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

                                    FORM 10-K

         (Mark one)
         [X]      Annual  Report   pursuant  to  Section  13  or  15(d)  of  the
                  Securities  Exchange  Act of 1934 For the  fiscal  year  ended
                  December 31, 1998

         [ ]      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 1200, Irving, Texas 75039
              (Address of principal executive offices) (zip code)


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

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

    Title of each class               Name of each exchange on which registered

Common Stock ($.002 par value)                 American Stock Exchange
------------------------------                 -----------------------

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

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding 12 months (or for such  shorter  period that the  registrant  was
required  to file  such  reports),  and  (2) has  been  subject  to such  filing
requirements for the past 90 days.
      Yes [X]      No [   ]

Indicate by check mark if disclosure of delinquent  filers  pursuant to Item 405
of regulation  S-K is not contained  herein,  and will not be contained,  to the
best of registrant's  knowledge,  in definitive proxy or information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

As of March  31,  1999,  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 $51,469,744.

The number of shares  outstanding of the registrant's  common stock at March 31,
1999 was 20,082,341.



<PAGE>




                                TABLE OF CONTENTS

                       Securities and Exchange Commission
                           Item Number and Description


                                     PART I

Item 1.    Business............................................................1
            The Company........................................................1
            Business Strategy .................................................2
            Recent Acquisitions ...............................................3
            Development and Exploration Activities ............................6
            Gathering and Processing of Gas ...................................8
            Marketing of Production ...........................................9
            Petroleum Management and Consulting Services ......................9
            Competition........................................................9
            Regulation .......................................................10
            Employees ........................................................13
            Facilities .......................................................13
Item 2.    Properties.........................................................14
            Oil and Gas Reserves .............................................14
            Oil and Gas Production, Prices and Costs .........................16
            Drilling Activity ................................................17
            Oil and Gas Wells ................................................18
            Oil and Gas Acreage ..............................................18
Item 3.    Legal Proceedings..................................................19
Item 4.    Submission of Matters to a Vote of Security Shareholders...........19

                                     PART II

Item 5.    Market for Common Equity and Related Stockholder Matters...........20
Item 6.    Selected Financial Data............................................21
Item 7.    Management's Discussion and Analysis of Financial 
            Condition and Results of Operations...............................23
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk.........32
Item 8.    Financial Statements and Supplementary Data........................35
Item 9.    Change in and Disagreements with Accountants on 
            Accounting and Financial Disclosure...............................36

                                    PART III

Item 10.  Directors and Executive Officers of the Registrant..................36
Item 11.  Executive Compensation..............................................40
Item 12.  Security Ownership of Certain Beneficial Owners and Management......42
Item 13.  Certain Relationships and Related Transactions......................43
          Glossary............................................................44
Item 14.  Exhibits and Reports on Form 8-K....................................46





                                        i

<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  exploitation  and
development,  acquisition,  exploration  and operation of oil and gas properties
with a geographic focus in Texas, Oklahoma and New Mexico. In December 1995, the
Company  consummated  the  acquisition  of  all of the  subsidiaries  of  Hunter
Resources,  Inc., a Pennsylvania  corporation (the "Magnum Hunter Combination"),
and the management of Hunter  Resources,  Inc. assumed  operating control of the
Company.  The new  management  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, in June 1996 the Company
acquired the Panoma  Properties (as defined  herein) from  Burlington  Resources
Inc.  ("Burlington")  for a net  purchase  price of $34.7  million  (the "Panoma
Acquisition").  Additionally,  in April 1997 the  Company  acquired  the Permian
Basin Properties (as defined herein) from Burlington for a net purchase price of
$133.8  million  (the  "Permian  Basin  Acquisition").  On December 31, 1998 the
Company acquired the Spirit 76 Properties (as defined herein) from Spirit Energy
76 ("Spirit 76"), a business unit of Union Oil Company of California,  for a net
purchase price of approximately $25 million (the "Spirit 76  Acquisition").  The
Company presently intends to focus its efforts on additional  producing property
acquisitions,   its  substantial   inventory  of  exploitation  and  development
opportunities and, to a lesser extent,  selected exploratory drilling prospects.
The Company has identified over 400 development  drilling  locations  (including
both  production and injection  wells) on its properties,  substantially  all of
which are low-risk in-fill drilling opportunities.

     On March 27, 1998 the  Company  acquired an  approximately  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  $10.3  million (the "TEL  Acquisition").  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.



                                       

<PAGE>



     At December  31,  1998,  the Company had an interest in 3,059 wells and had
estimated  Proved  Reserves  of 323.2 Bcfe with an SEC PV-10 of $179.4  million.
Approximately 70% of these reserves were Proved Developed Producing Reserves and
88.1% were attributable to the Panoma  Properties,  the Permian Basin Properties
and the Spirit 76  Properties.  At  December  31,  1998,  the  Company's  Proved
Reserves had an estimated  Reserve Life of  approximately  13 years and were 68%
gas. The Company  serves as operator  for  approximately  65% of its  properties
(based on the number of producing  wells in which the Company owns an interest).
Additionally, the Company owns over 480 miles of gas gathering systems and a 50%
interest in a gas  processing  plant that is located  adjacent to the  Company's
largest gas gathering system.

     Beginning with the Magnum Hunter  Combination in December 1995, the Company
has completed twelve  acquisitions for an aggregate net purchase price of $221.8
million.   This  strategy  has  added   approximately  346.6  Bcfe  of  reserves
(determined as of the respective times of their  acquisition) at an average cost
of $0.63 per Mcfe, as well as a 427 mile gas gathering system and a 50% interest
in the McLean Gas Plant (the  "McLean  Plant  Acquisition").  As a result of its
property  acquisitions  and  successful  drilling  activities,  the  Company has
achieved substantial growth as described below:

     o Proved  Reserves  increased to 323.2 Bcfe at year end 1998 from 36.7 Bcfe
at year end 1995;

     o SEC PV-10 increased to $179.4 million at year end 1998 from $37.2 million
at year end 1995; and

     o Average daily production increased to 57.8 MMcfe in the fourth quarter of
1998 from 0.8 MMcfe in fiscal 1995


Recent Developments

     On February 3, 1999,  the Company closed  various  transactions  with ONEOK
Resources  Company  ("ONEOK"),  a  wholly-owned  subsidiary of ONEOK,  Inc., the
eighth largest  natural gas  distributor  in the United States,  relating to (i)
ONEOK's  purchase of $50 million of Convertible  Preferred Stock of the Company,
(ii) ONEOK's  ability to market certain of the Company's  natural gas production
in the state of Oklahoma  and (iii)  ONEOK's  ability to  participate  in future
acquisitions of the Company in the state of Oklahoma (the "ONEOK Transaction").

     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  to repay
senior bank indebtedness. ONEOK had the right to nominate two new members to the
Company's  existing  Board of  Directors  which ONEOK  exercised on February 18,
1999.  See  "Selected  Financial  Data"  and  "Directors,   Executive  Officers,
Promoters and Control Persons."

     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.  On  February  17,  1999,  the
Company revised its previously announced stock repurchase program to spend up to
$4 million without a share limitation.

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) strategic acquisitions of Proved Reserves and (iii) a selective
exploration program.

     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.



                                        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 65% of its properties (78% of its SEC 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. The Company owns over 85% and markets directly and
indirectly  approximately  95% of the 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  approximately  350 MMcf per day as of
December 31, 1998. NGTS markets  substantially all of the Company's natural gas.
The Company is also considering  opportunities to acquire or develop  additional
gas gathering and processing  facilities  that are  associated  with its current
production.

     Exploration.  The  Company is  systematically  increasing  its  exploration
efforts,  focusing on established geological trends where the Company can employ
its geological,  geophysical and engineering expertise.  The Company is actively
generating  and  evaluating  prospects  for the  application  of 3-D seismic and
advanced drilling technologies.

Recent Acquisitions

     The most significant of the Company's completed acquisitions are the Spirit
76 Acquisition,  the Permian Basin Acquisition,  the Panoma Acquisition, the TEL
Acquisition and the McLean Plant Acquisition.

Spirit 76 Acquisition

     On  December  31,  1998 the  Company  acquired  from  Spirit 76 natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
(the "Spirit 76 Properties")  currently producing about 12 million cubic feet of
natural gas  equivalent per day. The net purchase  price was  approximately  $25
million after certain purchase price adjustments  including  preferential rights
exercised by third parties and other customary adjustments.

     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 acquired from Spirit 76.
According to Ryder Scott,  as of December 31, 1998, the Spirit 76 Properties had
Proved  Reserves  of .98 MMBbl of oil and 35.7 Bcf of gas,  or on a Natural  Gas
Equivalent basis 41.6 Bcfe. Ryder Scott further  estimated the SEC PV-10 for the
Spirit 76 Properties to be $37.6 million as of December 31, 1998 based on prices
of $9.42  per Bbl of oil and  $2.18  per Mcf of gas.  The  Proved  Reserves  are
located  principally  in the Ardmore Basin in south central  Oklahoma and in the
Oklahoma/Texas  panhandle.  Approximately 86% of the estimated  reserves are gas
and 14% are oil located on approximately  50,000 net mineral  leasehold acres in
twelve  counties  in  Oklahoma  and five  counties  in  Texas.  Total  net daily
production to the Company's  interest acquired is approximately 11 million cubic
feet of natural gas production and 165 barrels of oil.  Approximately 80% of the
Proved  Reserves  were  classified  Proved  Developed  Producing  Reserves as of
December  31,  1998.  The  Company has  engaged  its  Houston  based  geological
affiliate, Swanson Consulting Services, Inc., to begin an evaluation of the most
prospective  undeveloped  properties located in one of the fields acquired.  The
Company's wholly-owned  subsidiary,  Gruy Petroleum Management Co. ("Gruy"), has
become the operator of 62% or 111 of the 179 wells acquired from Spirit 76.



                                        3

<PAGE>



     The major fields in the Spirit 76 Properties are the Cumberland,  Caddo and
Hitchcock.

     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.  Potential exists for three additional wells to complete development
of the shallow gas on 160-acre spacing.  The shallowest zone in the field is the
Goddard,  which is a channel  sand.  The Company has  interest in a total of 128
wells in this field,  with  working  interest  varying  from 17.2% to 100%.  The
Company  operates  all but nine of  these  wells.  The  latest  available  gross
production from such wells averaged 6,200 Mcf/d and 190 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.  The latest  available gross  production
from the wells averaged 1,920 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  six of these  wells.  The
latest  available  gross  production  from the wells averaged 1,676 Mcf/d and 23
Bbl/d.

Permian Basin Acquisition

     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  included  1,852  producing  oil  and  gas  wells  on
approximately  113,810  gross acres  (82,175 net  acres).  One of the  Company's
subsidiaries,  Gruy  Petroleum  Management Co.  ("Gruy"),  serves as operator on
approximately  60% of the  wells on the  Permian  Basin  Properties.  Management
believes the Permian Basin  Properties  provide  significant  opportunities  for
exploitation  and  development  of  both  oil  and  gas  through  workovers  and
recompletions, enhanced recovery projects and in-fill drilling.

     According  to Ryder  Scott,  as of December  31,  1998,  the Permian  Basin
Properties had Proved  Reserves of 10.65 MMBbl of oil and 85.3 Bcf of gas, or on
a Natural Gas Equivalent  basis,  149.2 Bcfe. Ryder Scott further  estimated the
SEC PV-10 for the Permian Basin  Properties to be $59.12  million as of December
31,  1998  based on  prices  of $9.42 per Bbl of oil and $2.18 per Mcf of gas at
December 31, 1998.  Approximately  60% of the Proved Reserves were classified as
proved developed  producing  reserves as of December 31, 1998. 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  Properties  are the  Westbrook,
Levelland/Slaughter, Lea County Shallow Properties and the Brunson Ranch.



                                        4

<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  in  the  Permian  Basin
Acquisition:
<TABLE>
<CAPTION>
<S>                                      <C>                <C>             <C>            <C>               <C>    

                                                                                                              Gross Oil
                                                              Well          Working        Net Revenue       Production
               Property                     Operator         Count          Interest         Interest          (Bbl/d)
------------------------------------------------------------------------------------------------------------------------------------
Southwest Westbrook Unit...............     Company           135            89.9%            77.5%               425
Morrison "G" Lease (1).................     Company            12            83.3%            72.9%                26
North Westbrook Unit...................   Third Party         294             2.0%             2.8%(2)          1,200
</TABLE>

       (1)   Subsequent to the Permian Basin  Acquisition,  the Company acquired
             the  remaining  16.7% of the working  interest in the  Morrison "G"
             Lease, increasing its Net Revenue Interest to 87.5%.
       (2)   Includes an overriding Royalty Interest.

     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 plans to initiate
waterflood  enhancement  operations  on the  Southwest  Westbrook  Unit  and the
Morrison  "G" Lease in either  1999 or 2000  assuming  oil  prices  continue  to
improve.

     Levelland/Slaughter.  The  Levelland and  Slaughter  Fields  consist of 155
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)
------------------------------------------------------------------------------------------------------------------------------------
TLB Unit...............................     Company            20            100.0%           87.3%               80
Veal Lease.............................     Company            52            100.0%           87.1%              220
NW Slaughter Unit......................     Company            83             74.8%           62.8%              290
</TABLE>

     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 are likely. 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 anticipated  for
that  property.  The  operator of an  adjacent  property  has been  successfully
injecting carbon dioxide for a number of years to 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 which
are planned.

     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. The wells are currently  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 and completing  such wells using  technology  designed for high
bottom hole pressure conditions.

                                        5

<PAGE>



Panoma Acquisition

     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").  By year-end of 1998,  the  Company had drilled an  additional  80
wells. A continuous  drilling  program is budgeted,  with an additional 20 wells
proposed to be drilled in 1999. The net purchase price,  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.  According to
Ryder Scott,  the Proved Reserves  attributable  to the Panoma  Properties as of
December 31, 1998 aggregated 94 Bcfe with an SEC PV-10 of $50.9 million.

     The Panoma  Properties  currently consist of approximately 630 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 gas from the
Granite Wash and/or Brown Dolomite formations.

TEL Acquisition

     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 $10.3 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 1.3
Bcfe in 1998.

McLean Plant Acquisition

     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,
which is connected  to the Panoma gas  gathering  system and a related  products
pipeline. The Company receives 100% of the net profits from the McLean Gas Plant
until it recoups  the $2.5  million  purchase  price,  after  which time it will
receive 50% of the net profits.  At January 31,  1999,  the Company had recouped
approximately $1.36 million or 54% of its initial investment. See "Gathering and
Processing of Gas."

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, to a lesser extent, 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 $9.0 million
for exploitation and development activities for 1999. The Company has identified
over 400 development drilling locations (including both production and injection
wells) on its properties.  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.

                                        6

<PAGE>



     Permian Basin Properties.  In evaluating the Permian Basin Properties,  the
Company has identified approximately 400 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 1998, the Company drilled 19 wells
in the Sawyer Canyon Field in the Sonora area located in Sutton  County,  Texas.
The Company  owns an  interest  in 146 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.  The
Company has plans to continue to develop the Sawyer  Canyon  Field in 1999.  The
Company has budgeted  approximately  $3.5 million for development of the Permian
Basin properties in 1999.

     Panoma  Properties.  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  westernmost  field with 80 wells
having been completed  during the two years ended December 1998. Upon completion
of this well program, the westernmost field will have been effectively developed
with 320 acre spacing.  The Company has budgeted  approximately $1.5 million for
development of the Panoma Properties through 1999.

     Spirit 76 Acquisition. The Company has engaged its Houston based geological
affiliate, Swanson Consulting Services, Inc., to begin an evaluation of the most
prospective undeveloped properties located in one of the fields acquired,  being
the  Cumberland  Field.  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.  Potential exists for
three  additional  wells to complete  development of the shallow gas on 160-acre
spacing. The Company has budgeted  approximately $1.5 million for development of
the Cumberland Field through 1999.

Exploratory Drilling

     The Company  attempts to lessen the risks inherent in exploratory  drilling
by: (i) concentrating in specific areas in the United States where the Company's
technical  staff has  considerable  experience and which are in known  producing
trends where the potential for significant  reserves exists;  (ii)  diversifying
through investment in multiple prospects;  (iii) utilizing 3-D seismic and other
advanced technologies; and (iv) promoting out interests to industry partners.

     The  Company  spent  approximately  $6.0  million of its $36  million  1998
capital  budget  on  exploratory  drilling.  The  Company  has  a  $1.0  million
exploration budget for 1999,  including  geological and geophysical expenses for
its currently owned  properties.  Six exploratory  wells were drilled in 1998 of
which  five were  successful.  Exploratory  successes  include  the Mossy  Grove
Prospect in Walker  County,  Texas where a discovery  completed in July 1998 has
produced nearly 750 MMcf of natural gas in 8 months and is currently  flowing at
approximately  2 MMcf/d.  A confirmation  to this  discovery,  located 3.5 miles
southwest, has been recently completed and is flowing over 5 MMcf/d. The Company
owns 25% and 55% working  interest,  respectively,  in these two producing wells
and owns an average  of a 25%  working  interest  in a 43,000  acre lease  block
surrounding the new wells where additional development drilling is planned.



                                        7

<PAGE>



     A new oil  discovery on the  Sunburst  Prospect in Terry  County,  Texas is
currently  producing  approximately  42 Bbls  of oil  per  day.  This  well  was
completed in September 1998 and a confirmation  test is planned by the middle of
1999.  The Company is operator and owns a 39% working  interest in the discovery
and approximately 1,500 acres of the prospect.  Additional  development drilling
is expected later in 1999.

     A 3-D seismic  program on the Bobcat Project in Hockley  County,  Texas has
been  completed  and the  interpretation  of the data  confirms  the presence of
numerous high quality,  exploratory  prospects.  The entire  project covers over
30,000  acres  with  approximately  15,000  acres  under  lease  or  option.  An
exploratory  drilling  program is  expected  to commence in late 1999 and extend
into 2000.

     The Company is actively generating and evaluating other projects for future
exploration activity.

Gathering and Processing of Gas

     Hunter Gas Gathering,  Inc., a wholly-owned subsidiary of the Company, owns
two gas gathering  systems  located in Oklahoma and Texas,  neither of which are
subject to regulation by the Federal Energy Regulatory Commission ("FERC"),  and
a 50% ownership  interest in the McLean Gas Plant in the Texas  Panhandle.  Gruy
operates  both gas  gathering  systems.  In October of 1998,  the Company sold a
small  gathering  system located in Louisiana that accounted for less than 2% of
the Company's total gas gathering throughput.

     Generally,  the gathering  systems transport the 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.

     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 1998, gas
throughput for the Panoma gas gathering system was  approximately  18.2 MMcf per
day. The Panoma gas  gathering  system was  recently  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  535  of the
approximately 630 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.

     The Company's  North Appleby gas gathering  system is located  primarily in
Nacogdoches  County in east Texas.  Approximately  39 wells are connected to the
system,  which  delivers  approximately  2.2 MMcf per day for third  parties  to
Natural Gas Pipeline Co. for  transportation  to other  markets.  The Company is
currently  negotiating  with several  third parties for the possible sale of the
North Appleby gas gathering system.

     Effective  January 1, 1997,  the Company  purchased  for $2.5 million a 50%
ownership  interest  in the  McLean  Gas  Plant,  the  gas  processing  facility
connected to the  Company's  Panoma gas  gathering  system.  The  purchase  also
included a 23-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.  Current  throughput  is
approximately 16.4 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.  Under the
terms of the Company's  operating  agreement with Carrera,  the Company receives
100% of the net  profits  from the  McLean Gas Plant  until it recoups  the $2.5
million  purchase  price,  at which  point net profits  will be divided  equally
between the Company and Carrera. As of January 31, 1999 the Company had recouped
approximately 54% of its $2.5 million investment.



                                        8

<PAGE>



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 the spot market
on a  month-to-month  basis at  prevailing  spot market  prices or at negotiated
prices under long-term contracts.  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 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
$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
1998,  NGTS reported total revenues of  approximately  $224.7  million.  NGTS is
presently marketing approximately 350 million cubic feet of natural gas per day.
As of December 1, 1997, the Company and its gas gathering subsidiary, Hunter Gas
Gathering,  Inc.,  dedicated  substantially all of its natural gas production to
NGTS for  marketing.  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.

Petroleum Management and Consulting Services

     The Company  acquired  Gruy in the Magnum  Hunter  Combination  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 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

                                        9

<PAGE>



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,  gas 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.

     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;

                                       10

<PAGE>



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 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

                                       11

<PAGE>



procedures.  Because of the novelty and  uncertainty  surrounding  the  indexing
methodology, as well as the possibility of the use of cost of service ratemaking
and  market-based  rates,  the  Company is not able at this time to predict  the
effects of Order No. 561, if any, on the  transportation  costs  associated with
oil production from the Company's oil producing operations.

       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.

     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,  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

                                       12

<PAGE>



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 1999 and $75,000 in 2000.

     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, 1998,  the Company had 69 full-time  employees of which 12
were management, 26 were administrative and 31 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  11,590 square feet of office space at
600 East Las Colinas Boulevard,  Suite 1200,  Irving,  Texas, under a lease that
expires in November 2001. The Company owns a field office and production yard in
Shamrock,  Texas. The Company also has field  production  offices in Midland and
Abilene, Texas, Hobbs, New Mexico and Oklahoma City, Oklahoma.


                                       13

<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 SEC 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  ("PGH") of Austin,  Texas,  both
independent  petroleum  engineers  with  respect to the  Company's  interests at
December  31, 1998 (using oil and gas prices in effect at December 31, 1998) and
December 31, 1997. 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.

     SEC 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, 1998,  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, 1998, or
as otherwise indicated.

     In accordance with Commission guidelines,  the estimates of future net cash
flows from Proved  Reserves and their SEC 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 SEC PV-10 were estimated using the following
weighted average prices, before deduction of production taxes:

<TABLE>
<CAPTION>
<S>                                            <C>              <C>    
                                          Prices used in Reserve Reports at
                                                     December 31,
                                         ---------------------------------------
                                                1998              1997
                                         ---------------------------------------

Gas (per Mcf)............................       $2.12            $ 2.34
Oil (per Bbl)............................       $9.42            $16.08
</TABLE>

     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.

                                       14

<PAGE>



     Results of drilling,  testing, and production subsequent to the date of the
estimate may justify  revision of such estimate.  Future prices received for the
sale of oil and gas will likely be different from those used in preparing  these
reports.  The amounts and timing of future  operating and development  costs may
also differ from those used. Accordingly,  reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.

     Except for the effect of changes in oil and gas prices,  no major discovery
or other  favorable  or adverse  event is believed to have caused a  significant
change in these  estimates of the Company's  Proved  Reserves since December 31,
1998.  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, 1998.

Company Reserves

     The following tables set forth the estimated Proved Reserves of oil and gas
of the Company and the SEC PV-10 thereof on an actual basis at December 31, 1998
and 1997.

                Estimated Proved Oil and Natural Gas Reserves (1)
<TABLE>
<CAPTION>
<S>                                                            <C>                 <C>   

                                                                       At December 31,
                                                           ---------------------------------------
                                                                   1998                1997
                                                           ---------------------------------------

Net gas reserves (Mcf):
     Proved developed producing...........................       173,220,374         154,749,340
     Proved developed non-producing.......................         1,767,000             215,056
     Proved undeveloped...................................        44,072,300          52,811,374
                                                           ---------------------------------------

       Total proved gas reserves..........................       219,059,674         207,775,770
                                                           ---------------------------------------

Net oil reserves (Bbl):
    (including condensate and NGL)
     Proved developed producing ..........................         9,015,703          12,021,950
     Proved developed non-producing.......................           458,888              14,284
     Proved undeveloped...................................         7,874,050           8,910,181
                                                           ---------------------------------------

       Total proved oil reserves..........................        17,348,641          20,946,415
                                                           ---------------------------------------

Total Proved Reserves (Mcfe)..............................       323,151,521         333,454,260
                                                           ---------------------------------------
</TABLE>
<TABLE>
<CAPTION>
<S>                                                            <C>                 <C>    
                   Estimated SEC PV-10 of Proved Reserves (1)

                                                                        At December 31,
                                                           ---------------------------------------

                                                                   1998                1997
                                                           ---------------------------------------
Estimated SEC PV-10 (2) :
     Proved developed producing ..........................     $ 156,629,617       $ 173,189,655
     Proved developed non-producing ......................         4,355,278             342,473
     Proved undeveloped ..................................        18,424,052          38,054,232
                                                           ---------------------------------------
       Total Proved Reserves..............................     $ 179,408,947       $ 211,586,360

                                                           ---------------------------------------
</TABLE>
-----------

     (1) Based upon  reserve  reports at December 31, 1998 and December 31, 1997
prepared by Ryder Scott and PGH.  
     (2) SEC 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.
                                       15
<PAGE>
       Significant Properties

     On December 31, 1998, 82% of the Company's  Proved Reserves on a Bcfe basis
were located in the Spirit 76 Properties,  the Permian Basin  Properties and the
Panoma  Properties.  On such date,  the Company's  properties  included  working
interests in 3,059 gross (1,671 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, 1998.
<TABLE>
<CAPTION>
<S>                                  <C>                 <C>        <C>            <C>            <C>    

                                             SEC PV-10 (1)
                                     ----------------------------------------------------------------------------
                                                                                                    Natural Gas
                                           Amount         % of          Oil             Gas          Equivalent
                                       (in thousands)     Total        (Bbl)           (Mcf)           (Bcfe)
                                     -------------------------------------------- --------------- ---------------

Spirit 76 Properties (2)............. $  37,593,943       21.0%        978,496      35,721,581         41.59
Permian Basin Properties (2)(3)......    59,012,596       32.9%     10,650,255      85,237,426        149.14
Panoma Properties (2)  ..............    50,989,042       28.4%      2,842,637      76,923,054         93.98
Other (2)(3).........................    31,813,366       17.7%      2,877,253      21,177,613         38.44
                                     -------------------------------------------- --------------- ---------------

       Total ........................   179,408,947      100.0%     17,348,641     219,059,674        323.15
                                     -------------------------------------------- --------------- ---------------
</TABLE>

----------

       (1)    SEC 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.
       (2)    Based on a reserve  report at  December  31,  1998  prepared by 
              Ryder Scott. 
       (3)    Based on reserve reports at December 31, 1998 prepared by PGH.


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>    

                                                                Year Ended December 31,
                                                               1998                1997
                                                        ----------------------------------------

Oil and gas production:
  Oil (Mbbl)..........................................         1,141                737
  Gas (MMcf)..........................................        14,119              9,614
  Natural Gas Equivalents (MMcfe).....................        20,965             14,037
Average sales price (1):
  Oil (per Bbl).......................................       $ 12.67            $ 17.70
  Gas (per Mcf).......................................          2.02               2.24
  Natural Gas Equivalents (per Mcfe)..................          2.05               2.46
Oil and gas production lifting costs (per Mcfe) ......           .68                .56
Production taxes and other costs (per Mcfe)(2)........       $   .31            $   .35
</TABLE>

----------

     (1) Before deduction of production taxes and net of hedging results for the
two years ended  December 31, 1998.  
     (2) Includes ad valorem  taxes,  insurance, bonds, company overhead and net
profits interest.


                                       16

<PAGE>



Drilling Activity

     The  following  table sets  forth the  results  of the  Company's  drilling
activities during the two fiscal years ended December 31, 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)
    ----         ------------       -----       -------------      -------          -----      -------------      -------
    1998       Exploratory
                 Texas                5              4                1              3.25          2.64             .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.




                                       17

<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,  1998.  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, 1998
                                            Gross(1)                                     Net(2)
Location                        Oil           Gas           Total           Oil            Gas           Total
--------                        ---           ---           -----           ---            ---           -----

Texas......................    1,438           904          2,342           671            621          1,292
Oklahoma...................       31           361            392            27            160            187
Mississippi................        4             0              4             3              0              3
New Mexico.................       60           245            305            37            149            186
California.................       14             0             14             1              0              1
Kansas.....................        2             0              2             2              0              2
                           ---------------------------------------------------------------------------------------------------------

         Total ............    1,549         1,510          3,059           741            930          1,671
                           ---------------------------------------------------------------------------------------------------------
</TABLE>


----------


       (1)   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, but do not include injector wells.
       (2)   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, 1998.
<TABLE>
<CAPTION>
<S>                                          <C>              <C>             <C>                <C>    

                                                     Developed                         Undeveloped
                                             Gross (a)        Net (b)         Gross (a)          Net (b)
Texas..............................           258,664         210,972          75,381             39,373
Oklahoma...........................            93,138          66,370           6,582              3,302
Mississippi........................               528             452               0                  0
New Mexico.........................            41,437          35,420               0                  0
California.........................               509              38               0                  0
Kansas.............................                80              69               0                  0
                                   -------------------------------------------------------------------------------------------------

    Total..........................           394,356         313,321          81,963             42,675
                                   -------------------------------------------------------------------------------------------------

</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.




                                       18

<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  developed   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 1998.

















                     [Rest of page intentionally left blank]

                                       19

<PAGE>



                                     PART II

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

     The Common Stock 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."
Prior to March 8,  1996,  the  Common  Stock was  listed on the  American  Stock
Exchange  Emerging Company  Marketplace.  At December 31, 1998, there were 3,543
stockholders of record.
<TABLE>
<CAPTION>
<S>                                                                     <C>            <C>           <C>    

                                                                                                     Average Daily
                                                                                                     Trading Volume
                                                                          High           Low            (Shares)
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
1997
   First Quarter . . . . . . . . . . . . . . . . . . . . . . . . .       $6.63         $4.19             96,554
   Second Quarter . . . . . . . . . . . . . . . . . . . . . . . .        $6.31         $5.00             41,845
   Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . .       $6.44         $5.00             55,194
   Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . .        $7.94         $4.88            159,423

</TABLE>

     On March 31, 1999,  the last reported  sale price of the  Company's  Common
Stock on the American Stock Exchange was $2.88 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.



                                       20

<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, 1998,  1997,  1996, 1995 and 1994, which have been derived from the
Company's  audited  consolidated  financial  statements and notes  thereto,  and
unaudited  summary pro forma data for the year ended  December 31, 1998. The pro
forma data gives  effect to the  consummation  of the TEL Offshore and Spirit 76
Acquisitions and the ONEOK Transaction.  The pro forma income statement data and
other data for the year ended December 31, 1998 reflects such  adjustments as if
the TEL  Offshore  and  Spirit 76  Acquisitions  and the ONEOK  Transaction  had
occurred on January 1, 1998.  The pro forma  balance  sheet data  reflects  such
adjustments as if the ONEOK  Transaction  had occurred on December 31, 1998. The
pro forma  financial  data does not  purport  to  represent  what the  Company's
financial position or results of operations would actually have been had the TEL
Offshore and Spirit 76 Acquisition and the ONEOK Transaction in fact occurred on
the assumed date and are not necessarily  indicative of future operating results
or financial position.  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."
<TABLE>
<CAPTION>
<S>                                                <C>         <C>       <C>         <C>         <C>         <C>

                                                                         Year Ended December 31,
                                                                                                              Pro forma
                                                     1994       1995       1996        1997        1998         1998
                                                     ----       ----       ----        ----        ----         ----
                                                                          (dollars in thousands)
Income Statement Data:
Total operating revenues.........................  $     745   $     649    $16,412    $48,834      $51,400     $ 62,588

                                                                             
                                                       1,336       1,692     13,541     39,187       94,362      101,420 
Total operating costs and expenses (1)........... ----------------------------------------------------------------------

Operating profit (loss)..........................       (591)     (1,043)     2,871      9,647      (42,962)     (38,833)
Net income (loss) before extraordinary loss......       (546)       (968)       509     (2,108)     (47,080)     (41,639)
Extraordinary loss from early extinguishment
  of debt, net of taxes .........................          -           -          -     (1,384)           -            -
Net Income (loss) ...............................       (546)       (968)       509     (3,492)     (47,080)     (41,639)
                                                                              
                                                        (580)       (617)      (406)      (875)        (875)      (4,875) 
Dividends applicable to preferred shares......... ----------------------------------------------------------------------
                                                                          
                                                    $ (1,126)    $(1,585)  $    103   $ (4,367)    $(47,955)    $(46,514) 
Income (loss) applicable to common shares........ ----------------------------------------------------------------------
Income (loss) per common share before
 extraordinary item
   Basic.........................................  $   (0.27)   $  (0.28) $    0.01  $   (0.21)   $   (2.26) $     (2.20)
   Diluted.......................................  $   (0.27)   $  (0.28) $    0.01  $   (0.21)   $   (2.26) $     (2.20)
Income (loss) per common share after
 extraordinary item
   Basic.........................................  $   (0.27)   $  (0.28) $    0.01  $   (0.30)   $   (2.26) $     (2.20)
   Diluted.......................................  $   (0.27)   $  (0.28) $    0.01  $   (0.30)   $   (2.26) $     (2.20)

Other Data:
EBITDA (2).......................................  $    (297)   $   (545)   $ 6,166   $ 22,772     $ 22,112   $   31,597
Capital expenditures (3).........................   $  1,945    $  1,244    $41,471   $160,059     $ 70,187   $   71,529
</TABLE>
--------
(1)   Includes in 1998 and pro forma 1998 the write-down of $42,745,000 of oil 
      and gas properties in the full-cost pool due to ceiling test limitation.
(2)   EBITDA is defined as net 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.
(3)   Capital expenditures include cash expended for acquisitions plus normal
      additions to oil and natural gas properties and other
      fixed assets.

                                       21

<PAGE>


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



                                                                              December 31,                              
                                                 -----------------------------------------------------------------------
                                                                                                              Pro forma
                                                     1994       1995        1996        1997        1998        1998
                                                     ----       ----        ----        ----        ----        ----
                                                                         (dollars in thousands)
Balance Sheet Data:
Working capital (deficiency)....................    $1,197   $  (916)    $  2,279   $   2,610    $   (723)   $   (723)
Property, plant and equipment, net..............     7,255     36,405      73,648     221,259     228,436     228,436
Total assets....................................     9,575     40,065      83,072     251,069     267,142     267,142
Total debt(1)...................................       186      9,612      38,766     161,543     231,020     184,637
Stockholders' equity............................    $8,645   $ 24,496    $ 35,154   $  72,140    $ 20,992    $ 67,375
</TABLE>

-----------
(1)      Consists of long-term debt,  including current  maturities of long-term
         debt,  and  excluding   production  payment  liabilities  of  $288,000,
         $937,000, $743,000 and $633,000 as of December 31, 1995, 1996, 1997 and
         1998, respectively.



     The following  table sets forth  unaudited  summary  finacial  results on a
quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
<S>                                          <C>        <C>           <C>        <C>    
                                                                1998
                                            ----------------------------------------------
                                             First       Second        Third      Fourth
                                            ----------------------------------------------
(In thousands, except per share data)
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           973   (46,490) 
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>
<TABLE>
<CAPTION>
<S>                                          <C>        <C>           <C>        <C>    
                                                                1997
                                            ----------------------------------------------
                                             First       Second        Third      Fourth
                                            ----------------------------------------------
Revenues..................................   $ 10,339   $  9,872      $ 13,389   $15,234
Depreciation, depletion and amortization..      1,081      3,379         4,147     3,756
Net Operating Profit......................      1,428      2,039         3,298     2,882
Net Income (Loss) before 
  extraordinary item......................        250       (974)         (509)     (872)
Net Income (Loss).........................        250     (2,358)         (509)     (872)
Income (Loss) per common share, basic
     Before extraordinary loss............   $   0.00   $  (0.09)     $  (0.05)  $ (0.06)
     Extraordinary loss...................        -        (0.10)          -         -
     After extraordinary loss.............       0.00      (0.19)        (0.05)    (0.06)
Income (Loss) per common share, diluted
     Before extraordinary loss............   $   0.00   $  (0.09)     $  (0.05)  $ (0.06)
     Extraordinary loss...................        -        (0.10)          -         -
     After extraordinary loss.............       0.00      (0.19)        (0.05)    (0.06)

</TABLE>

                     


                                       22

<PAGE>



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

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

     During 1996,  management  implemented a business  strategy that  emphasized
acquisition of long-lived,  Proved Reserves with  significant  exploitation  and
development  opportunities  that  management  considered  to have a  lower  risk
profile  than the  Company's  historic  projects.  Prior to 1996 and under prior
management,  the Company was primarily  focused on developing and selling higher
risk,  non-operated  exploratory and  development  projects and did not focus on
acquisitions.  In order to improve the  economics of  acquisitions,  the Company
emphasizes  strict  cost  control in all  aspects of its  business  and seeks to
operate its properties  wherever possible.  The Company also participates,  to a
lesser extent, in selected exploration projects on a controlled risk basis.

     As a part of the Company's new strategy,  in June 1996 the Company acquired
the Panoma Properties for a net purchase price of $34.7 million from Burlington,
which  included  interests in 520 gas wells in the Texas  Panhandle  and western
Oklahoma and an associated 427 mile gas gathering  system.  The Company  assumed
operations of  approximately  90% of the wells and of the  gathering  system and
began  planning  for  increased  density  development  drilling  on  the  Panoma
Properties.

     In January 1997 the Company  purchased for $2.5 million a 50% interest in a
gas processing  plant, the McLean Gas Plant,  which currently  processes 100% of
the gas produced from the Panoma  Properties.  The Company  receives 100% of the
net profits of the plant until it recoups its  investment,  after which time the
Company will receive 50% of the net  profits.  At January 31, 1999,  the Company
had  recouped  approximately  54% of its  $2.5  million  investment.  Management
believes  that the  acquisition  of the McLean Gas Plant  allows the  Company to
capture a significant  portion of the profits  generated from processing the gas
produced  at the  Panoma  Properties  that  would  otherwise  go to third  party
processors.

     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  consist 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  April  29,  1997  the  Company  received  and  accepted  two  new  loan
commitments  from Bankers Trust  Company,  as Agent,  and other banks for senior
credit facilities for the Company and several of its  subsidiaries.  The two new
senior credit  facilities  were structured as the $130.0 million Credit Facility
with a term of five  years  and a $60.0  million  one year  senior  subordinated
bridge  facility (the "Term Loan  Facility")  convertible  into a five year term
loan. The new credit facilities were conditioned,  among other things,  upon the
closing of the Permian  Basin  Acquisition,  which took place on April 30, 1997.
The Credit Facility  provided the Company the flexibility of choosing a range of
either  "LIBOR" or "Prime" based  interest rate  options.  This Credit  Facility
replaced the Company's  previously  existing  $100.0  million  revolving  credit
facility.

     On May 29, 1997, the Company placed,  through a Rule 144A private placement
offering,  $140 million in Senior  Notes due 2007.  The Notes have a 10% coupon,
with interest  payable on June 1 and December 1, commencing on December 1, 1997.
Except for Bluebird  Energy,  Inc. there is no restriction on the ability of any
consolidated  or  unconsolidated  subsidiary to transfer funds to the Company in
the form of cash dividends, loans or advances. Net proceeds from the sale of the
Senior Notes were used to completely repay the Company's outstanding bridge loan
facility in the principal amount of $60 million with the remaining proceeds used
to repay a substantial  portion of the Company's  outstanding  revolving  credit
facility. At that time, the maximum commitment under the revolving credit

                                       23

<PAGE>



facility was reduced from $130 million to $75 million,  with a borrowing base of
$60  million.  The credit  facility was amended as of  September  30,  1997,  to
increase the maximum  commitment from $75 million to $125 million,  increase the
borrowing  base by $5 million to $65 million,  and modify the  interest  expense
coverage ratio test.

     On  December  18,  1997,  the  Company  acquired  a  thirty  percent  (30%)
membership  interest in NGTS,  LLC., a newly formed  wholly-owned  subsidiary of
Natural Gas  Transmission  Services,  Inc., a natural gas  marketing and trading
company. NGTS, LLC assumed all of the parent company's operations as of December
1, 1997.  The  Company,  as of  December  1, 1997,  dedicated  its  natural  gas
production to NGTS, LLC for marketing.  The Company's $4.35 million  acquisition
was completed for a combination  of cash ($2.35  million) and  promissory  notes
($2.0  million)  that  had  equity  "put"  features.  The  Company  retired  the
promissory notes with cash on January 31, 1999.

     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,  became 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 newly  formed 100% owned
subsidiary,  Bluebird Energy,  Inc. acquired from Spirit 76 natural gas reserves
and  associated  assets  in  producing  fields  located  in  Oklahoma  and Texas
currently  producing about 12 million cubic feet of natural gas equivalent per
day. 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
the 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 banks. The maturity date of the bridge
loan facility,  as amended,  is April 15, 1999. The loan is  non-recourse to the
Company.  Bluebird has secured a commitment for permanent  financing from a bank
providing  for a  revolving  credit  facility  of $75  million  with an  initial
borrowing  base of $30  million,  due  three  years  from  the  date of  closing
(anticipated  to be April 15,  1999) with  interest  rates for both  "LIBOR" and
"Base Rate" (Prime).

     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 SEC 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.



                                       24

<PAGE>



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.

     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 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. While
this write-down is not recoverable if prices increase, it should have the effect
of  lowering  the  Company's  future  depletion  rates.  Without  the benefit of
improvements in pricing  subsequent to December 31, 1998, the Company would have
incurred an  impairment of $81.2  million.  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 $52.6 million to a loss of $43.0 million in 1998
versus a profit of $9.6 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 decreased 25% to $572,000 in 1998 versus $762,000 in 1997 due
to gain on sale of  marketable  securities  in 1997 which did not occur in 1998.
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

                                       25

<PAGE>



interest loss in Hunter Butcher,  the Company reported a net loss in 1998 before
extraordinary  item of  $47.1  million,  or $2.26  per  common  share,  versus a
minority  interest loss of $19,000 and a net 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  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) in 1997 compared to a net loss of $48.0 million
($2.26 per common share) in 1998. The Company  accrued  $875,000 in dividends on
its preferred stock in both years 1998 and 1997.

Results of Operations For the Years Ended 1997 and 1996

     As discussed  above,  the Company  acquired the Panoma  Properties  in June
1996, the McLean Gas Plant in January 1997, and the Permian Basin  Properties in
April 1997. As such,  the results of  operations  for the fiscal year ended 1997
included  twelve months of operations  for the Panoma  Properties and the McLean
Gas  Plant  and  eight  months  for the  Permian  Basin  Properties,  while  the
corresponding  period in 1996  contained six months of operations for the Panoma
Properties and no results  related to the McLean Gas Plant and the Permian Basin
Properties.  Unless otherwise stated,  the increases in the 1997 period over the
1996 period were a direct result of these acquisitions.

     Oil and gas sales were $34.6 million in 1997, a 237% increase over sales of
$10.2  million in 1996.  In 1997,  the Company  sold  737,289 Bbl of oil, a 286%
increase,  and 9,614 MMcf of gas, a 259% increase over the prior year. The price
received  for oil was  $17.70  per Bbl and for gas was  $2.24  per Mcf in  1997,
representing  a 13%  decrease  in oil price from $20.46 per Bbl in 1996 and a 5%
decrease in gas price from $2.37 per Mcf in 1996. Oil and gas  production  costs
increased  192% to $12.8  million in 1997 from $4.4  million in 1996.  The gross
operating  margin from oil and gas  production was $21.8 million in 1997, a 271%
increase over the gross  operating  margin of $5.9 million in 1996,  principally
due to the volume increase of oil and gas sold. On an equivalent unit basis, the
gross margin was $1.55 per Mcfe in 1997 versus $1.53 in 1996, a 1% increase.

     Gas gathering, marketing, and processing revenues were $10.3 million in the
1997 period,  a 79% increase over  revenues of $5.8 million in 1996.  Costs from
these  activities  were $7.9 million in 1997, a 68% increase  over costs of $4.7
million in 1996.  Gross  operating  margin was $2.4  million in 1997 versus $1.1
million in 1996, a 125% increase.  Total gathering system  throughput  increased
60% to 20.5 MMcf per day in 1997 compared with 12.8 MMcf per day in 1996. Due to
the McLean Gas Plant acquisition,  gas plant processing throughput was 14.9 MMcf
per day in 1997  versus  none  reported  in 1996.  Gross  operating  margin from
gathering  operations  was $0.22 per Mcf of  throughput in 1997 versus $0.23 per
Mcf in 1996. The gross operating margin from gas processing was $0.20 per Mcf of
throughput versus none reported in 1996.

     Revenues from oil field services and international  sales were $4.0 million
in 1997, an 885% increase over revenues of $396,000 in 1996,  principally due to
an increase in sales of Hunter Butcher International,  L.L.C. ("Hunter Butcher")
in the amount of $3.4 million. Operating costs were $3.7 million in 1997, a $3.5
million  increase over 1996, also  principally due to Hunter Butcher.  The gross
operating  margin from these  activities was $223,000 in 1997 versus $129,000 in
the 1996 period.  The margin from Hunter Butcher  operations was $60,000 in 1997
versus  $32,000 in the 1996  period.  Oil field  services  produced an operating
margin of $163,000 in 1997 versus a loss of $97,000 in 1996.

     Depreciation and depletion  expense increased 319% to $12.4 million in 1997
from $3.0 million in 1996 due to the acquisitions.  Depletion expense on oil and
gas production in 1997 was $11.6 million, or $0.82 per Mcfe, in 1997 versus $2.6
million,  or  $0.70  per  Mcfe,  in 1996.  General  and  administrative  expense
increased  92% to $2.4  million  in 1997  from  $1.2  million  in  1996,  due to
increased staffing and other costs as a result of the acquisitions and increased
activity levels of the Company.



                                       26

<PAGE>



     Operating  profit  increased  to $9.6  million in 1997 from $2.9 million in
1996, a 236% increase.  Equity in earnings of affiliate,  net of income tax, was
$6,000 in 1997  versus  none  reported  in 1996 due to the NGTS  acquisition  in
December,  1997.  Other income increased 122% to $762,000 due to gain on sale of
marketable securities.  Interest expense increased to $13.8 million in 1997 from
$2.4 million in 1996, an increase of 476%, due to increased  levels of borrowing
under the Company's revolving credit lines, the Notes, and bridge financing used
to fund the acquisitions  previously mentioned.  The Company incurred a net loss
before  income tax and  minority  interest of $3.4  million in 1997,  versus net
income  of  $821,000  in  1996,  principally  due  to  interest  expense  on the
acquisitions  exceeding  operating  income  and  due to the  higher  charge  for
depreciation  and  depletion.  The Company  provided  for a deferred  income tax
benefit of $1.3 million on this loss in 1997 versus  deferred income tax expense
of $312,000 in 1996. After recording a $19,000 minority  interest loss in Hunter
Butcher,  the Company reported a net loss in 1997 before  extraordinary items of
$2.1 million,  or $0.21 per common share,  versus a $509,000 net profit, or $.01
per common share, in 1996.

     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  Standards  ("SFAS")  No. 4, from the early
extinguishment of bank debt. The early  extinguishment was a result of the Notes
financing and new amended  revolving  credit  agreements  with banks arranged to
repay the Company's previous credit facility in conjunction with the purchase of
the Permian Basin  Properties from  Burlington.  The net loss in 1997, after the
extraordinary charge,  applicable to common shareholders was $4.4 million ($0.30
per common share)  compared to net income of $103,000 ($.01 per common share) in
1996. The Company  accrued  $875,000 in dividends on its preferred stock in 1997
versus $406,000 in 1996.

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 December 1996 the Company issued $10.0 million of TCW Preferred Stock to
facilitate its development drilling program.

     On April 30, 1997 the Company  closed the  acquisition of the Permian Basin
Properties for a net purchase price of approximately $133.8 million. At the same
time, the Company's  previously  existing  $100.0  million  credit  facility was
replaced by two new credit  facilities;  a $130.0 million Credit  Facility and a
$60.0  million  Term Loan  Facility  for a combined  aggregate  amount of $190.0
million. The initial advances under these new facilities totaled $179.5 million,
including funds to complete the Permian Basin Acquisition,  to pay principal and
accrued interest  remaining on the Company's  previous credit  facility,  and to
provide cash for working capital purposes.

     On May 29, 1997 the Company  sold,  through a Rule 144A  private  placement
offering,  $140.0 million aggregate principal amount of Notes. Net proceeds from
the sale of the Notes  were used to  completely  repay the  Company's  Term Loan
Facility in the  principal  amount of $60.0  million and to repay a  substantial
portion of the indebtedness  outstanding  under the Credit  Facility.  The Notes
bear interest at 10% per annum,  with interest  payable on June 1 and December 1
commencing on December 1, 1997. After paydown,  the maximum commitment under the
Credit  Facility  was  reduced  from  $130.0  million to $75.0  million,  with a
Borrowing  Base of $60.0  million.  The Credit  Facility  was amended  effective
September  30, 1997 to increase  the maximum  commitment  from $75.0  million to
$125.0 million, increase the Borrowing Base by $5.0 million to $65.0 million and
modify the  Consolidated  EBITDA to Interest  Expense  ratio.  In July 1998, the
Credit  Facility was enhanced by extending the term of the facility from four to
five years, improving the tests concerning certain financial covenants which the
Company  must meet,  and  lowering  interest  rate  spreads by 1/4  percent.  In
December 1998, the Credit Facility was amended to allow for a temporary increase
of the borrowing  base to $70 million in  anticipation  of the sale of preferred
stock described below.  With these  adjustments,  total long-term debt under the
Credit Facility at December 31, 1998 was $65 million, leaving

                                       27

<PAGE>



     $5 million available to draw at such time, prior to the next borrowing base
redetermination.  At December 31, 1998, the Company had $4.9 million in cash and
cash equivalents a working capital  deficiency of $723 thousand,  in addition to
the funds available under the Credit Facility.

     The Company called for redemption on November 14, 1997 its publicly  traded
Warrants,  each of which was  exercisable for three shares of Common Stock at an
exercise  price of $5.50 per share and  redeemable  at $0.02 per  Warrant.  As a
result,  Warrants were  exercised  for an aggregate of 846,256  shares of Common
Stock and the  remaining  Warrants  covering  7,920  shares of Common Stock were
redeemed.  The Company received cash proceeds of approximately $4.7 million.  In
addition,  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.

     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.

     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 $1.9 million.  In February 1999,
the program was revised to remove the share limitation discussed above.

     In December  1998, the Company's 100% owned  subsidiary,  Bluebird  Energy,
Inc.,  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
banks. The maturity date of the bridge loan facility,  as amended,  is April 15,
1999, and is non-recourse to the Company.  Bluebird has secured a commitment for
permanent financing from a bank providing for a revolving credit facility of $75
million with an initial borrowing base of $30 million,  due three years from the
date of closing  (anticipated to be April 15, 1999) with interest rates for both
"LIBOR" and "Base Rate" (Prime).

     In December 1998, the Company  announced a letter of intent for a strategic
alliance  with another  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 will be payable in cash  beginning  August of
1999 at the  rate of 8% per  annum  and  will be  cumulative.  The net  proceeds
received  from the sale of Preferred  Stock,  $46.4  million,  was used to repay
senior bank indebtedness.

     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 $75.4 million
in  investing  activities  for  additions to property  and  equipment  and other
investments.  Cash flow from financing activities were $63.5 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.


                                       28

<PAGE>



     For 1996, the Company had a net increase in cash of $143,000. The Company's
operating  activities  provided  net  cash of  $3.0  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
$41.5 million in investing activities, principally for additions to property and
equipment of $41.5  million,  as well as increases in deposits and other assets.
Financing  activities  provided  $38.6  million  of cash,  principally  from the
aggregate  proceeds  from the  issuance of long-term  debt of $56.5  million and
production  payments of $750,000,  less the  combined  payments on such debt and
production  payments  totaling  $27.5  million,  as well as  proceeds  from  the
issuance of preferred  stock of $9.8 million.  The Company also paid $295,000 to
redeem a portion of the outstanding Series C Preferred Stock and $438,000 to pay
dividends on preferred stock.

Capital Requirements

     For fiscal  1999 the  Company has  budgeted  approximately  $10 million for
development  and  exploration  activities,  including  $9 million  budgeted  for
development  projects on the Permian Basin,  Panoma Properties and Walker County
and $1 million budgeted for exploration projects.  While the Company has not yet
developed  a budget  for  fiscal  2000,  the  reserve  report  includes  capital
expenditures  of  approximately  $12.7 million on  development  activities.  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. Due to the recent decline in oil and gas prices, the Company may
redirect  some of its budgeted  funds or it may defer certain  projects  until a
later date. As a result, actual capital expenditures may vary significantly from
current expectations.

     In  connection  with  the  acquisition  of 30% of  the  outstanding  common
member's equity of NGTS, the Company was obligated to pay a note of $2.0 million
to current and former shareholders of NGTS. The loan repayment was originally at
the Company's  option  payable in common stock or cash at December 31, 1998. The
repayment  date was amended to February 1, 1999 and was paid on such date by the
Company with cash.

     During February 1999, the Company closed its sale of Convertible  Preferred
Stock  realizing  net  proceeds  of  approximately  $46.4  million,  which  were
principally used to repay senior bank indebtedness.

     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  $42  million  after  the  sale of  Convertible
Preferred  Stock in  February  1999) will be  adequate  to meet its  anticipated
requirements for working capital,  capital  expenditures and scheduled  interest
payments  for the  foreseeable  future.  The Credit  Facility  contains  several
financial loan  covenants,  one of which in  particular,  the EBITDA to interest
ratio, is very sensitive to oil and natural gas price levels.  While the Company
is in compliance  with this covenant at December 31, 1998, a continuation of low
product prices in the future might  jeopardize this ratio.  The Company has been
considering several  alternatives to reduce this risk, including the acquisition
or drilling of higher cash flow producing  properties  (shorter reserve life) to
somewhat offset its long lived reserve base or monetizing certain  non-strategic
assets.

     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 would 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 1996, the Company  experienced  some inflation in oil and gas prices
with moderate increases in property  acquisition and development  costs.  During
1997,  the Company  received  significantly  lower (13%) oil prices and slightly
lower (1%) gas prices for the natural resources produced from its properties. In
1998, the Company

                                       29

<PAGE>



experienced  a further  erosion of prices of 28% for oil and 10% gas. Due to the
severity  of the  decline in prices,  the  Company  experienced  a loss from the
write-down of its full cost pool. 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 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.  Subsequent  to year end 1998,  oil prices rose while gas prices
declined slightly.

     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

     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, 1998, the Company had the following open contracts:

         Type              Volume/Month            Duration           Avg. Price
Oil
         Collar.......            15,000 Bbl   Jan 99 - Dec 99    Floor - $15.00
                                                                  Cap -   $19.20
         Call Option..            15,000 Bbl   Jan 99 - Dec 99            $19.20
Gas
         Swap ........         100,000 MMBtu   Jan 99 - Mar 99             $2.36
         Swap.........         600,000 MMBtu   Apr 99 - Oct 99             $2.04
         Collar.......         600,000 MMBtu   Jan 99 - Mar 99    Floor -  $2.23
                                                                  Cap -    $2.68
         Call Option..         200,000 MMBtu   Jan 99 - Mar 99             $2.75

     Net gains and (losses)  related to  derivative  transactions  for the years
ended  December  31,  1998,  1997 and 1996  were  $2,739,000,  $(1,537,000)  and
$(272,000),  respectively.  At  December  31,  1998,  the  unrealized  gain from
derivative transactions was $1,198,000.

Year 2000 Compliance

     Year 2000 issues relate to the ability of computer programs or equipment to
accurately  calculate,  store or use dates after December 31, 1999.  These dates
can be handled or interpreted in a number of different ways, but the most common
errors are for the system to contain a two digit year which may cause the system
to interpret  the year 2000 as 1900 or 1980,  and the system will not  recognize
the  year  2000 as a leap  year.  Errors  such as these  can  result  in  system
failures,  miscalculations  and the disruption of operations,  including,  among
other things, a temporary  inability to process  transactions,  send invoices or
engage in similar normal business activities. In response to the Year 2000

                                       30

<PAGE>



issues,  the Company has  developed a strategic  plan divided into the following
phases:  inventory,  product  compliance  based on  vendor  representations  and
in-house testing, third party integration and development of a contingency plan.

     All of the Company's  processing  needs are handled by third party systems,
none of which  have  been  substantially  modified  and all of which  have  been
purchased  or  upgraded  within the last few  years.  Therefore,  the  Company's
initial review of its in-house  systems with regard to Year 2000 issues required
an  inventory  of its  systems and a review of the vendor  representations.  The
Company has completed this initial review of its  information  systems,  various
types of equipment and non-information  technology have also been reviewed,  and
based on vendor  representations,  are either compliant,  will be compliant with
the next forthcoming software release or are systems that are not date specific.

     The Company's non-information  technology consists primarily of various oil
and gas exploration and production equipment. The initial review has established
that the primary  non-information  technology  systems  functions are either not
date sensitive or are Year 2000 compliant based on vendor  representations,  and
are  therefore  predicted to operate in  customary  manners when faced with Year
2000 issues.  However, the Company has determined that in the event such systems
are unable to address the Year 2000, employees can manually perform most, if not
all, functions.

     In  anticipation  of Year 2000 issues,  the Company is also  evaluating the
Year 2000 readiness status of its third party service suppliers.  In addition to
reviewing Year 2000 readiness  statements  issued by the third parties  handling
the Company's  processing needs, to date the Company has received and is relying
upon, Year 2000 readiness reports  periodically issued by its financial services
and electrical  service  providers,  vendors and purchasers of the Company's oil
and  natural  gas  products.  The  Company  is  continuing  to review  Year 2000
readiness of third party service  suppliers and based on their  representations,
does not currently foresee material  disruptions in the Company's  business as a
result of Year 2000 issues.  Unanticipated prolonged losses of certain services,
such as  electrical  power,  could  cause  material  disruptions  for  which  no
economically feasible contingency plan has been developed.

     The Company is continuing to conduct  in-house  testing of the core systems
and  non-information  technology,  and to date  either all  systems  tested have
adequately  addressed  possible Year 2000 scenarios or the Company has a plan in
place to remedy the  deficiency.  The Company  expects  testing to be  completed
during the second quarter of 1999.  After the completion of its Year 2000 review
and testing,  the Company will further  develop a contingency  plan as required,
including  replacing or  upgrading by December 31, 1999 any system  incapable of
addressing the Year 2000 correctly.  This final step is expected to be completed
during the third quarter of 1999.

     Although  the  effects  of  Year  2000  issues  cannot  be  predicted  with
certainty,  the Company  believes  that the  potential  impact,  if any, of such
events will, at most, require employees to manually complete otherwise automated
tasks or  calculations,  other than those which  might  occur in a "worst  case"
scenario as described below, which the Company does not anticipate will occur.

     After  considering  Year 2000 effects on in-house  operations,  the company
expects a minimal  level of  additional  training  would be  required to perform
these tasks on a manual basis due to the level of  experience  of its  personnel
and the routine nature of the tasks being performed. If, based on the results of
its in-house testing,  the Company should determine that certain systems are not
Year 2000  compliant  and it  appears  as though  the system is not likely to be
compliant  within a  reasonable  time  period,  the Company will either elect to
perform  the task  manually or will  attempt to purchase a different  system for
that  particular task and convert before December 31, 1999. The Company does not
believe  that  either  option  would  impact the  Company's  ability to continue
exploration  drilling,  production or sales  activities,  although the tasks may
require  additional  time and  personnel to complete  the same  functions or may
require  incremental  time and  personnel  during 1999 for a conversion to a new
system.

     The Company's core business consists primarily of oil and gas acquisitions,
development  and exploration  activities.  The equipment that is deemed "mission
critical" to the Company's  activities  requires  external power sources such as
electricity  supplied by third parties.  Although the Company  maintains limited
on-site secondary power

                                       31

<PAGE>



sources  such  as  generators,  it is  not  economically  feasible  to  maintain
secondary  power  supplies for any major  component  of its  "mission  critical"
equipment.  Therefore,  the most reasonably likely worst case Year 2000 scenario
for the Company would involve a disruption  of third party  supplied  electrical
power,  which  would  result in a  substantial  decrease  in the  Company's  oil
production.  Such  event  could  result in a  business  interruption  that could
materially affect the Company's operations, liquidity or capital resources.

     The  Company  has  initiated  the third  party  integration  phase and will
continue to have formal communications with its significant suppliers,  business
partners  and key  customers  to  determine  the extent to which the  Company is
vulnerable  to either the third parties or its own failure to correct their Year
2000 issues.  The Company has been communicating with such third parties to keep
them informed of the Company's  internal  assessment of its Year 2000 review and
plans. This portion of the review and discussions with third parties is expected
to be  completed  during the  second  quarter  of 1999.  To date,  approximately
three-quarters   of  these  third  parties  have  provided   certain   favorable
representations   as  to  their  Year  2000   readiness  and  received   similar
representations from the Company.  There can be no guarantee that the systems of
other companies on which the Company relies will be timely converted or that the
conversion  will be  compatible  with  the  Company's  systems.  However,  after
reviewing and estimating the effects of such events,  the Company's  contingency
plan involves identifying and arranging for other vendors,  purchasers and third
party contractors to provide such services,  if necessary,  in order to maintain
its normal operations.

     The Company has, and will  continue to,  utilize both internal and external
resources to complete  tasks and perform  testing  necessary to address the Year
2000 issue.  The Company has not incurred,  and does not anticipate that it will
incur, any significant  costs relating to the assessment and remediation of Year
2000 issues.

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 will be effective
for the Company's fiscal year 2000,  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

                                       32

<PAGE>



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  applies to related  contract  volumes,  the  Company has a
credit risk in the event of nonperformance of the counterparty to the agreement.
The Company does not anticipate any material impact to its results of operations
as a result of nonperformance by such parties.

     At March 1, 1999, the Company had the following open contracts:


             Type             Volume/Month          Duration          Avg. Price
Oil
     Collar.............        15,000 Bbl     Jan 99 - Dec 99   Floor - $15.00
                                                                 Cap -   $19.20
     Call Option........        15,000 Bbl     Jan 99 - Dec 99           $19.20
Gas
     Swap ..............       100,000 MMBtu   Jan 99 - Mar 99            $2.36
     Swap...............       600,000 MMBtu   Apr 99 - Oct 99            $2.04
     Swap...............       555,000 MMBtu       March 99               $1.796
     Collar ............       600,000 MMBtu   Jan 99 - Mar 99   Floor -  $2.23
                                                                 Cap -    $2.68
     Call Option........       200,000 MMBtu   Jan 99 - Mar 99            $2.75

     Based on future market  prices at December 31, 1998,  the fair value of the
open contracts was $1,198,000. If future market prices were to increase 10% from
those in effect at December 31, 1998, the fair value of the open contracts would
be $(236,000).  If future market prices were to decline 10% from those in effect
at December 31, 1998, the fair value of the open contracts would be $2,682,000.

     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.






                     [Rest of page intentionally left blank]


                                       33

<PAGE>



     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 Company does not hold or
issue derivative financial instruments for trading purposes.

     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>      <C>


  Expected Maturity Dates
      (in thousands)          1999      2000       2001      2002      2003    2004-2006   2007      Total   Fair Value
                              ----      ----       ----      ----      ----    ---------   ----      -----   ----------
Variable Rate Debt:
Bank Debt (1)..............   $  -      $ -        $ -       $26,000   $65,000    $ -     $ -       $ 91,000   $ 91,000

Fixed Rate Debt:
Senior Notes (2)...........   $  -      $ -        $ -       $ -       $ -        $ -     $140,000  $140,000   $117,600
Other (3)..................   $2,020    $ -        $ -       $ -       $ -        $ -     $ -       $  2,020   $  2,020
</TABLE>

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


(1) The average interest rate on the bank debt is 7.6%. (2) The interest rate on
the senior  notes is a fixed 10%.  (3) The  average  interest  rate on the other
notes is 8.9%.











                     [Rest of page intentionally left blank]


                                       34

<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, 1998 and 1997..................F-2

  Consolidated Statements of Operations and Comprehensive Income
    for the Years Ended December 31, 1998, 1997 and 1996.....................F-3

  Consolidated Statements of Stockholders' Equity for the
    Years Ended December 31, 1998, 1997 and 1996.............................F-4

  Consolidated Statements of Cash Flows for the Years
    Ended December 31, 1998, 1997 and 1996...................................F-5

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

Supplemental Information (Unaudited)........................................F-26

                                       35

<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, 1998, and 1997, and
the related  statements of operations and  comprehensive  income,  stockholders'
equity,  and cash flows for the three  years  ended  December  31,  1998.  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  generally  accepted  auditing
standards.  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, 1998 and 1997, and
the  results of their  operations  and its cash flows for the three  years ended
December 31, 1998, in conformity with generally accepted accounting principles.



Deloitte & Touche LLP


Dallas, Texas
April 6, 1999




















                                       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,
                                                                                     1998              1997
                                                                                -----------------------------------
                                    ASSETS
Current Assets
     Cash and cash equivalents................................................  $    4,853           $   3,030
     Restricted cash .........................................................         459
     Accounts receivable
          Trade, net of allowance of $166 for 1998 and 1997...................       5,686              12,850
          Due from affiliates.................................................         310                  58
     Notes receivable from affiliate..........................................         747                 355
     Current portion of long-term notes receivable, net of 
       allowance of $790 and $200.............................................          57                 357
     Prepaid and other........................................................       1,577               1,299
                                                                                -----------------------------------
           Total Current Assets...............................................      13,689              17,949
                                                                                -----------------------------------
Property, Plant, and Equipment
     Oil and gas properties, full cost method
           Unproved...........................................................       1,655                 517
           Proved.............................................................     296,545             227,389
     Pipelines................................................................       9,131               9,166
     Other property...........................................................       1,554                 776
                                                                                -----------------------------------
     Total Property, Plant and Equipment......................................     308,885             237,848
           Accumulated depreciation, depletion, amortization and impairment...     (80,449)            (16,589)
                                                                                -----------------------------------
     Net Property, Plant and Equipment........................................     228,436             221,259
                                                                                -----------------------------------
Other Assets
     Deposits and other assets................................................       6,644               5,863
     Investment in unconsolidated affiliate...................................       4,266               4,372
     Deferred tax asset ......................................................      13,351                 -
     Long-term notes receivable, net of imputed interest......................         756               1,626
                                                                                -----------------------------------
     Total Assets                                                               $  267,142           $ 251,069
                                                                                -----------------------------------
                     LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
     Trade payables and accrued liabilities...................................  $   11,821           $   9,235
     Dividends payable........................................................         219                 219
     Suspended revenue payable................................................         359               1,162
     Current maturities of long-term debt.....................................          13                  24
     Notes payable............................................................       2,000               4,699
                                                                                -----------------------------------
           Total Current Liabilities..........................................      14,412              15,339
                                                                                -----------------------------------
Long-Term Liabilities
     Long-term debt, less current maturities..................................     231,007             161,519
     Production payment liability.............................................         633                 743
     Deferred income taxes....................................................         -                 1,289
     Minority interest........................................................          98                  39
Commitments and Contingencies (Note 11)
Stockholders' Equity
     Preferred stock - $.001 par value;  10,000,000 shares  authorized,  
         216,000 designated as Series A; 80,000 issued and outstanding,
         liquidation amount $0................................................         -                   -
         1,000,000 designated as 1996 Series A Convertible; 1,000,000
         issued and outstanding, liquidation amount $10,000,000...............           1                   1
     Common Stock - $.002 par value; 50,000,000 shares authorized,
         21,738,320 shares issued.............................................          43                  43
     Additional paid-in capital...............................................      80,000              80,731
     Accumulated other comprehensive income...................................      (1,429)                -
     Accumulated deficit......................................................     (55,714)             (8,634)
                                                                                -----------------------------------
                                                                                    22,901              72,141
Treasury stock, at cost 
     (1,054,507 and 538,633 shares of common stock, respectively)                   (1,909)                 (1)
                                                                                -----------------------------------
Total Stockholders' Equity....................................................      20,992              72,140
                                                                                -----------------------------------
Total Liabilities and Stockholders' Equity....................................  $  267,142           $ 251,069
                                                                                -----------------------------------
             
   The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
                                       F-2

<PAGE>
                 Magnum Hunter Resources, Inc. and Subsidiaries
         Consolidated Statements of Operations and Comprehensive Income
                  (in thousands, except for per share amounts)
<TABLE>
<CAPTION>
<S>                                                                             <C>               <C>               <C>        
                                                                                                  For the Years Ended
                                                                                                      December 31,
                                                                                ----------------------------------------------------
                                                                                      1998            1997             1996
                                                                                ----------------------------------------------------
Operating Revenues:
   Oil and gas sales..........................................                  $    43,565       $    34,569       $    10,248
   Gas gathering, marketing and processing....................                        6,954            10,297             5,768
   Oil field services and international sales.................                          881             3,968               396
                                                                                ----------------------------------------------------
         Total Operating Revenues.............................                       51,400            48,834            16,412
                                                                                ----------------------------------------------------
Operating Costs and Expenses:
   Oil and gas production lifting costs.......................                       14,265             7,901             4,390
   Production taxes and other costs...........................                        6,417             4,911               -
   Gas gathering, marketing and processing....................                        5,750             7,909             4,708
   Oil field services and international sales.................                          467             3,745               267
   Depreciation, depletion and amortization...................                       21,757            12,363             2,951
   Write-down of oil and gas properties ......................                       42,745               -                 -
   General and administrative.................................                        2,961             2,358             1,225
                                                                                ----------------------------------------------------
         Total Operating Costs and Expenses...................                       94,362            39,187            13,541
                                                                                ----------------------------------------------------
Operating Profit (Loss).......................................                      (42,962)            9,647             2,871

   Equity in earnings (loss) of affiliate, net of income tax..                         (116)                6               -
   Other income...............................................                          572               762               344
   Interest expense...........................................                      (18,207)          (13,788)           (2,394)
                                                                                ----------------------------------------------------
Net Income (Loss) before income tax and minority interest.....                      (60,713)           (3,373)              821
   Benefit (Provision) for deferred income tax................                       13,670             1,284              (312)
                                                                                ----------------------------------------------------
Net Income (Loss) before minority interest....................                      (47,043)           (2,089)              509
   Minority interest in subsidiary earnings (loss)............                          (37)              (19)              -
                                                                                ----------------------------------------------------
Net Income (Loss) Before Extraordinary Loss...................                      (47,080)           (2,108)              509

Extraordinary Loss From Early Extinguishment of Debt, net of
tax benefit of $848...........................................                          -              (1,384)              -
                                                                                ----------------------------------------------------
Net Income (Loss).............................................                      (47,080)           (3,492)              509
   Dividends Applicable to Preferred Stock....................                         (875)             (875)             (406)
                                                                                ----------------------------------------------------
Income (Loss) Applicable to Common Shares.....................                  $   (47,955)      $    (4,367)      $       103
                                                                                ----------------------------------------------------
Net Income (Loss)                                                               $   (47,080)      $    (3,492)      $       509
Other Comprehensive Income, net of tax
   Sale of Investment Shares..................................                          -                 (51)              (57)
   Unrealized Gain (Loss) on Investments......................                       (1,429)              -                  51
                                                                                ----------------------------------------------------
Comprehensive Income (Loss)                                                     $   (48,509)      $    (3,543)      $       503
                                                                                ----------------------------------------------------
Income (Loss) per Common Share - Basic
   Before Extraordinary Loss..................................                  $     (2.26)      $     (0.21)      $      0.01
   Extraordinary Loss.........................................                          -               (0.09)              -
                                                                                ----------------------------------------------------
   After Extraordinary Loss...................................                  $     (2.26)      $     (0.30)      $      0.01
                                                                                ----------------------------------------------------
Income (Loss) per Common Share - Diluted
   Before Extraordinary Loss..................................                  $     (2.26)      $     (0.21)      $      0.01
   Extraordinary Loss.........................................                          -               (0.09)              -
                                                                                ----------------------------------------------------
   After Extraordinary Loss...................................                  $     (2.26)      $     (0.30)      $      0.01
                                                                                ----------------------------------------------------
Common Shares Used in Per Share Calculation
   Basic .....................................................                   21,189,516        14,535,805        12,485,893
                                                                                ----------------------------------------------------
   Diluted ...................................................                   21,189,516        14,535,805        12,561,760
                                                                                ----------------------------------------------------
</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, 1998, 1997 and 1996
                             (dollars in thousands)
<TABLE>
<CAPTION>
<S>                                                   <C>                       <C>                     <C>    

                                                                                                                              
                                                       Preferred Stock             Common Stock           Treasury Stock         
                                                       Shares   Amount          Shares       Amount     Shares         Amount       
                                                   ---------------------------------------------------------------------------------
Balance at December 31, 1995.......................     767,050  $  1           11,598,183   $   23          -       $     -    

  Conversion of preferred stock to common stock...     (658,934)   (1)           1,821,638        4                                 
   preferred stock.................................     (28,116)    -                                                         
  Issuance of 1996 Series A convertible preferred
      stock, net of offering costs.................   1,000,000     1                                                         
  Shares issued as collateral, returned and held as
      treasury stock...............................                                610,170        1     (610,170)         (1)       
  Exercise of employees' common stock options......                                                       12,258          
  Issuance of common stock to acquire oil and gas
    properties.....................................                                188,410        1       51,300                  
  Sale of investment shares........................                                                                                 
  Dividends declared on preferred stock............                                 34,421        -        2,117                  
  Net income from operations.......................                                                                                 
  Unrealized gain on investments...................                                                                                 
                                                   ---------------------------------------------------------------------------------
Balance at December 31, 1996.......................   1,080,000  $  1           14,252,822   $   29     (544,495)    $    (1)       

  Common stock contributed to 401(k) plan..........                                                       13,556           -        
  Exercise of employees' common stock options......                                 89,242        -                                 
  Issuance of common stock for services............                                                        1,000           -        
  Issuance of warrants for services................                                                                                 
  Issuance and costs from exercise of warrants.....                                896,256        2      100,000           -        
  Issuance of common stock to acquire oil and gas
        properties.................................                                                       16,306           -        
  Issuance of common stock, net of offering costs..                              6,500,000       12                                 
  Return of common stock held as collateral to
      treasury.....................................                                                     (125,000)          -
  Costs associated with issuance of preferred stock                                                                                 
  Dividends declared on preferred stock............                                                                                 
  Net loss from operations.........................                                                                                 
  Unrealized (loss) on investments.................                                                                                 
                                                   ---------------------------------------------------------------------------------

Balance at December 31, 1997 ......................   1,080,000  $  1           21,738,320   $   43     (538,633)    $    (1)       
  Common Stock contributed to 401(k) plan .........                                                       12,813           -        
  Exercise of employees' common stock options .....                                                       96,913           -        
  Purchase of treasury stock ......................                                                     (625,600)     (1,908)
  Dividends declared on preferred stock ...........                                                                                 
  Net loss from operations ........................                                                                                 
  Unrealized (loss) on investment .................                                                                                 
                                                   ---------------------------------------------------------------------------------
Balance at December 31, 1998.......................   1,080,000  $  1           21,738,320   $   43   (1,054,507)    $(1,909)       
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S>                                                    <C>                      <C>                     <C>    

                                                   ---------------------------------------------------------------------------------
                                                       Additional               Accumulated Other
                                                        Paid-In                   Comprehensive         Accumulated
                                                        Capital                       Income              Deficit
                                                   ---------------------------------------------------------------------------------

Balance at December 31, 1995.......................   $   29,660                    $     57             $   (5,245)

  Conversion of preferred stock to common stock...            (3)
  Redemption of 28,116 shares of Series C
   preferred stock.................................         (294)
  Issuance of 1996 Series A convertible preferred
      stock, net of offering costs.................        9,785
  Shares issued as collateral, returned and held as
      treasury stock...............................           (1)
  Exercise of employees' common stock options......            9
  Issuance of common stock to acquire oil and gas
    properties.....................................          938
  Sale of investment shares........................                                      (57) 
  Dividends declared on preferred stock............          122                                               (406)
  Net income from operations.......................                                                             509
  Unrealized gain on investments...................                                       51
                                                   ---------------------------------------------------------------------------------
Balance at December 31, 1996.......................    $  40,216                    $     51             $   (5,142)

  Common stock contributed to 401(k) plan..........           59
  Exercise of employees' common stock options......          269
  Issuance of common stock for services............            4
  Issuance of warrants for services................           34
  Issuance and costs from exercise of warrants.....        5,277
  Issuance of common stock to acquire oil and gas
        properties.................................           90
  Issuance of common stock, net of offering costs..       36,161
  Return of common stock held as collateral to
      treasury.....................................    
  Costs associated with issuance of preferred stock         (505)
  Dividends declared on preferred stock............         (875)
  Net loss from operations.........................                                                          (3,492)
  Unrealized (loss) on investments.................                                      (51)
                                                   ---------------------------------------------------------------------------------

Balance at December 31, 1997 ......................    $  80,731                    $      -             $   (8,634)

  Common Stock contributed to 401(k) plan .........           66
  Exercise of employees' common stock options .....           78
  Purchase of treasury stock ......................
  Dividends declared on preferred stock ...........         (875)
  Net loss from operations ........................                                                         (47,080)
  Unrealized (loss) on investment .................                                   (1,429)
                                                   ---------------------------------------------------------------------------------

Balance at December 31, 1998.......................    $  80,000                    $ (1,429)            $  (55,714)
                                                   ---------------------------------------------------------------------------------
</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,
                                                                                ----------------------------------------------------
                                                                                       1998              1997             1996
                                                                                ----------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
   Net Income (loss)..........................................................    $  (47,080)        $   (3,492)       $    509
   Adjustments to reconcile net income (loss) to cash provided by
   (used for) operating activities:
      Extraordinary loss......................................................           -                1,384             -
      Depreciation, depletion and amortization................................        21,757             12,363           2,951
      Write-down of oil and gas properties ...................................        42,745                -               -
      Amortization of financing fees..........................................           793                508             -
      Increase in reserve for doubtful accounts...............................           591                322             -
      Deferred income taxes...................................................       (13,670)            (1,284)            312
      Equity in unconsolidated affiliate......................................           116                 (6)            -
      Minority interest.......................................................            37                 19             -
      (Gain) Loss on sale of assets...........................................            52               (386)           (143)
      Other...................................................................           (83)                93              32
      Changes in certain assets and liabilities
         Accounts and notes receivable........................................         6,859             (8,295)         (3,250)
         Other current assets.................................................          (278)            (1,247)            (30)
         Accounts payable and accrued liabilities.............................         1,849              5,673           2,647
                                                                                ----------------------------------------------------

   Net Cash Provided By Operating Activities..................................        13,688              5,652           3,028
                                                                                ----------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Proceeds from sale of assets...............................................           359                593             318
   Additions to property and equipment........................................       (70,187)          (160,059)        (41,471)
   Increase in deposits and other assets......................................        (3,878)            (6,159)           (527)
   Loan made for promissory note receivable...................................        (1,691)              (237)            (58)
   Payments received on promissory note receivable ...........................            28                256             277
   Other long-term investments................................................           -                 (361)            -
   Investment in unconsolidated affiliate.....................................           -               (2,362)            -
                                                                                ----------------------------------------------------

   Net Cash Used In Investing Activities......................................       (75,369)          (168,329)        (41,461)
                                                                                ----------------------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES:
   Proceeds from the issuance of long-term debt and production payment........        80,000            352,500          57,262
   Fees paid related to financing activities..................................           -               (1,800)            -
   Proceeds from short-term notes payable.....................................           -                2,699             -
   Payments of principal on long-term debt and production payment.............       (10,633)          (229,917)        (27,459)
   Payment of short-term notes payable .......................................        (2,699)               -               -
   Payments of other liabilities..............................................           -                  -              (290)
   Payment of fees on issuance of preferred stock.............................           -                 (505)            -
   Proceeds from issuance of common and preferred stock,
      net of offering costs...................................................            78             41,721           9,796
   Redemption of preferred stock..............................................           -                  -              (295)
   Purchase of treasury stock ................................................        (1,908)               -               -
   (Decrease) in segregated funds for payment of notes payable ...............          (459)               -               -
   Dividends paid.............................................................          (875)              (678)           (438)
                                                                                ----------------------------------------------------

   Net Cash Provided By Financing Activities..................................        63,504            164,020          38,576
                                                                                ----------------------------------------------------


NET INCREASE IN CASH AND CASH EQUIVALENTS.....................................         1,823              1,343             143
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..............................         3,030              1,687           1,544
                                                                                ----------------------------------------------------

CASH AND CASH EQUIVALENTS AT END OF PERIOD....................................  $      4,853         $    3,030        $  1,687
                                                                                ----------------------------------------------------
</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  is  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 a natural gas
processing plant located in Texas.

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,  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 consolidated
on a pro rata  basis  its 40%  ownership  of TEL  Offshore  Trust.  The  Company
accounts  for its  investment  in  NGTS,  Inc.  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   inconsequential
subsidiaries),  and the Company has not presented separate financial  statements
and  other  disclosures   concerning  each  Guarantor  because   management  has
determined  that such  information  is not  material  to  investors.  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  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 at December 31, 1998 is the cash balance of Bluebird.  Cash
funds of Bluebird  are not  permitted to be  commingled  with the Company or its
other  subsidiaries or affiliates.  There was no restricted cash at December 31,
1997.

                                       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, 1997, the Company had no securities  available for sale and
no gross unrealized gains reported in equity.  During 1997, securities were sold
for gross proceeds of $483,500 and the Company realized a gain of $330,000.

     At December 31, 1998,  the  Company's  available for sale  securities  were
classified as non-current  assets and included in deposits and other assets. The
securities  had an amortized  cost basis of $2,954,000,  gross  unrealized  loss
reported in other comprehensive  income of $2,304,000  ($1,429,000 net of income
tax benefit) and a fair market value of $650,000.

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

     The Company  follows the  full-cost  method of  accounting  for oil and gas
properties,  as prescribed by the  Securities and Exchange  Commission  ("SEC").
Accordingly, all costs associated with acquisition,  exploration and development
of oil  and  gas  reserves,  including  directly  related  overhead  costs,  are
capitalized.

     All capitalized  costs of oil and gas  properties,  including the estimated
future costs to develop proved reserves, are amortized on the unit-of-production
method using  estimates of proved  reserves.  Cost 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  periodically  and any  provision  for  impairment  is
transferred to the full-cost  amortization base. Sales of oil and gas properties
are  credited to the  full-cost  pool  unless the sale would have a  significant
effect on the amortization rate. Abandonments of properties are accounted for as
adjustments to capitalized costs with no loss recognized. The Company's unproved
properties  excluded from the amortization  base were $1,655,000 and $517,000 at
December 31, 1998 and 1997, respectively.

     The net capitalized  costs are subject to a "ceiling test," which generally
limits such costs 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.  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.



                                       F-7

<PAGE>


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

Derivative Instruments

     The  Company  frequently  enters  into  swaps,  futures,  options and other
derivative  contracts to hedge the impact of market  fluctuations in gas and oil
prices on  anticipated  future gas and oil  production.  The Company  defers the
impact of  changes  in the market  value of the  contracts  that serve as hedges
until the related transaction is completed.

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.

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.

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.

Comprehensive Income

     SFAS No. 130, "Reporting  Comprehensive Income," became effective as of the
first quarter of 1998. This statement  requires  companies to report and display
comprehensive income and its components (revenues,  expenses, gains and losses).
Comprehensive income includes all changes in equity during a period except those
resulting from investments by owners and  distributions  to owners.  The Company
had an unrealized  loss on investments of $1,429,000  (net of income tax benefit
of $876,000) at December 31,  1998,  resulting in a  comprehensive  loss for the
year ended December 31, 1998, of $48,509,000.

     For the year ended  December 31, 1997,  the Company  recognized  gains from
sale  of  investments  of  $330,000  in net  income,  and a loss  from  sale  of
investment  shares of  $51,000  (net of  income  tax  benefits  of  $31,000)  in
comprehensive income, resulting in a comprehensive loss of $3,643,000.


                                       F-8

<PAGE>


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

     At December 31, 1996, the Company recognized a gain from sale of securities
of $143,000 in net income,  booked an unrealized  gain on investments of $51,000
(net of income tax of $31,000) and  realized a loss from the sale of  investment
shares of  $57,000  (net of income  tax  benefit of  $35,000)  in  comprehensive
income, resulting in comprehensive income of $503,000.

Changes in Accounting Standards

     SFAS  131,  "Disclosures  About  Segments  of  an  Enterprise  and  Related
Information," became effective in 1998. This statement establishes standards for
defining and  reporting  business  segments.  The Company has  determined it has
three reportable  segments,  (1) Exploration and Production,  (2) Gas Gathering,
Marketing and  Processing and (3) Oil Field  Services.  The adoption of SFAS 131
does not  affect  the  Company's  consolidated  financial  position,  results of
operations or cash flows.

     SFAS 133,  "Accounting for Derivative  Instruments and Hedging Activities,"
is effective  for fiscal years  beginning  after June 15, 1999.  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,  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
generally accepted accounting  principles  requires the Company's  management to
make  estimates  and  assumptions  that  affect the  amounts  reported  in these
financial  statements and accompanying  notes.  Actual results could differ from
those estimates. Significant assumptions are required in the valuation of proved
oil and gas  reserves,  which as described  above may affect the amount at which
oil and gas properties are recorded.  It is at least  reasonably  possible those
estimates  could be  revised  in the  near  term and  those  revisions  could be
material.

NOTE 2 -- ACQUISITIONS

     On June 28, 1996, the Company purchased 470 gas wells and approximately 427
miles of a gas  gathering  pipeline  system  for a net  purchase  price of $34.7
million.  The  properties  are  located in the  Panhandle  of Texas and  western
Oklahoma and are referred to as the "Panoma Properties." As the purchase was not
completed  until  the  end of the  second  quarter  of  1996,  the  consolidated
financial  statements  for 1996  include  the  operating  results  of the Panoma
Properties for only the last six months of the year.

     In January 1997,  the Company  purchased a fifty percent (50%)  interest in
the McLean Gas Plant,  the gas  processing  facility  connected to the Company's
Panoma gas gathering  system for $2.5  million.  Under the terms of the purchase
agreement,  the Company  will receive 100% of the net profits of the plant until
it  receives  the $2.5  million  purchase  price at which  point its net profits
interest will revert to fifty percent (50%), the Company's ownership position.



                                       F-9

<PAGE>


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

     On April 30, 1997,  the Company  acquired  from a subsidiary  of Burlington
Resources,  Inc., effective as of January 1, 1997, the Permian Basin Properties,
consisting  of 25 field areas in west Texas and 22 field areas in southeast  New
Mexico,  for a net purchase  price of $133.8  million after  adjustments of $9.7
million for  production  cash flow from  January 1, 1997 to the closing date and
other minor adjustments.

     On  December  18,  1997,  the  Company  acquired  a  thirty  percent  (30%)
membership   interest  in  NGTS,  LLC,  ("NGTS")  a  newly  formed  wholly-owned
subsidiary of Natural Gas Transmission  Services,  Inc., a natural gas marketing
and  trading  company  based in Dallas,  Texas.  NGTS  assumed all of the parent
company's operations as of December 1, 1997. The Company dedicated substantially
all of its natural gas  production to NGTS for  marketing.  The Company's  $4.35
million acquisition was completed with a combination of cash ($2.35 million) and
promissory notes ($2.0 million), which were paid in cash on February 1, 1999.

     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  currently  producing about 16.2
million cubic feet of natural gas equivalent per day. The net purchase price was
approximately  $25 million after certain  purchase price  adjustments  including
preferential rights exercised by third parties and other customary adjustments.

     The following summary,  prepared on a pro forma basis, presents the results
of  operations  for the  years  ended  December  31,  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>    
                                                              1998                1997               
                                                       ----------------------------------------
                                                                               (Unaudited)
                                                       ----------------------------------------
Revenue..............................................    $     62,588,000      $    76,547,000     
Net Income (Loss) Applicable to Common Stock
  before extraordinary items.........................         (46,514,000)          (2,287,000)            
Net Income (Loss) Per Common Share before
  extraordinary items Basic..........................    $          (2.20)     $          (.16)                 
  Diluted............................................    $          (2.20)     $          (.16)                 
</TABLE>

NOTE 3 -- NOTES RECEIVABLE

     On July  28,  1995,  the  Company  received  a  non-interest  bearing  note
receivable  in the amount of $223,500 in exchange for its interest in an oil and
gas  property.  Interest at 10 percent was  imputed on the note  resulting  in a
discount of $28,366.  The note  provides  for payments of $7,000 per month which
were received timely in 1997. As of December 31, 1997, the unpaid  balance,  net
of discount, was $27,705. This note was paid off in 1998.



                                      F-10

<PAGE>


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

     On November 4, 1996, the Company  received an interest  bearing note due on
November  1, 1999,  in  exchange  for its  interest  in oil and gas  properties.
Interest is at the rate of 12% per annum. The note was collateralized by the oil
and gas  properties  sold.  As of  December  31,  1997,  the unpaid  balance was
$1,598,238. During 1998, the required payments under the note were not made, and
the  Company  took  possession  of  the  properties.  The  Company  recorded  an
impairment to the properties of $579,000 at the time it took possession.

     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, 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  and  $353,071  at December  31, 1998 and
1997,  respectively,  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,
1999.

     Through  December 31, 1998, the Company  loaned the Magnum Hunter  Employee
Stock Ownership Plan (ESOP) a total of $878,997 (of which $756,000 is classified
as long-term at December  31,  1998)for  purposes of  purchasing  Magnum  Hunter
Resources Common Stock on the open market.  The loan is interest free and is due
December 31, 2003. The loan is secured by 291,300 shares of the Company's Common
Stock.

     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.  Provided the Company does not  consummate a
business  transaction with the publicly traded oil and gas company by the end of
1999, 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.

     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. The loan bears interest at
10% and is due December 31, 1999.  Subsequent to December 31, 1998,  $65,000 was
repaid on the loan.

     During 1996, as part of the Company's  overall  compensation  package,  the
Company's  officers  and  directors  were  granted the right to  participate  in
certain development and exploration projects of the Company on a promoted basis.
As of December 31, 1996, eleven (11) of the Company's  officers and directors as
a group spent an aggregate  of $137,340  participating  in 6 wells.  The Company
discontinued this program as of January 1, 1997.


                                      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, 1998 and 1997 consisted of
the following:
<TABLE>
<CAPTION>
<S>                                                                           <C>                    <C>    


                                                                                    1998               1997
                                                                             ---------------------------------------

Notes Payable:
Note payable to bank, due March 3, 1998,
  including interest at 8.25%..............................................     $        -             $  2,699,000

Note payable,  secured by stock in NGTS,  LLC.,  due February 1, 1999,  
  interest payable at 9% quarterly
   beginning March 31, 1998................................................        2,000,000              2,000,000
                                                                             ---------------------------------------

         Total Notes Payable...............................................     $  2,000,000           $  4,699,000
 
                                                                             ---------------------------------------


Long-Term Debt:

Banks
Revolving promissory note, collateralized by pipeline and
  oil and gas properties, due April 30, 2003
  (effective rate of 6.81% at December 31, 1998) (1).......................     $ 65,000,000           $ 21,500,000

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) (2) .....................      $ 26,000,000                    -

Note payable to bank collateralized by vehicle,  payable in monthly 
  installments of $1,031 including interest at 8.5% through
  February 1999............................................................            2,000                 13,000

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, assumed in
  Hunter acquisition.......................................................           18,000                 30,000
                                                                             ---------------------------------------
         Total Long-Term Debt..............................................     $231,020,000           $161,543,000
                             Less Current Portion..........................           13,000                 24,000
                                                                             ---------------------------------------
                 Long-Term Debt............................................     $231,007,000           $161,519,000
                                                                             ---------------------------------------

</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:

1999......................................................     $      13,000
2000......................................................             7,000
2001......................................................               -
2002......................................................        26,000,000
2003 to 2006..............................................        65,000,000
2007......................................................       140,000,000
                                                              -----------------
                                                               $ 231,020,000
                                                              =================
    
     (1) 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
$70,000,000  at December 31, 1998.  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, 1998, the amounts borrowed
at these rates were:


LIBOR + 1.5% (total of 6.81%).............................     $  65,000,000
Base Rate (Prime) at 7.75%................................               -
                                                              -----------------
       Total..............................................     $  65,000,000
                                                              -----------------


     (2) 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,  is
April 15, 1999.  The bridge loan is  non-recourse  to the Company.  Bluebird has
secured  a  commitment  for  permanent  financing  from a bank  providing  for a
revolving  credit facility of $75 million with an initial  borrowing base of $30
million,  due three years from the date of closing  (anticipated to be April 15,
1999) with  interest at rate options for both  "LIBOR" and "Base Rate"  (Prime).
The level of the  borrowing  base is  dependent  on the  valuation of the assets
pledged, primarily oil and gas reserve values and Bluebird's interest in the TEL
Offshore Trust. 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.
Borrowings under the line of credit are non-recourse to the Company.

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
and $147,000 at December 31, 1998 and 1997, respectively.

     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  $540,000 and $596,000 at December 31, 1998 and 1997,
respectively.  The  production  payment bears  interest at the rate of 13.5% per
annum and is non-recourse to the Company.



                                      F-13

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

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>    
                                                                              1998                 1997
                                                                      -----------------------------------------

Income tax expense (benefit) at statutory rates......................   $   (21,263,000)     $    (1,153,000)
State tax expense (benefit)..........................................        (1,747,000)            (133,000)
Other................................................................               -               (288,000)
Change in valuation allowance........................................         8,370,000              290,000
                                                                      -----------------------------------------

       Tax expense (benefit).........................................   $   (14,640,000)     $    (1,284,000)
                                                                      -----------------------------------------
</TABLE>
     The tax effects of significant  temporary differences and carryforwards are
as follows:
<TABLE>
<CAPTION>
<S>                                                                      <C>                    <C>    

                                                                                    December 31,
                                                                      ------------------------------------------
                                                                              1998                 1997
                                                                      ------------------------------------------
Property and equipment, including intangible drilling costs..........     $        -            $   (5,245,000)
                                                                      ------------------------------------------
         Total deferred tax liability................................              -                (5,245,000)
                                                                      ------------------------------------------
Allowance for doubtful accounts......................................          414,000                 191,000
Reserves.............................................................           33,000                     -
Property and equipment, including intangible drilling costs..........        8,812,000                     -
Depletion carryforwards..............................................          196,000                 196,000
Operating loss and other carryforwards...............................       12,556,000               3,859,000
                                                                      ------------------------------------------

         Total deferred tax assets...................................       22,011,000               4,246,000
                                                                      ------------------------------------------
Valuation allowance..................................................       (8,660,000)               (290,000)
                                                                      ------------------------------------------
         Net Deferred Tax Asset (Liability)..........................     $ 13,351,000          $   (1,289,000)
                                                                    ------------------------------------------
</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, $876,000.

     The Company and its subsidiaries  have net operating loss  carryforwards of
approximately  $32,986,000 that expire,  if unused,  in years 1999 through 2018,
and of  which  approximately  $608,000  expire  in  1999.  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.

                                      F-14

<PAGE>


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

NOTE 8 -- STOCKHOLDERS' EQUITY

     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 and 1,000,000  shares have been  designated as 1996
Series A Convertible Preferred Stock. Thus, 7,234,000 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.

     The  Series B  Preferred  Stock was  issued as a unit,  comprised  of 1,000
shares of Series B Preferred Stock and two production certificates. The Series B
preferred  stockholders  are entitled to receive  cumulative  dividends of $0.35
annually per share, payable quarterly.  The holders of the units are entitled to
receive $10,000 per unit in dividends and in production payments. The production
payments were derived from 50% of the  Company's net revenue from  production of
oil and gas.  Beginning  June 15,  1994,  the Company  offered to exchange  (the
"Exchange  Offer")  1,250  shares of common  stock for each Series B  production
certificate. All of the shares were converted to common stock during 1996.

     Separate and apart from the Exchange Offer,  two of the Company's  previous
officers and directors (the  "Officers")  set aside 125,000 shares (the "Stock")
of  their  own  common  stock  of  the  Company  for a  single  individual  (the
"Individual")   who  owned   approximately   55%  of  the  Series  B  production
certificates  that were  exchanged.  The Stock was being held by an  independent
party to this transaction  until fair market value of the Exchange Shares,  when
the  Exchange  Shares  become  eligible  for  sale  pursuant  to Rule 144 of the
Securities Act of 1933, was determined. The Company issued 125,000 shares of its
common stock to the Officers in exchange for their  assignment to the Company of
all of the Officers'  rights,  title and interest in the Stock.  The Company has
recorded the new shares  issued at par value.  The value of the exchange  shares
was  determined in 1996, and the Company issued 5,000 shares of its common stock
to the  Individual.  Subsequent to December 31, 1996,  the 125,000  shares being
held were returned to the Company and are being held as treasury stock.

     The Series C preferred stock was convertible at the option of the holder at
any time into three shares of common stock and, after  November 12, 1994,  would
automatically  convert  into common  stock any time the closing bid price of the
common stock equals or exceeds  $5.00 per share for twenty  consecutive  trading
days.  The Series C preferred  stock was  redeemable  by the  Company  beginning
November 12, 1995,  at $10.50 per share plus  accrued and unpaid  dividends.  If
declared  by the Board of  Directors,  dividends  accrued at the annual  rate of
$1.10 per share,  were  cumulative from the date of first issuance and were paid
quarterly in arrears.  The Board of Directors declared dividends on the Series C
preferred  stock of $339,827 for the year ended December 31, 1996. The aggregate
annual dividend  requirements for the 625,000 shares of Series C preferred stock
outstanding at December 31, 1996 was none. As of December 31, 1996, all Series C
preferred stock had been redeemed or converted to common stock.



                                      F-15

<PAGE>


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

     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 $122,000,  $875,000 and $875,000  were  declared in 1996,  1997 and
1998, respectively.

     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.

     The Series C preferred  stock was originally  issued as a unit comprised of
one share of Series C preferred  stock and warrants to purchase three (3) shares
of common stock. A total of 1,687,500  warrants were issued 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 and expiring in January  1999.  At December 31, 1998,  45,000 of these
warrants  had been  earned.  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 expiring 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. No warrants were exercised in 1996. At December 31, 1996,
the Company had 1,176,676 total warrants  issued,  including the publicly traded
warrants.  Additionally,  in 1996,  610,170 shares of the Company's common stock
that had been held as collateral were returned and held in the treasury,  12,258
shares of common stock were issued upon  exercise of employees'  stock  options,
239,710 shares of common stock,  valued at $939,000,  were issued to acquire oil
and gas  properties,  and 36,538 shares of common stock were issued as dividends
on the Company's Series C Preferred Stock.

     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.  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.  At
December 31, 1998 and 1997,  the Company had 166,000 total warrants  issued,  of
which 141,000 had been earned.



                                      F-16

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

     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,  and 96,913 shares were issued upon exercise of
employee stock options.

       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, 1998                December 31, 1997                December 31, 1996
                         -----------------------------------------------------------------------------------------------------------
                                                    Per                              Per                                    Per
                             Loss       Shares     Share       Loss       Shares     Share     Income       Shares         Share
                         (Numerator) (Denominator)Amount    (Numerator) (Denominator)Amount  (Numerator) (Denominator)     Amount
                         -----------------------------------------------------------------------------------------------------------
Income (Loss) before
    extraordinary item...$(47,080,000)                     $(2,108,000)                      $  509,000
  Less: Preferred Stock
              dividends..    (875,000)                        (875,000)                        (406,000)
                         -----------------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available 
  to common stockholders. (47,955,000)  21,189,516 $(2.26)  (2,983,000)  14,535,805  $(.21)     103,000  12,485,893       $   .01
Effect of dilutive 
  securities
   Warrants..............         -            -                   -            -                   -        14,943
   Options...............         -            -                   -            -                   -        60,924
   Convertible preferred 
     stock                        -            -                   -            -                   -           -
Diluted EPS
Income (Loss) available to
  common stockholders and
                         -----------------------------------------------------------------------------------------------------------
   assumed conversions...$(47,955,000)  21,189,51  $(2.26) $(2,983,000)  14,535,805  $(.21)  $  103,000  12,561,760       $   .01
                         -----------------------------------------------------------------------------------------------------------
</TABLE>

     The warrants, options, and convertible preferred stock were not included in
the computation of diluted earnings per share in 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.

                                      F-17

<PAGE>

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

NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION

     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.

     During  1996,  the  Company  purchased  oil and gas  properties  by issuing
239,710 shares of its common stock,  valued at $938,444.  The Company  converted
658,934 shares of Series B and Series C preferred stock into 1,821,638 shares of
common  stock.  The  Company  issued  36,538  shares of common  stock  valued at
$121,700 in lieu of cash  dividends on  preferred  stock.  The Company  received
equity  securities with a fair value of $150,000 as partial payment for the sale
of property interests. Interest paid in 1996 was $2,344,308.

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.

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 2001 with an
option to renew the lease for a three year term.  The various  office  equipment
leases extend until 2002. 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:
1999...............................................................   $  293,662
2000...............................................................      300,516
2001...............................................................      261,072
2002...............................................................       12,475
Thereafter.........................................................          -
                                                                     -----------
 Total Minimum Payments Required                                      $  867,725
                                                                     -----------


     Rental expense was $327,934, $218,951 and $129,169 for 1998, 1997 and 1996,
respectively.

                                      F-18

<PAGE>


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


     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, 1998 and 1997, 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, 1998 is adequate.

     To the extent the Company  receives the spread  between the contract  floor
and the Index  price  applies 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  provided a
$590,000 reserve for the carrying value of a note receivable. After establishing
this  reserve,  management  believes  those market values  approximate  carrying
values at December 31, 1998 and 1997.  The market  values of equity  investments
are based upon quoted prices (see Note 1). At December 31, 1998, the fair market
value of the Company's debt was equal to its carrying value,  except for the 10%
Senior Notes. The fair market value of the 10% Senior Notes was $117,600,000.

NOTE 13 -- COMMODITY DERIVATIVES AND HEDGING ACTIVITIES

     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, 1998, the Company had the following open contracts:
<TABLE>
<CAPTION>
<S>                       <C>                  <C>                 <C>                  <C>    


         Type              Volume/Month            Duration         Avg. Price          Fair Value
Oil
  Collar..............       15,000 Bbl        Jan 99 - Dec 99    Floor - $15.00
                                                                  Cap -   $19.20        $  673,425
  Call Option.........       15,000 Bbl        Jan 99 - Dec 99            $19.20               -
Gas
  Swap ...............      100,000 MMBtu      Jan 99 - Mar 99             $2.36        $  111,000
  Swap................      600,000 MMBtu      Apr 99 - Oct 99             $2.04        $   50,750
  Collar .............      600,000 MMBtu      Jan 99 - Mar 99    Floor -  $2.23
                                                                  Cap -    $2.68        $  363,000
  Call Option.........      200,000 MMBtu      Jan 99 - Mar 99             $2.75               -
</TABLE>

                                      F-19

<PAGE>


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

     Net gains and (losses)  related to  derivative  transactions  for the years
ended  December  31,  1998,  1997 and 1996  were  $2,739,000,  $(1,537,000)  and
$(272,000),  respectively.  At  December  31,  1998,  the  unrealized  gain from
derivative transactions was $1,198,000.

NOTE 14 -- STOCK COMPENSATION PLAN

     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").

ESOP

     The Company  established an ESOP and a related trust 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.  The Plan also allows
for the Company to make discretionary  contributions to the ESOP. It is also the
Company's  intent to invest all  contributions in the Company's Common Stock. In
this  regard,  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.  To fund this
purchase,  the ESOP  borrowed  $84,585 from a bank.  At December  31, 1997,  the
Company contributed funds sufficient to pay off the 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.  The loan is  interest  free and is due
December 31, 2003. The loan is secured by 291,300 shares of the Company's Common
Stock.

1996 Incentive Stock Option Plan

     The Company  established this plan effective April 1, 1996, and is governed
by Section 422 of the Internal Revenue Code, and Section 16(b) of the Securities
Exchange Act of 1934. The Option Plan covers  1,200,000  shares of the Company's
Common Stock.  Eligibility  is limited to employees and directors of the Company
and its  subsidiaries.  The actual selection of grantees is made by the Board of
Directors.  The  term of the  Option  Plan  is 10  years,  and  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 are fully vested and  exercisable  when
granted.  The exercise  price is fair market value at the date of grant,  except
for individuals who own 10% or more of the Company's stock.

     During 1996, the Board granted the remaining  935,442  options to employees
and directors at an exercise price of $4.50 per share.

     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 5
years.

     During  1998,  the Board  granted  220,000 new options to  employees  at an
average  price of $5.89.  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-20

<PAGE>


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

     The following is a summary of stock option activity under the Option Plan:
<TABLE>
<CAPTION>
<S>                        <C>          <C>          <C>         <C>           <C>        <C>


                                     1998                    1997                     1996
                           ----------------------------------------------------------------------------
                                         Weighted                 Weighted                Weighted
                                         Average                  Average                  Average
                                         Exercise                 Exercise                Exercise
                              Shares      Price       Shares       Price       Shares       Price
                           ----------------------------------------------------------------------------
Outstanding -
Beginning of Year..........  2,538,500   $   5.00    1,187,742    $   3.72       264,558    $ 0.82
Granted....................    220,000       5.89    1,440,000        5.93       935,442      4.50
Exercised..................    (96,913)       .81      (89,242)       3.01       (12,258)      .73
Canceled...................        -           -           -            -            -          -
Repriced - previous........ (1,590,000)      5.96          -            -            -          -
Repriced - new.............  1,590,000       3.75          -            -            -          -
                           ----------------------------------------------------------------------------
Outstanding -
End of Year................  2,661,587   $   3.90    2,538,500    $   5.00     1,187,742    $ 3.72
                           ----------------------------------------------------------------------------
Exercisable -
End of Year................  2,501,587               2,338,500                   970,684
                           ----------------------------------------------------------------------------
</TABLE>


     The  following is a summary of stock  options  outstanding  at December 31,
1998:

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

                                                                  Weighted
                                                                   Average
                                           Number of              Remaining
                                            Options           Contractual Life             Number of
Exercise Price                            Outstanding              (Years)            Exercisable Options
                                      ----------------------------------------------------------------------

   $   .73..........................         102,145                 1.0                    102,145
      1.65...........................         18,000                 1.0                     18,000
      3.75...........................      1,590,000                 4.0                  1,430,000
      4.375..........................         25,000                 3.0                     25,000
      4.50...........................        881,442                 2.3                    881,442
      5.25...........................         35,000                 3.4                     35,000
      5.375..........................         10,000                 3.3                     10,000
                                      ----------------------------------------------------------------------
                                           2,661,587                                      2,501,587
                                      ----------------------------------------------------------------------
</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-21

<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>    

                                                                    1998              1997              1996
                                                             ----------------------------------------------------

Net Income (Loss) Applicable to Common Stock:
  As reported..............................................    $ (47,955,000)     $(4,367,000)      $   103,000
  Pro Forma................................................      (49,160,000)      (6,573,000)       (1,540,000)
Basic Earnings (Loss) per Share:
  As reported, after extraordinary loss....................    $       (2.26)     $      (.30)      $       .01
  Pro Forma................................................            (2.32)            (.45)             (.12)
Diluted Earnings (Loss) per Share:
  As reported, after extraordinary loss....................    $       (2.26)     $      (.30)      $       .01
  Pro Forma................................................            (2.32)            (.45)             (.12)
</TABLE>

     The  weighted  average  grant date fair value of new  options  granted  was
$580,000  during  1998.  The weighted  average  grant date fair value of options
repriced in 1998 was $624,884. Fair value of options and warrants was calculated
by using the  Black-Scholes  options pricing model using the following  weighted
average  assumptions  for 1998 activity:  risk free interest rate of 5.5% on new
options and 5.75% on repriced  options,  expected life of 5 years on new options
and 4 years on  repriced  options,  expected  volatility  of 57% 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 and Mr.
Chris  Tong  each  have  employment  agreements  with the  Company.  Mr.  Evans'
agreement  terminates January 1, 2003 and continues thereafter on a year to year
basis and  provides  for a salary of $250,000 per annum.  Mr.  Lutz's  agreement
terminates January 1, 2003 and continues  thereafter on a year to year basis and
provides for a salary of $150,000 per annum. Mr. Frazier's agreement  terminates
January 1, 2001 and  continues  thereafter  on a year to year basis and provides
for a salary of $150,000 per annum. Mr. Tong's agreement  terminates  January 1,
2001 and continues  thereafter on a year to year basis and provides for a salary
of $150,000 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 and
Mr. Lutz,  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.  Frazier and Mr. Tong,  the employee  shall
receive the greater of (i) the employee's  base salary for the remaining term or
any renewal period thereof,  or (ii) 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
$5,000,000.



                                      F-22

<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 one natural gas liquids processing plant 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,  1998  follows (in
thousands):

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

                                                          Gas Gathering,
                                          Exploration &    Marketing &
                  1998:                    Production       Processing    Oil Field 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         (1,995)                 (42,962)
Equity earnings (losses) of affiliates..                                                           (116)                    (116)
Interest expense........................                                                        (18,207)                 (18,207)
Other income............................                                                            572                      572
                                                                                                                       ------------
Loss before income taxes................                                                                               $ (60,713)
Provision for deferred income 
  tax benefit...........................                                                         13,670                   13,670   
Minority interest.......................                                                            (37)                     (37)
                                                                                                                       ------------
Net loss................................                                                                               $ (47,080)
                                                                                                                       ============ 

Segment assets..........................  $   233,824      $    13,729         $   7,230       $ 12,359                $ 267,142
Equity subsidiary investments...........                                                          4,266                    4,266
Capital expenditures (net of asset sales)      70,294              (35)              740             38                   71,037
</TABLE>
<TABLE>
<CAPTION>
<S>                            <C>          <C>    


  Geographic Information:      Revenues     Long-Lived Assets
  -----------------------      ---------    -----------------
United States..............    $  51,400      $   228,436
Foreign countries..........            -                -
                           ----------------------------------
Total......................    $  51,400      $   228,436
                           ----------------------------------
</TABLE>

                                      F-23
<PAGE>
<TABLE>
<CAPTION>
<S>                                       <C>             <C>             <C>                  <C>         <C>         <C>    
                                                          Gas Gathering,
                                          Exploration &    Marketing &
                  1997:                    Production       Processing    Oil Field 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         (1,576)                   9,647
Equity earnings (losses) of affiliates..                                                              6                        6
Interest expense........................                                                        (13,788)                 (13,788)
Other income............................                                                            762                      762
                                                                                                                       ------------
Loss before income taxes................                                                                               $  (3,373)
Provision for deferred income 
  tax benefit...........................                                                          1,284                    1,284   
Minority interest.......................                                                            (19)                     (19)
                                                                                                                       ------------
Net loss................................                                                                               $  (2,108)
                                                                                                                       ============ 

Segment assets..........................  $   221,272      $    14,275         $   5,092       $ 10,430                $ 251,069
Equity subsidiary investments...........                                                          4,372                    4,372
Capital expenditures (net of asset sales)     156,872            2,064               395            -                    159,331
</TABLE>


  Geographic Information:           Revenues     Long-Lived Assets
United States..............    $      45,436      $       221,259
Foreign countries..........            3,398                  -
                           ------------------------------------------
Total......................    $      48,834      $       221,259
                           ------------------------------------------
<TABLE>
<CAPTION>
<S>                                       <C>             <C>             <C>                  <C>         <C>         <C>    

                                                          Gas Gathering,
                                          Exploration &    Marketing &
                  1996:                    Production       Processing    Oil Field Services   All Other   Elimination Consolidated
                  -----                    ----------       ----------    -------------------  ---------   ----------- ------------
Revenue from external customers.........  $    10,248      $     5,768         $     373       $     23     $    -     $  16,412
Intersegment revenues...................            -            3,999               666              -       (4,665)
Depreciation, depletion, amortization and
impairment..............................        2,599              288                42             22                    2,951

Segment profit (loss)...................        2,991              869              (223)          (766)                   2,871
Interest expense........................                                                         (2,394)                  (2,394)
Other income............................                                                            344                      344
                                                                                                                       ------------
Earnings before income taxes............                                                                               $     821
Provision for deferred income tax ......                                                           (312)                    (312)   
                                                                                                                       ------------
Net income..............................                                                                               $     509
                                                                                                                       ============ 

Segment assets..........................  $    61,281      $    10,604         $   1,703       $  9,484     $          $  83,072
Equity subsidiary investments...........                                                              -                      -
Capital expenditures (net of asset sales)      33,934            6,015               235              -                   40,184
</TABLE>
<TABLE>
<CAPTION>
<S>                            <C>          <C>    


  Geographic Information:      Revenues     Long-Lived Assets
  -----------------------      ---------    -----------------
United States..............    $  16,389      $    73,648
Foreign countries..........           23                -
                           ----------------------------------
Total......................    $  16,412      $    73,648
                           ----------------------------------
</TABLE>
                                      F-24
<PAGE>

NOTE 17 -- SUBSEQUENT EVENTS

     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 $46.4 million, to repay senior bank debt.

     On February 17, 1999, the Company  revised its previously  announced  stock
repurchase  program  to  spend  up to $4  million  without  a share  limitation.
Subsequent to December 31, 1998, the Company  repurchased  601,472 shares of its
common stock for $1.7 million.

                                      F-25

<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.

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

                                                                     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

     The changes in Proved  Reserves  for the years ended  December 31, 1997 and
1996 were as follows:

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


                                      F-26

<PAGE>
                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
   SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES --(Continued)
                                   (Unaudited)

     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, 1998 and 1997 were as follows:
<TABLE>
<CAPTION>
<S>                                                                             <C>                <C>    
                                                                                    1998               1997
                                                                                ---------------------------------
Unproved oil and gas properties.............................................    $   1,654,986      $     516,560
Proved properties...........................................................      296,545,064        227,389,446
                                                                                ---------------------------------

Gross Capitalized Costs.....................................................      298,200,050        227,906,006
Accumulated depreciation, depletion, amortization and impairment............      (79,193,796)       (16,091,001)
                                                                                ---------------------------------
          Net Capitalized Costs.............................................    $ 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, 1998 and 1997 as follows:
<TABLE>
<CAPTION>
<S>                                                                             <C>                <C>    
                                                                                   1998               1997
                                                                                -----------------------------------
Property acquisition costs
  Proved properties.........................................................    $   36,619,796      $ 137,430,583
  Unproved properties.......................................................         1,138,426             57,306
Exploration costs...........................................................         4,696,095            737,936
Development costs...........................................................        27,839,727         18,284,460
                                                                                -----------------------------------
          Total Costs Incurred..............................................    $   70,294,044      $ 156,510,285
                                                                                -----------------------------------
</TABLE>
     Results of operations  from oil and gas producing  activities for the years
ended December 31, 1998 and 1997 were as follows:
<TABLE>
<CAPTION>
<S>                                                                             <C>                <C>    
                                                                                   1998               1997
                                                                                ---------------------------------
Oil and gas production revenue.............................................     $ 43,564,728       $ 35,658,032
Disposal services revenue..................................................              -                5,130
Production costs...........................................................      (20,682,187)       (13,901,537)
Depreciation, depletion, amortization and impairment.......................      (63,102,795)       (11,577,460)
                                                                                ---------------------------------
          Results of Operations for Producing Activities                        $(40,220,254)      $ 10,184,165
                                                                                ---------------------------------
</TABLE>
     The  standardized  measure of  discounted  estimated  future net cash flows
related to proved oil and gas  reserves  at  December  31, 1998 and 1997 were as
follows:
<TABLE>
<CAPTION>
<S>                                                                             <C>                 <C>    
                                                                                     1998                 1997
                                                                                ------------------------------------
Future cash inflows......................................................       $ 625,818,712       $  811,512,060
Future development and production costs..................................        (278,222,069)        (336,730,398)
                                                                                ------------------------------------

Future net cash flows, before income tax.................................         347,596,643          474,781,662
Future income taxes......................................................                   -          (93,828,793)
                                                                                ------------------------------------
Future Net Cash Flows....................................................         347,596,643          380,952,869
10% annual discount......................................................        (168,187,696)        (211,181,318)
                                                                                ------------------------------------
          Standardized Measure of Discounted Future Net
                 Cash Flows..............................................       $ 179,408,947       $  169,771,551
                                                                                ------------------------------------
</TABLE>
                                      F-27

<PAGE>



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

     The primary  changes in the  standardized  measure of discounted  estimated
future net cash flows for the years  ended  December  31,  1998 and 1997 were as
follows:
<TABLE>
<CAPTION>
<S>                                                                             <C>                  <C>    

                                                                                    1998                1997
                                                                                -------------------------------------

Purchases of minerals-in-place.......................................           $ 46,388,818         $ 136,739,277
Sales of minerals-in-place...........................................                 (8,604)             (191,741)
Extensions, discoveries and improved recovery, less related costs                 10,836,769                38,555
Sales of oil and gas produced, net of production costs...............            (22,882,541)          (21,756,495)
Development costs incurred during the period.........................             27,839,727            16,289,428
Revision of prior estimates:
  Net change in prices and costs.....................................            (61,951,610)         (141,112,592)
  Change in quantity estimates.......................................            (55,991,223)           46,255,955
Accretion of discount................................................             16,977,155            11,708,486
Net change in income taxes...........................................             48,428,905             4,715,817
                                                                                -------------------------------------

                 Net Change..........................................           $  9,637,396         $  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-28

<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...................  41        Director, President and Chief Executive Officer
Matthew C. Lutz.................  64        Chairman of the Board and Executive Vice President of
                                            Exploration and Business Development
Richard R. Frazier..............  52        President and Chief Operating Officer of Magnum Hunter
                                            Production, Inc. and Gruy
Chris Tong......................  42        Senior Vice President and Chief Financial Officer
R. Douglas Cronk . . . . . . . .  51        Senior Vice President of Magnum Hunter Production, Inc. and Gruy
David S. Krueger................  49        Vice President and Chief Accounting Officer
Morgan F. Johnston..............  38        Vice President, General Counsel and Secretary
Michael McInerney . . . . . . .   57        Vice President, Corporate Development & Investor Relations
Craig Knight....................  42        Vice President of Operations of Hunter Gas Gathering, Inc.
Gregory L. Jessup...............  45        Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits..............  47        Vice President and Controller of Gruy
Gerald W. Bolfing...............  70        Director
Jerry Box.......................  60        Director
Larry W. Brummett...............  48        Director
David L. Kyle...................  46        Director
Oscar C. Lindemann..............  76        Director
John H. Trescot, Jr.............  73        Director
James E. Upfield................  78        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,  a NASDAQ listed
manufacturing company. He also serves as a Trustee of TEL Offshore Trust, an OTC
listed oil and gas trust.



                                       36

<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 of Exploration and Business  Development 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  are  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.

     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.



                                       37

<PAGE>



     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.

     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.

     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.

     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.

     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.

                                       38

<PAGE>



     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.

     John H.  Trescot,  Jr. has served as a director of the  Company  since June
1997.  For the  last  five  years,  Mr.  Trescot  has  been a  principal  of AWA
Management  Corporation,  a professional  consulting  firm  specializing in oil,
timber,  pulp and paper,  and  financial  management.  Early in his career,  Mr.
Trescot held various  positions in woodlands,  and pulp and paper,  advancing to
the  position of Senior Vice  President,  Southern  Operations  at Hudson Pulp &
Paper Corp. (now part of Georgia  Pacific Corp.).  Later Mr. Trescot became Vice
President  of The  Charter  Company,  a  corporation  with  operations  in  oil,
communications  and insurance.  In 1979, Mr. Trescot became the Chief  Executive
Officer of "Jari"  Florestal e  Agropecuaria,  Ltda.,a  pulp,  timber,  rice and
kaolin  operation in the Amazon Basin of Brazil owned by D.K.  Ludwig.  In 1981,
Mr. Trescot became the Chief Executive Officer of TOT Drilling Corp., a contract
drilling company with operations in west Texas and New Mexico.



                                       39

<PAGE>



     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.

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, 1998  (collectively  the "Named Executive
Officers").
<TABLE>
<CAPTION>
<S>                       <C>    <C>        <C>             <C>            <C>         <C>         <C>        <C>


                                                                                Long Term Compensation
                                                                          ----------------------------------
                                    Annual Compensation
                                 -----------------------------------------    Awards                Payout
                                                                          ----------------------------------

(a)                       (b)    (c)         (d)                (e)           (f)         (g)        (h)           (i)
Name,                                                          Other                    Number
Principal                                                      Annual      Restricted   Options      LTP        All Other
Position                  Year   Salary      Bonus          Compensation     Stock       SARs      Payouts    Compensation
----------------------------------------------------------------------------------------------------------------------------

Gary C. Evans             1998   $250,000    $300,000
President and CEO         1997   $200,025    $250,000             -             -          -          -             -
                          1996   $150,000    $100,000             -             -          -          -             -

Matthew C. Lutz           1998   $156,000    $100,000
Executive V.P. and        1997   $106,000    $100,000             -             -          -          -             -
Chairman                  1996   $ 65,600    $ 10,000             -             -          -          -             -

Richard R. Frazier        1998   $154,200    $ 50,000
President of              1997   $124,200    $ 50,000             -             -          -          -             -
Magnum Hunter             1996   $ 98,350    $  9,000
Production, Inc.

Chris Tong                1998   $156,000    $ 30,000
Senior Vice President &   1997(1)$ 78,500    $ 25,000             -             -          -          -             -
Chief Financial Officer

R. Douglas Cronk          1998   $104,200    $20,000
Senior V.P. of Magnum     1997   $ 92,033    $10,000              -             -          -          -             -
Hunter Production, Inc.   1996(2)$ 37,100    $ 3,000

---------------------
</TABLE>


       (1) Mr. Tong was hired in August of 1997.
       (2) Mr. Cronk was hired in July of 1996.




                                       40

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

                         Shares acquired on                               Exercisable/            Exercisable/
         Name               exercise (#)        Value Realized ($)       unexercisable           unexercisable
          (a)                    (b)                    (c)                   (d)                      (e)
                                                              
     Gary C. Evans             89,377                $280,711              650,000 / 0               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  receive a $10,000  retainer  for being a board member and in addition
shall receive $1,000 per meeting attended.  Each new independent  director added
to the board in fiscal  year 1999 will be 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 and Mr.
Chris  Tong  each  have  employment  agreements  with the  Company.  Mr.  Evans'
agreement  terminates January 1, 2003 and continues thereafter on a year to year
basis and  provides  for a salary of $250,000 per annum.  Mr.  Lutz's  agreement
terminates January 1, 2003 and continues  thereafter on a year to year basis and
provides for a salary of $150,000 per annum. Mr. Frazier's agreement  terminates
January 1, 2001 and  continues  thereafter  on a year to year basis and provides
for a salary of $150,000 per annum. Mr. Tong's agreement  terminates  January 1,
2001 and continues  thereafter on a year to year basis and provides for a salary
of $150,000 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 and
Mr. Lutz,  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.  Frazier and Mr. Tong,  the employee  shall
receive the greater of (i) the employee's  base salary for the remaining term or
any renewal period thereof,  or (ii) 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
$5,000,000.

                                       41

<PAGE>



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

     The following  table sets forth certain  information  as of March 17, 1999,
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
17, 1999,  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 1200,
Irving, Texas 75039.
<TABLE>
<CAPTION>
<S>                                                                             <C>                    <C>    


                                                                                         Common Stock
                                                                                       Beneficially Owned
                                                                                Number of                Percent
                             Name                                                Shares                of Class (12)
Directors and Executive Officers
     Gary C. Evans ............................................                 2,164,766    (1)          10.4%
     Matthew C. Lutz...........................................                   683,388    (2)           3.3%
     Richard R. Frazier........................................                   259,213    (3)           1.2%
     Chris Tong................................................                    98,951    (4)            *
     R. Douglas Cronk .........................................                   103,768    (5)            *
     Gerald W. Bolfing.........................................                   363,558    (6)           1.8%
     Jerry Box.................................................                       0                     -
     Oscar C. Lindemann........................................                    41,160    (7)            *
     John H. Trescot, Jr.......................................                    87,154    (8)            *
     James E. Upfield.........................................                     87,642    (9)            *
     David L. Kyle ............................................                       0                     -
     Larry M. Brummett ........................................                       0                     -
     All directors and executive officers as a group
     (11persons)                                                                3,889,600                 18.0%
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    (10)         32.2%
     TCW Group, Inc.
     865 South Figueroa Street
     Los Angeles, CA  90017....................................                 1,904,762    (11)          8.7%
     Janus Capital Corporation
     100 Fillmore St. , Suite 300
     Denver, CO.  80206........................................                 1,800,595                  9.0%
</TABLE>

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


       (1)    Includes 650,000 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.

                                       42

<PAGE>



              
       (2)    Includes 526,073 shares of common stock issuable upon the exercise
              of certain currently exercisable options.
       (3)    Includes 200,000 shares of common stock issuable upon the exercise
              of certain currently exercisable options.
       (4)    Includes 90,000 shares of common stock issuable upon the exercise 
              of certain currently exercisable options.
       (5)    Includes 100,000 shares of common stock issuable upon the exercise
              of certain currently exercisable options.
       (6)    Includes 35,536 shares of common stock issuable upon the exercise 
              of certain currently exercisable options.
       (7)    Includes 35,536 shares of common stock issuable upon the exercise
              of certain currently exercisable options.
       (8)    Includes 35,000 shares of common stock issuable upon the exercise 
              of certain currently exercisable options.
       (9)    Includes 35,536 shares of common stock issuable upon the exercise 
              of certain currently exercisable options.
       (10)   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.
       (11)   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.
       (12)   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.

     During December 1998, the Company's Board of Directors authorized a loan of
up to $300,000 be made available to Gary C. Evans, President and Chief Executive
Officer of the Company, as part of his 1998 compensation package and to exercise
certain  stock  options.  A total of  $230,000  was drawn  under  the loan,  and
subsequent to year-end $65,000 was repaid.  The balance  outstanding at December
31, 1998 was  $230,000  and bears  interest at 10% and is due December 31, 1999.
The outstanding balance as of March 31, 1999 was $165,000.

     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.  Provided  the
Company does not consummate a business  transaction with the publicly traded oil
and gas company by the end of 1999, 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.

                                       43

<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.

                                       44

<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 oil,  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.

     Proved  Undeveloped  Reserves.  Proved  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.

     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.

     SEC 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,
1998, 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,  1998,  or as  otherwise
indicated.

     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.


                                       45

<PAGE>



Item 14.          Exhibits and Reports on Form 8-K.

                                                      Exhibit
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
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.
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.
10.5          Employment Agreement for Gary C. Evans (Incorporated by reference
              to Registration Statement on Form S-4, File No. 333-2290)
10.6          Employment Agreement for Matthew C. Lutz (Incorporated by 
              reference to Registration Statement on Form S-4,File No. 333-2290)
10.7          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)
10.8          Registration Rights Agreement, dated May 29, 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)
10.9          Purchase and Sale Agreement,  dated May 17, 1996 between  Meridian
              Oil, Inc. and ConMag Energy Corporation (Incorporated by reference
              to Form 8-K, dated June 28, 1996, filed July 12, 1996)
10.10         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)

                                       46

<PAGE>



10.11         Purchase and Sale Agreement between Magnum Hunter Resources,  Inc.
              , NGTS, et al., dated December 17, 1997 (Incorporated by reference
              to Form 8-K, dated December 17, 1997, filed December 29, 1997)
10.12*        Purchase and Sale Agreement dated November 25, 1998 between Magnum
              Hunter Production, Inc. and Unocal Oil Company of California
10.13         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

* Filed herewith.

(B) Form 8-K's

     A Form 8-K,  dated  December  14, 1998 was filed by the Company on December
15, 1998 under Item 5 concerning  the Company's  execution of a Letter of Intent
with ONEOK Inc., the eighth largest natural gas distributor in the United States
relating to ONEOK's  purchase of $50 million of Convertible  Preferred  Stock of
the Company,  ONEOK's ability to market the Company's  natural gas production in
the state of Oklahoma,  ONEOK's ability to participate in future acquisitions of
the Company in the state of Oklahoma and ONEOK's  participation in the Company's
acquisition of certain oil and gas assets acquired from Spirit 76.


                                       47

<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 report to be signed
on its behalf by the undersigned, thereunto duly authorized.

MAGNUM HUNTER RESOURCES, INC.


By:    /s/ Gary C. Evans                                          April 14, 1999
---------------------------------------------
         Gary C.  Evans, President & CEO

     In  accordance  with the Exchange Act, this report 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                        April 14, 1999
Gary C. Evans                                    Chief Executive Officer

/s/ Matthew C.  Lutz                             Chairman of the Board and                  April 14, 1999
--------------------------
Matthew C. Lutz                                  Executive Vice President of
                                                 Exploration and Business
                                                 Development

/s/ Chris Tong                                   Senior Vice President and                  April 14, 1999
--------------------------
Chris Tong                                       Chief Financial Officer

/s/ David S. Krueger                             Vice President and                         April 14, 1999
David S. Krueger                                 Chief Accounting Officer

/s/ Morgan F. Johnston                           Vice President, General Counsel            April 14, 1999
--------------------------
Morgan F. Johnston                               and Secretary

/s/ Gerald W.  Bolfing                           Director                                   April 14, 1999
--------------------------
Gerald W. Bolfing

/s/ Oscar C.  Lindemann                          Director                                   April 14, 1999
--------------------------
Oscar C. Lindemann

/s/ John H. Trescot, Jr.                         Director                                   April 14, 1999
--------------------------
John H. Trescot, Jr.

/s/ James E. Upfield                             Director                                   April 14, 1999
--------------------------
James E. Upfield
</TABLE>


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