ii) Reserves  which can be produced  economically  through  application of
improved  recovery  techniques  (such as fluid  injection)  are  included in the
"proved"  classification  when  successful  testing by a pilot  project,  or the
operation of an installed  program in the  reservoir,  provides  support for the
engineering analysis on which the project or program was based.

     (iii) Estimates of proved reserves do not include the following:

                                       59

<PAGE>

     (A) oil that may become  available from known  reservoirs but is classified
separately as "indicated additional reserves";

     (B) crude oil, natural gas, and natural gas liquids,  the recovery of which
is subject to reasonable  doubt because of uncertainty as to geology,  reservoir
characteristics, or economic factors;

     (C) crude oil,  natural  gas,  and natural gas  liquids,  that may occur in
undrilled prospects; and

     (D) crude oil, natural gas, and natural gas liquids,  that may be recovered
from oil shales, coal, gilsonite and other such sources.

     "PV-10" means the pre-tax  present  value of estimated  future net revenues
computed by applying current prices of oil and gas reserves (with  consideration
of price changes only to the extent  provided by  contractual  arrangements)  to
estimated  future  production  of proved oil and gas  reserves,  less  estimated
future  expenditures  (based on current  costs) to be incurred in developing and
producing  the  proved  reserves  computed  using a  discount  factor of 10% and
assuming continuation of existing economic conditions.

     "Proved developed oil and gas reserves" means reserves that can be expected
to be recovered  through  existing  wells with existing  equipment and operating
methods.  Additional oil and gas expected to be obtained through the application
of fluid injection or other improved  recovery  techniques for supplementing the
natural forces and mechanisms of primary  recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

     "Proved  undeveloped  reserves"  means  reserves  that are  expected  to be
recovered  from new wells on undrilled  acreage,  or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling  units  offsetting  productive  units
that are  reasonably  certain of production  when drilled.  Proved  reserves for
other  undrilled  units can be claimed  only where it can be  demonstrated  with
certainty  that there is continuity of production  from the existing  productive
formation.  Under no  circumstances  should  estimates  for  proved  undeveloped
reserves  be  attributable  to any  acreage  for which an  application  of fluid
injection or other  improved  recovery  technique is  contemplated,  unless such
techniques  have been proved  effective  by actual  tests in the area and in the
same reservoir.

     "Reserve Life" is an estimate of the productive life of a proved  reservoir
and for purposes of this document is calculated by dividing the proved  reserves
(on an Mcfe basis) at the end of the period by historical production volumes for
the prior 12 months.

     "Standardized  Measure of  Discounted  Future Net Cash  Flows"  means PV-10
after income taxes.

                                       60

<PAGE>

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

     (a) The following documents are filed as part of this report:
<TABLE>
<CAPTION>
<S>                                                                                                       <C>
1.  Financial Statements

     Independent Auditors' Report...........................................................................F-1

     Financial Statements:
             Consolidated Balance Sheets at December 31, 2001 and 2000......................................F-2

             Consolidated Statements of Operations and Comprehensive Income
                          for the Years Ended December 31, 2001, 2000 and 1999..............................F-3

             Consolidated Statements of Stockholders' Equity for the
                      Years Ended December 31, 2001, 2000 and 1999..........................................F-4

             Consolidated Statements of Cash Flows for the Years
                      Ended December 31, 2001, 2000 and 1999................................................F-5

     Notes to Consolidated Financial Statements.............................................................F-6

     Supplemental Information (Unaudited)..................................................................F-30

</TABLE>

2. Financial Statement Schedule

     We have  included on page 64 of this Annual  Report on Form 10-K  Financial
Statement Schedule II, Valuation and Qualifying Accounts.


                                       61

<PAGE>

3. Exhibits
<TABLE>
<CAPTION>
<S>              <C>

Number            Description of Exhibit

3.1 & 4.1         Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-18, File
                  No. 33-30298-D)
3.2 & 4.2         Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for
                  the year ended December 31, 1990)
3.3 & 4.3         Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration
                  Statement on Form SB-2, File No. 33-66190)
3.4 & 4.4         Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration
                  Statement on Form S-3, File No. 333-30453)
3.5 & 4.5 *       Articles of Amendment to Articles of Incorporation
3.6 & 4.6         By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File
                  No. 33-66190)
3.7 & 4.7         Amendment to By-Laws (Incorporated by reference to Registration Statement on Form S-4, File
                  No. 333-76774)
3.8 & 4.8         Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K
                  dated December 26, 1996, filed January 3, 1997)
3.9 & 4.9         Amendment to Certificate of Designations for 1996 Series A Convertible Preferred Stock
                  (Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453)
4.10              Form of Warrant Agreement by and between Magnum Hunter Resources, Inc. and American Stock
                  Transfer & Trust Company, as warrant agent (Incorporated by reference to Registration Statement
                  on Form S-3, File No. 333-82552)
4.11              Form of Warrant Agreement by and between Midland Resources, Inc. and Stock Transfer
                  Company of America, Inc., as warrant agent, dated November 1, 1990 (Incorporated by reference to
                  Registration Statement on Form S-3, File No. 333-83376)
4.12              Form of Warrant Agreement by and between Vista Energy Resources, Inc. and American Stock
                  Transfer & Trust Company, as warrant agent, dated October 28, 1998 (Incorporated by reference to
                  Registration Statement on Form S-3, File No. 333-83376)
4.13              Indenture dated May 29, 1997 between Magnum Hunter Resources, the subsidiary guarantors
                  named therein and First Union National Bank of North Carolina, as Trustee (Incorporated by
                  reference to Registration Statement on Form S-4, File No. 333-2290)
4.14              Supplemental Indenture dated January 27, 1999 between Magnum Hunter Resources, the
                  subsidiary guarantors named therein and First Union National Bank of North Carolina, as Trustee
                  (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1998 filed April 14,
                  1999)
4.15              Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form
                  S-4, File No. 333-2290)
4.16 *            Indenture, dated March 15, 2002, 2002, between Magnum Hunter Resources, Inc., the subsidiary
                  guarantors named therein and Bankers Trust Company, as Trustee.
4.17              Shareholder Rights Agreement dated as of January 6, 1998 by and between Magnum Hunter
                  Resources, Inc. and Securities Transfer Corporation, as Rights Agent (Incorporated by reference
                  to Form 8-K dated January 7, 1998, filed January 9, 1998)
10.1 *            Fourth Amended and Restated Credit Agreement, dated March 15, 2002, between Magnum Hunter
                  Resources, Inc. and Bankers Trust Company, et al.
10.2              Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-K for the fiscal
                  year-end December 31, 1999 filed March 30, 2000)
10.3              Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-K for the
                  fiscal year-end December 31, 1999 filed March 30, 2000)
10.4 *            Employment Agreement for Chris Tong
10.5 *            Employment Agreement for R. Douglas Cronk
10.6 *            Employment Agreement for Charles Erwin
</TABLE>

                                       62

<PAGE>

<TABLE>
<CAPTION>
<S>             <C>

10.7              Purchase and Sale Agreement, dated February 27, 1997 among
                  Burlington Resources Oil and Gas Company, Glacier Park Company
                  and Magnum Hunter Production, Inc. (Incorporated by reference
                  to Form 8-K, dated April 30, 1997, filed May 12, 1997)
10.8              Purchase and Sale Agreement between Magnum Hunter Resources, Inc. , NGTS, et al., dated
                  December 17, 1997  (Incorporated by reference to Form 8-K, dated December 17, 1997, filed
                  December 29, 1997)
10.9              Purchase and Sale Agreement dated November 25, 1998 between Magnum Hunter Production, Inc.
                  and Unocal Oil Company of California (Incorporated by reference to Form 10-K for the fiscal year-
                  end December 31, 1998 filed April 14, 1999)
10.10             Stock Purchase Agreement dated February 3, 1999 between ONEOK Resources Company and
                  Magnum Hunter Resources, Inc. (Incorporated by reference to Form 8-K, dated February 3, 1999,
                  filed February 11, 1999)
10.11             Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by
                  reference to Form 10-Q/A for the period ended June 30, 2000 filed November 30, 2000)
21*               Subsidiaries of the Registrant
23*               Consent of Deloitte and Touche LLP
</TABLE>

* Filed herewith.

(B) Form 8-K's - None.

                                       63

<PAGE>

Independent Auditors' Report


Board of Directors and Stockholders
Magnum Hunter Resources, Inc.


     We have audited the  consolidated  financial  statements  of Magnum  Hunter
Resources,  Inc. and Subsidiaries as of December 31, 2001 and 2000, and for each
of the three years in the period ended  December  31, 2001,  and have issued our
report thereon dated March 22, 2002;  such report is included  elsewhere in this
Annual Report on Form 10-K. Our audits also included the consolidated  financial
statement schedule of Magnum Hunter Resources, Inc. and Subsidiaries,  listed in
Item 14. This consolidated financial statement schedule is the responsibility of
the Company's  management.  Our responsibility is to express an opinion based on
our audits. In our opinion, such consolidated financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a
whole,  presents  fairly,  in all material  respects,  the information set forth
therein.



/s/ Deloitte & Touche LLP

Dallas, Texas
March 22, 2002


                                       64
<page>

                        Valuation and Qualifying Accounts
                                ($ in thousands)

For the year ended December 31, 2001:
<TABLE>
<CAPTION>
<S>                                           <C>                  <C>              <C>                 <C>
                                                   Balance at        Additions
                                                  Beginning of       Charged to        Deductions         Balance at
                 Description                         Period           Expenses          Writeoffs             end
                                                                                                           of Period
---------------------------------------------  ------------------ ----------------  -----------------  -----------------
Accounts receivable, trade                      $       50          $      3,214         $        -          $    3,264
Current portion of long-term notes                   1,170                     -                  -               1,170
 receivable
Investment in unconsolidated affiliate                   -                   453                  -                 453
</TABLE>



For the year ended December 31, 2000:
<TABLE>
<CAPTION>
<S>                                             <C>               <C>                <C>               <C>
                                                   Balance at        Additions
                                                  Beginning of       Charged to        Deductions         Balance at
                 Description                         Period           Expenses          Writeoffs             end
                                                                                                           of Period
---------------------------------------------  ------------------ ----------------  -----------------  -----------------
Accounts receivable, trade                           $ 166           $   80            $ (196)            $      50
Current portion of long-term notes                     790              384                (4)                1,170
 receivable
</TABLE>

                                       65

<PAGE>


                                   SIGNATURES

     Pursuant to the  requirements of the Section 13 or 15 (d) of the Securities
and  Exchange  Act of 1934,  the  Company  has duly  caused this Form 10-K to be
signed on its behalf by the undersigned, thereunto duly authorized.

MAGNUM HUNTER RESOURCES, INC.


By:       /s/ Gary C. Evans                                      April 12, 2002
   ---------------------------------------------
         Gary C.  Evans, Chairman, President
                          & CEO

     In  accordance  with the Exchange Act, this Form 10-K has been signed below
by the following  persons on behalf of the Company and in the  capacities and on
the dates indicated.

<TABLE>
<CAPTION>
<S>                                       <C>                                         <C>

Signature                                   Title                                       Date

/s/ Gary C. Evans                           Chairman, President                         April 12, 2002
-------------------------------------       Chief Executive Officer
Gary C. Evans


/s/ Chris Tong                              Senior Vice President and                   April 12, 2002
---------------------------------------     Chief Financial Officer
Chris Tong


/s/ David S. Krueger                        Vice President and                          April 12, 2002
-----------------------------------         Chief Accounting Officer
David S. Krueger

/s/ Morgan F. Johnston                      Vice President, General Counsel             April 12, 2002
-------------------------------             and Secretary
Morgan F. Johnston

/s/ Gerald W. Bolfing                       Director                                    April 12, 2002
-----------------------------------
Gerald W. Bolfing

/s/ Matthew C. Lutz                         Director                                    April 12, 2002
-----------------------------------
Matthew C. Lutz

/s/ John H. Trescot, Jr.                    Director                                    April 12, 2002
-----------------------------------
John H. Trescot, Jr.

/s/ James E. Upfield                        Director                                    April 12, 2002
------------------------------------
James E. Upfield

</TABLE>

                                       66