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

                                   FORM 10-K/A

       (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, 1999

       [ ] 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
     ------------------------------          -----------------------
     Common Stock Purchase Warrants          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 27, 2000,  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 $60,993,489.

     The number of shares outstanding of the registrant's  common stock at March
27, 2000 was 19,699,086.
<PAGE>
                                TABLE OF CONTENTS

                       Securities and Exchange Commission
                           Item Number and Description


                                     PART I
<TABLE>
<CAPTION>
<S>       <C>                                                                                                   <C>
Item 1.    Business...............................................................................................1
            The Company...........................................................................................1
            Business Strategy ....................................................................................2
            Properties ...........................................................................................3
            Development and Exploration Activities ...............................................................8
            Gathering and Processing of Gas .....................................................................10
            Marketing of Production .............................................................................11
            Petroleum Management and Consulting Services ........................................................12
            Competition..........................................................................................12
            Regulation ..........................................................................................12
            Employees ...........................................................................................15
            Facilities ..........................................................................................15
            Risk Factors.........................................................................................15
Item 2.    Description of Properties.............................................................................22
            Oil and Gas Reserves ................................................................................22
            Oil and Gas Production, Prices and Costs ............................................................24
            Drilling Activity ...................................................................................25
            Oil and Gas Wells ...................................................................................26
            Oil and Gas Acreage .................................................................................26
Item 3.    Legal Proceedings.....................................................................................27
Item 4.    Submission of Matters to a Vote of Security Shareholders..............................................27

                                     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.................31
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..............................................39
Item 8.   Financial Statements and Supplementary Data...........................................................F-1
Item 9.    Change in and Disagreements with Accountants on Accounting and Financial Disclosure...................42

                                    PART III

Item 10.  Directors and Executive Officers of the Registrant.....................................................42
Item 11.  Executive Compensation.................................................................................47
Item 12.  Security Ownership of Certain Beneficial Owners and Management.........................................49
Item 13.  Certain Relationships and Related Transactions.........................................................50
          Glossary...............................................................................................51
Item 14.  Exhibits, Financial Statement Schedule and Reports on Form 8-K.........................................53
</TABLE>
<PAGE>
                                     PART I

                SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

     Certain  statements  in this Form 10-K under "Item 1.  Business,"  "Item 7.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations"  and  elsewhere  in  this  Form  10-K  constitute   "forward-looking
statements"  within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21B of the Securities Exchange Act of 1934, as amended. All
statements,  other than  statements of historical  facts,  included in this Form
10-K  that  address  activities,  events  or  developments  that  Magnum  Hunter
Resources,  Inc. and its  subsidiaries  (collectively,  the "Company")  expects,
projects,  believes or  anticipates  will or may occur in the future,  including
such matters as oil and gas reserves,  future  drilling and  operations,  future
production of oil and gas,  future net cash flows,  future capital  expenditures
and other such matters,  are forward-looking  statements.  Such  forward-looking
statements  involve  known and unknown  risks,  uncertainties  and other factors
which may cause the actual  results,  performance or achievements of the Company
to be materially different from any future results,  performance or achievements
expressed or implied by such forward-looking  statements.  Such factors include,
among others, the following: the volatility of oil and gas prices, the Company's
drilling results, the Company's ability to replace reserves, the availability of
capital  resources,  the reliance upon estimates of proved  reserves,  operating
hazards and uninsured risks, competition,  government regulation, the ability of
the Company to implement its business  strategy and other factors  referenced in
this Form 10-K.

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  Coast/Gulf  of  Mexico.  In  December  1995,  the  Company
consummated  the  acquisition of all of the  subsidiaries  of Hunter  Resources,
Inc., a Pennsylvania  corporation,  and the management of Hunter Resources, Inc.
assumed operating control of the Company.  The new management team implemented a
business  strategy that emphasized  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  1999,  the  Company  acquired  properties  from
Burlington  Resources  Inc.  ("Burlington"),  Spirit Energy 76 ("Spirit  76"), a
business unit of Union Oil Company of  California,  and Vastar  Resources,  Inc.
("Vastar").  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  in  its  geographic  area  of  operations  and  on  its
substantial  inventory of exploitation and development  drilling  opportunities.
The Company has identified over 350 development  drilling  locations  (including
both production and injection  wells) on its properties to which proved reserves
have been attributed,  substantially  all of which are low-risk in-fill drilling
opportunities.

     In 1998, the Company  acquired  approximately  a 40%  beneficial  ownership
interest in TEL Offshore  Trust  ("TEL"),  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  in the  shallow  waters in the Gulf of
Mexico.

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

     At December  31,  1999,  the Company had an interest in 3,100 wells and had
estimated  Proved  Reserves  of  383.2  Bcfe  with a PV-10  of  $370.1  million.
Approximately 74% of these reserves were Proved Developed  Reserves and 48% were
attributable to the Mid-Continent  Region,  47% were attributable to the Permian
Basin,  and 5% were  attributable  to the Gulf  Coast/Gulf of Mexico Region.  At
December 31, 1999, the Company's  Proved Reserves had an estimated  Reserve Life
of  approximately  14 years and were 60%  natural  gas.  The  Company  serves as
operator for approximately  73% of its properties,  based on the gross number of
producing wells in which the Company owns an interest and 89% of its properties,
based upon the year-end SEC PV-10 value.

     As a result of its property acquisitions and successful drilling activities
during 1999, the Company has achieved growth as described below:

     o Proved  Reserves  increased 19% to 383.2 Bcfe at year end 1999 from 323.2
Bcfe at year end 1998;

     o PV-10  increased  106% to $370.1  million  at year end 1999  from  $179.4
million at year end 1998; and

     o Average daily  production  increased 28% to 73.7 MMcfe during fiscal 1999
from 57.4 MMcfe in fiscal 1998

Recent Acquisition

     In June 1999,  Magnum Hunter closed the acquisition of oil and gas reserves
and related assets from Vastar.  The acquisition  included  Vastar's interest in
476 wells, a gas processing  plant and two gas gathering  systems located in the
states of Texas,  Oklahoma  and  Arkansas.  The total  purchase  price was $32.5
million, after purchase price adjustments,  including an April 1, 1999 effective
date.  The reserves  and related  assets are located in the Walnut Bend Field in
North Central Texas, the Madill Field in Southern Oklahoma, and the Walker Creek
Field in Southwestern  Arkansas.  The Company's  working  interests in the three
fields  range from  56-100%.  For the month of December  1999,  the three fields
generated  net sales of  approximately  930  barrels  per day of liquids and 5.9
million cubic feet per day of natural gas  production  (total 11.5 million cubic
feet  equivalents  per  day).  Magnum  Hunter's  wholly-owned  subsidiary,  Gruy
Petroleum  Management  Co.  ("Gruy"),  is the  operator  of all of the wells and
related assets.

Business Strategy

     The Company's objective is to increase its reserves,  production, cash flow
and earnings utilizing a program of (i) exploitation and development of acquired
properties,   (ii)  a  selective   exploration   program  and  (iii)   strategic
acquisitions of Proved Reserves.

     The following are key elements of the Company's strategy:

     Exploitation  and  Development  of Existing  Properties.  The Company has a
substantial  inventory of exploitation  projects including development drilling,
workovers  and  recompletions.  The Company  seeks to maximize  the value of its
properties   through   development   activities   including   in-fill  drilling,
waterflooding and other enhanced recovery techniques.

     Exploration.  The  Company  is  participating  in  drilling  Gulf of Mexico
exploratory wells in an effort to add shorter-lived, higher output production to
its reserve mix. The use of 3-D seismic as a tool in its exploratory drilling in
the Gulf of Mexico has to date been highly effective.  The Company also attempts
to align  itself with active Gulf of Mexico  industry  partners who have similar
philosophies  and goals with  respect to a "fast  track"  program in placing new
production  online. The Company also has an active onshore  exploration  program
concentrated in its various areas of operation.

                                        2
<PAGE>

     Management of Operating Costs. The Company  emphasizes strict cost controls
in all  aspects of its  business  and seeks to operate its  properties  wherever
possible.  By operating  approximately  73% of its properties  (89% of its PV-10
value),  the Company is generally able to control direct  operating and drilling
costs as well as to manage the timing of development and exploration activities.

     Property  Acquisitions.  Although the Company has an extensive inventory of
exploitation  and development  opportunities,  it continues to pursue  strategic
acquisitions which fit its objectives of having Proved Reserves with development
potential and operating control.

     Expansion  of Gas  Gathering,  Processing  and  Marketing  Operations.  The
Company has implemented  several  programs to expand and increase the efficiency
of its gas gathering  systems and gas processing  plants.  The Company owns over
70% and markets  directly and  indirectly  approximately  91% of the natural gas
that moves through its gas gathering systems and,  therefore,  benefits from any
cost and productivity improvements. In December 1997, the Company acquired a 30%
interest in NGTS, LLC ("NGTS"),  a natural gas marketing  company  marketing gas
for  third  parties,  in the  amount  of  approximately  350  MMcf per day as of
December 31, 1999. At December 31, 1999, NGTS marketed  approximately 53% of the
Company's  natural gas. The Company will  consider  opportunities  to acquire or
develop  additional gas gathering and processing  facilities that are associated
with its current production.

Properties

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

Mid-Continent Region

     The Company's  properties located in the Mid-Continent Region were acquired
principally from Burlington, Spirit 76 and Vastar.

     On June 28, 1996, the Company  purchased from  Burlington  interests in 520
gas wells in the Texas Panhandle and western Oklahoma (470 of which are operated
by the Company) and an  associated  427 mile gas  gathering  system (the "Panoma
Properties").  As of year-end  1999,  the Company had drilled an  additional  85
wells and net production was  approximately 13 million cubic feet of natural gas
per day. The net purchase  price for this  acquisition  in 1996,  after  certain
purchase price  adjustments,  was $34.7 million,  funded by borrowings under the
Company's  previous  senior  credit  facility.  Gruy is the  operator of the gas
gathering system and the wells that were previously operated by Burlington.

     On  December  31,  1998 the  Company  acquired  from  Spirit 76 natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
producing  approximately 11 million cubic feet of natural gas equivalent per day
net to the  Company.  The purchase  price was  approximately  $25 million  after
certain purchase price adjustments  including  preferential  rights exercised by
third parties and other customary adjustments.

     In June 1999, the Company  acquired  Vastar's  interest in 476 wells, a gas
processing  plant and two gas gathering  systems located in the states of Texas,
Oklahoma  and  Arkansas.  The total  purchase  price was  $32.5  million,  after
purchase  price  adjustments,  including an April 1, 1999  effective  date.  The
reserves  and  related  assets are  located  in the  Walnut  Bend Field in North
Central Texas, the Madill Field in Southern Oklahoma, and the Walker Creek Field
in Southwestern  Arkansas.  The Company's  working interests in the three fields
range from 56-100%.  For December 1999, the three fields  generated net sales of
approximately  930 barrels per day of liquids and 5.9 million cubic feet per day
of natural gas production (total 11.5 million cubic feet equivalents per day).

                                        3
<PAGE>

     The Company has received an engineering evaluation from Ryder Scott Company
("Ryder  Scott"),  independent  petroleum  engineers  engaged by the  Company to
evaluate the  Company's  properties,  on the net reserves in the Mid-  Continent
Region.  According to Ryder Scott,  as of December 31, 1999,  the  Mid-Continent
properties had Proved Reserves of 8.7 MMBbl of oil and 131.8 Bcf of natural gas,
or on a Natural Gas Equivalent basis,  184.1 Bcfe. Ryder Scott further estimated
the PV-10 for the  Mid-Continent  properties to be $174.4 million as of December
31,  1999 based on prices of $25.60 per Bbl of oil and $2.305 per Mcf of natural
gas. The Proved  Reserves are located  principally in the Ardmore Basin in south
central Oklahoma, in the Oklahoma/Texas  panhandle and in Southwestern Arkansas.
Approximately  72% of the  estimated  reserves  are  natural gas and 28% are oil
located on approximately  50,000 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
1999 was  approximately  29 million cubic feet of natural gas production and 700
barrels of oil.  Approximately 87% of the Proved Reserves were classified Proved
Developed  Reserves as of December 31, 1999. The Company has engaged its Houston
based geological  affiliate,  Swanson Consulting  Services,  Inc., to conduct an
evaluation of the most prospective  undeveloped properties located in one of the
fields acquired.  The Company's  wholly-owned  subsidiary,  Gruy, has become the
operator of 89% or 655 of the 735 wells located in the Mid-Continent Region.

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

     Panoma.  The  Panoma  Properties  currently  consist of  approximately  560
natural gas wells in the West Panhandle,  East Panhandle, and South Erick Fields
along a corridor 65 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 1999, net production was approximately 13 MMcf/d.

     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  potential  exists for additional  wells 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 128
wells,  with working  interests varying from 17.2% to 100%. The Company operates
all but nine of these wells.  For the month of December 1999,  gross  production
from the field averaged 6,000 Mcf/d and 250 Bbl/d.

     Caddo.  The Caddo  Field is  located  in Carter  County,  Oklahoma.  It was
discovered in 1939 and currently  produces gas from various shallow  reservoirs,
such as the Goddard,  Sycamore,  Woodford,  Hunton, and Viola, at depths ranging
from  2,200'  to  4,200'.  Initially  all  of  these  reservoirs  were  produced
separately;  however, today, many are commingled down-hole. The Company operates
14 wells with a 100% working  interest.  For the month of December  1999,  gross
production from the wells averaged 2,100 Mcf/d.

     Hitchcock.  The Hitchcock Field is located in Blaine County,  Oklahoma.  It
was  discovered  in 1965 and  produces  gas from the Morrow  formation at depths
ranging from 8,000' to 8,200'.  Original  development in this field was based on
640-acre  spacing.  Recent drilling activity has focused on in-fill locations in
the Morrow.  The  Company  currently  has  interest  in 15 wells,  with  working
interest  varying from 12.5% to 87.5%, and operates four of these wells. For the
month of December 1999, gross production from the wells averaged 3,000 Mcf/d.

     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 39
active injection wells.  The Company's  working interest  ownership in the wells
varies from 85.7% to 100%. For the month of December 1999, gross production from
the wells averaged 180 Mcf/d and 800 Bbl/d.

                                        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
56 active producing wells. The Company's working interest ownership in the wells
varies from 32.7% to 100%. For the month of December 1999, gross production from
the wells averaged 2,300 Mcf/d and 100 Bbl/d.

     Walker Creek. The Walker Creek Field is located in Southwestern Arkansas in
Lafayette and Columbia Counties. This field was discovered in March of 1968. The
field  produces from the Smackover  formation at an average depth of 10,800' and
covers 14,840 gross acres.  There are currently 29 active  producing  wells. The
Company's  working  interest  ownership  in the  wells  and the  associated  gas
processing  plant is 57.21%.  For the month of December 1999,  gross  production
from the wells averaged  9,000 Mcf/d and 400 Bbl/d and the gas processing  plant
stripped  approximately  380 barrels per day of additional  liquids from the gas
stream.

Permian Basin

     On April 30, 1997 the Company  acquired  from  Burlington,  effective as of
January 1, 1997, 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"),  for a net  purchase  price of $133.8  million  after  adjustments
aggregating $9.7 million.  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; the San Andres in the Levelland/Slaughter Field
in Cochran  County,  Texas;  and the Canyon Sand in Sutton  County,  Texas.  The
Permian  Basin  Properties   include  1,792  producing  oil  and  gas  wells  on
approximately  113,810  gross acres  (82,175 net  acres).  One of the  Company's
subsidiaries,  Gruy, serves as operator on approximately 55% 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 100  possible  sites in the  Westbrook  Field  (5.1  MMBbl of  Proved
Reserves) and opportunities for tertiary recovery using carbon dioxide injection
in the Levelland-Slaughter Field (1.8 MMBbl of Proved Reserves).

     According  to  Ryder  Scott  and  Pollard,   Gore  and  Harrison  ("PG&H"),
independent  petroleum  engineers  engaged by the Company to evaluate certain of
the Company's properties,  as of December 31, 1999, the Permian Basin Properties
had Proved  Reserves  of 15.8 MMBbl of oil and 84.5 Bcf of gas,  or on a Natural
Gas Equivalent  basis,  179.6 Bcfe. Ryder Scott further  estimated the SEC PV-10
for the Permian Basin  Properties  to be $169.8  million as of December 31, 1999
based on prices of $25.60 per Bbl of oil and  $2.305 per Mcf of gas at  December
31, 1999.  Approximately  56% of the Proved  Reserves were  classified as Proved
Developed  Producing reserves as of December 31, 1999. See "Properties - Oil and
Gas Reserves."  Based on the $133.8 million  adjusted  purchase price and Proved
Reserves  of 186.9 Bcfe as of April 30,  1997,  the Company  paid  approximately
$0.72 per Mcfe for the Permian Basin Properties.

     The   major   fields   in   the   Permian   Basin   are   the    Westbrook,
Levelland/Slaughter, Lea County Shallow Properties and the Brunson Ranch.

                                        5
<PAGE>

     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  following  table  sets  forth  information
regarding three properties in the Westbrook Field:
<TABLE>
<CAPTION>
<S>                                      <C>                <C>           <C>             <C>               <C>
                                                                                                              Gross Oil
                                                              Well          Working        Net Revenue       Production
               Property                     Operator         Count          Interest         Interest        (Bbl/d) (b)
---------------------------------------------------------------------------------------------------------------------------

Southwest Westbrook Unit...............     Company           135             89.9%           77.5%              420
Morrison "G" Lease.....................     Company            12            100.0%           87.5%               16
North Westbrook Unit...................   Third Party         206              2.0%            2.8% (a)        1,200
</TABLE>

     (a) Includes an overriding Royalty Interest.

     (b) Gross oil  production was calculated by using the average for the month
of December 1999.

     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  initiated
waterflood  enhancement  operations  on the  Southwest  Westbrook  Unit  and the
Morrison "G" Lease in the first quarter of 2000.

     Levelland/Slaughter.  The  Levelland and  Slaughter  Fields  consist of 174
wells  located  in  Cochran  County,  Texas  that  produce  from the San  Andres
formation at a depth of 5,000 feet. The interests  acquired in the Permian Basin
Acquisition  include  the  following  three  properties  in  the  Levelland  and
Slaughter Fields:
<TABLE>
<CAPTION>
<S>                                        <C>             <C>            <C>             <C>               <C>
                                                                                                             Gross Oil
                                                              Well          Working        Net Revenue       Production
               Property                     Operator         Count          Interest         Interest        (Bbl/d) (a)
----------------------------------------------------------------------------------------------------------------------------

TLB Unit...............................     Company            20            100.0%           87.3%               75
Veal Lease.............................     Company            52            100.0%           87.1%              190
NW Slaughter Unit......................     Company            83             74.8%           62.8%              265
</TABLE>

     (a) Gross oil  production was calculated by using the average for the month
of December 1999.

     Discovered  in  the  1930's,   all  three  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 Ryder Scott to either the TLB Unit or the
Veal Lease.  Proved Undeveloped  Reserves were assigned by Ryder Scott 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 to successfully  enhance
production.

     Lea County Shallow Properties. The Lea County Shallow Properties consist of
approximately  300 wells in Lea  County,  New  Mexico  which are in 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.  Production is generally high Btu gas, which produces
into low  pressure  gathering  systems.  At  year-end  approximately  15  proved
undeveloped  locations were identified and the Company anticipates that numerous
additional   recompletion,   stimulation,   workover  or  development   drilling
opportunities will result from detailed  geological and engineering studies that
are in progress.

     Brunson  Ranch.  The Brunson Ranch Field  consists of four wells located in
Loving  County,  Texas in the deep  Delaware  Basin  geological  province of the
Permian Basin.  For the month of December 1999, the wells were producing a total
of approximately  4.2 MMcf of gas per day from the Atoka formation at a depth of
approximately  16,000  feet.  Undeveloped  potential  exists  on the  properties
through redrilling the Atoka formation, sidetracking certain existing wells, and
completing  such wells using  technology  designed for high bottom hole pressure
conditions.

                                        6
<PAGE>

Gulf Coast/Gulf of Mexico

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

Onshore Gulf Coast

     The Company  owns  interests in three  horizontal  wells in the Mossy Grove
prospect in Walker County,  Texas. The interests which the Company owns in these
three wells range from a 25% to a 65% working interest.  The field produces from
the Glen Rose  formation at a depth of  approximately  12,000 feet.  The initial
discovery  was  completed  in July 1998 and a  confirmation  to this  discovery,
located 3.5 miles southwest,  was completed at year-end 1998. The third well was
drilled in 1999.  The  Company  owns an average of a 25%  working  interest in a
36,000  acre lease  block  surrounding  the  producing  wells.  A fourth well is
currently being drilled in which the Company owns a 25% working interest.  Union
Pacific  Resources  Corporation  is the operator of the drilling  phase for this
well and owns the  remaining  75%  working  interest.  For the month of December
1999, gas production  from the three  producing  wells was  approximately  2,000
Mcf/d.  Additional development drilling is planned in this field during 2000, if
the Company can continue to reduce the drilling costs of each well.

     Other onshore Gulf Coast  properties are located in the Giddings Field, the
First Shot Field and the Clinton Field. These properties are typically producing
from horizontal legs of vertical wells in these fields.

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. TEL produced a total of approximately 1.2
Bcfe in 1999.

     In May 1999, the Company  entered the Gulf of Mexico as a working  interest
participant  in new  exploratory  drilling on the shallow water shelf.  This new
program  yielded four new discoveries in six attempts in 1999 and is expected to
continue to add  significantly  to reserves and cash flow as these wells are put
on  production.  Initial  sales  from  one of  the  Company's  1999  discoveries
commenced in February  2000.  This well, on  Vermillion  Block 84 in the Gulf of
Mexico,  at March 15,  2000 was  flowing at a rate of  approximately  16 million
cubic feet of natural gas and 1,000  barrels of  condensate  per day from one of
two major pay  intervals.  Production  from other Gulf of Mexico  discoveries is
scheduled to commence during 2000 and into 2001. The Company owns an interest in
34 blocks in the Gulf of  Mexico  with  working  interest  generally  at the 25%
level.

Gas Processing Plants

McLean Plant

     On January 1, 1997,  the Company  complemented  its Panoma  acquisition  by
purchasing for $2.5 million a 50% ownership interest in the McLean Gas Plant and
a related 22 mile  products  pipeline.  This plant is a modern  cryogenic  plant
utilizing  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 1999, throughput of the plant was approximately 16.5 million cubic feet
per day with  processed  liquids of 1,150 barrels per day. The Company  received
100% of the net profits  from the McLean Gas Plant  until it  recouped  the $2.5
million purchase price, after which time it receives 50% of the net profits.  At
December 31, 1999, the Company had recouped its initial investment.

                                        7
<PAGE>

Dynegy Plant

     On December 1, 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 for  approximately  $8.4
million.  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.
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  1999,  throughput of the plant was  approximately  13 million
cubic feet per day of natural gas with processed liquids of 900 barrels per day.
The effective date of the  acquisition  was November 1, 1999. See "Gathering and
Processing of Gas."

Walker Creek Plant

     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.  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 1999,  throughput of
the plant was  approximately 9 MMcf/d with processed  liquids of 380 Bbl/d.  The
effective  date  of the  acquisition  was  April  1,  1999  with  assumption  of
operations on June 1, 1999.

Development and Exploration Activities

Overview

     The Company  presently intends to continue to focus its efforts on property
acquisitions,   its  substantial   inventory  of  exploitation  and  development
activities and selected exploratory drilling prospects.

     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 $10.0 million
for exploitation  and development  activities for 2000 with $3.2 million of such
budget developing the Company's booked proved undeveloped reserves.  The Company
spent $1.4 million, $7.9 million and $3.0 million, respectively,  developing its
proved undeveloped reserves for the years ended 1999, 1998 and 1997. The Company
has  identified  over  350  development   drilling  locations   (including  both
production and injection  wells) 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.
In-fill  development  has been  underway in the fields with 85 wells having been
completed  during  the last  three  years.  The  westernmost  field has now been
effectively developed with 320 acre spacing.

                                        8
<PAGE>

     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,  Hunton,  and Viola. These formations are predominantly gas productive
and are produced commingled. The Company has identified three locations in which
additional wells could be drilled to complete  development of the shallow gas on
160-acre  spacing.  The first well is scheduled to be drilled in April 2000. The
Company  will have a 50%  working  interest in the well.  The Company  will also
evaluate  revamping  water  injection  and  production  from the oil zones,  and
development  drilling utilizing 3-D seismic which has been obtained covering the
field area.

     Permian Basin Properties.  In evaluating the Permian Basin Properties,  the
Company has  identified  over 300 drilling  locations  including  production and
injection wells.  Engineering and geological studies are being initiated to more
precisely  identify  specific  development  locations.  The Lea  County  Shallow
Properties  consist of approximately  300 wells in Lea County,  New Mexico which
are in the Rhodes, Jalmat,  Monument,  Langlie Mattix, Eumont and Eunice Fields.
These fields produce from the Yates, Seven Rivers, Queen and other formations at
depths  generally  shallower  than 3,000 feet.  Production is generally high Btu
gas,  which  produces  into  low  pressure   gathering   systems.   At  year-end
approximately  15 proved  undeveloped  locations were identified and the Company
anticipates  that numerous  additional  recompletion,  stimulation,  workover or
development  drilling  opportunities  will result from detailed  geological  and
engineering  studies  which are  planned.  During  1999,  the Company  drilled 5
successful wells in the Sawyer Canyon Field in the Sonora area located in Sutton
County,  Texas.  The  Company  owns an  interest in 160 wells in this area which
consists  of  the  Sawyer  Canyon  Field,   the  Sonora  Canyon  Field  and  the
Phyllis-Sonora  Field.  Production  from all  fields  is from a series  of tight
canyon-age gas sands.

     Onshore Gulf Coast.  During 1999,  the Company  drilled a third  horizontal
well in the Mossy Grove  Prospect in Walker  County,  Texas.  This well produces
from the Glen Rose  formation  at a depth of  approximately  12,000 feet and was
producing  at March  15,  2000  approximately  1,000  Mcf/d.  A  fourth  well is
currently being drilled in which the Company owns a 25% working  interest.  This
well is  anticipated  to be completed  in April 2000.  Union  Pacific  Resources
Corporation  is the  operator of the  drilling  phase for this well and owns the
remaining 75% working interest.  Additional  development  drilling is planned in
this field during 2000,  with as many as 12 additional  wells if drilling  costs
and reserve estimates appear favorable.

     The Company recently reentered a 100% owned well in the First Shot Field in
Gonzales County,  Texas and also drilled a new Austin Chalk lateral leg that was
successful.  At March  15,  2000,  production  was 230  barrels  of oil per day.
Similar  re-drills  are planned in the Giddings  Field during the next couple of
years.

Exploratory Drilling

     The Company  spent $9 million of its $60  million  1999  capital  budget on
exploratory   drilling  and  related  land  and  geophysical   costs.   Fourteen
exploratory wells were drilled in 1999 of which 11 were successful providing the
Company  with a 79%  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 four new discoveries in six attempts in 1999 and is expected to
continue to add  significantly to reserves and cash flow as these new properties
are  put on  production.  Initial  production  from  one of the  Company's  1999
discoveries commenced in February 2000. This well, on Vermillion Block 84 in the
Gulf of Mexico,  at March 15,  2000 was  flowing at a rate of  approximately  16
million cubic feet of natural gas and 1,000  barrels of condensate  per day from
one of two pay  intervals.  Two  additional  wells have been approved by all the
working  interest owners to continue  development of the block.  Production from
other Gulf of Mexico  discoveries are scheduled to commence during 2000 and into
2001 with additional  drilling  planned to fully develop these new  discoveries.
The Company  owns an  interest in 34 separate  blocks in the Gulf of Mexico with
ownership generally at the 25% level.

     The onshore  exploration program also continues to meet with success. A new
discovery  on the Bobcat  project in Hockley  County,  Texas has been  completed
producing  at an initial  rate in excess of 200 Bbl/d.  The  Company  owns a 25%
working  interest in this well and in the 3-D  controlled  project where some 15
exploratory prospects have been

                                        9
<PAGE>

     identified.  The Company has leased  approximately 15,000 mineral acres for
this project.  A new exploratory  well is scheduled to commence by mid-year 2000
to further evaluate this area. The Company also owns a 34% working interest in a
recent discovery operated by Occidental  Petroleum  Corporation in Ector County,
Texas.  Additional  development  drilling is scheduled to offset this well which
was completed producing 80 Bbl/d and 100 Mcf/d.

     Also in West Texas, a deeper zone discovery in an older field was completed
flowing at over 300 Bbl/d.  The Company owns a 27% working interest in this well
and plans to continue  development of this area with  participation  in at least
four additional wells.

     The Company has a  significant  inventory  of  exploration  prospects  both
onshore and offshore and is actively  generating and  evaluating  other projects
for future  exploration  activity.  The recent  acquisition  of 3-D seismic data
covering  over 300 blocks in the Gulf of Mexico  will  assist in  continuing  to
build a substantial, high-quality prospect inventory.

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 an  approximate  50% ownership  interest in three gas  processing
plants.  Gruy  operates  one of the  gas  gathering  systems  and one of the gas
processing  plants.  In July 1999,  the Company  sold a small  gathering  system
located in East Texas that accounted for less than 4% of the Company's total gas
gathering throughput for an approximate $200,000 gain.

     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 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.

     The Panoma  system,  the largest of the Company's  gas  gathering  systems,
consists of approximately 442 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 year end 1999, gas
throughput for the Panoma gas gathering system was  approximately  16.8 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 496 of the approximately 586
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 1, 1997,  the Company  purchased  for $2.5 million 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
1999,  throughput was approximately  16.5 MMcf 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.

                                       10
<PAGE>

     On December 1, 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  1999,  throughput of the plant was  approximately  13 million
cubic feet per day of natural gas with processed liquids of 900 barrels per day.
The effective date of the acquisition was November 1, 1999.

     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.  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 1999,  throughput of
the plant was  approximately 9 MMcf/d with processed  liquids of 380 Bbl/d.  The
effective  date  of the  acquisition  was  April  1,  1999  with  assumption  of
operations on June 1, 1999.

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  month-to-month  basis  contracts at prevailing  spot market prices
(approximately  10% of our volume) or (ii) at negotiated  prices under long-term
contracts  (approximately 90% 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,  a newly formed  subsidiary  of Natural Gas
Transmission  Services,  Inc.  ("NGTS,  Inc.").  NGTS assumed all of NGTS Inc.'s
operations as of December 1, 1997. The Company acquired its interest in NGTS for
consideration of $4.35 million.

     NGTS is a five year old natural gas  marketing  and  trading  company  with
operations  concentrated  in the western  two-thirds  of the country.  In fiscal
1999,  NGTS reported  total  revenues of  approximately  $277  million.  NGTS is
presently marketing approximately 350 million cubic feet of natural gas per day.
For 1998,  the Company and its gas gathering  subsidiary,  Hunter Gas Gathering,
Inc.,  dedicated  substantially  all of its natural gas  production  to NGTS for
marketing.  As of December  31, 1999,  NGTS  marketed  approximately  55% of the
Company's  natural gas under short term contracts.  The balance of the Company's
production  is dedicated to either ONEOK or various  third  parties  through gas
processing agreements.

     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.

                                       11
<PAGE>

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 40-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.

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

     The Company's oil and gas  exploration,  production and related  operations
are subject to extensive rules and regulations  promulgated by federal and state
agencies.  Failure  to comply  with such  rules and  regulations  can  result in
substantial  penalties.  The  regulatory  burden  on the oil  and  gas  industry
increases the Company's  cost of doing  business and affects its  profitability.
Because such rules and regulations are frequently amended or reinterpreted,  the
Company is unable to predict  the future cost or impact of  complying  with such
laws.

     The State of Texas and many  other  states  require  permits  for  drilling
operations,  drilling bonds and reports  concerning  operations and impose other
requirements  relating to the  exploration  and  production of oil and gas. Such
states  also have  statutes  or  regulations  addressing  conservation  matters,
including  provisions for the  unitization or pooling of oil and gas properties,
the  establishment of maximum rates of production from wells, and the regulation
of  spacing,  plugging  and  abandonment  of such wells.  Many  states  restrict
production  to the  market  demand for oil and gas.  Some  states  have  enacted
statutes prescribing ceiling prices for gas sold within their states.

     Historically,  the  transportation  and sale for resale of  natural  gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal  Energy  Regulatory  Commission  (the "FERC").  In the
past,  the federal  government  has regulated the wellhead price of natural gas.
Deregulation  of  wellhead  sales in the  natural  gas  industry  began with the
enactment  of the NGPA.  In 1989,  the Natural Gas  Wellhead  Decontrol  Act was
enacted,  which  amended  the NGPA to  remove  wellhead  price  controls  on all
domestic  natural gas as of January 1, 1993. While sales by producers of natural
gas, and all sales of oil, condensate and natural gas liquids,  can currently be
made at  uncontrolled  market prices,  Congress could re-enact price controls in
the future.

                                       12
<PAGE>

     Several major  regulatory  changes have been  implemented  by the FERC from
1985 to the  present  that  have had a major  impact  on  natural  gas  pipeline
operations, services and rates and thus have significantly altered the marketing
and price of natural gas.  Commencing in April 1992,  the FERC issued Order Nos.
636, 636-A and 636-B (collectively, "Order No. 636"), which, among other things,
require  each  interstate   pipeline   company  to   "restructure"   to  provide
transportation  separate  or  "unbundled"  from  the  sale  of gas  and to  make
available on an open and  nondiscriminatory  basis numerous constituent services
(such  as  gathering   services,   storage  services,   firm  and  interruptible
transportation  services) and to adopt a new ratemaking methodology to determine
appropriate rates for those services.  To the extent the pipeline company or its
sales  affiliate  makes gas sales as a  merchant  in the  future,  it does so in
direct  competition  with all  other  sellers  pursuant  to  private  contracts;
however,  pipeline  companies and their  affiliates  were not required to remain
"merchants" of gas and several of the interstate  pipeline companies have become
"transporters"  only.  Following  the  conclusion  of  individual  restructuring
proceedings for each interstate  pipeline pursuant to Oder No. 636, the FERC has
approved, with modifications,  all of the restructuring plans implementing Order
No. 636 on every interstate pipeline.

     On July 16, 1996, the Court of Appeals for the District of Columbia Circuit
(D.C. Circuit) issued its opinion on review of Order No. 636. The opinion upheld
most  elements  of  Order  No.  636  including  the   unbundling  of  sales  and
transportation services, curtailment of pipeline capacity, implementation of the
capacity release program and the mandatory  imposition of  straight-fix-variable
("SFV") rate design for  interstate  pipeline  companies.  The D.C.  Circuit did
remand  certain  aspects  of Order No. 636 to the FERC for  further  explanation
including,  inter alia, the FERC's decision to exempt  pipelines from sharing in
gas supply realignment  ("GSR") costs caused by restructuring;  FERC's selection
of a 20 year matching cap for the  right-of-first-refusal  mechanism; the FERC's
restriction on the entitlement of no-notice transportation service to only those
customers  receiving  bundled  sales service at the time of  restructuring;  and
FERC's determination that pipelines should focus on individual customers, rather
than customer classes,  in mitigating the effects of SFV rate design. On May 12,
1997,  the United States Supreme Court denied  certiorari of the D.C.  Circuit's
decision.

     On  February  27,  1997,  the FERC  issued its order on remand  ("Order No.
636-C"). The order reaffirmed the holding of Order No. 636 that pipelines should
be entitled to recover 100% of their prudently incurred GSR costs. Moreover, the
FERC  determined  since Order No.  636,  the  average  length of  transportation
contracts was substantially  less than 20 years. Thus, FERC reduced the contract
matching cap for the right-of-first-refusal mechanism to five years. In light of
the varied  post-restructuring  experience with no-notice service, the FERC also
decided to no longer limit a pipeline's  no-notice  service to its bundled sales
customers  at the  time of  restructuring.  Finally,  the FERC  reaffirmed  that
pipelines should focus on individual customers, rather than customer classes, in
mitigating the effects of SFV rate design. On May 28, 1998, FERC denied requests
for rehearing of Order No. 636-C.  Appeals of individual pipeline  restructuring
orders are still pending before the D.C. Circuit.

     On May 31,  1995,  the FERC  issued a policy  statement  on how  interstate
natural gas  pipelines  can recover the costs of new  pipeline  facilities.  The
policy statement  focused on whether projects would be priced on rolled-in basis
(rolling  in  the  expansion  costs  with  the  existing  facilities)  or  on an
incremental basis (establishing separate cost of services and separate rates for
the existing and  expansion  facilities).  The policy  statement  established  a
presumption  in favor of  rolled-in  rates when the rate  increase  to  existing
customers  from  rolling  in the new  facilities  is 5% or less.  In the  policy
statement,  the FERC  contemplated  that the  resolution of pricing  methodology
would take place in individual  proceedings based on the facts and circumstances
of the project. The Company cannot predict what action the FERC will take in the
individual proceedings.

     In October  1992,  Congress  passed the Energy  Policy Act of 1992 ("Energy
Policy Act").  The Energy Policy Act deemed  petroleum  pipeline rates in effect
for the 365-day  period ending on the date of enactment of the Energy Policy Act
or that were in effect on the  365th day  preceding  enactment  and had not been
subject to complaint,  protest or investigation  during the 365-day period to be
just and  reasonable  under the  Interstate  Commerce Act. The Energy Policy Act
also  provides  that  complaints  against such rates may only by filed under the
following  limited  circumstances:  (i) a substantial  change has occurred since
enactment  in either the  economic  circumstances  or the nature of the services
which were a basis for the rate; (ii) the complainant was  contractually  barred
from  challenging  the rate  prior to  enactment;  or (iii)  the rate is  unduly
discriminatory  or preferential.  The Energy Policy Act further required FERC to
issue rules  establishing  a  simplified  and  generally  applicable  ratemaking
methodology for petroleum pipelines  proceedings.  On October 22, 1993, the FERC
responded to the Energy  Policy Act  directive by issuing  Order No. 561,  which
adopts a new

                                       13
<PAGE>

     indexing  rate   methodology  for  petroleum   pipelines.   Under  the  new
regulations,  which were effective January 1, 1995, petroleum pipelines are able
to change  their rates  within  prescribed  ceiling  levels that are tied to the
Producer Price Index for Finished Goods, minus one percent.  Rate increases made
pursuant to the index will be subject to  protest,  but such  protest  must show
that the portion of the rate increase resulting from application of the index is
substantially  in excess of the pipeline's  increase in costs.  The new indexing
methodology  can be  applied  to any  existing  rate,  even if the rate is under
investigation.  If  such  rate  is  subsequently  adjusted,  the  ceiling  level
established under the index must be likewise adjusted.

     In Order No. 561, FERC said that as a general rule  pipeliners must utilize
the index  methodology to change their rates. FERC indicated,  however,  that it
was retaining cost of service ratemaking, market-based rates, and settlements as
alternatives to the indexing approach.  A cost of service  methodology will also
continue  to be used to  determine  just and  reasonable  initial  rates for new
services.  A pipeline can also follow a cost of service approach when seeking to
increase  its rates  above  index  levels for  uncontrollable  circumstances.  A
pipeline can seek to charge market-based rates if it can establish that it lacks
market power.  Finally, a pipeline can establish rates pursuant to settlement if
agreed upon by all current shippers.

     On May 10, 1996,  the D.C.  Circuit  affirmed Order No. 561. The Court held
that  by  establishing  a  general  indexing   methodology  along  with  limited
exceptions   to  index   rates,   FERC   had   reasonably   balanced   its  dual
responsibilities   of  ensuring  just  and  reasonable  rates  and  streamlining
ratemaking through generally applicable procedures.

       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.

     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.

                                       14
<PAGE>

     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.
Notwithstanding  the  Company's  lack of control over wells owned by the Company
but operated by others,  the failure of the  operator to comply with  applicable
environmental regulations may, in certain circumstances,  be attributable to the
Company. The Company currently expects to spend approximately  $400,000 over the
next five years in connection  with  remediation and  environmental  compliance,
including $75,000 in 2000 and $75,000 in 2001.

     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.

Employees

     At December  31, 1999,  the Company had 89 full-time  employees of which 25
were management, 31 were administrative and 33 were field employees. 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 and Taylor,  Arkansas.  The Company also leases
field production  offices in Midland and Abilene,  Texas,  Hobbs, New Mexico and
Oklahoma City, Oklahoma.

Risk Factors

Risks Related to Substantial Leverage

We have a significant amount of debt

     We are highly leveraged,  with outstanding  long-term debt of approximately
$234.8 million compared to stockholders'  equity of $53.6 million as of December
31, 1999. Our level of indebtedness  affects our future  operations.  Because we
must  dedicate a  substantial  portion of our cash flow from  operations  to the
payment of interest on our debt,

                                       15
<PAGE>

     the cash flow is not available for other purposes.  The covenants contained
in our credit  facilities  require us to meet certain  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, our high debt to equity ratio,  and the
pledge of  substantially  all of our assets as collateral for our primary credit
facility will, for the  foreseeable  future,  make it difficult for us to obtain
financing  on an  unsecured  basis or to obtain  secured  financing  other  than
certain "purchase money" indebtedness collateralized by the acquired assets.

To service our indebtedness, we will require a significant amount of cash

     While we  reported  an  operating  profit for fiscal  1999,  we reported an
operating  loss for fiscal 1998, and at December 31, 1999, we had an accumulated
deficit of $62.5  million.  Our ability to meet our  financial  covenants and to
make  scheduled  payments of principal  and  interest to repay our  indebtedness
depends upon our operating results and our ability to obtain financing. However,
we cannot be certain that our business will generate  sufficient  cash flow from
operations or that future bank credit will be available in an amount  sufficient
to enable us to service our indebtedness or make necessary capital expenditures.
In such event,  we would need to obtain such  financing  from the sale of equity
securities,  other  debt  financing  or the  sale of  certain  of the  Company's
properties.  We cannot  predict  whether any such financing will be available on
terms acceptable to us. If we are not able to secure such financing,  we may not
be able to continue to implement our business strategy.

Despite our current indebtedness levels, we still may be able to incur more debt

     Our primary  credit  facility  limits our  borrowings  to a borrowing  base
amount determined by the lenders, in their sole discretion, based upon a variety
of factors,  including the amount of indebtedness  that our oil and gas reserves
and other assets can  adequately  support.  As of December 31, 1999, we had $7.0
million of borrowing  available  under the borrowing base for our current credit
facility.  Our subsidiary  Bluebird  Energy,  Inc. has a non-recourse  revolving
credit  facility  which,  as of December 31, 1999, had $3.2 million of borrowing
available.  However,  as of March 30,  2000,  Bluebird has $200,000 of borrowing
capacity  available under its credit facility.  A significant  decline in oil or
gas prices below their  current  levels could  materially  adversely  affect the
availability of funds under our credit facility.

We must maintain certain financial ratios

     Our primary credit facility also requires us to satisfy  certain  financial
ratios in the future.  One covenant  requires that we maintain a ratio of funded
indebtedness divided by the sum of funded indebtedness plus equity (the "Debt to
Capitalization  Ratio") of not more than 0.80 to 1.0. At December 31,  1999,  we
had a Debt to Capitalization  Ratio of 0.68 to 1.0. Another covenant requires us
to maintain a ratio of  Consolidated  EBITDA to Interest  Expense (as defined in
our primary credit facility agreements) of not less than

     o 1.50 to 1.0 for the calendar  quarters ending  September 30, 1999 through
December 31, 1999;

     o 1.75 to 1.0 for the calendar  quarters ending March 31, 2000 through June
30, 2000; and

     o 2.00 to 1.0 for the  calendar  quarters  ending  September  30,  2000 and
thereafter.

     We had a ratio of Consolidated EBITDA to Interest Expense of 1.52 to 1.0 as
of December 31, 1999. The Consolidated  EBITDA to Interest Expense ratio is very
sensitive to oil and gas price levels,  and a lowering of product  prices in the
future might  jeopardize  our  compliance  with this ratio.  We are  considering
several  alternatives to reduce this risk, including the acquisition or drilling
of higher cash flow  producing  properties  (shorter  reserve  life) to somewhat
offset our long-lived  reserve base or monetizing  certain of our  non-strategic
assets.

     If we fail to satisfy these  covenants or any of the other covenants in our
credit facilities,  that failure would constitute an event of default thereunder
and, subject to certain grace periods,  may permit the lenders to accelerate the
indebtedness  then outstanding  under the applicable  credit facility and demand
immediate repayment thereof.

                                       16
<PAGE>

Our Business Is Dependent on Conditions in the Oil and Gas Industry
-------------------------------------------------------------------

     Our  revenues,  profitability  and the  carrying  value  of our oil and gas
properties 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; 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.  Our
production is  predominantly  weighted  toward gas, making our earnings and cash
flow more sensitive to gas price  fluctuations.  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 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.  An affiliate of ONEOK Inc. has
the right to market the undedicated natural gas we sell in the state of Oklahoma
until  February  2004 or such  earlier date as ONEOK  affiliates  cease to own a
specified  percentage  of our equity  securities.  ONEOK is currently  marketing
production from five wells for a total of 375 Mcf/d.

     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. As a result
of the severe  decline in oil and gas prices in 1998,  we  recognized a non-cash
impairment  of oil and gas  properties  of $42.7  million at  December  31, 1998
pursuant to such "ceiling"  test in the full cost method of accounting.  Certain
subsequent  improvements in pricing  reduced the amount of such charge.  Without
the benefit of these pricing improvements,  we would have incurred an impairment
of $81.2 million.  Once incurred,  a write-down of oil and gas properties is not
reversible at a later date even if oil and gas prices increase.

You Should Not Place Undue Reliance on Our Reserve Data Because They
   Are Estimates

     This annual report  contains  estimates of our oil and gas reserves and the
future  net cash  flows from those  reserves  that were  prepared  or audited by
independent petroleum consultants.  There are numerous uncertainties inherent in
estimating quantities of proved reserves of oil and gas and in projecting future
rates of production and the timing of development  expenditures,  including many
factors beyond our control.  The estimates in this annual report rely on various
assumptions,  including,  for example,  constant  oil and gas prices,  operating
expenses,  capital  expenditures and the availability of funds, and,  therefore,
are 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. Additionally, we
may have to revise  our  reserves  based  upon  actual  production  performance,
results of future development and exploration, prevailing oil and gas prices and
other factors, many of which are beyond our control.

                                       17
<PAGE>

     You should not construe the present value of proved reserves referred to in
this annual report as the current market value of the estimated  proved reserves
of oil and gas attributable to our properties. In accordance with Securities and
Exchange Commission requirements,  we have based the estimated discounted future
net cash flows from  proved  reserves  on prices and costs as of the date of the
estimate,  whereas  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 using a 10% discount as required by the Securities and Exchange Commission
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,
supply  and  demand  for oil and gas,  prevailing  oil and gas  prices and other
factors.

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.  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 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.

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.

     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 that we will be able to successfully integrate
all of the oil and gas  properties  that we acquire into our  operations or will
achieve desired profitability objectives.

Risks Associated With Exploration And Development

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 recently  expanded,  and plan to increase our capital  expenditures  on our
exploration efforts,  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  recovery  of  drilling,
completion and operating costs.

                                       18
<PAGE>

We conduct waterflood projects and other secondary recovery operations

     Secondary recovery operations involve certain risks,  especially the use of
waterflooding  techniques,  and drilling activities in general. 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 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 costs.  Costs are also higher during the later stages of the life of the
project as crude oil production 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  injector  wells and the spacing of both
producing and injector wells.

We Are Subject to Casualty Risks in Our Onshore And Offshore Activities

     Our 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  insurance at levels that we believe are
reasonable, we are not fully insured against all risks. We do not carry business
interruption  insurance except on rare occasion.  Losses and liabilities arising
from uninsured or  under-insured  events could  materially  affect our financial
condition and operations.

We Hedge Our Oil And Gas Production

     As of December 31,  1999,  we had hedged  approximately  (i) 16% of our gas
production through December 31, 2000, and (ii) 63% of our oil production through
December  31,  2000.  These  hedges  have  in  the  past  involved  fixed  price
arrangements  and other price  arrangements  at a variety of prices,  floors and
caps.  We have in the past and may in the future  enter into oil and gas futures
contracts,  options and swaps. Our hedging activities,  while intended to reduce
our  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 could fail to perform. Additionally, the fixed price sales and
hedging contracts limit the benefits we 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
management  of waste,  protection  of  water,  air  quality,  the  discharge  of
materials into the environment, and 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 certain circumstances, impose
retroactive,  strict, and joint and several liability,  potentially resulting in
liability for environmental  damage regardless of negligence or fault. From time
to time,  we have agreed to indemnify  sellers of producing  properties  against
certain liabilities for environmental claims associated with such properties. We
cannot  assure  that  new  laws  or  regulations,  or  modifications  of or  new
interpretations   of  existing   laws  and   regulations,   will  not   increase
substantially the cost of

                                       19
<PAGE>

     compliance  or adversely  affect our oil and gas  operations  and financial
condition.  Material  indemnity claims may also arise with respect to properties
acquired by or from us. 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.

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,  numerous  independents,   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: Gary C.
Evans,  Matthew C. Lutz and Richard R. Frazier.  The loss of the services of any
one of these individuals could materially impact our operations.

Shares Eligible For Future Sale; Absence of Dividends

     The market price of our common  stock could be adversely  affected by sales
of  substantial  amounts of common stock in the public market or the  perception
that such sales could occur

     We are authorized to issue up to 100,000,000  shares of common stock. As of
March 15, 2000,  20,243,601  shares were issued and outstanding,  and 15,269,663
shares were reserved for issuance upon the conversion of shares of our preferred
stock and upon the exercise of certain outstanding warrants and options. We also
reserve  10,512,149  shares for issuance upon exercise of the warrants issued in
June 1999. Issuing additional shares of common stock pursuant to such conversion
rights,   outstanding   warrants,   options  and   warrants   would  reduce  the
proportionate  ownership and voting rights of the common stock then outstanding.
Our existing  management  and their  affiliates  own 2,403,644  shares of common
stock that may in the future be sold in  compliance  with Rule 144 adopted under
the Securities Act of 1933. In addition,  our primary credit facility contains a
debt to capitalization ratio covenant requiring us to maintain a ratio of .80 to
1.0. The possibility that substantial amounts of common stock may be sold in the
public market may adversely  affect  prevailing and future market prices for the
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 the common stock and do
not anticipate  paying dividends on the common stock in the foreseeable  future.
We intend to reinvest all available  funds for the  development of our business.
In addition, we cannot pay any dividends on the common stock unless and until we
pay all dividend  rights on outstanding  preferred  stock which have in the past
been paid on a timely  basis.  Our primary  credit  facility  and the  indenture
governing  our 10%  Senior  Notes due 2007 also  restrict  the  payment  of cash
dividends on certain securities.

Preferred Stock; Anti-takeover Provisions

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 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 shareholder approval,  except in limited
circumstances.  We have  previously  issued several  series of preferred  stock,
although only the 1996 Series A Convertible  Preferred Stock and the 1999 Series
A 8% Convertible Preferred Stock, are currently outstanding.  The holders of the
1996 Series A Convertible  Preferred  Stock  currently have the right to appoint
one additional member to the Board of Directors and upon certain  circumstances,
up to 75% of our Board. The

                                       20
<PAGE>

     holders of the 1999 Series A 8% Convertible  Preferred Stock currently have
the right to nominate  two members of our Board,  and,  subject to the rights of
the  1996  Series  A  Convertible   Preferred   Stock   holders,   upon  certain
circumstances have the right to nominate additional  directors.  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 shareholders' interest.

Certain anti-takeover provisions may affect your rights as a stockholder

     Our Articles of  Incorporation  and Bylaws include certain  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 and the  availability of authorized but unissued common
stock.  In addition,  on January 9, 1998, we adopted a shareholder  rights plan.
Under the shareholder  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 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 our common  stock.  Until they become  exercisable,  these rights
attach  to and  trade  with our  common  stock.  The  rights  issued  under  the
shareholder  rights plan expire January 20, 2008.  Issuing  preferred  stock may
delay  or  prevent  a  change  in  control  of  Magnum  Hunter  without  further
shareholder  action and may  adversely  affect the rights and powers,  including
voting rights,  of the holders of common stock.  In certain  circumstances,  the
issuance of preferred  stock could depress the market price of the common stock.
In  addition,  a change  of  control,  as  defined  under the 10%  Senior  Notes
indenture,  would  entitle the  holders of our 10% Senior  Notes due 2007 to put
those notes to Magnum  Hunter under the indenture  governing  such notes and the
lenders to  accelerate  payment  of  outstanding  indebtedness  under our credit
facility. Both of these events could discourage takeover attempts by making such
attempts more expensive.

General Business Risks

"Year 2000" Readiness

     Beginning in 1998,  the Company was involved in a program to be "Year 2000"
ready.  The program  involved  reviews of major  business,  financial  and other
information   systems,   including  equipment  with  embedded   microprocessors,
development of specific plans for modification or replacement of  date-sensitive
software  or  microprocessors,  execution  of such plans and the testing of such
systems to ensure their "Year 2000" readiness.  Included within the scope of the
program were contacts with key suppliers and customers to determine  their "Year
2000"  readiness  in order to ensure a steady flow of goods and  services to the
Company and  continuity  with respect to customer  service.  As a result of this
program,  there were no significant  occurrences of Year 2000-related  failures.
Additionally,  the Company does not anticipate that any  significant  subsequent
events will occur.

                                       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 Ryder  Scott  Company of
Houston,  Texas and Pollard,  Gore & 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) and December 31, 1998.
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, 1999,  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.  As
required by rules of the Securities and Exchange Commission, 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. In accordance with Commission rules, estimates have been made
using constant oil and gas prices and operating  costs, at December 31, 1999, or
as otherwise indicated.

     In accordance with Commission guidelines,  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,
                                         ----------------------------------
                                                1999              1998
                                         ----------------------------------
Gas (per Mcf)............................       $2.25             $2.12
Oil (per Bbl)............................      $24.03             $9.42

     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  SEC  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.

     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.

                                       22
<PAGE>

     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,
1999.  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 Commission) since January 1, 1999.

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, 1999 and
1998.

                Estimated Proved Oil and Natural Gas Reserves (a)
<TABLE>
<CAPTION>
<S>                                                 <C>                   <C>               <C>
                                                                      At December 31,
                                                 ---------------------------------------------------------------
                                                         1999                1998               1997
                                                 ---------------------------------------------------------------

Net gas reserves (Mcf):
     Proved developed...........................          184,954,732         174,787,374      154,964,396
     Proved undeveloped.........................           45,044,794          44,072,300       52,811,374
                                                 ---------------------------------------------------------------
       Total proved gas reserves................          229,999,526         219,059,674      207,775,770
                                                 ===============================================================


Net oil reserves (Bbl):
    (including condensate and NGL)
     Proved developed...........................           16,299,585           9,474,591       12,036,234
     Proved undeveloped.........................            9,234,165           7,874,050        8,910,181
                                                 ---------------------------------------------------------------
       Total proved oil reserves................           25,533,750          17,348,641       20,946,415
                                                 ===============================================================
Total Proved Reserves (Mcfe)....................          383,202,026         323,151,521      333,454,260
                                                 ===============================================================
</TABLE>
                     Estimated PV-10 of Proved Reserves (a)
<TABLE>
<CAPTION>
<S>                                               <C>                  <C>                 <C>
                                                                       At December 31,
                                                ----------------------------------------------------------------
                                                        1999                 1998                1997
                                                ----------------------------------------------------------------

Estimated PV-10 (b) :
     Proved developed..........................       $  282,481,193     $   160,984,895      $173,532,128
     Proved undeveloped .......................           87,609,991          18,424,052        38,054,232
                                                ----------------------------------------------------------------
       Total Proved Reserves...................       $  370,091,184     $   179,408,947      $211,586,360
                                                ================================================================
</TABLE>
-----------

     (a) Based upon reserve reports at December 31, 1999,  December 31, 1998 and
December 31, 1997 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.

                                       23
<PAGE>
       Significant Properties

     On December 31, 1999, 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
Coast/Gulf of Mexico.  On such date, the Company's  properties  included working
interests in 3,100 gross (1,797 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, 1999.
<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)...............          $174,419     47           8,721,097    131,813,000      184.14
Permian Basin Region (b)(c)..........          $169,845     46          15,846,808     84,484,000      179.56
Gulf Coast/Gulf of Mexico (b)  ......           $25,827     7              965,845     13,703,000       19.50
                                     ----------------------------------------------------------------------------

       Total ........................          $370,091    100          25,533,750    230,000,000      383.20
                                     ============================================================================
</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 a reserve report at December 31, 1999 prepared by Ryder Scott.

     (c) Based on reserve reports at December 31, 1999 prepared by PG&H.

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,
                                                          1999             1998              1997
                                                   ------------------------------------------------------
Oil and gas production:
  Oil (Mbbl)......................................        1,307             1,141               737
  Gas (MMcf)......................................       19,026            14,119             9,614
  Natural Gas Equivalents (MMcfe).................       26,868            20,965            14,037
Average sales price (a):
  Oil (per Bbl)...................................      $ 15.01           $ 12.67           $ 17.70
  Gas (per Mcf)...................................         2.16              2.02              2.24
  Natural Gas Equivalents (per Mcfe)..............         2.26              2.05              2.46
Oil and gas production lifting costs (per Mcfe) ..          .57               .68               .56
Production taxes and other costs (per Mcfe) (b)...      $   .30           $   .31           $   .35
</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.

                                       24
<PAGE>

Drilling Activity

     The  following  table sets  forth the  results  of the  Company's  drilling
activities during the three fiscal years ended December 31, 1999, 1998 and 1997.
<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)
    ----         ------------       -----      -------------       -------         -----      -------------      -------
    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

    1998       Exploratory
                 Texas                5               4               1             3.25           2.64            0.61
                 Oklahoma             0               0               0                0              0               0
                 New Mexico           1               1               0              .05            .05               0
                 Other                0               0               0                0              0               0
               Development
                 Texas               79              79               0             74.4           74.4               0
                 Oklahoma             0               0               0                0              0               0
                 New Mexico           5               5               0                5              5               0
                 Other                0               0               0                0              0               0

    1997       Exploratory
                 Texas                1               0               1               .2              0              .2
                 Oklahoma             1               1               0              .25            .25               0
                 Other                1               0               1                1              0               1
               Development
                 Texas               71              71               0             67.1           67.1               0
                 Oklahoma             5               2               3             1.24            .51             .73
                 Other                1               1               0               .5             .5               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.

                                       25
<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,  1999.  All of these
wells are located in the United States.
<TABLE>
<CAPTION>
<S>                            <C>          <C>            <C>               <C>          <C>           <C>
                                Productive Wells
                             As of December 31, 1999
------------------------------------------------------------------------------------------------------------------------
                                            Gross (a)                                      Net (b)
Location                        Oil           Gas           Total           Oil            Gas           Total
--------                        ---           ---           -----           ---            ---           -----

Texas......................        1,372            834          2,206            690         590.00       1,280.00
Offshore Texas ............            0              1              1              0           0.25           0.25
Oklahoma...................          139            274            413             83         164.00         247.00
Mississippi................            2              0              2              2           0.00           2.00
New Mexico.................          148            274            422             73         164.00         237.00
California.................            5              0              5              1           0.00           1.00
Offshore Louisiana.........            0              5              5              0           1.88           1.88
Arkansas...................           46              0             46             28           0.00          28.00
                           ---------------------------------------------------------------------------------------------

         Total.............        1,712          1,338          3,100            877         920.13       1,797.13
                           =============================================================================================
</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, 1999.
<TABLE>
<CAPTION>
<S>                                       <C>                   <C>             <C>                       <C>
                                                     Developed                              Undeveloped
                                                     ---------                              -----------
                                          Gross (a)             Net (b)          Gross (a)                  Net (b)
                                          ---------             -------          ---------                 -------
Offshore...........................              35,760              11,440              52,280              11,100
Texas..............................             257,138             210,398              74,381              39,365
Oklahoma...........................              97,637              71,351               6,582               3,302
Mississippi........................                  80                  80                   0                   0
New Mexico.........................              41,437              35,439                   0                   0
California.........................                 509                  38                   0                   0
                                   ------------------------------------------------------------------------------------

      Total .......................             432,561             328,746             133,243              53,767
                                   ====================================================================================
</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.

                                       26
<PAGE>

     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  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 1999.


                     [Rest of page intentionally left blank]

                                       27
<PAGE>

                                     PART II

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

     The Common  Stock of the  Company  has been  listed on the  American  Stock
Exchange  since March 8, 1996. The Common Stock has been listed under the ticker
symbol "MHR" since March 18,  1997,  prior to which time it was listed under the
ticker symbol "MPM." At March 15, 2000, there were 3,452 stockholders of record.
<TABLE>
<CAPTION>
<S>                                                                             <C>          <C>            <C>
                                                                                                           Average Daily
                                                                                                           Trading Volume
                                                                                 High           Low            (Shares)
                                                                                -----------------------------------------------
1999
   First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .        $3.19           $2.50            53,351
   Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .       $4.19           $2.75            45,792
   Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .        $4.25           $3.19            25,211
   Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .       $3.94           $2.50            46,576
1998
   First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .        $5.50           $3.88            85,139
   Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .       $7.94           $5.13           210,992
   Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .        $6.88           $3.00           118,228
   Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .       $4.38           $2.75           133,437
</TABLE>

     On March 28, 2000,  the last reported  sale price of the  Company's  Common
Stock on the American Stock Exchange was $4.00 per share.

     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 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.

     The  Company's  Common  Stock  Purchase  Warrants  have been  listed on the
American Stock Exchange since July 19, 1999. The Common Stock Purchase  Warrants
have been listed under the ticker symbol "MHR.WS". At March 15, 2000, there were
3,279 warrant holders of record.
<TABLE>
<CAPTION>
<S>                                                                             <C>            <C>              <C>
                                                                                                                Average Daily
                                                                                                                Trading Volume
                                                                                High           Low                (Shares)
                                                                                -----------------------------------------------
1999
   Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . .        $1.06           $0.31               15,842
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . .   . . . . . .        $0.44           $0.19                6,911
</TABLE>

     On March 28, 2000,  the last reported  sale price of the  Company's  Common
Stock Purchase Warrants on the American Stock Exchange was $0.69 per share.

                                       28
<PAGE>

Item 6. Selected Financial Data

     The  selected  historical  financial  data sets  forth  summary  historical
consolidated  financial  data  of the  Company  as of and for  the  years  ended
December 31, 1999,  1998,  1997, 1996 and 1995, which have been derived from the
Company's  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 the Company's  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>
                                                      1995           1996         1997 (d)       1998 (d)       1999 (d)
                                                   ----------     ----------     ----------     ----------    -------------
Income Statement Data:
Total operating revenues..........................  $     649        $16,412       $ 48,834      $  51,400         $ 69,626
Total operating costs and expenses (a)............      1,692         13,541         38,833         94,414           54,514
                                                  -------------------------------------------------------------------------
Operating profit (loss)...........................     (1,043)         2,871         10,001       (43,014)           15,112
Income (loss) before extraordinary loss...........       (968)           509         (2,128)      (47,080)           (6,826)
Extraordinary loss from early extinguishment
  of debt, net of taxes ..........................          -              -        (1,384)             -                 -
Net Income (loss) ................................       (968)           509        (3,512)       (47,080)           (6,826)
Dividends applicable to preferred shares..........       (617)          (406)         (875)          (875)           (4,509)
                                                    -------------------------------------------------------------------------
Income (loss) applicable to common shares.........  $  (1,585)       $   103       $(4,387)      $(47,955)         $(11,335)
                                                    =========================================================================
Income (loss) per common share before
 extraordinary item
   Basic..........................................  $   (0.28)       $  0.01       $ (0.21)      $  (2.27)      $    (0.57)
   Diluted........................................  $   (0.28)       $  0.01       $ (0.21)      $  (2.27)      $    (0.57)
Income (loss) per common share after
 extraordinary item
   Basic..........................................  $   (0.28)       $  0.01       $ (0.30)      $  (2.27)      $    (0.57)
   Diluted........................................  $   (0.28)       $  0.01       $ (0.30)      $  (2.27)      $    (0.57)

Other Data:
EBITDA (b)........................................  $    (545)       $ 6,166       $ 22,740      $ 22,112       $   37,538
Capital expenditures (c)..........................  $   1,244        $41,471       $160,059      $ 70,187        $  59,968
</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.

     (b) EBITDA is defined as income  (loss)  before  income  taxes and minority
interest,  plus the sum of depletion  and  depreciation  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.

     (c) Capital expenditures include cash expended for acquisitions plus normal
additions to oil and natural gas properties and other fixed assets.

     (d) As restated. See Note 18 to the consolidated financial statements.

                                       29
<PAGE>

<TABLE>
<CAPTION>
<S>                                                <C>           <C>           <C>            <C>            <C>
                                                      1995          1996        1997 (b)       1998 (b)         1999 (b)
                                                    ---------     ---------    -----------    -----------     ------------
Balance Sheet Data:
Working capital (deficiency).......................  $  (916)      $  2,279      $   2,610     $  (1,203)     $    (1,314)
Property, plant and equipment, net.................    36,405        73,648        221,259        228,436          265,195
Total assets.......................................    40,065        83,072        251,069        265,724          304,022
Total debt (a).....................................     9,612        38,766        161,543        231,020          234,806
Stockholders' equity...............................  $ 24,496      $ 35,154      $  72,152     $   19,697     $     51,552
</TABLE>
-----------

     (a) Consists of long-term debt,  including current  maturities of long-term
debt,  and excluding  production  payment  liabilities  of $288  thousand,  $937
thousand,  $743  thousand,  $633  thousand and $460  thousand as of December 31,
1995, 1996, 1997, 1998 and 1999, respectively. As of December 31, 1999 and 1998,
$41.8 million and $26 million, respectively, of the debt was non-recourse to the
Company.

     (b) As restated. See Note 18 to the consolidated financial statements.

     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>
                                                                                 1999
                                                    ---------------------------------------------------------------
                                                       First          Second          Third             Fourth
                                                   --------------  -------------  --------------   ----------------
Revenues...........................................   $    13,105    $    15,359     $    19,864       $     21,298
Depreciation, depletion and amortization...........         5,148          5,467           5,768              5,689
Net Operating Profit...............................         1,266          2,539           5,539              5,768
Net Income (Loss)..................................       (4,962)        (2,340)             213                263
Loss per common share, basic.......................   $    (0.29)    $    (0.18)     $     (0.05)      $      (0.05)
Loss per common share, diluted.....................   $    (0.29)    $    (0.18)     $     (0.05)      $      (0.05)
</TABLE>

<TABLE>
<CAPTION>
<S>                                                 <C>            <C>             <C>            <C>
                                                                                 1998
                                                    ---------------------------------------------------------------
                                                       First           Second          Third            Fourth
                                                   --------------  --------------  -------------   ----------------
Revenues...........................................    $   12,753      $   13,261    $    13,580        $    11,806
Depreciation, depletion and amortization...........         3,875           4,941          4,805              8,136
Write-down of oil and gas properties...............             -               -              -             42,745
Net Operating Profit (Loss)........................         1,295           1,260            891            (46,460)
Net Loss...........................................        (1,747)         (1,915)        (2,272)           (41,146)
Loss per common share, basic.......................    $    (0.09)     $    (0.10)   $     (0.12)       $     (1.96)
Loss per common share, diluted.....................    $    (0.09)     $    (0.10)   $     (0.12)       $     (1.96)
</TABLE>
                                       30
<PAGE>

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

     Subsequent to the issuance of the consolidated financial statements for the
year ended  December 31, 1999,  the  Company's  management  determined  that the
Company's  loans to a  shareholder  and  transactions  involving  the  Company's
Employee  Stock  Ownership  Plan  ("ESOP")  should have been  accounted for as a
reduction  in  Stockholders'  Equity  rather than as assets.  In  addition,  the
Company determined that common shares acquired by the ESOP but not yet allocated
to participants should not have been considered outstanding in the determination
of the number of shares included in the calculation of loss per common share. As
a result, the accompanying  consolidated financial statements have been restated
from the amounts previously reported.

     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.

     In April 1997,  the Company  purchased  the Permian Basin  Properties  from
Burlington  for a net purchase  price of $133.8  million  after  purchase  price
adjustments of $9.7 million.  These properties  consisted of approximately 1,852
producing oil and gas wells and  associated  acreage in west Texas and southeast
New Mexico. This acquisition substantially increased the Company's cash flow and
inventory of exploitation, development and exploration opportunities.

     On January 28, 1998, the Company  commenced a cash purchase offer for Units
of TEL Offshore  Trust.  Previous to the offer,  the Company owned 161,500 Units
representing  3.4% of the  Units  outstanding.  As  amended,  the  offer  was to
purchase  between  forty  percent  (40%) and sixty  percent (60%) of the Trust's
outstanding  Units at $5.50 per Unit. On March 27, 1998,  the Company  purchased
1,745,353  Units for $10.4  million  pursuant to the tender offer and,  together
with the Units it previously owned, became the owner of approximately 40% of the
total  number  of Units  outstanding  for an  aggregate  consideration  of $10.4
million.

     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.  The net  purchase  price was  approximately  $25 million  after  certain
purchase price  adjustments,  including  preferential  rights exercised by third
parties  and  other  customary  adjustments.  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.  To  finance  the Spirit 76
acquisition,  Bluebird  borrowed $26 million  under a bridge loan  facility with
several  banks.  The bridge  loan was  replaced  on June 7, 1999 with  permanent
financing from banks  providing for a revolving  credit  facility of $75 million
with an initial borrowing base of $41.5 million,  due June 7, 2002 with interest
rates based upon either "LIBOR" or "Base Rate" (Prime). The loan is non-recourse
to the  Company.  In  addition  to retiring  the bridge  loan,  a portion of the
proceeds from the permanent  financing  was used to finance the  acquisition  of
properties from Vastar Resources, Inc. ("Vastar") discussed below.

     On  February  3, 1999,  the  Company  sold $50  million of its  Convertible
Preferred  Stock in a private  placement.  The Preferred Stock has a liquidation
value of $50 million and is convertible into the Company's common stock at $5.25
per share.  Dividends on the preferred  stock are payable in cash at the rate of
8% per annum and are  cumulative.  The Company  used the net  proceeds  from the
transaction, approximately $46.3 million, to repay senior bank indebtedness.

     On June 8, 1999,  the Company  acquired  oil and gas  reserves  and related
assets from Vastar for a total  purchase  price of $32.5 million after  purchase
price adjustments.  The effective date of the acquisition was April 1, 1999. The
acquisition  included Vastar's interest in 476 wells, a gas processing plant and
two gas gathering systems located in the states of Texas, Oklahoma and Arkansas.

                                       31
<PAGE>

     On December 1, 1999,  the Company  acquired 50%  ownership  interest in the
Madill  Gas  Processing  Plant  and  associated  gathering  system  from  Dynegy
Midstream Services,  L.P., a wholly-owned subsidiary of Dynegy, Inc. This modern
cryogenic  plant includes  3,350  horsepower of high-speed  compression  and has
gas-processing  capacity of  approximately  18,000  Mcf/d.  The  facilities  are
located in Marshall and Bryan  counties,  Oklahoma.  The  effective  date of the
acquisition was November 1, 1999.

     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 reserves are capitalized
into a "full cost pool" 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. 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 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 increase.  Due primarily to
the severe  decline in world  crude oil and natural  gas prices  experienced  in
1998, the Company recognized a non-cash  impairment of oil and gas properties of
$42.7 million at December 31, 1998 pursuant to the ceiling  limitation  required
by the full cost method of  accounting,  using certain  improvements  in pricing
experienced after the end of the period.  Without the benefit of improvements in
pricing  subsequent  to December 31, 1998,  the Company  would have  incurred an
impairment of $81.2 million.  The Company's PV-10 property valuation at December
31,  1999  exceeded  the  capitalized  cost at that date.  Significant  downward
revisions of quantity  estimates or declines in oil and gas prices which are not
offset by other factors could  possibly  result in write-down  for impairment of
oil and gas properties in the future.

Results of Operations For the Years Ended 1999 and 1998

     As  discussed  above,  the Company  acquired  the Spirit 76  Properties  in
December  1998,  the Vastar  properties in June 1999 and the Madill Gas Plant in
December 1999.  Unless otherwise  stated,  the increases in the 1999 period over
the 1998  period  were  substantially  a result  of these  acquisitions  and the
increases  in  daily  oil and  gas  production  associated  with  the  Company's
successful drilling operations.

     Oil and gas sales were  $60.7  million in 1999,  a 39%  increase  over 1998
sales of $43.6  million.  In 1999, the Company sold 1,307 MBbl of oil and 19,026
MMcf of gas which  represents  a 15%  increase in oil and a 35%  increase in gas
volume over the prior year.  The price  received  for oil was $15.01 per Bbl and
for gas was $2.16 per Mcf in 1999, representing an 18% increase in oil price and
a 7% increase in gas price. Oil and gas production lifting costs increased 8% to
$15.4  million in 1999 from 1998.  The gross  operating  margin from oil and gas
production was $37.1 million in 1999, a 62% increase over 1998. On an equivalent
unit basis,  the gross margin was $1.39 per Mcfe in 1999 versus $1.06 in 1998, a
31% increase. The sales price per Mcfe was $2.26 in 1999 versus $2.05 in 1998, a
10% increase.  Production  lifting costs decreased 16% to $0.57 per Mcfe in 1999
from $0.68 per Mcfe in 1998.  Production  tax and other  costs  decreased  3% to
$0.30 per Mcfe in 1999 from $0.31 per Mcfe in 1998.  Total equivalent units sold
increased 28% to 26.9 Bcfe in 1999 from 21.0 Bcfe in 1998.

     Gas  gathering,  marketing,  and  processing  revenues were $8.2 million in
1999, an 18% increase from 1998. Gross operating margin was $2.3 million in 1999
versus $1.2 million in 1998, an 92% increase.  Total gathering system throughput
decreased  11% to 18.5 MMcf per day in 1999  compared  with 20.8 MMcf per day in
1998,  principally due to the sale of a gathering  system.  Gas plant processing
throughput was 21.5 MMcf per day in 1999 versus 15.7 MMcf per day in 1998, a 37%
increase due to the Vastar and Madill acquisitions.  Gross operating margin from
gathering  operations  was $0.14 per Mcf of  throughput in 1999 versus $0.11 per
Mcf in 1998, a 27% increase.  The gross operating margin from gas processing was
$0.16  per Mcf of  throughput  in 1999  versus  $0.07  per Mcf in  1998,  a 129%
increase resulting from substantially improved processing economics.

     Revenues from oil field services and international sales were $768 thousand
in 1999, a 13% decrease from revenues of $881 thousand in 1998,  principally due
to a  decrease  in oil field  management  services  provided  to third  parties.
Operating costs were $350 thousand in 1999, a $117 thousand  decrease over 1998.
The gross  operating  margin from these  activities  was $418,000 in 1999 versus
$414,000 in the 1998 period.

                                       32
<PAGE>

     Depreciation  and depletion  expense  increased 1% to $22.1 million in 1999
from $21.8 million in 1998.  Depletion expense on oil and gas production in 1999
was $21.2 million,  or $.79 per Mcfe, versus $20.9 million, or $1.00 per Mcfe in
1998,  principally  due to the  write-down  of the value of its oil and gas full
cost pool by $42.7 million in 1998 versus none in 1999.  This write-down was the
result of the low oil and gas prices  experienced in December 1998.  Without the
benefit of improvements in pricing  subsequent to December 31, 1998, the Company
would have incurred an impairment of $81.2 million. While this write-down is not
recoverable  if prices  increase,  it has the effect of lowering  the  Company's
future  depletion  rates.  The  Company  had a gain on sale  of  assets  of $272
thousand in 1999,  principally from the sale of a gas gathering system, versus a
loss on sale of assets  of $52  thousand  in 1998.  General  and  administrative
expense decreased 2% to $2.9 million in 1999 from $3.0 million in 1998.

     Operating  profit increased to $15.1 million in 1999 versus a loss of $43.0
million in 1998. Equity in earnings of affiliate,  net of income tax, was a loss
of $103 thousand in 1999 versus a loss of $116 thousand  reported in 1998. Other
income  decreased  43% to $354  thousand in 1999  versus $624  thousand in 1998.
Interest expense  increased to $22.1 million in 1999 from $18.2 million in 1998,
an increase of 21%, due to increased  levels of  borrowing  under the  Company's
revolving  credit lines and an increase in floating  interest rates. The Company
incurred a net loss before  income tax and minority  interest of $6.7 million in
1999,  versus a net loss of $60.7 million in 1998.  The Company  provided for no
deferred  income tax  benefit in 1999  versus a deferred  income tax  benefit of
$13.7 million in 1998. The Company  reported a net loss in 1999 of $6.8 million,
versus a net loss of $47.1 million in 1998.

     The Company  accrued $4.5 million in  dividends on its  preferred  stock in
1999 compared to $875 thousand in 1998. The increase in dividends was due to the
sale of $50  million of its  convertible  preferred  stock in 1999.  The Company
reported net loss to common  shareholders of $11.3 million, or $.57 per share in
1999 versus $48.0 million,  or $2.27 per share in 1998. The Company provided for
no deferred  tax  benefit in 1999 versus a deferred  income tax benefit of $13.7
million in 1998.  The Company  increased its income tax  valuation  allowance by
$2.3 million to approximately $11 million.  The valuation allowance  established
by the Company  reduces the  Company's  deferred tax asset to the amount that is
more likely than not to be realized.  The Company determines the adequacy of the
valuation  allowance  based on a number of factors  including  projected  future
taxable income and anticipated levels of capital spending.

Results of Operations For the Years Ended 1998 and 1997

     As discussed  above,  the Company  acquired the Permian Basin Properties in
April 1997, and its interest in TEL in March 1998. Unless otherwise stated,  the
increases in the 1998 period over the 1997 period were substantially a result of
these acquisitions and the increases in daily oil and gas production  associated
with the Company's successful drilling operations.

     Oil and gas sales were $43.6  million in 1998, a 26% increase over sales of
$34.6  million in 1997.  In 1998,  the Company sold  1,140,762 Bbl of oil, a 55%
increase,  and 14,119 MMcf of gas, a 47% increase over the prior year. The price
received  for oil was  $12.67  per Bbl and for gas was  $2.02  per Mcf in  1998,
representing  a 28%  decrease in oil price from $17.70 per Bbl in 1997 and a 10%
decrease in gas price from $2.24 per Mcf in 1997. Oil and gas production lifting
costs  increased  81% to $14.3  million in 1998 from $7.9  million in 1997.  The
gross operating  margin from oil and gas production was $22.9 million in 1998, a
5% increase  over the gross  operating  margin of $21.8  million in 1997.  On an
equivalent unit basis,  the gross margin was $1.06 per Mcfe in 1998 versus $1.55
in 1997, a 32% decrease. The sales price per Mcfe was $2.05 in 1998 versus $2.46
in 1997, a 17% decrease.  Production  lifting  costs  increased 21% to $0.68 per
Mcfe in 1998  from  $0.56  per  Mcfe in 1997.  Production  tax and  other  costs
decreased  11% to $0.31  per Mcfe in 1998  from  $0.35  per Mcfe in 1997.  Total
equivalent units sold increased 49% to 21 Bcfe in 1998 from 14 Bcfe in 1997.

     Gas gathering,  marketing, and processing revenues were $7.0 million in the
1998  period,  a 32%  decrease  from  revenues of $10.3  million in 1997.  Gross
operating  margin was $1.2  million in 1998 versus $2.4  million in 1997,  a 50%
decrease. Total gathering system throughput increased 1% to 20.8 MMcf per day in
1998 compared with 20.5 MMcf per day in 1997.  Gas plant  processing  throughput
was 15.7 MMcf per day in 1998 versus 14.9 MMcf per day. Gross  operating  margin
from  gathering  operations was $0.11 per Mcf of throughput in 1998 versus $0.22
per Mcf in 1997, a 48% decrease.  The gross operating margin from gas processing
was $0.07 per Mcf of  throughput  in 1998  versus  $0.20 per Mcf in 1997,  a 67%
decrease.

                                       33
<PAGE>

     Revenues from oil field services and international sales were $881 thousand
in 1998, a 78% decrease from revenues of $4.0 million in 1997,  principally  due
to a  decrease  in  sales  in  Hunter  Butcher  International,  L.L.C.  ("Hunter
Butcher") in the amount of $3.1 million.  Operating  costs were $467 thousand in
1998, a $3.3 million decrease over 1997, also principally due to Hunter Butcher.
The gross  operating  margin from these  activities  was $414,000 in 1998 versus
$223,000 in the 1997 period.

     Depreciation and depletion  expense  increased 76% to $21.8 million in 1998
from $12.4 million in 1997 due to the  acquisitions and to loss of reserves as a
result of year-end commodity prices. Depletion expense on oil and gas production
in 1998 was $20.9 million,  or $1.00 per Mcfe, in 1998 versus $11.6 million,  or
$0.82 per Mcfe in 1997. The Company wrote-down the value of its oil and gas full
cost pool by $42.7 million in 1998 versus none in 1997.  This write-down was the
result of the low oil and gas prices  experienced  by all  producers in December
1998.  Without the benefit of improvements in pricing subsequent to December 31,
1998, the Company would have incurred an impairment of $81.2 million. While this
write-down is not recoverable if prices  increase,  it should have the effect of
lowering  the  Company's  future  depletion  rates.  General and  administrative
expense  increased 26% to $3.0 million in 1998 from $2.4 million in 1997, due to
increased  staffing and other costs as a result of the  acquisitions,  increased
activity levels of the Company and the provision for doubtful accounts on a note
receivable.

     Operating profit decreased $53.0 million to a loss of $43.0 million in 1998
versus a profit of $10.0 million in 1997.  Equity in earnings of affiliate,  net
of income tax, was a loss of $116,000 in 1998 versus a profit of $6,000 reported
in 1997.  Other income increased 66% to $624,000 in 1998 versus $376,000 in 1997
due to an increase in  interest  income.  Interest  expense  increased  to $18.2
million in 1998 from $13.8 million in 1997, an increase of 32%, due to increased
levels of borrowing  under the Company's  revolving  credit lines and the Notes.
The Company incurred a net loss before income tax and minority interest of $60.7
million in 1998,  versus a net loss of $3.4 million in 1997,  principally due to
the  write-down  of oil and gas  reserves,  lower oil and gas  prices and higher
interest  expense.  The Company  provided  for a deferred  income tax benefit of
$13.7 million on this loss in 1998 versus a deferred  income tax benefit of $1.3
million in 1997.  After  recording a $37,000  minority  interest  loss in Hunter
Butcher,  the Company reported a loss in 1998 before extraordinary item of $47.1
million,  or $2.27 per common share,  versus a minority interest loss of $19,000
and a loss before  extraordinary item of $2.1 million, or $0.21 per common share
in 1997.

     The  Company  realized an  extraordinary  loss of $1.4  million  ($0.09 per
common share) as required under Accounting  Principles  Board ("APB")  Statement
No. 26 and Statement of Financial  Accounting Standards ("SFAS") No. 4, from the
early  extinguishment  of bank  debt in 1997 and  none in 1998.  The net loss in
1997, after the extraordinary charge, applicable to common shareholders was $4.4
million  ($0.30 per common  share) as  compared  to a net loss of $48.0  million
($2.27 per common share) in 1998. The Company  accrued  $875,000 in dividends on
its  preferred  stock in both years 1998 and 1997.  The Company  provided  for a
deferred  income  tax  benefit of $13.7  million  on this loss in 1998  versus a
deferred  income tax benefit of $1.3 million in 1997. The Company  increased its
income tax valuation  allowance by $8.4 million to  approximately  $8.7 million.
The  valuation  allowance  established  by the  Company  reduces  the  Company's
deferred  tax asset to the amount that is more  likely than not to be  realized.
The Company determines the adequacy of the valuation allowance based on a number
of factors including  projected future taxable income and anticipated  levels of
capital spending.

                                       34
<PAGE>

Liquidity and Capital Resources

     The Company has three principal operating sources of cash: (i) sales of oil
and gas, (ii) revenues from gas gathering,  processing, and marketing, and (iii)
revenues from petroleum management and consulting  services.  The Company's cash
flow is highly dependent upon oil and gas prices.  Decreases in the market price
of oil and gas could result in  reductions  of both cash flow and the  borrowing
base under the Company's Credit Facility,  which would result in decreased funds
available, including funds for capital expenditures.

     In September 1998, the Company  announced a stock repurchase  program of up
to one million shares at a cost not to exceed $4 million.  At December 31, 1998,
the Company had repurchased  625,600 shares for approximately  $1.9 million.  In
February 1999, the program was revised to remove the share limitation  discussed
above.  In 1999,  the Company has  purchased an  additional  601,472  shares for
approximately $1.7 million.

     In December 1998, the Company's 100% owned subsidiary,  Bluebird,  acquired
for approximately  $25 million,  certain natural gas reserves and related assets
from Spirit 76.  Additionally,  the Company capitalized  Bluebird with 1,840,271
units of TEL  Offshore  Trust.  To finance the Spirit 76  acquisition,  Bluebird
borrowed $26 million under a bridge loan facility with several banks. The bridge
loan was replaced on June 7, 1999 with permanent  financing from banks providing
for a revolving credit facility of $75 million with an initial borrowing base of
$41.5  million,  due three years from the date of closing  with  interest  rates
based upon either "LIBOR" or "Base Rate"  (Prime).  The loan is non- recourse to
the Company.  In addition to retiring the bridge loan, a portion of the proceeds
from the permanent  financing was used to finance the  acquisition of properties
from Vastar discussed below.

     In December 1998, the Company  announced a letter of intent for a strategic
alliance with ONEOK Resources  Company,  to include the purchase by this company
of $50 million of the Company's  Convertible  Preferred Stock. In February 1999,
this transaction was consummated. The Preferred Stock has a liquidation value of
$50 million and is  convertible  into the  Company's  common  stock at $5.25 per
share.  Dividends on the Preferred Stock are payable in cash beginning August of
1999 at the rate of 8% per annum and are  cumulative.  The net proceeds of $46.3
million  received from the sale of Preferred Stock was used to repay senior bank
indebtedness.

     On June 8, 1999,  the Company  acquired  oil and gas  reserves  and related
assets from Vastar for a total  purchase  price of $32.5 million after  purchase
price adjustments.  The effective date of the acquisition was April 1, 1999. The
acquisition  included Vastar's interest in 476 wells, a gas processing plant and
two gas gathering systems located in the states of Texas, Oklahoma and Arkansas.

     On December 1, 1999,  the  Company,  through  its  wholly-owned  subsidiary
Bluebird, acquired 50% ownership interest in the Madill Gas Processing Plant and
associated gathering system from Dynegy Midstream Services, L.P., a wholly-owned
subsidiary of Dynegy, Inc. This modern cryogenic plant includes 3,350 horsepower
of  high-speed  compression  and has  gas-processing  capacity of  approximately
18,000  Mcf/d.  The  facilities  are  located in  Marshall  and Bryan  counties,
Oklahoma. The effective date of the acquisition was November 1, 1999.

     In  connection  with the Madill  Gas Plant  acquisition,  Bluebird's  banks
increased  the  borrowing  base  under the  credit  agreement  to $45.0  million
effective November 30, 1999, subject to a provision to automatically  reduce the
borrowing  base to $41.5 million on March 31, 2000,  with further  reductions to
the borrowing base of $2.0 million to occur on June 30, 2000 and each subsequent
quarter-end.   Effective  March  27,  2000,  the  banks  suspended  the  various
requirements  of the  November 30, 1999  adjustment  to the  borrowing  base and
established a current  borrowing base for Bluebird of $43.5  million.  The banks
agreed to redetermine  the borrowing base and the need to reimplement  the other
requirements  of the  November 30, 1999  adjustment  upon the earlier of May 15,
2000  or the  consummation  or  termination  of a  proposed  sale of oil and gas
properties.  The Company believes that this agreement, along with cash flow from
operations,  provides  Bluebird  with  sufficient  liquidity  to  meet  interest
payments as well as to carry out its capital spending plans in the year 2000.

                                       35
<PAGE>

     The Company's borrowing base under its revolving credit line with banks was
$60,000,000 at December 31, 1999,  providing  $7,000,000 of additional borrowing
capacity at that date. The Company believes that this  availability,  along with
cash  flow  from  operations,  is  sufficient  to  meet  interest  and  dividend
requirements in 2000 as well as to carry out its capital spending needs.

     For 1999,  the Company  had a net  decrease  in cash of $3.3  million.  The
Company's operating  activities provided net cash of $17.4 million.  The Company
used  $58.5  million in  investing  activities,  principally  for  additions  to
property and  equipment.  Financing  activities  provided $37.7 million of cash,
principally from the aggregate  proceeds from the issuance of preferred stock of
$46.3 million. The Company also paid $4.2 million in cash dividends on preferred
stock.

     For 1998,  the Company  had a net  increase  in cash of $1.8  million.  The
Company's operating  activities provided net cash of $13.7 million,  principally
from operating income before depreciation,  depletion, write-down of oil and gas
properties  and  deferred  tax  benefit,  as well  as a  reduction  in  accounts
receivable and an increase in accounts  payable.  The Company used $74.0 million
in  investing  activities  for  additions to property  and  equipment  and other
investments.  Cash flow from financing activities were $62.1 million, consisting
of proceeds  from  issuance of  long-term  debt of $80  million,  the payment of
principal on long and short-term debt of $13.3 million, the purchase of treasury
stock for $1.9 million and other uses, including the payment of $875 thousand in
dividends on preferred stock.

     For 1997,  the Company  had a net  increase  in cash of $1.3  million.  The
Company's operating  activities  provided net cash of $5.7 million,  principally
from  operating  income  before  depreciation,  depletion,  and deferred  taxes,
reduced by a net increase in accounts  receivable  over  accounts  payable.  The
Company used $168.3 million in investing  activities,  principally for additions
to property  and  equipment of $160.1  million.  Financing  activities  provided
$164.0  million  of cash,  principally  from  the  aggregate  proceeds  from the
issuance of long-term debt of $352.5 million,  less principal payments of $229.9
million on this debt, as well as proceeds from issuance of common stock of $41.7
million and proceeds from short-term notes payable of $2.7 million.  The Company
also paid $678,000 in dividends on preferred stock.

Capital Requirements

     For fiscal  2000,  the Company has budgeted  approximately  $25 million for
development and exploration activities,  including approximately $15 million for
participation in exploration and development  projects in the shallow water area
of the Gulf of Mexico.  The Company is not  contractually  obligated  to proceed
with any of its 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  and  changes  in oil  and  gas  prices.  As a  result,  actual  capital
expenditures may vary significantly from current expectations.

     On June 8, 1999, the Company's  borrowing  base under its revolving  credit
line was reduced from $65 million to $60 million as a result of the December 31,
1998 reserve engineering report.

     Based upon the  Company's  anticipated  level of  operations,  the  Company
believes that cash flow from operations together with the availability under the
Credit Facility  (approximately  $7.0 million available as of December 31, 1999)
will be  adequate to meet its  anticipated  requirements  for  working  capital,
capital  expenditures  and  scheduled  interest  and  dividend  payments for the
foreseeable future.

     In  addition,   the  Company's  wholly-owned   subsidiary,   Bluebird,  has
availability  under its own credit  facility  (non-  recourse to the Company) of
approximately  $3.2  million  at  December  31,  1999 after the  borrowing  base
increased  to $45.0  million on November 30, 1999.  However,  this  increase was
subject to a  provision  to  automatically  reduce the  borrowing  base to $41.5
million on March 31, 2000, with further reductions to the borrowing base of $2.0
million to occur on June 30,  2000 and each  subsequent  quarter-end.  Effective
March 27, 2000, the banks suspended the various requirements of the November 30,
1999 adjustment to the borrowing base and  established a current  borrowing base
for Bluebird of $43.5  million.  The banks agreed to  redetermine  the borrowing
base and the need to reimplement the other requirements of the November 30, 1999
adjustment  upon the earlier of May 15, 2000 or the  consummation or termination
of a proposed  sale of oil and gas  properties.  The Company  believes that this
agreement, along with cash flow from

                                       36
<PAGE>

     operations,  provides  Bluebird with sufficient  liquidity to meet interest
payments as well as to carry out its capital spending plans in the year 2000.

     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.

Inflation and Changes in Prices

     During 1999,  the Company  experienced  an increase in prices for oil (18%)
and for  natural  gas  (7%)  compared  to the  previous  year.  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.
Periodically  the Company  enters into futures,  options,  and swap contracts to
reduce the effects of fluctuations in crude oil and gas prices. It is the policy
of the Company not to enter into any such  arrangements  which exceed 75% of the
Company's oil and gas production during the next 12 months.

     The Company  markets  oil and gas for its own  account,  which  exposes the
Company  to  the  attendant  commodities  risk.  A  substantial  portion  of the
Company's gas production is currently  sold to NGTS, LLC 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.  The Company
normally  sells  its  oil  under  month-to-month   contracts  to  a  variety  of
purchasers.

Hedging Activity

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 natural gas
prices. At December 31, 1999, the Company had the following open contracts:


            Type             Volume/Month         Duration         Avg. Price
          ----------------------------------------------------------------------
Oil
------
          Swap...........    30,000 Bbl        Jan 00 - Dec 00            $17.60
          Collar.........    30,000 Bbl        Jan 00 - Mar 00    Floor - $18.00
                                                                  Cap -   $22.65
          Collar.........    30,000 Bbl        Jan 00 - Mar 00    Floor - $18.00
                                                                  Cap -   $23.87
          Collar.........    30,000 Bbl        Apr 00 - Jun 00    Floor - $18.00
                                                                  Cap -   $24.50
          Collar.........    30,000 Bbl        Apr 00 - Jun 00    Floor - $18.00
                                                                  Cap -   $26.00
          Collar.........    30,000 Bbl        Jul 00 - Sep 00    Floor - $18.00
                                                                  Cap -   $24.00
          Collar.........    30,000 Bbl        Jul 00 - Sep 00    Floor - $18.00
                                                                  Cap -   $24.65

                                       37
<PAGE>

Gas
------
          Collar.........  300,000 MMBtu       Jan 00 - Mar 00   Floor - $  2.00
                                                                 Cap -   $  2.32
          Collar ........  300,000 MMBtu       Apr 00 - Oct 00   Floor - $  1.80
                                                                 Cap -   $  2.25
          Swap...........  100,000 MMBtu       Jan 00 - Mar 00           $  2.86
          Collar ........  100,000 MMBtu       Jan 00 - Mar 00   Floor - $  2.62
                                                                 Cap -   $  3.82
          Purchased
          Call...........  100,000 MMBtu       Feb 00 - Mar 00           $  2.86

     Net gains or losses related to derivative  transactions for the years ended
December 31, 1999, 1998 and 1997 were $(3,232,000), $2,739,000 and $(1,537,000),
respectively.  At  December  31,  1999,  the  unrealized  loss  from  derivative
transactions was $3,812,000.

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 next twelve months.
<TABLE>
<CAPTION>
<S>                              <C>                    <C>                     <C>                      <C>
           Type                   Notional Amount        Termination Date            Pay Rate                Receive Rate
---------------------------     -------------------     -------------------     -------------------     ----------------------
Pay Variable/Receive Fixed          $50,000,000              06/01/02           LIBOR + 3.34%                 10% fixed
                                                                                through 05/31/00

                                                                                LIBOR + 3.69%
                                                                                from 06/01/00 to
                                                                                06/01/02
Pay Fixed/Receive Variable          $50,000,000              06/01/00           9.16% fixed                 LIBOR + 3.34%
</TABLE>

     The pay  variable/receive  fixed  swap has an early  termination  provision
granting the  counterparty  the right to terminate  the swap on June 1, 2000, in
exchange for a fee payment to the Company of $125,000.  As a result of these two
swaps, the Company saved  approximately  $209,000 in interest expense during the
year ended  December 31, 1999.  The  unrealized  savings in interest  expense at
December 31, 1999 calculated  through May 31, 2000 was  approximately  $175,000.
Thereafter,  the economic  impact depends on whether or not LIBOR rates increase
significantly.

Year 2000 Compliance

     Beginning in 1998,  the Company was involved in a program to be "Year 2000"
ready.  The program  involved  reviews of major  business,  financial  and other
information   systems,   including  equipment  with  embedded   microprocessors,
development of specific plans for modification or replacement of  date-sensitive
software  or  microprocessors,  execution  of such plans and the testing of such
systems to ensure their "Year 2000" readiness.  Included within the scope of the
program were contacts with key suppliers and customers to determine  their "Year
2000"  readiness  in order to ensure a steady flow of goods and  services to the
Company and  continuity  with respect to customer  service.  As a result of this
program,  there were no significant  occurrences of Year 2000-related  failures.
Additionally,  the Company does not anticipate that any  significant  subsequent
events will occur.

                                       38
<PAGE>

Recently Issued Accounting Pronouncements

     In June 1998,  the FASB  issued  SFAS No. 133,  Accounting  for  Derivative
Instruments and Hedging Activities, which established a new model for accounting
for derivatives and hedging  activities.  SFAS No. 133, which as amended will be
effective for the Company's  fiscal year 2001,  requires that all derivatives be
recognized in the balance sheet as either assets or liabilities  and measured at
fair value.  The Statement  also requires that changes in fair value be reported
in earnings  unless specific hedge  accounting  criteria are met. The Company is
currently  evaluating  the  effect  of  the  adoption  of the  Statement  on its
consolidated financial position and results of operations.

Item 7A. Qualitative and Quantitative Disclosure About Market Risk

     Energy swap  agreements.  The  Company  engages in futures  contracts  with
certain of its production  through various  contracts ("Swap  Agreements").  The
Company considers these contracts to be hedging activities and, as such, monthly
settlements on these  contracts are reflected in oil and gas sales.  In order to
consider these contracts as hedges,  (i) the Company must designate the contract
as a hedge of future  production and (ii) the contract must reduce the Company's
exposure  to the risk of  changes in  prices.  Changes  in the  market  value of
contracts  treated as hedges are not  recognized in income until the hedged item
is also  recognized  in income.  If the above  criteria are not met, the Company
will  record  the  market  value of the  contract  at the end of the  month  and
recognize  a  related  gain or  loss.  Proceeds  received  or paid  relating  to
terminated  contracts or contracts  that have been sold are  amortized  over the
original  contract period and reflected in oil and gas sales. The Company enters
into hedging  activities in order to secure an acceptable  future price relating
to a portion of future production.  The primary objective of these activities is
to protect against 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 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.


                     [Rest of page intentionally left blank]

                                       39
<PAGE>

     At December 31, 1999, the Company had the following open contracts:


          Type                Volume/Month        Duration         Avg. Price
       -------------------------------------------------------------------------
Oil
------
       Swap................    30,000 Bbl      Jan 00 - Dec 00            $17.60
       Collar..............    30,000 Bbl      Jan 00 - Mar 00    Floor - $18.00
                                                                  Cap -   $22.65
       Collar..............    30,000 Bbl      Jan 00 - Mar 00    Floor - $18.00
                                                                  Cap -   $23.87
       Collar..............    30,000 Bbl      Apr 00 - Jun 00    Floor - $18.00
                                                                  Cap -   $24.50
       Collar..............    30,000 Bbl      Apr 00 - Jun 00    Floor - $18.00
                                                                  Cap -   $26.00
       Collar..............    30,000 Bbl      Jul 00 - Sep 00    Floor - $18.00
                                                                  Cap -   $24.00
       Collar..............    30,000 Bbl      Jul 00 - Sep 00    Floor - $18.00
                                                                  Cap -   $24.65
Gas
------
       Collar..............   300,000 MMBtu    Jan 00 - Mar 00   Floor - $  2.00
                                                                 Cap -   $  2.32
       Collar .............   300,000 MMBtu    Apr 00 - Oct 00   Floor - $  1.80
                                                                 Cap -   $  2.25
       Swap................   100,000 MMBtu    Jan 00 - Mar 00           $  2.86
       Collar .............   100,000 MMBtu    Jan 00 - Mar 00   Floor - $  2.62
                                                                 Cap -   $  3.82
       Purchased Call......   100,000 MMBtu    Feb 00 - Mar 00           $  2.86

     Based on future market  prices at December 31, 1999,  the fair value of the
open  contracts was  $(3,812,000).  If future market prices were to increase 10%
from those in effect at December 31, 1999,  the fair value of the open contracts
would be $(6,360,000). If future market prices were to decline 10% from those in
effect at  December  31,  1999,  the fair value of the open  contracts  would be
$(1,755,000).

     The Company  currently intends to commit no more than 75% of its 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.

                                       40
<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 next twelve months.
<TABLE>
<CAPTION>
<S>                             <C>                  <C>                  <C>                   <C>
            Type                 Notional Amount      Termination Date         Pay Rate            Receive Rate
-----------------------------  -------------------   ------------------   ------------------   --------------------
 Pay Variable/Receive Fixed        $50,000,000            06/01/02          LIBOR + 3.34%           10% fixed
                                                                           through 05/31/00

                                                                            LIBOR + 3.69%
                                                                           from 06/01/00 to
                                                                               06/01/02
 Pay Fixed/Receive Variable        $50,000,000            06/01/00           9.16% fixed          LIBOR + 3.34%
</TABLE>

     The pay  variable/receive  fixed  swap has an early  termination  provision
granting the  counterparty  the right to terminate  the swap on June 1, 2000, in
exchange for a fee payment to the Company of $125,000.  As a result of these two
swaps, the Company saved  approximately  $209,000 in interest expense during the
year ended  December 31, 1999.  The  unrealized  savings in interest  expense at
December 31, 1999 calculated  through May 31, 2000 was  approximately  $175,000.
Thereafter,  the economic  impact depends on whether or not LIBOR rates increase
significantly.

     Based on future market  prices at December 31, 1999,  the fair value of the
open contracts was $(536,000).  If future market rates were to increase 10% from
those in effect at December  31, 1999 the fair value of the  contracts  would be
$(984,000).  If future  market rates were to decline 10% from those in effect at
December 31, 1999 the fair value of the open contracts would be $(88,000).

     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.
<TABLE>
<CAPTION>
<S>                           <C>       <C>       <C>         <C>       <C>        <C>         <C>         <C>
   Expected Maturity Dates
        (in thousands)          2000      2001      2002       2003     2004-2006     2007       Total     Fair Value
                              --------  --------  ---------   -------   ---------  ----------  ---------   ----------
Variable Rate Debt:
Bank Debt with Recourse (a)...  $ -       $ -       $     -    $53,000   $   -       $      -    $ 53,000   $ 53,000
Bank Debt without Recourse (b)  $ -       $ -       $41,800    $     -   $   -       $      -    $ 41,800   $ 41,800
Fixed Rate Debt:
Senior Notes (c)..............  $ -       $ -       $     -    $     -   $   -       $140,000    $140,000   $119,000
Other (d).....................  $ 6       $ -       $     -    $     -   $   -       $      -    $      6   $      6
------------
</TABLE>

(a)    The average interest rate on the bank debt with recourse is 8.15%.
(b)    The average interest rate on the bank debt without recourse is 9.23%.
(c)    The interest rate on the senior notes is a fixed 10%.
(d)    The other notes are non-interest bearing.

                                       41
<PAGE>

Item 8. Consolidated Financial Statements and Unaudited Supplemental Information


                   Index to Consolidated Financial Statements
                                                                            Page

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

     Financial Statements:
             Consolidated Balance Sheets at December 31, 1999 and 1998.......F-2

             Consolidated Statements of Operations and Comprehensive Income
                 for the Years Ended December 31, 1999, 1998 and 1997........F-3

             Consolidated Statements of Stockholders' Equity for the
                      Years Ended December 31, 1999, 1998 and 1997...........F-4

             Consolidated Statements of Cash Flows for the Years
                      Ended December 31, 1999, 1998 and 1997.................F-5

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

     Supplemental Information (Unaudited)...................................F-31

                                       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, 1999, and 1998, 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, 1999. These financial  statements are the  responsibility  of
the Company's  management.  Our responsibility is to express an opinion on these
financial statements based on our audits.

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

     In our opinion,  the 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, 1999 and 1998, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 1999, in conformity with accounting  principles
generally accepted in the United States of America.

     As discussed in Note 18, the accompanying consolidated financial statements
have been restated.



Deloitte & Touche LLP


Dallas, Texas
March 28, 2000
(January 31, 2001 as to Note 18)


                                       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,
                                                                                     1999                1998
                                                                              ------------------------------------------
                                    ASSETS                                         (as restated, see Note 18)
Current Assets
     Cash and cash equivalents................................................  $     1,565             $    4,853
     Restricted cash .........................................................        2,145                    459
     Accounts receivable
          Trade, net of allowance of $166 for 1999 and 1998...................       10,203                  5,686
          Due from affiliates.................................................           48                     60
     Notes receivable from affiliate..........................................          398                    394
     Current portion of long-term notes receivable, net of allowance of $790
                      for 1999 and 1998.......................................           57                     57
     Prepaid and other........................................................        1,296                  1,577
                                                                              ------------------------------------------
           Total Current Assets...............................................       15,712                 13,086
                                                                              ------------------------------------------
Property, Plant, and Equipment
     Oil and gas properties, full cost method
           Unproved...........................................................        3,567                  1,655
           Proved.............................................................      349,510                296,545
     Pipelines................................................................       12,462                  9,131
     Other property...........................................................        1,964                  1,554
                                                                              ------------------------------------------
     Total Property, Plant and Equipment......................................      367,503                308,885
           Accumulated depreciation, depletion, amortization and impairment...     (102,308)               (80,449)
                                                                              ------------------------------------------
     Net Property, Plant and Equipment........................................      265,195                228,436
                                                                              ------------------------------------------
Other Assets
     Deposits and other assets................................................        5,663                  6,647
     Investment in unconsolidated affiliate...................................        4,163                  4,266
     Deferred tax asset ......................................................       13,289                 13,289
                                                                              ------------------------------------------
                                                                                $   304,022             $  265,724
     Total Assets.............................................................==========================================


                     LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
     Trade payables and accrued liabilities...................................  $    15,111             $   11,698
     Dividends payable........................................................          552                    219
     Suspended revenue payable................................................        1,357                    359
     Current maturities of long-term debt, with recourse......................            6                     13
     Notes payable............................................................            -                  2,000
                                                                              ------------------------------------------
           Total Current Liabilities..........................................       17,026                 14,289
                                                                              ------------------------------------------
Long-Term Liabilities
     Long-term debt, with recourse, less current maturities...................      193,000                205,007
     Long-term debt, non recourse, less current maturities....................       41,800                 26,000
     Production payment liability.............................................          460                    633
     Minority interest........................................................          184                     98
Commitments and Contingencies (Notes 10 and 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
             issued and outstanding, liquidation amount $10,000,000...........            1                      1
           50,000 designated as 1999 Series A 8% Convertible; 50,000 and none
             issued and outstanding, respectively,  liquidation
             amount $50,000,000...............................................            -                      -
     Common Stock - $.002 par value; 100,000,000 shares authorized,
           21,738,320 shares issued...........................................           43                     43
     Additional paid-in capital...............................................      121,845                 80,032
     Accumulated other comprehensive (loss)...................................       (1,713)                (1,308)
     Accumulated deficit......................................................      (62,560)               (55,734)
     Receivable from stockholder..............................................         (795)                  (672)
     Unearned common stock in ESOP at cost (537,515 and 250,423
        shares, respectively).................................................       (1,638)                  (756)
                                                                              ------------------------------------------
                                                                                     55,183                 21,606
     Treasury stock, at cost (1,512,719 and 1,054,507 shares of
       common stock, respectively)............................................       (3,631)                (1,909)
                                                                              ------------------------------------------

     Total Stockholders' Equity...............................................       51,552                 19,697
                                                                              ------------------------------------------

     Total Liabilities and Stockholders' Equity...............................  $   304,022             $  265,724
                                                                              ==========================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                       F-2
<PAGE>

                 Magnum Hunter Resources, Inc. and Subsidiaries
         Consolidated Statements of Operations and Comprehensive Income
             (in thousands of dollars, except for per share amounts)
<TABLE>
<CAPTION>
<S>                                                           <C>               <C>             <C>
                                                                             For the Year Ended
                                                                                December 31,
                                                              ----------------------------------------------------------
                                                                    1999            1998             1997
                                                              ----------------------------------------------------------
                                                                         (as restated, see Note 18)
Operating Revenues:
   Oil and gas sales..........................................  $       60,673   $       43,565  $       34,569
   Gas gathering, marketing and processing....................           8,185            6,954          10,297
   Oil field services and international sales.................             768              881           3,968
                                                              ----------------------------------------------------------
         Total Operating Revenues.............................          69,626           51,400          48,834
                                                              ----------------------------------------------------------

Operating Costs and Expenses:
   Oil and gas production lifting costs.......................          15,431           14,265           7,901
   Production taxes and other costs...........................           8,144            6,417           4,911
   Gas gathering, marketing and processing....................           5,870            5,750           7,909
   Oil field services and international sales.................             350              467           3,745
   Depreciation, depletion and amortization...................          22,072           21,757          12,363
   Provision for non-cash impairment of oil and gas reserves..               -           42,745               -
   (Gains) losses on sale of assets...........................            (272)              52            (386)
   General and administrative.................................           2,919            2,961           2,390
                                                              ----------------------------------------------------------
         Total Operating Costs and Expenses...................          54,514           94,414          38,833
                                                              ----------------------------------------------------------

Operating Profit (Loss).......................................          15,112          (43,014)         10,001

   Equity in earnings (loss) of affiliate.....................            (103)            (116)              6
   Other income...............................................             354              624             376
   Interest expense...........................................         (22,103)         (18,207)        (13,788)
                                                              ----------------------------------------------------------
Loss before income tax and minority interest..................          (6,740)         (60,713)         (3,405)
   Benefit for deferred income tax............................               -           13,670           1,296
                                                              ----------------------------------------------------------
Loss before minority interest.................................          (6,740)         (47,043)         (2,109)
   Minority interest in subsidiary (loss).....................             (86)             (37)            (19)
                                                              ----------------------------------------------------------
Loss Before Extraordinary Loss................................          (6,826)         (47,080)         (2,128)

Extraordinary Loss From Early Extinguishment of Debt, net of tax
benefit of $848...............................................               -                -          (1,384)
                                                              ----------------------------------------------------------

Net Loss......................................................          (6,826)         (47,080)         (3,512)
   Dividends Applicable to Preferred Stock....................          (4,509)            (875)           (875)
                                                              ----------------------------------------------------------

Loss Applicable to Common Shares..............................  $      (11,335)  $      (47,955) $       (4,387)
                                                              ==========================================================

Net Loss......................................................  $       (6,826)  $      (47,080) $       (3,512)
Other Comprehensive Loss, net of tax
   Sale of Investment Shares..................................               -                -             (51)
   Unrealized Loss on Investments.............................            (405)          (1,308)              -
                                                              ----------------------------------------------------------
Comprehensive Loss............................................  $       (7,231)  $      (48,388) $       (3,563)
                                                              ==========================================================

Loss per Common Share - Basic and Diluted
   Before Extraordinary Loss.................................. $         (0.57)  $        (2.27) $        (0.21)
   Extraordinary Loss.........................................               -                -           (0.09)
                                                              ----------------------------------------------------------
   Net Loss................................................... $         (0.57)  $        (2.27) $        (0.30)
                                                              ==========================================================
Common Shares Used in Per Share Calculation
   Basic and Diluted .........................................      19,743,738       21,151,442      14,535,805
                                                              ==========================================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                       F-3
<PAGE>
                 Magnum Hunter Resources, Inc. and Subsidiaries
                 Consolidated Statements of Stockholders' Equity
             For the Periods Ended December 31, 1999, 1998 and 1997
                           (as restated, see Note 18)
                             (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, 1996........................  1,080,000   $  1    14,252,822 $  29    (544,495)  $    (1)     $  40,216

  Common stock contributed to 401(k) plan...........                                            13,556         -             59
  Exercise of employees' common stock options.......                          89,242     -                                  269
  Issuance of common stock for services.............                                             1,000         -              4
  Issuance of warrants for services.................                                                                         34
  Issuance and costs from exercise of warrants......                         896,256     2     100,000         -          5,277
  Issuance of common stock to acquire oil and gas
        properties..................................                                            16,306         -             90
  Issuance of common stock, net of offering costs...                       6,500,000    12                               36,161
  Return of common stock held as collateral to
            treasury................................                                          (125,000)        -
  Costs associated with release of shares from ESOP.                                                                         32
  Costs associated with issuance of preferred stock.                                                                       (505)
  Dividends declared on preferred stock.............                                                                       (875)
  Net loss..........................................
  Sale of investment shares.........................
                                               -----------------------------------------------------------------------------------
Balance at December 31, 1997 .......................  1,080,000   $  1    21,738,320 $  43    (538,633)  $    (1)     $  80,763

  Common Stock contributed to 401(k) plan ..........                                            12,813         -             66
  Exercise of employees' common stock options ......                                            96,913         -             78
  Purchase of treasury stock .......................                                          (625,600)   (1,908)
  Dividends declared on preferred stock ............                                                                       (875)
  Net loss..........................................
  Unrealized (loss) on investment ..................
  Loan to stockholder...............................
  Unearned shares in ESOP...........................
                                               -----------------------------------------------------------------------------------
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 8% Convertible stock,
          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
                                               ===================================================================================
</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, 1996.......................     $     51          $  (5,142)    $     -            -          $     -
  Common stock contributed to 401(k) plan..........
  Exercise of employees' common stock options......
  Issuance of common stock for services............
  Issuance of warrants for services................
  Issuance and costs from exercise of warrants.....
  Issuance of common stock to acquire oil and gas..
        properties.................................
  Issuance of common stock, net of offering costs..
  Return of common stock held as collateral to
            treasury...............................
  Costs associated with release of shares from ESOP
  Costs associated with issuance of preferred stock
  Dividends declared on preferred stock............
  Net loss.........................................                          (3,512)
  Sale of investment shares........................          (51)
                                               ---------------------------------------------------------------------------------
Balance at December 31, 1997 ......................     $      -          $  (8,654)    $     -            -          $     -

  Common Stock contributed to 401(k) plan .........
  Exercise of employees' common stock options .....
  Purchase of treasury stock ......................
  Dividends declared on preferred stock ...........
  Net loss.........................................                         (47,080)
  Unrealized (loss) on investment .................       (1,308)
  Loan to stockholder..............................                                        (672)
  Unearned shares in ESOP..........................                                                 (250,423)            (756)
                                               ---------------------------------------------------------------------------------
Balance at December 31, 1998.......................     $ (1,308)         $ (55,734)    $  (672)    (250,423)         $  (756)
                                               ---------------------------------------------------------------------------------
  Issuance of 1999 Series A 8% Convertible stock,
          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)
                                               =================================================================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                       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,
                                                                                   ----------------------------------------
                                                                                       1999          1998         1997
                                                                                   ----------------------------------------
                                                                                          (as restated, see Note 18)
                                                                                         ----------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
   Net Loss........................................................................  $ (6,826)   $ (47,080)    $   (3,512)
   Adjustments to reconcile net loss to cash provided by operating activities
      Extraordinary loss...........................................................         -            -          1,384
      Depreciation, depletion and amortization.....................................    22,072       21,757         12,363
      Write-down of oil and gas properties ........................................         -       42,745              -
      Amortization of financing fees...............................................     2,091          793            508
      Increase in reserve for doubtful accounts....................................         -          591            322
      Deferred income taxes........................................................         -      (13,670)        (1,296)
      Equity in loss (income) of unconsolidated affiliate..........................       103          116             (6)
      Minority interest............................................................        86           37             19
      Cost of shares released from ESOP............................................       151          123              -
      (Gain) Loss on sale of assets................................................      (272)          52           (386)
      Other........................................................................        (2)         (83)           125
      Changes in certain assets and liabilities
         Accounts and notes receivable.............................................    (4,660)       6,859         (8,295)
         Other current assets......................................................       281         (278)        (1,247)
         Accounts payable and accrued liabilities..................................     4,411        1,726          5,673
                                                                                   ----------------------------------------

   Net Cash Provided By Operating Activities.......................................    17,435       13,688          5,652
                                                                                   ----------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Proceeds from sale of assets....................................................     1,499          359            593
   Additions to property and equipment.............................................   (59,968)     (70,187)      (160,059)
   Increase in deposits and other assets...........................................         -       (3,878)        (6,159)
   Loan made for promissory note receivable........................................         -         (332)          (237)
   Payments received on promissory note receivable ................................         -           28            256
   Other long-term investments.....................................................         -            -           (361)
   Investment in unconsolidated affiliate..........................................         -            -         (2,362)
                                                                                   ----------------------------------------
   Net Cash Used In Investing Activities...........................................   (58,469)     (74,010)      (168,329)
                                                                                   ----------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES:
   Proceeds from the issuance of long-term debt and production payment.............   106,800       80,000        352,500
   Fees paid related to financing activities.......................................    (1,603)           -         (1,800)
   Proceeds from short-term notes payable..........................................         -            -          2,699
   Payments of principal on long-term debt and production payment..................  (103,186)     (10,633)      (229,917)
   Payment of short-term notes payable ............................................    (2,000)      (2,699)             -
   Loan to stockholder.............................................................      (123)        (480)             -
   Loan to ESOP....................................................................      (759)        (879)             -
   Payment of fees on issuance of warrants and preferred stock.....................      (133)           -           (505)
   Proceeds from issuance of common and preferred stock, net of offering costs.....    46,334           78         41,721
   Purchase of treasury stock .....................................................    (1,722)      (1,908)             -
   Increase in restricted cash for payment of notes payable .......................    (1,686)        (459)             -
   Dividends paid..................................................................    (4,176)        (875)          (678)
                                                                                   ----------------------------------------
   Net Cash Provided By Financing Activities.......................................    37,746       62,145        164,020
                                                                                   ----------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...............................    (3,288)       1,823          1,343
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.....................................     4,853        3,030          1,687
                                                                                   ----------------------------------------

CASH AND CASH EQUIVALENTS AT END OF YEAR...........................................  $  1,565    $   4,853     $    3,030
                                                                                   ========================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                       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,  SPL Gas Marketing,  Inc. and its 51% owned
subsidiary,  Hunter Butcher International Limited Liability Company. The Company
consolidates  on a pro rata basis its 40% 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). Except for Bluebird, there
is no restriction on the ability of consolidated or unconsolidated  subsidiaries
to  transfer  funds to the  Company  in the form of cash  dividends,  loans,  or
advances.

     Bluebird was formed in December 1998, for the purpose of acquiring  certain
assets of  Spirit  76 (see  "Acquisitions").  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

     Restricted cash is the cash balance of Bluebird. Cash funds of Bluebird are
not  permitted  to be  commingled  with  funds of  Magnum  Hunter  or its  other
subsidiaries or affiliates.  Such funds cannot be dividended or loaned to Magnum
Hunter or its other  subsidiaries  or affiliates but must be used to satisfy the
cash  requirements  of Bluebird,  including  payment of  Bluebird's  outstanding
borrowings.

                                       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.

     At December 31, 1999 and 1998, the Company's  available for sale securities
were classified as non-current assets and included in deposits and other assets.
At December 31, 1999,  the securities had an amortized cost basis of $2,762,000,
gross unrealized  losses reported in accumulated other  comprehensive  income of
$2,514,000 ($1,713,000 net of income tax benefit) and had a fair market value of
$248,000.  At December 31, 1998,  the  securities had an amortized cost basis of
$2,762,000,  gross unrealized losses reported in accumulated other comprehensive
income of  $2,108,000  ($1,308,000  net of income  tax  benefit)  and had a fair
market value of $654,000.

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,  $600,000 and
$579,000 for the years ended December 31, 1999,  1998,  and 1997,  respectively.
The balance of capitalized  costs  included in  capitalized  costs for the years
ended December 31, 1999 and 1998 were $2,079,000 and  $1,479,000,  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, 1999 and the year in which they were  incurred
follows:
<TABLE>
<CAPTION>
<S>                                           <C>        <C>        <C>          <C>         <C>
                                                                 December 31, 1999
                                                                    Incurred In
                                            --------------------------------------------------------------
                                               Prior       1997         1998         1999       Total
                                               -----       ----         ----         ----       -----
Property Acquisition Costs..................     -          -         1,397,000   1,905,000    3,302,000
Exploration Costs...........................     -          -                 -     265,000      265,000
Development Costs...........................     -          -                 -           -            -
                                            --------------------------------------------------------------
     Total..................................     -          -         1,397,000   2,170,000    3,567,000
</TABLE>

     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, 1998, the Company wrote down the
costs of its oil and gas  properties  by  $42,745,000,  pursuant  to the ceiling
limitation,  using certain  improvements in pricing  experienced after year-end.
The effect of this  write-down is a non-cash  charge to earnings of  $42,745,000
and  an  increase  in  accumulated  depreciation,  depletion,  amortization  and
impairment for the same amount.  Without the benefit of  improvements in pricing
after  December 31,  1998,  the Company  would have  incurred an  impairment  of
$81,154,000. The Company experienced no impairment in 1999.

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

     Amortization  expense per thousand cubic feet  equivalent was $0.79,  $1.00
and $0.82 for the years ended December 31, 1999, 1998, and 1997, respectively.

Derivative Instruments

     The  Company  enters  into swaps,  futures,  options  and other  derivative
contracts  to hedge the impact of market  fluctuations  in gas and oil prices on
anticipated future oil and gas production.  The Company is exposed to price risk
related to its future oil and gas production  and enters into these  instruments
to manage this  exposure.  The  Company  hedges  only those  anticipated  future
transactions  for which the significant  characteristics  and expected terms are
identified  and are  probable of  occurring.  The  Company  defers the impact of
changes  in the market  value of the  contracts  that serve as hedges  until the
related  transaction is completed.  Any derivative  instruments that do not meet
this  criteria  are  marked-to-market.  The  Company  does  not  hold  or  issue
derivative financial instruments for trading purposes.

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

                                       F-8
<PAGE>

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

     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 oil and gas properties in
which the Company holds an ownership or other  economic  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.

Recently Issued Accounting Pronouncements

     SFAS 133, "Accounting for Derivative Instruments and Hedging Activities,"as
amended,  is effective  for fiscal  years  beginning  after June 15, 2000.  This
statement   establishes   accounting  and  reporting  standards  for  derivative
instruments and for hedging activities.  Management is currently  evaluating the
effect of adopting SFAS 133 on the Company's consolidated financial statements.

Income or Loss Per Common Share

     Income or loss per common share is based on the weighted  average number of
shares of common stock  outstanding.  Convertible  securities  and warrants were
anti-dilutive  due to net losses for December  31, 1999,  1998 and 1997 and were
not included in the calculation of income or loss per common share.

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

                                       F-9
<PAGE>

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

     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

     On January 28, 1998, the Company  commenced a cash purchase offer for Units
of TEL Offshore  Trust.  Previous to the offer,  the Company owned 161,500 Units
representing  3.4% of the  Units  outstanding.  As  amended,  the  offer  was to
purchase  between  forty  percent  (40%) and sixty  percent (60%) of the Trust's
outstanding  Units at $5.50 per Unit. On March 27, 1998,  the Company  purchased
1,745,353  Units  pursuant to the tender offer and,  together  with the Units it
previously  owned,  was the owner of  approximately  40% of the total  number of
Units outstanding for an aggregate of $10.4 million.

     On December 31, 1998,  the Company  (through its  wholly-owned  subsidiary,
Bluebird)  acquired from Spirit 76 natural gas reserves and associated assets in
producing  fields  located in Oklahoma  and Texas.  The net  purchase  price was
approximately  $25 million after certain  purchase price  adjustments  including
preferential rights exercised by third parties and other customary adjustments.

     On June 10, 1999, the Company and Bluebird  acquired from Vastar Resources,
Inc. oil and gas reserve  interests in 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 years ended  December 31, 1999,  1998 and 1997 as if the
acquisitions occurred as of the beginning of the respective years. The pro forma
information  includes  the  effects of  adjustments  for  increased  general and
administrative  expense,  interest expense,  depreciation,  depletion and income
taxes:
<TABLE>
<CAPTION>
<S>                                                     <C>             <C>              <C>
                                                             1999             1998             1997
                                                             ----             ----             ----
                                                                          (Unaudited)
                                                        ---------------------------------------------------------
Revenue................................................ $     73,104,000   $  77,181,000   $    76,547,000
Net Income (Loss) Applicable to Common Stock...........      (12,022,000)    (44,911,000)       (2,307,000)
Net Income (Loss) Per Common Share
   Basic............................................... $          (0.61)  $       (2.12)  $         (0.16)
  Diluted.............................................. $          (0.61)  $       (2.12)  $         (0.16)
</TABLE>
                                      F-10
<PAGE>

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

NOTE 3 -- NOTES RECEIVABLE

     On  September  30,  1997,  the Company sold its  investment  in  securities
available for sale to an unrelated entity for $483,500.  Prior to the sale, this
entity owed the  Company  $92,610.  The total  amount owed was secured by a note
payable to the Company with interest at 10% per annum and principal installments
of $50,000  per month  commencing  November  5, 1997,  with  final  payment  due
November 5, 1998.  The note is  collateralized  by shares of an  American  Stock
Exchange  listed company and by shares of the Company held by the entity.  After
making the  payment  due  November  5, 1997,  the entity was unable to  continue
making  further  payments.  The net carrying  value of the note, at December 31,
1997 was $350,016. During 1998, the Company made further advances of $290,525 to
this  entity,  and at December  31, 1998 an  additional  allowance  provision of
$590,525 was made. The carrying value of the note, net of allowance, at December
31, 1999 and 1998 was $50,016.

NOTE 4 -- RELATED PARTY TRANSACTIONS

     In conjunction  with the acquisition of Hunter,  the Company assumed a note
receivable  with a balance of $379,321 at  December  31, 1999 and 1998,  from an
owner in an affiliated limited liability company. The note provides for interest
at 10 percent and has a due date of December 31, 2000.

     At December  31, 1999 and 1998,  the  Company's  note  receivable  from the
Magnum Hunter  Employee Stock Ownership Plan (ESOP) was $1,638,000 and $756,000,
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, 1999 and 1998,
the  number  of  unearned   shares  in  the  ESOP  were   537,515  and  250,423,
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 loan to  stockholder  and has been shown as a  reduction  to  stockholders'
equity at December 31, 1999 and 1998.

     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  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.
Subsequent  to this date,  $225,000  was repaid on the loan  leaving a principal
balance of $146,860.  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.

                                      F-11
<PAGE>

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

NOTE 5 -- DEBT

     Notes Payable and Long-term debt at December 31, 1999 and 1998 consisted of
the following:
<TABLE>
<CAPTION>
<S>                                                                             <C>                 <C>
                                                                                      1999                 1998
                                                                                ------------------------------------------
Notes Payable:
Note payable, secured by stock in NGTS, LLC., due February 1, 1999,
interest payable at 9% quarterly beginning March 31, 1998..................     $          -            $    2,000,000
                                                                                ------------------------------------------
         Total Notes Payable...............................................     $          -            $    2,000,000
                                                                                ==========================================
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 8.15% at
  December 31, 1999) (a)...................................................     $  53,000,000           $   65,000,000
Note payable to bank collateralized by vehicle, payable in monthly installments
  of $1,031 including interest at 8.5% through
  February 1999............................................................                 -                    2,000
Other
Senior notes, unsecured, due June 1, 2007, interest at 10% payable
semi-annually on June 1 and December 1.....................................       140,000,000              140,000,000
Notes payable, non-interest bearing and uncollateralized, payable in
monthly installments of $1,000 through July 1, 2000........................             6,000                   18,000
                                                                                -------------------------------------------
         Total Long-Term Debt, with recourse...............................     $ 193,006,000           $  205,020,000
                 Less Current Portion......................................             6,000                   13,000
                                                                                -------------------------------------------
         Long-Term Debt, with recourse.....................................     $ 193,000,000           $  205,007,000
                                                                                ===========================================
Long-Term Debt, non recourse to the Company:
Banks
Note payable, collateralized by oil and gas property and 1,840,271 units of Tel
  Offshore Trust, due April 15, 1999, interest at Prime + 2%
  (Effective rate of 9.75% at December 31, 1998) (b) ......................     $           -           $   26,000,000
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 9.23% at December 31, 1999) (c)..................        41,800,000                        -
                                                                                -------------------------------------------
         Total Long-Term Debt, non recourse................................     $  41,800,000           $   26,000,000
                                                                                ===========================================
</TABLE>
                                      F-12
<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:

2000.............................................................$       6,000
2001.............................................................            -
2002.............................................................   41,800,000
2003.............................................................   53,000,000
2004 to 2006.....................................................            -
2007.............................................................  140,000,000
                                                                     ----------
         Total...................................................$ 234,806,000
                                                                     ----------

     (a) The  revolving  promissory  note to the  banks is a  borrowing  under a
$125,000,000  line  of  credit  on  which  there  existed  a  borrowing  base of
$60,000,000  at December 31, 1999.  The level of the borrowing base is dependent
on the valuation of the assets  pledged,  primarily oil and gas reserve  values.
During 1998,  the  termination  date was extended by one year to April 30, 2003.
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, 1999, the amounts borrowed
at these rates were:

LIBOR + 2.0% (total of 8.15%)...............................$    3,000,000
Base Rate (Prime) + .75% (total of 9.25%)...................             -
                                                            -----------------
       Total................................................$   53,000,000
                                                            =================

     (b) The note payable was incurred by Bluebird  Energy,  Inc., the Company's
wholly-owned   unrestricted  subsidiary,   in  connection  with  the  Spirit  76
acquisition.  The maturity date of this bridge loan  facility,  as amended,  was
April 15, 1999. The bridge loan is non-recourse to the Company. Bluebird secured
a commitment  for  permanent  financing  from a bank  providing  for a revolving
credit facility of $75 million. See item (c) below.

     (c) The  revolving  promissory  note to the  banks is a  borrowing  under a
$75,000,000  line  of  credit  on  which  there  existed  a  borrowing  base  of
$45,000,000  at December 31, 1999.  The level of the borrowing base is dependent
on the valuation of the assets pledged,  primarily oil and gas reserves, natural
gas processing  plants,  and units of Tel Offshore  Trust. On November 30, 1999,
the line of credit was amended to provide that the borrowing  base will decrease
to  $41,500,000  on March 31, 2000 and thereafter the borrowing base will reduce
by $2,000,000  quarterly  beginning June 30, 2000.  Effective March 27, 2000 the
banks  suspended this amendment and established a borrowing base of $43,500,000.
The banks agreed to  redetermine  the borrowing base and the need to reimplement
the  amendment  upon  the  earlier  of  May  15,  2000  or the  consummation  or
termination  of a proposed  sale of oil and gas  properties.  The line of credit
includes  covenants,  the most  restrictive of which  requires  maintenance of a
current  ratio and an interest  coverage  ratio,  and  restrictions  on upstream
loans,  dividends and commingling of funds.  The credit  agreement  provides for
both "LIBOR" and "Base Rate" (Prime) interest rate options. At December 31, 1999
the amounts borrowed at these rates were:

LIBOR + 2.75% (total of 9.23%)..............................$       41,800,000
Base Rate (Prime) + 1.25% (total of 9.75%)..................                 -
                                                            -------------------
       Total................................................$       41,800,000
                                                            -------------------

                                      F-13
<PAGE>

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

NOTE 6 -- PRODUCTION PAYMENT LIABILITY

     The Company has an obligation under a production  payment  conveyance.  The
conveyance  provides  for a  royalty  payment  equal to 50% of the  monthly  net
revenue proceeds received by the Company in certain oil and gas properties.  The
balance  owed  under  the  conveyance  bears  interest  at 15% per  annum and is
non-recourse to the Company.  The balance owed under this conveyance was $93,000
at December 31,  1998.  During  1999,  the Company  sold a number of  properties
covered by the  conveyances and used the proceeds to repay the total balance due
at that time.

     In November,  1996, the Company  entered into a second  production  payment
conveyance with the same party. 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  $460,000 and $540,000 at December 31, 1999 and 1998,
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>
                                                               1999              1998              1997
                                                        -------------------------------------------------------
Income tax expense (benefit) at statutory rates.........     $ (2,352,000)    $  (21,263,000)   $  (1,164,000)
State tax expense (benefit).............................         (193,000)        (1,747,000)        (134,000)
Change in valuation allowance...........................        2,315,000          8,370,000          290,000
Other...................................................          230,000                  -         (288,000)
                                                        -------------------------------------------------------
       Tax expense (benefit)............................     $          -     $  (14,640,000)   $  (1,296,000)
                                                        -------------------------------------------------------
</TABLE>
     The tax effects of significant  temporary differences and carryforwards are
as follows:

<TABLE>
<CAPTION>
<S>                                                                              <C>                     <C>
                                                                                                December 31,
                                                                                ---------------------------------------------
                                                                                        1999                    1998
                                                                                ---------------------------------------------
Property and equipment, including intangible drilling costs.....................$(12,325,000)              $            -
        Total deferred tax liability............................................ (12,325,000)                           -
                                                                                ---------------------------------------------
Allowance for doubtful accounts.................................................     425,000                      414,000
Reserves........................................................................      33,000                       33,000
Property and equipment, including intangible drilling costs.....................   1,984,000                    8,812,000
Depletion carryforwards.........................................................     196,000                      196,000
Operating loss and other carryforwards..........................................  33,951,000                   12,494,000
                                                                                ---------------------------------------------
        Total deferred tax assets...............................................  36,589,000                   21,949,000
                                                                                ---------------------------------------------
Valuation allowance............................................................. (10,975,000)                  (8,660,000)
                                                                                ---------------------------------------------
        Net Deferred Tax Asset (Liability)......................................$ 13,289,000               $   13,289,000
                                                                                =============================================
</TABLE>
     The  following  deferred tax benefits  were  excluded  from the benefit for
deferred   income  tax  in  the   Consolidated   Statement  of  Operations   and
Comprehensive  Income at December  31,  1998:  Equity in Earnings of  Affiliate,
$71,000; Minority Interest in Subsidiary Earnings,  $23,000; and Unrealized Loss
on Investments, $801,000.

                                      F-14
<PAGE>

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

     The Company and its subsidiaries  have net operating loss  carryforwards of
approximately  $57,119,000 that expire,  if unused,  in years 2001 through 2019.
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  in  connection  with the  Hunter  Resources
acquisition  on December 31, 1995.  A second  change is deemed to have  occurred
February 3, 1999 in  connection  with the purchase of  preferred  stock by ONEOK
Resources  Company.  Approximately  $1,992,000 of the net  operating  losses are
subject to  limitation  of $718,000  per year and  $31,113,000  are subject to a
limitation  of  $7,850,000  per year.  In  addition,  the Company has  depletion
carryforwards  of $517,000  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,  925,000  shares have
been designated as Series B Preferred Stock, 625,000 shares have been designated
as Series C  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,  7,184,000 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.

     Holders of the Series A Preferred  Stock are entitled to receive  dividends
only to the extent that funds are available from the West Dilley Prospect.  Such
dividends are limited to $7.50 per share, in the aggregate. Dividend payments to
Series A  preferred  shareholders  are based on fifty  percent  (50%) of the net
operating  revenue  received by the working  interest  owners of the West Dilley
Prospect.  Due to no  production  from the well  located on this  prospect,  the
Company shut this well in and therefore is no longer producing the property. The
Series A dividends are not  cumulative  except for unpaid  amounts due from this
calculation.  No  dividends  have been paid on the Series A preferred  stock and
there is no aggregate  annual  dividend  requirement  for the Series A preferred
stock.

     On  December  6, 1996,  the  Company  entered  into an  agreement  to issue
1,000,000  shares of new Series A  preferred  stock,  known as the 1996 Series A
Convertible  Preferred Stock, in a private  placement.  The shares have a stated
and  liquidation  value  of $10 per  share  and pay a  fixed  annual  cumulative
dividend  of eight and three  quarters  percent  (8.75%)  payable  quarterly  in
arrears  beginning  December 31, 1996. The shares are convertible into shares of
common  stock at a  conversion  price of $5.25 per share.  Beginning in December
1998,  the  Company  has an  option  to  exchange  the  stock  into  convertible
subordinated  debentures  of  equivalent  value.  The  purpose  of  the  private
placement was to fund the capital cost  necessary to drill  certain  development
projects  and to fund  the  capital  costs  of  several  West  Texas  waterflood
projects. Proceeds from the offering were initially used to reduce the Company's
existing  bank  indebtedness.   Certain  capital  expenditure  requirements  for
developmental drilling and waterflood projects were required under the agreement
whereby this stock was issued. The Company has met all of these requirements. On
December 23, 1996,  the 1996 Series A  Convertible  Preferred  Stock was issued,
resulting in net proceeds to the Company  after  offering  costs of  $9,280,000.
Dividends of $875,000,  $875,000 and $875,000  were  declared in 1997,  1998 and
1999, respectively.

     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 has a liquidation  value of $50 million and is convertible  into
the Company's Common Stock at $5.25 per share.  Dividends on the Preferred Stock
are payable in cash at the rate of

                                      F-15
<PAGE>

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

     8% per annum and are cumulative. The Company used the net proceeds from the
transaction, approximately $46.3 million, to repay senior bank debt.

     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.  The Series A preferred
shareholders  would  receive an amount equal to the lesser of the proceeds  from
the  liquidation of the West Dilley Prospect or the remaining  unpaid  dividend.
The 1996 Series A Convertible Preferred Stock would receive an amount of $10 per
share.  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.

Warrants

     A total of 1,687,500  warrants were issued in 1994 and were  exercisable at
$5.50 per share through November 12, 1998, of which 833,324 were exercised prior
to 1996.  The warrants were  redeemable by the Company at $0.02 per warrant upon
30 day notice at any time after  November 12, 1995 or earlier if the closing bid
price of the common stock equaled or exceeded $6.75 for five consecutive trading
days. The Company called the warrants for redemption on November 14, 1997, after
which  846,256  warrants  were  exercised  for net  proceeds  to the  Company of
$4,654,000. The remaining 7,920 warrants were redeemed.

     In January 1996, 60,000 warrants were issued at an exercise price of $3.375
per share with an  expiration  date of January  1999.  None of the warrants were
exercised in 1999. In connection  with the receipt of a production  payment,  in
October 1996 the Company issued 25,000  warrants with an exercise price of $5.18
and with an expiration  date of October 1999,  25,000  warrants with an exercise
price of $5.65 expiring  October 2000 and 25,000 warrants with an exercise price
of $6.13  expiring  October 2001.  None of the warrants were  exercised  through
1999.

     In January 1997,  21,000  warrants were issued at a exercise price of $4.50
per share  expiring  January 1, 2000 in connection  with services  rendered by a
non-employee.  The  warrants  were not  exercised in 1999 and expired in January
2000. During June and October,  1997,  100,000 warrants and 50,000 warrants were
exercised  at $4.125 per share and an average of $4.25 per share,  respectively,
resulting in net proceeds to the Company of $625,000. In December,  1997, 37,500
warrants at an exercise price of $3.00 per share expired.

     In July 1999,  the  Company  issued a total of  10,512,150  warrants on the
basis of one warrant for every three common  shares owned,  .63492  warrants for
every  share of 1996  Series A  Convertible  Preferred  Stock  owned and  63.492
warrants  for every  share of 1999  Series A 8%  Convertible  Stock  owned.  The
warrants have an exercise price of $6.50 per share,  expire on June 30, 2002 and
are  redeemable  by the  Company  at any time prior to  expiration  at $0.01 per
share.  The warrants are publicly  traded on the  American  Stock  Exchange.  At
December 31, 1999, the Company had a total of 10,583,149 warrants issued.

     Warrants issued to non-employees  are valued based on the fair market value
of equity instrument issued determined by using the Black-Scholes  pricing model
if a quoted market price is not  available.  The  measurement  date for warrants
issued in exchange for goods and services is  established  as the earlier of the
date at which a  performance  commitment  is  reached  or the date at which  the
counterparty's performance is complete.

                                      F-16
<PAGE>

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

Common Stock

     On November 21, 1997, the Company sold 6,500,000 newly issued shares of its
common stock in a public  offering,  receiving  cash  proceeds of  approximately
$36.2 million after fees and expenses.  Additionally,  in 1997, 13,556 shares of
the Company's common stock were contributed to the 401(k) plan, 89,242 shares of
common stock were issued upon exercise of employees' stock options, 1,000 shares
of common  stock,  valued at $4,000 were issued in exchange  for  services,  and
16,306 shares of common stock, valued at $90,000, were issued to acquire oil and
gas properties.

     On January 9, 1998, the Company  adopted a Shareholder  Rights Plan.  Under
the 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 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 September 8, 1998, the Company announced a stock repurchase  program for
up to one million  shares of the  Company's  common  stock in the open market or
privately  negotiated  transactions,  to be completed before April 30, 1999 at a
value not to exceed $4 million in the aggregate.  Through December 31, 1998, the
Company had  repurchased  625,600  shares for $1.9 million  under this  program.
Additionally  in  1998,  12,813  shares  of  the  Company's  common  stock  were
contributed  to the 401(k)  plan,  96,913  shares were  issued upon  exercise of
employee  stock  options,  291,300  shares were purchased by the ESOP and 40,877
shares were released by the ESOP to participants.

     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 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.

       Earnings Per Share

     The following table reconciles the numerators and denominators  used in the
computations  of both  basic  and  diluted  EPS as  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, 1999                 December 31, 1998                 December 31, 1997
                                ----------------------------------------------------------------------------------------------------
                                                            Per                              Per                               Per
                                   Loss         Shares     Share     Loss       Shares      Share      Loss       Shares      Share
                                (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount  (Numerator) (Denominator)  Amount
                                ----------------------------------------------------------------------------------------------------
Income (Loss) before
  extraordinary item.........    $(6,826,000)                      $(47,080,000)                    $(2,128,000)
  Less: Preferred Stock
          dividends..........     (4,509,000)                          (875,000)                       (875,000)
                               -----------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available to
  common stockholders..........  (11,335,000) 19,743,738   $ (0.57) (47,955,000) 21,151,442  $(2.27) (3,003,000) 14,535,805  $(0.21)
Effect of dilutive securities
   Warrants....................                        -                      -           -                   -           -
   Options.....................                        -                      -           -                   -           -
   Convertible preferred stock.                        -                      -           -                   -           -
Diluted EPS
Income (Loss) available to
  common stockholders and      -----------------------------------------------------------------------------------------------------
  assumed conversions.......... $(11,335,000) 19,743,738  $ (0.57)  (47,955,000) 21,151,442  $(2.27) (3,003,000) 14,535,805  $(0.21)
                               =====================================================================================================
</TABLE>

                                      F-17
<PAGE>

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

     The warrants, options, and convertible preferred stock were not included in
the  computation of diluted  earnings per share in 1999, 1998 and 1997 since the
Company incurred a loss before  extraordinary  items for the year and any effect
would  be  anti-dilutive.  At  December  31,  1998 and  1997,  the  Company  had
outstanding  141,000  warrants at a weighted average exercise price of $4.75 per
share,  2,538,000  options at a  weighted  average  exercise  price of $5.00 per
share,  and 1,000,000  shares of preferred stock  convertible to common stock at
$5.25 per share.  At December 31, 1999, the Company had  outstanding  10,583,149
warrants  at a weighted  average  exercise  price of $6.49 per share,  3,788,092
options at a weighted  average  exercise  price of $3.55 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.

NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION

     During 1999,  the Company  contributed  41,115 shares valued at $123,000 to
the Company's  401(k) plan. The Company wrote down the carrying costs of certain
investments by $617,000. Interest paid in 1999 was $19,773,000.

     During 1998, the Company contributed 12,813 shares valued at $66,000 to the
Company's  401(k) plan. The Company  acquired  certain oil and gas properties in
exchange  for notes and accounts  receivable  totaling  $1,903,000.  The Company
wrote-down the carrying costs of certain  investments by $2,304,000  ($1,429,000
after income tax benefit). Interest paid in 1998 was $17,089,187.

     During 1997, the Company purchased oil and gas properties by issuing 16,306
shares  valued at  $90,000.  The Company  contributed  13,556  shares  valued at
$59,000 to the Company's  401(k) plan. The Company issued 1,000 shares valued at
$4,000 in exchange for services rendered. Interest paid in 1997 was $12,001,557.

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 and
office  equipment.  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 2003. 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:
2000...........................................................   $      717,432
2001...........................................................          710,008
2002...........................................................          695,666
2003...........................................................          627,544
2004...........................................................          608,036
Thereafter.....................................................          557,366
                                                                 ---------------
 Total Minimum Payments Required...............................    $   3,916,052

     Rental  expense was $367,000,  $327,934,  and $218,951 for 1999,  1998, and
1997, respectively.

     In December,  1997,  the Company  amended its Revolving Loan Agreement with
certain  banks  to  permit  guarantees  of  NGTS,  LLC's  debt,  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, 1999 and 1998, there was no NGTS, LLC debt outstanding.

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.  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, 1999 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, 1998,  the Company had provided a
$790,000 reserve for the carrying value of a note receivable. After establishing
this  reserve,  management  believes  those market values  approximate  carrying
values at December 31, 1999 and 1998.  The market  values of equity  investments
are based upon quoted prices (see Note 1). At December 31, 1999,  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 $119,000,000.

                                      F-19
<PAGE>

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

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, 1999, the Company had the following open contracts:
<TABLE>
<CAPTION>
<S>     <C>                      <C>                       <C>                      <C>
                Type                 Volume/Month                Duration                Avg. Price
        --------------------    ----------------------    -----------------------    -------------------
Oil
-------
        Swap................            30,000 Bbl            Jan 00 - Dec 00                $17.60
        Collar..............            30,000 Bbl            Jan 00 - Mar 00        Floor - $18.00
                                                                                     Cap -   $22.65
        Collar..............            30,000 Bbl            Jan 00 - Mar 00        Floor - $18.00
                                                                                     Cap -   $23.87
        Collar..............            30,000 Bbl            Apr 00 - Jun 00        Floor - $18.00
                                                                                     Cap -   $24.50
        Collar..............            30,000 Bbl            Apr 00 - Jun 00        Floor - $18.00
                                                                                     Cap -   $26.00
        Collar..............            30,000 Bbl            Jul 00 - Sep 00        Floor - $18.00
                                                                                     Cap -   $24.00
        Collar..............            30,000 Bbl            Jul 00 - Sep 00        Floor - $18.00
                                                                                     Cap -   $24.65
Gas
-------
        Collar..............           300,000 MMBtu          Jan 00 - Mar 00        Floor - $  2.00
                                                                                     Cap -   $  2.32
        Collar .............           300,000 MMBtu          Apr 00 - Oct 00        Floor - $  1.80
                                                                                     Cap -   $  2.25
        Swap................           100,000 MMBtu          Jan 00 - Mar 00                $  2.86
        Collar .............           100,000 MMBtu          Jan 00 - Mar 00        Floor - $  2.62
                                                                                     Cap -   $  3.82
        Purchased Call......           100,000 MMBtu          Feb 00 - Mar 00                $  2.86
</TABLE>

     Net gains and (losses)  related to  derivative  transactions  for the years
ended  December  31,  1999,  1998  and  1997  were   $(3,232,000),   $2,739,000,
$(1,537,000),  respectively.  At December 31,  1999,  the  unrealized  loss from
derivative transactions was $(3,812,000).

                                      F-20
<PAGE>

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

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 next twelve months.
<TABLE>
<CAPTION>
<S>                             <C>                 <C>                   <C>                  <C>
            Type                 Notional Amount      Termination Date         Pay Rate            Receive Rate
-----------------------------  -------------------   ------------------   ------------------   --------------------
Pay Variable/Receive Fixed         $50,000,000            06/01/02             LIBOR +              10% fixed
                                                                             3.34%through
                                                                               05/31/00
                                                                            LIBOR + 3.69%
                                                                           from 06/01/00 to
                                                                               06/01/02
Pay Fixed/Receive Variable         $50,000,000            06/01/00           9.16% fixed          LIBOR + 3.34%
</TABLE>

     The pay  variable/receive  fixed  swap has an early  termination  provision
granting the  counterparty  the right to terminate  the swap on June 1, 2000, in
exchange for a fee payment to the Company of $125,000.  As a result of these two
swaps, the Company saved  approximately  $209,000 in interest expense during the
year ended  December 31, 1999.  The  unrealized  savings in interest  expense at
December 31, 1999 calculated  through May 31, 2000 was  approximately  $175,000.
Thereafter,  the economic  impact depends on whether or not LIBOR rates increase
significantly.

NOTE 14 -- STOCK COMPENSATION PLANS

     The Company adopted in 1996 two stock  compensation plans for its employees
and directors,  (i) the Magnum Hunter  Resources  Employee Stock Ownership Plan,
(the "ESOP"),  and (ii) the Magnum Hunter  Resources,  Inc. 1996 Incentive Stock
Option Plan (the "Option Plan"). In addition, the Company has made non-incentive
stock option grants in 1999, 1998 and 1997.

ESOP

     The Company  established an ESOP and a related trust in 1996 as a long-term
benefit for its employees.  Under terms of the ESOP,  eligible  participants may
elect 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  ESOP 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 1 year of service are eligible
to  participate  in the plan.  Shares  purchased by the ESOP with loans from the
Company are released to participants as Company  contributions  are made and the
related loans are repaid. The Company has no repurchase obligations with respect
to released shares.

     On October 11, 1996,  the ESOP  purchased  22,556  shares of the  Company's
Common Stock for $3.75 per share from a third party.  At December 31, 1997,  the
Company  contributed  funds to pay off the related  third party loan and accrued
interest to the ESOP. The ESOP then retired the bank debt and 22,556 shares were
allocated among the plan participants.

     During  1998,  the Company  loaned the ESOP  $878,997  to purchase  291,300
shares of the  Company's  Common Stock on the open market at an average price of
$3.02 per share. At December 31, 1998, the Company  contributed  $123,345 to the
ESOP as a discretionary  contribution  under the plan. The ESOP then repaid that
portion  of its  outstanding  loan  from the  Company  and  40,877  shares  were
allocated among the plan participants.

                                      F-21
<PAGE>

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

     During 1999,  the Company  loaned the ESOP  $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
ESOP as a discretionary  contribution  under the plan. The ESOP then repaid that
portion  of its  outstanding  loan  from the  Company  and  51,808  shares  were
allocated  among the plan  participants.  The loan is  interest  free and is due
December 31, 2004.  The loan was secured by 537,515 shares and 250,423 shares of
the Company's common stock at December 31, 1999 and 1998, 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 ESOP are excluded from
the calculation of earnings per share.

     The ESOP shares are summarized as follows:


                                                December 31,
                                        1999                     1998
                             -------------------------- -----------------------
Allocated shares                         115,241                  63,433
Unreleased shares                        537,515                 250,423
                                         -------                 -------
  Total ESOP shares                      652,756                 313,856
Fair value of unreleased shares       $1,545,356           $     751,269

     The ESOP expense for the years ending  December 31, 1999, 1998 and 1997 was
$148,948, $122,631 and $117,009, 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 Option Plan coved  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 5 years. All options granted in
1996 were fully vested and exercisable when granted. The exercise price was fair
market value at the date of grant.

  Non-Incentive Stock Option Grants

     During  1997,  the  Board  granted   1,440,000  options  to  employees  and
directors,  1,240,000  of which were fully vested and 200,000 of which vest over
five years.  The term of the individual  option grants were for five years.  The
exercise price was fair market value on the date of grant.

     During  1998,  the Board  granted  220,000 new options to  employees  at an
average  price of $5.89.  All options were fully vested on the date of grant and
were for a term of five years. On December 14, 1998 the Board repriced 1,590,000
options to employees and  directors  from an average of $5.96 per share to $3.75
per share, the fair market value on that date.

                                      F-22
<PAGE>

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

     During 1999,  the Board  granted  1,306,650  new options to employees at an
average price of $2.69, of which 108,000 vested immediately and 1,198,650 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  employees was modified to
extend the expiration date from January 5, 2000 to January 5, 2002.

     The following is a summary of stock option activity under the Option Plans:
<TABLE>
<CAPTION>
<S>                                 <C>             <C>           <C>         <C>         <C>           <C>
                                              1999                       1998                      1997
                                   ----------------------------------------------------------------------------------
                                                        Weighted                Weighted                 Weighted
                                                        Average                 Average                  Average
                                                        Exercise                Exercise                 Exercise
                                        Shares           Price     Shares        Price       Shares       Price
                                   ----------------------------------------------------------------------------------
Outstanding - Beginning of Year....    2,661,587    $     3.90    2,538,500   $     5.00    1,187,742    $     3.72
Granted............................    1,306,650          2.69      220,000         5.89    1,440,000          5.93
Exercised..........................     (102,145)          .73      (96,913)         .81      (89,242)         3.01
Canceled...........................            -             -            -            -            -             -
Repriced - previous................            -             -   (1,590,000)        5.96            -             -
Repriced - new.....................            -             -    1,590,000         3.75            -             -
                                   ----------------------------------------------------------------------------------
Outstanding - End of Year..........    3,866,092    $     3.57    2,661,587   $     3.90    2,538,500    $     5.00
                                       =========                  =========                 =========
Exercisable - End of Year..........    2,787,172                  2,501,587                 2,338,500
                                       =========                  =========                 =========
</TABLE>
     The  following is a summary of stock  options  outstanding  at December 31,
1999:
<TABLE>
<CAPTION>
<S>                                      <C>                 <C>                    <C>
                                                                  Weighted
                                                                   Average
                                           Number of              Remaining
                                            Options           Contractual Life             Number of
Exercise Price                            Outstanding              (Years)            Exercisable Options
                                      --------------------------------------------------------------------
$     1.65...........................               18,000      less than .1                 18,000
      2.50...........................            1,198,650           5.0                    239,730
      2.875..........................                3,000           4.0                      3,000
      3.75...........................            1,620,000           3.0                  1,500,000
      4.375..........................               25,000           2.0                     25,000
      4.50...........................              881,442           2.0                    881,442
      5.25...........................              110,000           4.1                    110,000
      5.375..........................               10,000           2.3                     10,000
                                      -------------------------                 --------------------------
                                                 3,866,092                                2,787,172
                                      =========================                 ==========================
</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-23
<PAGE>

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

     On a pro forma  basis,  the  effect  of stock  based  compensation  had the
Company adopted Statement No. 123 is as follows:
<TABLE>
<CAPTION>
<S>                                                         <C>                    <C>                <C>
                                                                    1999               1998              1997
                                                             ----------------------------------------------------------
Net Income (Loss) Applicable to Common Stock:
  As reported..............................................       $(11,335,000)      $(47,955,000)     $(4,387,000)
  Pro Forma................................................        (13,313,000)       (49,160,000)      (6,593,000)
Basic Earnings (Loss) per Share:
  As reported, after extraordinary loss....................       $      (0.57)      $      (2.27)     $     (0.30)

  Pro Forma................................................              (0.67)             (2.32)           (0.45)
Diluted Earnings (Loss) per Share:
  As reported, after extraordinary loss....................       $      (0.57)      $      (2.27)     $     (0.30)

  Pro Forma................................................              (0.67)             (2.32)           (0.45)
</TABLE>

     The  weighted  average  grant date fair value of new  options  granted  was
$1,778,000  during 1999.  The weighted  average grant date fair value of options
whose  expiration date was extended in 1999 was $200,000.  Fair value of options
and warrants was  calculated by using the  Black-Scholes  options  pricing model
using the following  weighted average  assumptions for 1999 activity:  risk free
interest  rate of  5.875% on new  options,  expected  life of five  years on new
options and two years on options whose term was extended, expected volatility of
52% on new options and 60% on options  whose term was  extended  and no dividend
yield.

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

     Mr. Gary C. Evans,  Mr. Matthew C. Lutz, Mr. Richard R. Frazier,  Mr. Chris
Tong and Mr. R. Douglas Cronk each have employment  agreements with the Company.
Mr. Evans' agreement  terminates  January 1, 2005 and continues  thereafter on a
year to year basis and provides for a salary of $300,000 per annum.  Mr.  Lutz's
agreement  terminates January 1, 2005 and continues thereafter on a year to year
basis and provides for a salary of $175,000 per annum. Mr.  Frazier's  agreement
terminates January 1, 2005 and continues  thereafter on a year to year basis and
provides for a salary of $175,000 per annum.  Mr.  Tong's  agreement  terminates
January 1, 2003 and  continues  thereafter  on a year to year basis and provides
for a salary of $160,000 per annum. Mr. Cronk's agreement  terminates January 1,
2003 and continues  thereafter on a year to year basis and provides for a salary
of $122,500 per annum.  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, Mr.
Lutz 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 and Mr. Cronk, 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.

                                      F-24
<PAGE>

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

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
Footnote 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,  1999  follows (in
thousands):
<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>

                                      F-25
<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
                  1998:                    Production     Processing      Services    All Other  Elimination  Consolidated
                                         ----------------------------------------------------------------------------------
Revenue from external customers..........  $   43,565   $    6,954        $  881      $     -      $      -     $  51,400
Intersegment revenues....................           -       12,569         4,561            -       (17,130)            -
Depreciation, depletion, amortization and
impairment...............................      63,681          652           148           21                      64,502

Segment profit (loss)....................     (42,953)         521         1,465       (2,047)                    (43,014)
Equity earnings (losses) of affiliates...                                                (116)                       (116)
Interest expense.........................                                             (18,207)                    (18,207)
Other income.............................                                                 624                         624
                                                                                                                -----------
Loss before income taxes.................                                                                       $ (60,713)
Deferred income tax benefit..............                                              13,670                      13,670
Minority interest........................                                                 (37)                        (37)
                                                                                                                -----------
Net loss.................................                                                                       $ (47,080)
                                                                                                                ===========
Capital expenditures (net of asset sales)   $  70,294   $      (35)       $  740      $    38                   $  71,037
</TABLE>

<TABLE>
<CAPTION>
<S>                                         <C>            <C>              <C>         <C>         <C>           <C>
                                                           Gas Gathering,
                                            Exploration &   Marketing &     Oil Field
                  1997:                     Production      Processing      Services    All Other   Elimination   Consolidated
                                          --------------------------------------------------------------------------------------
Revenue from external customers...........  $    34,569      $    10,297    $   570     $   3,398    $      -     $      48,834
Intersegment revenues.....................            -           13,683      3,257             -     (16,940)                -
Depreciation, depletion, amortization and
impairment................................       11,578              661        104            20                        12,363

Segment profit (loss).....................        8,280            1,713      1,230        (1,222)                       10,001
Equity earnings (losses) of affiliates....                                                      6                             6
Interest expense..........................                                                (13,788)                      (13,788)
Other income..............................                                                    376                           376
                                                                                                                ----------------
Loss before income taxes..................                                                                        $      (3,405)
Deferred income tax benefit...............                                                  1,296                         1,296
Minority interest.........................                                                    (19)                          (19)
                                                                                                                ----------------
Net loss before extraordinary item........                                                                        $      (2,128)
                                                                                                                ================
Capital expenditures (net of asset sales).  $   156,872      $     2,064    $   395     $       -                 $  159,331
</TABLE>

                                      F-26
<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
                                           Production     Processing      Services    All Other  Elimination   Consolidated
                                          ------------------------------------------------------------------------------------
As of December 31, 1999...................
Segment assets............................ $     278,652  $     12,416    $  4,252     $  8,702                $    304,022
Equity subsidiary investments.............                                                4,163                       4,163

As of December 31, 1998...................
Segment assets............................       233,824        13,729       7,230       10,941                     265,724
Equity subsidiary investments.............                                                4,266                       4,266

As of December 31, 1997...................
Segment assets............................       221,272        14,275       5,092       10,430                     251,069
Equity subsidiary investments.............                                                4,372                       4,372
</TABLE>

NOTE 17 -- CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

     The   Company   and  its   subsidiaries,   except   Bluebird   and  certain
inconsequential  subsidiaries  (Inesco  Corporation,  SPL Gas  Marketing,  Inc.,
Midland  Hunter  Petroleum   Limited   Liability   Company  and  Hunter  Butcher
International 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  financial
information for Magnum Hunter  Resources,  Inc. and  subsidiaries as of December
31, 1999 and 1998 and for the year ended December 31, 1999 is as follows:

                 Magnum Hunter Resources, Inc. and Subsidiaries
                     Condensed Consolidating Balance Sheets
<TABLE>
<CAPTION>
<S>                                         <C>                  <C>                <C>             <C>
                                December 31, 1999
------------------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                          And Guarantor Subs    (Non Guarantor)    Eliminations     Consolidated
------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current assets..............................     $    14,572       $    3,741           $  (2,601)      $   15,712
Property and equipment
  (using full cost accounting)..............         211,159           54,036                              265,195
Investment in subsidiaries
 (equity method)............................          13,302                -             (13,302)               -
Other assets................................          22,605              510                               23,115
   Total assets.............................     $   261,638       $   58,287           $ (15,903)      $  304,022
                                                ==========================================================================

LIABILITIES AND SHAREHOLDERS'
EQUITY
Current liabilities.........................     $    16,442       $    3,185           $  (2,601)      $  17,026
Long-term liabilities.......................         193,644           41,800                             235,444
Shareholders' equity........................          51,552           13,302             (13,302)         51,552
   Total liabilities and shareholders' equity    $   261,638       $   58,287           $ (15,903)      $ 304,022
                                                ==========================================================================
</TABLE>

                                      F-27
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
<TABLE>
<CAPTION>
<S>                                           <C>                 <C>                 <C>            <C>


                                December 31, 1998
-----------------------------------------------------------------------------------------------------------------------
                                                 Magnum Hunter          Bluebird                       Magnum Hunter
                                                Resources, Inc.       Energy, Inc.                    Resources, Inc.
Amounts in Thousands                          And Guarantor Subs     (Non Guarantor)   Eliminations     Consolidated
-----------------------------------------------------------------------------------------------------------------------
ASSETS
Current assets..............................  $     11,707              $  1,379        $               $    13,086
Property and equipment
  (using full cost accounting)..............       203,766                24,670                            228,436
Investment in subsidiaries
 (equity method)............................             -                     -                                  -
Other assets................................        24,202                     -                             24,202
                                            ---------------------------------------------------------------------------
   Total assets.............................  $    239,675              $ 26,049        $     -         $   265,724
                                            ===========================================================================

LIABILITIES AND SHAREHOLDERS'
EQUITY
Current liabilities.........................  $     14,240              $     49        $               $    14,289
Long-term liabilities.......................       205,738                26,000                            231,738
Shareholders' equity........................        19,697                     -                             19,697
                                            ---------------------------------------------------------------------------
   Total liabilities and shareholders' equity $    239,675              $ 26,049        $     -         $   265,724
                                            ===========================================================================
</TABLE>
                 Magnum Hunter Resources, Inc. and Subsidiaries
                Condensed Consolidating Statement of Operations
<TABLE>
<CAPTION>
<S>                                        <C>                    <C>                <C>            <C>
                                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>
                 Magnum Hunter Resources, Inc. and Subsidiaries
                Condensed Consolidating Statement of Cash Flows
<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
------------------------------------------------------------------------------------------------------------------------
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 provided 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>
                                      F-28
<PAGE>

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

NOTE 18  - RESTATEMENT

     Subsequent to the issuance of the consolidated financial statements for the
year ended  December 31, 1999,  the  Company's  management  determined  that the
Company's  loans to a  shareholder  and  transactions  involving  the  Company's
Employee  Stock  Ownership  Plan  ("ESOP")  should have been  accounted for as a
reduction  in  Stockholders'  Equity  rather than as assets.  In  addition,  the
Company determined that common shares acquired by the ESOP but not yet allocated
to participants should not have been considered outstanding in the determination
of the number of shares included in the calculation of loss per common share. As
a result, the accompanying  consolidated financial statements have been restated
from the amounts previously  reported.  A summary of the significant  effects of
the restatement follows:
<TABLE>
<CAPTION>
<S>                                         <C>              <C>                <C>               <C>
                                                As of December 31, 1999              As of December 31, 1998
                                         --------------------------------------------------------------------------
                                            As Previously           As           As Previously           As
                                               Reported          Restated          Reported           Restated
                                         --------------------------------------------------------------------------
                                                                      ($ in thousands)
Accounts receivable, due from
   affiliates............................     $            48  $            48     $          310   $            60
Note receivable from affiliate...........                 902              398                747               394
Total Current Assets.....................              16,216           15,712             13,689            13,086
Deposits and other assets................               5,698            5,663              6,644             6,647
Deferred tax asset.......................              13,351           13,289             13,351            13,289
Long-term notes receivable,
   net of imputed interest...............               1,487                -                756                 -
Total Assets ............................             306,110          304,022            267,142           265,724
Trade payables and accrued liabilities...              15,111           15,111             11,821            11,698
Total Current Liabilities................              17,026           17,026             14,412            14,289
Additional paid-in capital...............             121,815          121,845             80,000            80,032
Accumulated other comprehensive  loss....              (2,046)          (1,713)            (1,429)           (1,308)
Accumulated deficit......................             (62,542)         (62,560)           (55,714)          (55,734)
Receivable from stockholder..............                   -             (795)                 -              (672)
Unearned common stock in ESOP, at cost
   (537,515 and 250,423 shares,
   respectively).........................                   -           (1,638)                 -              (756)
Total Stockholders' Equity...............              53,640           51,552             20,992            19,697
Total Liabilities and Stockholders' Equity            306,110          304,022            267,142           265,724
</TABLE>

                     [Rest of page intentionally left blank]

                                      F-29
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
<TABLE>
<CAPTION>
<S>                            <C>            <C>            <C>             <C>         <C>           <C>
                                                                For the Year Ended
                               ------------------------------------------------------------------------------------
                                    December 31, 1999            December 31, 1998           December 31, 1997
                               As Previously      As        As Previously       As      As Previously      As
                                 Reported      Restated       Reported       Restated     Reported      Restated
                               ------------------------------------------------------------------------------------
                                                                 ($ in thousands)
General and administrative
   expense.....................  $     2,921    $     2,919    $     2,961   $     2,961  $     2,358   $     2,390
Total Operating Costs and
   Expenses....................       54,516         54,514         94,414        94,414       38,801        38,833
Operating Profit (Loss)........       15,110         15,112        (43,014)      (43,014)      10,033        10,001
Loss before income tax and
   minority interest...........       (6,742)        (6,740)       (60,713)      (60,713)      (3,373)       (3,405)
Deferred income tax benefit....            -              -         13,670        13,670        1,284         1,296
Loss before minority interest..       (6,742)        (6,740)       (47,043)      (47,043)      (2,089)       (2,109)
Loss before extraordinary loss.       (6,828)        (6,826)       (47,080)      (47,080)      (2,108)       (2,128)
Net Loss.......................       (6,828)        (6,826)       (47,080)      (47,080)      (3,492)       (3,512)
Other Comprehensive Loss, net of
   tax, Unrealized Loss on
   Investments.................         (617)          (405)        (1,429)       (1,308)           -             -
Comprehensive Loss.............       (7,445)        (7,231)       (48,509)      (48,388)      (3,543)       (3,563)
</TABLE>

     Net loss per common share and the reported  weighted  average common shares
outstanding changed as follows:
<TABLE>
<CAPTION>
<S>                         <C>                <C>          <C>             <C>        <C>               <C>
                                As of December 31, 1999      As of December 31, 1998     As of December 31, 1997
                             ----------------------------------------------------------------------------------------
                              As Previously        As       As Previously      As      As Previously       As
                                 Reported       Restated      Reported      Restated      Reported      Restated
                             ----------------------------------------------------------------------------------------
                                                 (in thousands of $, except per share amounts)
Loss Applicable to
  Common Shares..............   $   (11,337)    $  (11,335)    $   (47,955)  $  (47,955)   $    (4,367)   $   (4,387)
Loss Per Common Share-
   Basic and Diluted.........         (0.56)         (0.57)          (2.26)       (2.27)         (0.30)        (0.30)
Common Shares Used in Per
  Share Calculation-Basic and
  Diluted....................    20,172,062     19,743,738      21,189,516   21,151,442     14,535,805    14,535,805
</TABLE>

                     [Rest of page intentionally left blank]

                                      F-30
<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,  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 reserves were  primarily due to
changes in commodity  prices at December 31, 1997,  1998 and 1999 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:
<TABLE>
<CAPTION>
<S>                                                               <C>                <C>
                                                                                          Gas
                                                                        Oil            (Thousand
                                                                     (Barrels)        Cubic Feet)
                                                                 ---------------------------------------
December 31, 1997
  Proved Reserves................................................     20,946,415       207,775,770
  Proved developed reserves......................................     12,036,234       154,964,396
December 31, 1998
  Proved Reserves................................................     17,348,641       219,059,674
  Proved developed reserves......................................      9,474,591       174,987,374
December 31, 1999
  Proved Reserves................................................     25,533,750       229,999,526
  Proved developed reserves......................................     16,299,585       184,954,732
</TABLE>

                     [Rest of page intentionally left blank]

                                      F-31
<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, 1998
and 1997 were as follows:
<TABLE>
<CAPTION>
<S>                                                                  <C>            <C>
                                                                                          Gas
                                                                           Oil         (Thousand
                                                                        (Barrels)     Cubic Feet)
                                                                     -----------------------------------
Reserves at December 31, 1996........................................      5,338,255      90,565,997
Purchase of minerals-in-place........................................     15,282,168     108,620,963
Sale of minerals-in-place............................................        (24,882)        (22,517)
Extensions and discoveries...........................................          1,777          18,000
Production...........................................................       (737,289)     (9,613,623)
Revisions of estimates...............................................      1,086,386      18,206,950
                                                                     -----------------------------------
Reserves at December 31, 1997........................................     20,946,415     207,775,770
Purchase of minerals-in-place........................................      1,362,404      39,535,361
Sale of minerals-in-place............................................         (4,314)              -
Extensions and discoveries...........................................        279,248      12,091,186
Production...........................................................     (1,140,762)    (14,119,330)
Revisions of estimates...............................................     (4,094,350)    (26,223,313)
                                                                     -----------------------------------
Reserves at December 31, 1998........................................     17,348,641     219,059,674
Purchase of minerals-in-place........................................      3,122,738      15,989,997
Sale of minerals-in-place............................................        (21,273)       (196,682)
Extensions and discoveries...........................................        163,865       6,067,527
Production...........................................................     (1,310,405)    (19,041,012)
Revisions of estimates...............................................      6,230,184       8,120,022
                                                                     -----------------------------------
Reserves at December 31, 1999........................................     25,533,750     229,999,526
                                                                     -----------------------------------
</TABLE>
     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,  1999,  1998 and 1997 were as
follows:
<TABLE>
<CAPTION>
<S>                                                            <C>               <C>              <C>
                                                                     1999             1998              1997
                                                               ----------------------------------------------------
Unproved oil and gas properties................................ $     3,566,902   $     1,654,986  $        516,560
Proved properties..............................................     349,510,185       296,545,064       227,389,446
                                                               ----------------------------------------------------
Gross Capitalized Costs........................................     353,077,087       298,200,050       227,906,006
Accumulated depreciation, depletion, amortization and impairment   (100,370,224)      (79,193,796)      (16,091,001)
                                                               ----------------------------------------------------
          Net Capitalized Costs................................   $ 252,706,863     $ 219,006,254     $ 211,815,005
                                                               ====================================================
</TABLE>

     Costs incurred in oil and gas producing  activities,  both  capitalized and
expensed,  during  the years  ended  December  31,  1999,  1998 and 1997 were as
follows:
<TABLE>
<CAPTION>
<S>                                                                 <C>             <C>               <C>
                                                                         1999            1998               1997
                                                                    ---------------------------------------------------
Property acquisition costs
  Proved properties................................................. $   34,477,750  $   36,619,796    $   137,430,583
  Unproved properties...............................................      1,911,916       1,138,426             57,306
Exploration costs...................................................      6,835,000       4,696,095            737,936
Development costs...................................................     12,176,557      27,839,727         18,284,460
                                                                    ---------------------------------------------------
          Total Costs Incurred...................................... $   55,401,223  $   70,294,044    $   156,510,285
                                                                    ===================================================
</TABLE>

                                      F-32
<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, 1999, 1998 and 1997 were as follows:
<TABLE>
<CAPTION>
<S>                                                                  <C>              <C>            <C>
                                                                           1999            1998            1997
                                                                   --------------------------------------------------
Oil and gas production revenue.....................................    $ 60,673,493    $ 43,564,728   $  35,658,032
Disposal services revenue..........................................               -               -           5,130
Production costs...................................................     (23,575,241)    (20,682,187)    (13,901,537)
Depreciation, depletion, amortization and impairment...............     (21,176,428)    (63,102,795)    (11,577,460)
Income taxes.......................................................      (5,572,638)     14,077,089      (3,564,458)
                                                                   --------------------------------------------------
          Results of Operations for Producing Activities               $ 10,349,186    $(26,143,165)  $   6,619,707
                                                                   ==================================================
</TABLE>
     The  standardized  measure of  discounted  estimated  future net cash flows
related to proved oil and gas reserves at December 31, 1999,  1998 and 1997 were
as follows:
<TABLE>
<CAPTION>
<S>                                                               <C>             <C>              <C>
                                                                        1999              1998             1997
                                                                ---------------------------------------------------------
Future cash inflows.............................................  $ 1,102,672,979   $  625,818,712   $  811,512,060
Future development costs........................................      (52,600,319)     (48,656,043)     (64,406,411)
Future production costs.........................................     (362,364,425)    (229,566,026)    (272,323,987)
                                                                    -------------    -------------    -------------
Future net cash flows, before income tax........................      687,708,235      347,596,643      474,781,662
Future income taxes.............................................     (131,499,755)     (25,670,854)     (93,828,793)
                                                                    -------------     ------------     ------------
Future Net Cash Flows...........................................      556,208,480      321,925,789      380,952,869
10% annual discount.............................................     (240,592,362)    (145,778,074)    (211,181,318)
                                                                    -------------    -------------    -------------
    Standardized Measure of Discounted Future Net Cash Flows....      315,616,118      176,147,715      169,771,551
                                                                    =============    =============    =============
</TABLE>
     The primary  changes in the  standardized  measure of discounted  estimated
future net cash flows for the years ended December 31, 1999,  1998 and 1997 were
as follows:
<TABLE>
<CAPTION>
<S>                                                             <C>                <C>                <C>
                                                                        1999              1998            1997
                                                                ---------------------------------------------------------
Purchases of minerals-in-place.................................   $   45,321,069     $ 46,388,818       $ 136,739,277
Sales of minerals-in-place.....................................         (167,874)          (8,604)           (191,741)
Extensions, discoveries and improved recovery, less related costs      8,398,247       10,836,769              38,555
Sales of oil and gas produced, net of production costs.........      (37,098,252)     (22,882,541)        (21,756,495)
Development costs incurred during the period...................       12,176,557       27,839,727          16,289,428
Revision of prior estimates:
  Net change in prices and costs...............................      118,271,081      (76,285,818)       (141,112,592)
  Change in quantity estimates.................................       36,936,790      (55,991,223)         46,255,955
Accretion of discount..........................................       17,614,772       16,977,155          11,708,486

Net change in income taxes.....................................      (61,983,987)               -           4,715,817
                                                                ---------------------------------------------------------
                 Net Change....................................   $  139,468,403     $  6,376,164       $  52,686,690
                                                                =========================================================
</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-33
<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...................  42        Director, President and Chief Executive Officer
Matthew C. Lutz.................  65        Chairman of the Board and Executive Vice President
Richard R. Frazier..............  53        President and Chief Operating Officer of Magnum Hunter
                                            Production, Inc. and Gruy
Chris Tong......................  43        Senior Vice President and Chief Financial Officer
R. Douglas Cronk . . . . . . . .  53        Senior Vice President of Operations of Magnum Hunter Production,
                                            Inc. and Gruy
Morgan F. Johnston..............  39        Vice President, General Counsel and Secretary
David S. Krueger................  50        Vice President and Chief Accounting Officer
Michael McInerney . . . . . . .   58        Vice President, Corporate Development & Investor Relations
Charles R. Erwin................  52        Vice President of Exploration of Magnum Hunter Production, Inc. and
                                            Gruy
Gregory L. Jessup...............  46        Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits..............  48        Vice President and Controller of Gruy
Craig Knight....................  43        Vice President of Operations of Hunter Gas Gathering, Inc.
Earl Krieg, Jr. ................  46        Vice President of Engineering of Magnum Hunter Production, Inc. and
                                            Gruy
Gerald W. Bolfing...............  71        Director
Jerry Box.......................  61        Director
Larry W. Brummett...............  49        Director
David L. Kyle...................  47        Director
Oscar C. Lindemann..............  77        Director
John H. Trescot, Jr.............  74        Director
James E. Upfield................  79        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  Swanson  Consulting  Services,  Inc.,  a private
Houston based geological firm, Novavax,  Inc., an American Stock Exchange listed
pharmaceutical  company,  and Karts  International  Incorporated,  an OTC listed
manufacturing company. He also serves as a Trustee of TEL Offshore Trust, an OTC
listed  oil and gas  trust  of  which  Magnum  Hunter  owns an  approximate  40%
interest.

                                       42
<PAGE>

     Matthew C. Lutz has served as Chairman since March 1997 after having served
as Vice Chairman of the Company since December 1995. Mr. Lutz has also served as
Executive  Vice President  since December 1995. Mr. Lutz held similar  positions
with Hunter from September 1993 until October 1996.  From 1984 through 1992, Mr.
Lutz was Senior Vice President of  Exploration  and on the Board of Directors of
Enserch  Exploration,  Inc. with responsibility for such company's 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.

     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.

     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  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.

                                       43
<PAGE>

     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.

     Charles R. Erwin has served as Manager of  Exploration  for Gruy  Petroleum
Management Co. since May of 1999. Mr. Erwin became Vice President of Exploration
for Magnum Hunter Production,  Inc. and Gruy in January 2000. 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,  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.

     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 Gruy
Petroleum  Management  Co.  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 24 years 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.

                                       44
<PAGE>

     Gerald W. Bolfing has been a director of the Company since  December  1995.
Mr. Bolfing was appointed a director of Hunter 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. During this time, he also joined 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 the Company  since March 1999.  From
February  1998 to March  1999 he  served in the  position  of  President,  Chief
Operating  Officer and Director of Oryx Energy Company  ("Oryx").  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.

     Larry W.  Brummett has served as a director of the Company  since  February
1999.  Mr.  Brummett has been employed by ONEOK Inc. for more than 23 years.  He
was  employed by ONEOK's  Oklahoma  Natural Gas Company  division as an engineer
trainee in June 1974 and,  after  receiving  a number of  promotions  within the
division, was elected Vice President of Tulsa District in September 1, 1986, and
Executive Vice President in May 1990. He was elected Executive Vice President of
ONEOK Inc. January 1993. He was elected President and Chief Executive Officer in
February  1994,  and was elected to the  additional  position of Chairman of the
Board  effective  June  1994.  Mr.  Brummett  is  a  director  of  American  Gas
Association;  Southern  Gas  Association;  Oklahoma  State  Chamber of Commerce;
Metropolitan  Chamber of Commerce,  Tulsa;  and the Oklahoma  City Branch of the
Federal  Reserve Bank.  He is also an officer or director of numerous  civic and
business  organizations  and  not-for-profit   associations.   He  attended  the
University of Oklahoma, earning B.S. and M.S. degrees in civil engineering,  and
is also a graduate  of the  Advanced  Management  Program  at  Harvard  Business
School.

     David L. Kyle has served as a director of the Company since  February 1999.
Mr.  Kyle is  currently  employed  by ONEOK  Inc.,  as its  President  and Chief
Operating  Officer.  Mr. Kyle was employed by Oklahoma  Natural Gas  Company,  a
division of ONEOK Inc., in 1974 as an engineer trainee. He served in a number of
positions prior to being elected Vice President of Gas Supply in September 1986,
and Executive Vice President in May 1990. He was elected  President in September
1994. He was elected  President of ONEOK Inc.  effective  September 1997. He has
the management  responsibility  for all of the  unregulated  companies of ONEOK,
Inc. He received a B.S.  degree in industrial  engineering  and management  from
Oklahoma  State  University  in 1974. He received an MBA degree in 1987 from The
University  of Tulsa,  and is a graduate of the Advanced  Management  Program at
Harvard Business School.

     Oscar C.  Lindemann has served as a director of the Company since  December
1995. Mr.  Lindemann was previously a director of Hunter,  having been appointed
in November  1995. Mr.  Lindemann has over 40 years  experience in the financial
industry.  Mr.  Lindemann began his banking career with the Texas Bank and Trust
in Dallas,  Texas in 1951.  He served  the bank  until 1977 in many  capacities,
including Chief Executive Officer and Chairman of the Board. Since leaving Texas
Bank and Trust,  he has served as Vice Chairman of both the United National Bank
and the National Bank of Commerce, also in Dallas. Mr. Lindemann has also served
as a consultant to the banking industry.  He retired from commercial  banking in
1987. Mr. Lindemann is a former President of the Texas Bankers Association,  and
a former state  representative  to the American  Bankers  Association.  He was a
Founding  Director  and Board  Member of VISA,  and a member of the Reserve City
Bankers  Association.  He has served as an instructor  at both the  Southwestern
Graduate  School of Banking at Southern  Methodist  University and the School of
Banking of the South at Louisiana State University.

                                       45
<PAGE>

     John H.  Trescot,  Jr. has served as a director of the  Company  since June
1997.  For the past  five  years,  Mr.  Trescot  has been the  principal  of AWA
Management Corporation, a consulting firm specializing in financial evaluations.
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,  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  Florestal e  Agropecuaria,  Ltda (JARI),  a timber,  pulp and mining
operation in the Amazon Basin of Brazil owned by billionaire D.K. Ludwig. 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 MBA from the Harvard Business School.

     James E.  Upfield has served as a director of the  Company  since  December
1995. Mr. Upfield was appointed a director of Hunter in August 1992. Mr. Upfield
is Chairman of Temtex Industries,  Inc. based in Dallas, Texas, a public company
that produces consumer hard goods and building  materials.  In 1969, Mr. Upfield
served on a select  Presidential  Committee  serving  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. ("Baifield") 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.

                     [Rest of page intentionally left blank]

                                       46
<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, 1999.
<TABLE>
<CAPTION>
<S>                       <C>       <C>       <C>         <C>              <C>        <C>       <C>          <C>
                                                                                 Long Term Compensation
                                           Annual                             Awards               Payout
                                        Compensation
           (a)               (b)      (c)         (d)            (e)            (f)       (g)        (h)           (i)
          Name,                                                 Other                    Number
        Principal                                               Annual      Restricted  Options      LTP        All Other
         Position           Year     Salary      Bonus     Compensation (b)    Stock      SARs     Payouts    Compensation
         --------           ----     ------      -----     -------------       -----      ----     -------    ------------
Gary C. Evans               1999    $250,000   $250,000        $ 7,500           -         -          -             -
President and CEO           1998    $250,000   $300,000           -              -         -          -             -
                            1997    $200,025   $250,000           -              -         -          -             -

Matthew C. Lutz             1999    $150,000   $125,000        $ 6,000           -         -          -             -
Executive V.P. and          1998    $156,000   $100,000           -              -         -          -             -
Chairman                    1997    $106,000   $100,000           -              -         -          -             -

Richard R. Frazier          1999    $150,000   $ 75,000        $ 4,200           -         -          -             -
President of                1998    $154,200   $ 50,000           -              -         -          -             -
Magnum Hunter               1997    $124,200   $ 50,000           -              -         -          -             -
Production, Inc.

Chris Tong (a)              1999    $150,000   $ 35,000        $ 6,000           -         -          -             -
Senior Vice President &     1998    $156,000   $ 30,000           -              -         -          -             -
Chief Financial Officer     1997    $ 78,500   $ 25,000           -              -         -          -             -

R. Douglas Cronk            1999    $115,000   $ 25,000        $ 4,200           -         -          -             -
Senior V.P. of Magnum       1998    $104,200   $ 20,000           -              -         -          -             -
Hunter Production, Inc.     1997    $ 92,033   $ 10,000           -              -         -          -             -
</TABLE>
---------------------

     (a) Mr. Tong was hired in August of 1997.

     (b)  Other  compensation  consists  of a  vehicle  allowance  paid  to  the
employee.

                                       47
<PAGE>

Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
<TABLE>
<CAPTION>
<S>                     <C>                      <C>                <C>                       <C>
                                                                      Number of securities     Value of unexercised
                                                                     underlying unexercised        in-the-money
                                                                     options/SARs at fiscal    options/SARs 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                  -                      -              700,000 / 200,000            0 / 0
   Matthew C. Lutz             51,073                $150,831           505,000 / 120,000            0 / 0
   Richard R. Frazier             -                      -              225,000 / 100,000            0 / 0
   R. Douglas Cronk               -                      -               96,000 / 44,000             0 / 0
   Chris Tong                     -                      -              121,000 / 84,000             0 / 0
</TABLE>

       Compensation of Directors

     The Company has nine individuals who serve as directors, seven of which are
independent.  Two of these directors receive  compensation with respect to their
services and in their  capacities  as  executive  officers of the Company and no
additional  compensation  has  historically  been paid for their services to the
Company as directors. The other seven directors of the Company are not employees
of the Company and receive no compensation for their services as directors other
than as stated  below.  For 1998,  independent  directors  received  $1,000  per
meeting as compensation  for their services.  For fiscal year 1999,  independent
directors  received a $10,000  retainer for being a board member and in addition
received $1,000 per meeting attended. Each new independent director added to the
board in fiscal year 1999 was granted an option to acquire  25,000 shares of the
Company's  common  stock at an exercise  price not less than the market price of
the  common  stock on the date of  grant.  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. Matthew C. Lutz, Mr. Richard R. Frazier,  Mr. Chris
Tong and Mr. R. Douglas Cronk each have employment  agreements with the Company.
Mr. Evans' agreement  terminates  January 1, 2005 and continues  thereafter on a
year to year basis and provides for a salary of $300,000 per annum.  Mr.  Lutz's
agreement  terminates January 1, 2005 and continues thereafter on a year to year
basis and provides for a salary of $175,000 per annum. Mr.  Frazier's  agreement
terminates January 1, 2005 and continues  thereafter on a year to year basis and
provides for a salary of $175,000 per annum.  Mr.  Tong's  agreement  terminates
January 1, 2003 and  continues  thereafter  on a year to year basis and provides
for a salary of $160,000 per annum. Mr. Cronk's agreement  terminates January 1,
2003 and continues  thereafter on a year to year basis and provides for a salary
of $122,500 per annum.  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, Mr.
Lutz 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 and Mr. Cronk, the employee
shall receive the employee's base

                                       48
<PAGE>

     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.

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

     The following  table sets forth certain  information  as of March 15, 2000,
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, 2000,  owned any shares of the Company's  Series A Preferred Stock, its 1996
Series  A  Convertible  Preferred  Stock or its  1999  Series  A 8%  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 (q)
-----------------------------------------------------------------------------------------------------------------
Directors and Executive Officers
     Gary C. Evans ............................................            2,262,952 (a)                10.8%
     Matthew C. Lutz...........................................              703,588 (b)                 3.4%
     Richard R. Frazier........................................              288,115 (c)                 1.4%
     Chris Tong................................................              129,951 (d)                    *
     R. Douglas Cronk .........................................               99,768 (e)                    *
     Gerald W. Bolfing.........................................              368,460 (f)                 1.8%
     Jerry Box.................................................               12,000 (g)                    *
     Oscar C. Lindemann........................................               39,526 (h)                    *
     John H. Trescot, Jr.......................................              102,056 (i)                    *
     James E. Upfield.........................................                93,544 (j)                    *
     David L. Kyle ............................................               19,342 (k)                    *
     Larry M. Brummett ........................................               10,342 (l)                    *
     All directors and executive officers as a group

     (12 persons)..............................................            4,129,644                    18.8%
Beneficial owners of 5 percent or more
(excluding persons named above)
     ONEOK Resources Company
     100 W. Fifth Street
     Tulsa, OK 74103-4298 .....................................            9,523,809 (m)                32.0%
     TCW Group, Inc.
     865 South Figueroa Street
     Los Angeles, CA  90017....................................            1,904,762 (n)                 8.6%
     Janus Capital Corporation
     100 Fillmore St., Suite 300
     Denver, CO.  80206........................................            1,653,075 (o)                 8.2%
     Dimensional Fund Advisors Inc.
     1299 Ocean Avenue, 11th Floor
     Santa Monica, CA 90401....................................            1,173,100 (p)                 5.8%
</TABLE>

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

     o Less than one percent.

     (a) Includes  700,000  shares of common stock issuable upon the exercise of
certain currently  exercisable options.  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.

                                       49
<PAGE>

     (b) Includes  505,000  shares of common stock issuable upon the exercise of
certain currently exercisable options.

     (c) Includes  225,000  shares of common stock issuable upon the exercise of
certain currently exercisable options.

     (d) Includes  121,000  shares of common stock issuable upon the exercise of
certain currently exercisable options.

     (e) Includes  96,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (f) Includes  12,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (g) Includes  2,000 shares of common  stock  issuable  upon the exercise of
certain currently exercisable options.

     (h) Includes  12,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (i) Includes  37,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (j) Includes  12,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (k) Includes  2,000 shares of common  stock  issuable  upon the exercise of
certain currently exercisable options.

     (l) Includes  2,000 shares of common  stock  issuable  upon the exercise of
certain currently exercisable options.

     (m) Consists of shares attributable to shares of Common Stock issuable upon
conversion  of  50,000  shares of the  Company's  1999  Series A 8%  Convertible
Preferred Stock.

     (n) Consists of shares attributable to shares of Common Stock issuable upon
conversion  of  1,000,000  shares of the  Company's  1996  Series A  Convertible
Preferred Stock.

     (o) Based on Schedule 13G filed by Janus  Capital  Corporation  on February
14, 2000.

     (p) Based on  Schedule  13G filed by  Dimensional  Fund  Advisors  Inc.  on
February 4, 2000.

     (q) 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% and is due December
31,2000.  Subsequent to year-end, $225,000 was repaid. The outstanding principal
balance as of March 15, 2000 was $146,860.

     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, 2001 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.

                                       50
<PAGE>

                                    GLOSSARY

     The terms defined in this glossary are used throughout this Form 10-K.

     Bbl. One stock tank barrel,  or 42 U.S. gallons liquid volume,  used herein
in reference to oil or other liquid hydrocarbons.

     Bbl/d. One barrel of oil or other liquid hydrocarbons per day.

     Bcf. One billion cubic feet of gas.

     Bcf/d. One billion cubic feet of gas per day.

     Bcfe. One billion cubic feet of Natural Gas Equivalents  converting one Bbl
of oil to six Mcf of gas.

     Btu. British Thermal Unit, the quantity of heat required to raise one pound
of water by one degree Fahrenheit.

     Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

     Development  Well. A well  drilled  within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.

     Dry Hole. A well found to be  incapable  of producing  either oil or gas in
sufficient quantities to justify completion as an oil or gas well.

     Exploratory  Well.  A well  drilled  to find and  produce  oil or gas in an
unproved  area,  to find a new  reservoir  in a  field  previously  found  to be
productive of oil or gas in another reservoir, or to extend a known reservoir.

     Gross Acres or Gross Wells.  The total acres or wells,  as the case may be,
in which a working interest is owned.

     In-fill  Well.  A well  drilled  between  known  producing  wells to better
exploit the reservoir.

     Mbbl. One thousand barrels of oil or other liquid hydrocarbons.

     Mcf. One thousand cubic feet of gas.

     Mcfe. One thousand cubic feet of Natural Gas Equivalents converting one Bbl
of oil to six Mcf of gas.

     Mcfe/d. Mcfe per day.

     MMBbl. One million barrels of oil or other liquid hydrocarbons.

     MMBtu. One million Btu.

     MMcf. One million cubic feet of gas.

     MMcfe. One million cubic feet of Natural Gas Equivalents converting one Bbl
of oil to six Mcf of gas.

     MMcf/d. One million cubic feet of gas per day.

     Natural Gas Equivalent.  The amount of gas having the same Btu content as a
given quantity of oil, with one Bbl of oil being converted to six Mcf of gas.

                                       51
<PAGE>

     Net Acres or Net Wells. The sum of the fractional  working  interests owned
in gross acres or gross wells.

     Net Revenue  Interest.  A share of the Working  Interest that does not bear
any portion of the expense of drilling and completing a well and that represents
the holder's share of production after  satisfaction of all royalty,  overriding
royalty, oil payments and other nonoperating interests.

     Productive  Well. A well that is producing oil or gas or that is capable of
production in paying quantities.

     Non-Producing  Reserves.  Proved  Developed  Reserves  that  consist of (i)
Proved  Reserves  from wells  which have been  completed  and tested but are not
producing due to lack of market or minor completion  problems which are expected
to be  corrected  and/or  (ii)  Proved  Reserves  currently  behind-the-pipe  in
existing  wells and which are expected to be productive due to both the well log
characteristics and analogous production in the immediate vicinity of the wells.

     Producing  Reserves.  Proved Developed  Reserves that can be expected to be
recovered  from  currently  producing  zones under the  continuation  of present
operating methods.

     Proved  Developed  Reserves.  Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

     Proved  Reserves.  The estimated  quantities 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:  (A) oil
that may become available form 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.

     Proved  Undeveloped  Reserves.  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.

     PV-10.  The  present  value  of  Proved  Reserves  is an  estimate  of  the
discounted  future net cash flows from each of the  properties  at December  31,
1999, 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. As required by
rules of the  Commission,  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.  In
accordance  with Commission  rules,  estimates have been made using constant oil
and gas prices and  operating  costs,  at December  31,  1999,  or as  otherwise
indicated.

                                       52
<PAGE>

     Recompletion.  The completion  for production of an existing  wellbore in a
different  formation  or  producing  horizon  from  that in  which  the well was
previously completed.

     Reserve Life. The estimated  productive  life of a proved  reservoir  based
upon the  economic  limit of such  reservoir  producing  hydrocarbons  in paying
quantities assuming certain price and cost parameters. For purposes of this Form
10- K, reserve life is  calculated  by dividing the Proved  Reserves (on an Mcfe
basis) at the end of the period by projected  production volumes for the next 12
months.

     Royalty  Interest.  An interest in an oil and gas  property  entitling  the
owner to a share of oil and gas production free of cost of production.

     Undeveloped Acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the  production of commercial  quantities
of oil and gas regardless of whether such acreage contains Proved Reserves.

     Working Interest.  The operating interest that gives the owner the right to
drill,  produce and conduct operating  activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all  costs  of  exploration,  development  and  operations  and all  risks in
connection therewith.

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

     (a) The following documents are filed as part of this report:

1.  Financial Statements

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

     Financial Statements:
             Consolidated Balance Sheets at December 31, 1999 and 1998.......F-2

             Consolidated Statements of Operations and Comprehensive Income
               for the Years Ended December 31, 1999, 1998 and 1997..........F-3

             Consolidated Statements of Stockholders' Equity for the
                      Years Ended December 31, 1999, 1998 and 1997...........F-4

             Consolidated Statements of Cash Flows for the Years
                      Ended December 31, 1999, 1998 and 1997.................F-5

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

     Supplemental Information (Unaudited)...................................F-28

2.  Financial Statement Schedule

     We have  included  on pages 56 and 57 of this  Annual  Report  on Form 10-K
Financial Statement Schedule II, Valuation and Qualifying Accounts.

                                       53
<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     By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File
              No. 33-66190)
3.6 & 4.6     Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated
              December 26, 1996, filed January 3, 1997)
3.7 & 4.7     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)
3.8 & 4.8     Certificate of Designation for 1999 Series A 8% Convertible Preferred Stock (Incorporated by reference
              to Form 8-K, dated February 3, 1999, filed February 11, 1999)
4.9           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)
4.10          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)
4.11          Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form S-4, File
              No. 333-2290)
10.1          Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum Hunter Resources, Inc.
              and Bankers Trust Company, et al. (Incorporated by reference to Registration Statement on Form S-4, File
              No. 333-2290)
10.2          First Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
              Hunter Resources, Inc. and Bankers Trust Company, et al. (Incorporated by reference to Registration
              Statement on Form S-4, File No. 333-2290)
10.3          Second Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
              Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the
              fiscal year-end December 31, 1998 filed April 14, 1999)
10.4          Third Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
              Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the
              fiscal year-end December 31, 1998 filed April 14, 1999)
10.5*         Employment Agreement for Gary C. Evans
10.6*         Employment Agreement for Matthew C. Lutz
10.7*         Employment Agreement for Richard R. Frazier
10.8          Stock Purchase  Agreement among Magnum Hunter Resources,  Inc. and
              Trust Company of the West and TCW Asset Management Company, in the
              capacities described herein, TCW Debt and Royalty Fund IVB and TCW
              Debt  and  Royalty  Fund  IVC,   dated  as  of  December  6,  1996
              (Incorporated  by reference  to Form 8-K dated  December 26, 1996,
              filed January 3, 1997)
10.9          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)
10.10         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)

                                       54
<PAGE>
10.11         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)
10.12         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)
21**          Subsidiaries of the Registrant
27**          Financial Data Schedule
</TABLE>

     * Filed with Form 10-K dated March 30, 2000.
     **Filed herewith.

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


                     [Rest of page intentionally left blank]

                                       55
<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, 1999 and 1998, and for each
of the three years in the period ended  December  31, 1999,  and have issued our
report  thereon  dated March 28, 2000  (January  31, 2001 as to Note 18),  which
report  expresses an unqualified  opinion and includes an explanatory  paragraph
referring to the restatement discussed in Note 18. Such financial statements and
report are  included  in your  Annual  Report on Form  10-K,  as amended by Form
10-K/A, and are incorporated  herein by reference.  Our audits also included the
financial  statement  schedule of Magnum Hunter  Resources,  Inc.  listed in the
accompanying  index  at  Item  14.  This  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 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.


DELOITTE & TOUCHE LLP


Dallas, Texas
March 28, 2000


                                       56
<PAGE>

                        Valuation and Qualifying Accounts
                                ($ in thousands)

For the year ended December 31, 1999:
<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              $ -                $ -              $ 166
Current portion of long-term notes receivable           790                -                  -                790
</TABLE>

For the year ended December 31, 1998:
<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          $     -                $ -              $ 166
Current portion of long-term notes receivable            199              591                  -                790
</TABLE>

                                       57
<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/A to be
signed on its behalf by the undersigned, thereunto duly authorized.

MAGNUM HUNTER RESOURCES, INC.


By:    /s/ Gary C. Evans                                     March 29, 2001
---------------------------------------------
 Gary C.  Evans, President & CEO

     In accordance with the Exchange Act, this Form 10-K/A 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                               Director, President                        March 29, 2001
----------------------------
Gary C. Evans                                    Chief Executive Officer

/s/ Matthew C.  Lutz                             Chairman of the Board and                  March 29, 2001
--------------------------
Matthew C. Lutz                                  Executive Vice President of
                                                 Exploration and Business
                                                 Development

/s/ Chris Tong                                   Senior Vice President and                  March 29, 2001
-------------------------------
Chris Tong                                       Chief Financial Officer


/s/ David S. Krueger                             Vice President and                         March 29, 2001
--------------------------
David S. Krueger                                 Chief Accounting Officer

/s/ Morgan F. Johnston                           Vice President, General Counsel            March 29, 2001
-------------------------
Morgan F. Johnston                               and Secretary

/s/ Gerald W.  Bolfing                           Director                                   March 29, 2001
--------------------------
Gerald W. Bolfing

/s/ Oscar C.  Lindemann                          Director                                   March 29, 2001
-----------------------
Oscar C. Lindemann

/s/ John H. Trescot, Jr.                         Director                                   March 29, 2001
---------------------------
John H. Trescot, Jr.

/s/ James E. Upfield                             Director                                   March 29, 2001
---------------------------
James E. Upfield
</TABLE>

                                       58