# UNITED STATES SECURITIES AND EXCHANGE COMMISSION  Washington, D.C. 20549 FORM 10-K

|        | (Mark one)                                                                                                                                          
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|[ X ]   | Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2003                    
|[     ] | Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934For the transition period from ____________ to ____________.

Commission File No. 1-12508

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

|Nevada  (State or other jurisdiction of  incorporation or organization) | 87-0462881(I.R.S. EmployerIdentification No.)
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|600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039(Address of principal executive offices) (zip code)
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|Registrant's telephone number, including area code: (972) 401-0752
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|Securities registered pursuant to Section 12(b) of the Exchange Act:
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|Title of each class Common Stock ($.002 par value) | Name of each exchange on which registeredNew York Stock Exchange
|-------------------------------------------------- | ----------------------------------------------------------------

Securities registered pursuant to 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. [    ]

Indicate by check mark whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes [ X ]     No [    ]

As of June 30, 2003, the aggregate market value of voting stock held by  non-affiliates,  computed by reference to the closing price as
reported by the New York Stock Exchange, was $537,254,295.62.

The number of shares outstanding of the registrant's common stock at March 5, 2004 was 68,903,516.

TABLE OF CONTENTS

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# PART ISPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

| | future stock market valuations;
|- | -------------------------------

| | repayment of debt;
|- | ------------------

| | business strategies;
|- | --------------------

| | expansion and growth of operations; and
|- | ---------------------------------------

| | future operating results and financial condition.
|- | -------------------------------------------------

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

| | general economic and business conditions;
|- | -----------------------------------------

| | prices of crude oil, natural gas and natural gas liquids and industry expectations about future prices;
|- | -------------------------------------------------------------------------------------------------------

| | the business opportunities, or lack of opportunities, that may be presented to and pursued by us; and
|- | -----------------------------------------------------------------------------------------------------

| | changes in laws or regulations.
|- | -------------------------------

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

Item 1. Business

The Company

In this Annual Report on Form 10K,
the words Magnum Hunter, company, we, our,
and us refer to Magnum Hunter Resources, Inc., and its consolidated
subsidiaries unless otherwise stated or the context otherwise requires.

We file Annual Reports on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registration statements and
other items with the Securities and Exchange Commission (SEC). We provide access free of
charge to all of these SEC filings, as soon as reasonably practicable after filing, on our
Internet site located at www.magnumhunter.com. In addition, the public may read and copy
any materials we file with the SEC at the SECs Public Reference Room at 450 Fifth
Street, NW., Washington, D.C. 20549. The public may obtain information on the operation of
the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an
Internet site (www.sec.gov) that contains reports, proxy and information statements and
other information regarding issuers that file electronically with the SEC.

Magnum Hunter was organized in 1989 as a Nevada corporation.  We are an independent energy company
engaged in the exploration, exploitation and development, acquisition and operation of oil
and gas properties with a geographic focus in the Mid-Continent Region, Permian Basin
Region, Gulf Coast Region and the Gulf of Mexico. Our management has implemented a
business strategy that emphasizes the acquisition of long-lived proved reserves with
significant exploitation and development opportunities where we generally can control the
operations of the properties.

1

As part of this strategy, from 1996
through 2003, we acquired significant properties from Burlington Resources Inc.
(Burlington), Spirit Energy 76 (Spirit 76), a business unit of
Union Oil Company of California, Vastar Resources, Inc. (Vastar) and Mallon
Resources Corporation (Mallon). On March 15, 2002, we acquired Prize Energy
Corp. (Prize), which was merged into one of our wholly owned subsidiaries. Prize was a publicly
traded independent oil and gas company engaged primarily in the acquisition, enhancement
and exploitation of producing oil and gas properties. Prize owned oil and gas properties
principally located in three core operating areas, which were in the Permian Basin of West
Texas and Southeastern New Mexico, the onshore Gulf Coast area of Texas and Louisiana and
the Mid-Continent area of Oklahoma and the Texas Panhandle. Over 80% of Prizes oil
and gas property base was located in Texas. In addition to our focus on selected
exploratory drilling prospects in the Gulf of Mexico as described below, we intend to
continue to concentrate our efforts on additional producing property acquisitions
strategically located within our geographic area of operations. We also intend to continue
to develop our substantial inventory of drilling and workover opportunities located
onshore.

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

At December 31, 2003, Magnum Hunter
had an interest in 5,591 wells and had estimated proved reserves of 838.4 Bcfe with a
present value discounted at 10% (PV-10) of $1.48 billion. PV-10 differs from the
standardized measure of cash flows set forth in the notes to the Consolidated Financial
Statements of the company, which is calculated after provision for future income taxes.
Approximately 75% of these reserves were proved developed reserves with a geographic
breakdown as follows: 35% attributable to the Mid-Continent Region, 46% attributable to
the Permian Basin Region, 8% attributable to the Gulf Coast Region and 11% attributable to
the Gulf of Mexico. At December 31, 2003, our proved reserves had an estimated reserve
life of approximately 10 years and were 59% natural gas. The company serves as operator
for approximately 79% of our properties, based on the gross number of wells in which we
own an interest, and 72% of our properties, based upon the year-end PV-10 value.

Business Strategy

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

| | selective exploration;
|- | ----------------------

| | the exploitation and development of acquired properties; and
|- | ------------------------------------------------------------

| | strategic acquisitions of additional proved reserves.
|- | -----------------------------------------------------

The following are key elements of our strategy:

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

Exploitation and Development of
Existing Properties. We will continue to seek to maximize the value of our existing
properties through development activities including in-fill drilling, waterflooding and
other enhanced recovery techniques. Typically, our exploitation projects do not have
significant time limitations due to the existing mineral acreage being held by current
production. By operating substantially all of our properties, our management is provided
maximum flexibility with respect to the timing of capital expended to develop these
opportunities.

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

2

Management of Overhead and Operating
Costs. We will continue to emphasize strict cost controls in all aspects of our business
and will continue to seek to operate our properties wherever possible, utilizing a minimum
number of personnel. By operating the substantial majority of our properties
(approximately 72% of our properties on a PV-10 basis), we will generally be able to
control direct operating and drilling costs as well as to manage the timing of development
and exploration activities. This operating control also provides greater flexibility as to
the timing requirements to fund new capital expenditures. By strictly controlling Magnum
Hunters general and administrative expenses, management strives to maximize our net
operating margin.

Properties

The companys major properties
are located in four core areas: (i) the Mid-Continent region, (ii) the Permian Basin,
(iii) the Gulf Coast region and (iv) the Gulf of Mexico.

Mid-Continent Region

The Companys Mid-Continent
operations include assets principally located in the Ardmore Basin in south central
Oklahoma/Texas Panhandle and in Southwestern Arkansas. The majority of these properties
were acquired from Burlington Resources, Spirit 76, Vastar and Prize. Approximately 75% of
the estimated reserves are natural gas and 25% are oil located on approximately 235,083
net mineral leasehold acres in twenty-seven counties in Oklahoma, eleven counties in Texas
and two counties in Arkansas. As of December 31, 2003, DeGolyer and MacNaughton
(D&M) and Cawley, Gillespie & Associates, Inc. (Cawley
Gillespie), independent reservoir engineers, have estimated the Mid-Continent properties
proved reserves at 10.5 MMBbl of oil and 183.7 Bcf of natural gas, or, on a natural gas
equivalent basis, 246.5 Bcfe. D&M and Cawley Gillespie further estimated the PV-10 for
the Mid-Continent properties to be $396.8 million as of December 31, 2003. Total net daily
production from the Mid-Continent properties for the month of December 2003 was 35.9
MMcf/d for natural gas and 1,437 Bbl/d of oil and natural gas liquids or 44.5 MMcfe/d.
Magnum Hunters wholly-owned subsidiary, Gruy Petroleum Management Co.
(Gruy), is the operator of approximately 85% of the wells located in the
Mid-Continent Region. Additional Mid-Continent development drilling, recompletion
activities and improvements to existing waterflood operations will focus on the Walnut
Bend Field, the Madill Field and the Eola-Robberson Field.

Panoma.    
          The Panoma properties currently consist of approximately 521 natural gas wells
          in the West Panhandle, East Panhandle, and South Erick Fields along a corridor
          66 miles long and 20 miles wide stretching from Beckham County, Oklahoma to Gray
          County, Texas. All wells are less than 2,300 feet deep and produce natural gas
          from the Granite Wash and/or Brown Dolomite formations. For the month of
          December 2003, net natural gas sales were approximately 9.6 MMcf/d, which
          excludes liquids processed from this natural gas stream through our gas
          processing facility located adjacent to these fields, known as the McLean Plant.
          Development continues with increased density drilling in the West Panhandle.

Eola-Robberson.    
          The Eola-Robberson Field is located in Garvin County, Oklahoma and has been
          producing since 1920. It is productive in multiple reservoirs from the fractured
          Devonion Klippe at 6,400 feet to the Basal Oil Creek at 11,800 feet. The field
          has primarily been developed within two units, the Eola North Fault Block Unit
          and the South Eola Bromide Sand Unit. The waterfloods for this field were
          discontinued in 1992, with the South Eola Bromide Sand Unit being disbanded in
          2003. The wellbores are being recompleted into bypassed oil pockets in the
          Bromide, McLish and Oil Creek and the fractured gas reservoirs such as the
          Sycamore, Woodford, Hunton and Viola. We have an interest in 66 producing wells,
          with working interests varying from 8% to 100%. We operate all but four of these
          wells. For the month of December 2003, net production from the field averaged
          6,869 Mcf/d and 446 Bbl/d.

Cumberland.    
          The Cumberland Field is located in Bryan and Marshall Counties, Oklahoma. It was
          discovered in 1940 and is productive in multiple reservoirs from the Goddard
          down to the Arbuckle formation. Depths range from 2,000 feet to 6,800 feet.
          Initially, the field produced oil from the Bromide, McLish and Oil Creek
          formations. These zones were unitized in 1964 for waterflood operations, which
          continue today. The Shallow Gas zones include the Sycamore,
          Woodford, Hunton, and Viola. These formations are predominantly gas productive
          and are produced commingled. Development drilling plans exist for four
          additional proved undeveloped locations to exploit the shallow gas on 160 acre
          spacing and one proved undeveloped location in the Oil Creek formation. The
          shallowest zone in the field is the Goddard, which is a channel sand. We have an
          interest in 74 active wells, with working interests varying from 17% to

3

100%.    
          We operate all but ten of these wells. For the month of December 2003, net
          production from the field averaged 5,123 Mcf/d and 142 Bbl/d.

Walnut Bend.     The Walnut Bend Field is
located in Cooke County, Texas. The field was discovered in the late 1930s and
produces oil and gas from numerous intervals ranging in depth from 2,000 feet in the
Montgomery sands to over 7,000 feet in the Ellenburger carbonate. There are currently 107
active producing wells and 31 active injection wells. Our working interest ownership in
the wells is approximately 91%. For the month of December 2003, net production from the
wells averaged 102 Mcf/d and 598 Bbl/d. Current activities in the field include a
recompletion program on both active and inactive wellbores as identified by a two-year
geological study. This will include the initiation of numerous small waterflood projects.

Madill.    
          The Madill Field is located in Marshall County in Southern Oklahoma. The first
          production from this field occurred in 1906 and produces primarily gas from
          various shallow reservoirs, such as the Sycamore, Woodford, Viola and Bromide at
          depths ranging from 3,750 feet to 5,700 feet. There are currently 57 active
          producing wells. Magnum Hunters working interest ownership in the wells
          varies from 41% to 100%. For the month of December 2003, net production from the
          wells averaged 1,324 Mcf/d and 124 Bbl/d.

Permian Basin

The companys Permian Basin
operations include assets located in Southwest Texas, far West Texas and Southeastern New
Mexico with an interest in 3,372 wells located in 170 different fields. Magnum
Hunters wholly-owned subsidiary, Gruy, is the operator of approximately 77% of the
producing wells. Management believes the Permian Basin properties will continue to provide
significant opportunities for exploitation of oil and natural gas through development
drilling, workovers, recompletions, and optimization of enhanced oil recovery projects. As
of December 31, 2003, the Permian Basin properties had proved reserves of 41.6 MMBbl of
oil and 188.6 Bcf of natural gas, or on a natural gas equivalent basis, 438.5 Bcfe with a
net pre-tax PV-10 value of $633 million as of December 31, 2003. Total net daily
production from the Permian Basin properties for the month of December 2003 was
approximately 42,358 Mcf/d of natural gas and 6,552 Bbls/d of oil, or 81.7 MMcfe/d.

In evaluating the Permian Basin
properties, Magnum Hunter has identified over 170 drilling locations including
developmental production and injection wells. The top valued fields in the Permian Basin
are Westbrook, Warwink, Howard Glasscock, Jo-Mill, Kermit, Keystone, Willo, P&P and
the Southeastern New Mexico area.

Westbrook.    
          The Westbrook field is located in Mitchell County, Texas and produces from the
          Clearfork formation at a depth of approximately 3,200 feet. Gruy operates the
          Southwest Westbrook Unit and Morrison G lease and the company owns an 89% and
          100% working interest, respectively. The company also owns a small working
          interest in the ChevronTexaco operated North Westbrook Unit. As of December 31,
          2003, there were 116 active wells in these three leases. For the month of
          December 2003, net production from the wells averaged 471 Bbl/d.

The initial wells in this area were
drilled in the 1920s and waterflood operations began in the 1960s. The company
is actively drilling infill wells and optimizing waterflood operations in the Southwest
Westbrook Unit.

Warwink.    
          The Warwink field is located in Ward and Winkler Counties, Texas. The company owns
          interests in 85 wells producing from the Cherry Canyon formation at depths from
          4,800 to 7,400 feet. The companys working interest ownership in these
          wells varies from 71% to 85% and all wells are operated by Gruy. For the month
          of December 2003, the companys net production from these wells averaged
          661 Bbl/d and 1,613 Mcf/d.

The wells in this field have multiple
stacked Cherry Canyon sands that can be produced together. Several behind pipe zones have
been identified and the company is actively adding these zones in the existing wells.

Howard Glasscock. The Howard
Glasscock field is located on the border of Howard and Glasscock Counties, Texas. The
company owns an interest in 311 wells, of which 78% are operated by Gruy. The company
acquired additional interests in 2002 on two properties, regaining operations and
increasing the working interest from 50% to 100%. The companys working interest in
the other wells in this area range from 5% to 100%. For the month of December 2003, the
companys net production from these wells averaged 721 Bbl/d for oil, and 143 Mcf/d
for gas.

4

The properties in the Howard
Glasscock field consist of multiple waterfloods in the San Andres, Glorietta and Clearfork
formations. The company also owns interests in leases that have been identified as future
waterflood candidates.

Jo-Mill.    
          The Jo-Mill field is located in Borden County, Texas and produces in the
          Sprayberry formation at approximately 7,100 to 7,500 feet. The company owns a
          non-operated working interest that ranges from 0.5% to 33% in three different
          waterflood units. The companys net production from these three units
          averaged 631 Bbl/d and 238 Mcf/d in December of 2003.

These fields were unitized between
1963 and 1973 and were initially waterflooded on a peripheral pattern with 80 acre
spacing. Since the mid 70s, multiple infill wells have been drilled to convert the
floods to a line drive pattern on 40 acre spacing. D&M has assigned net proved
undeveloped reserves of 1,091 MMcfe to an additional 13 locations in the ChevronTexaco
operated Jo-Mill Unit.

Kermit.    
          The Kermit field is located in the heart of Winkler County, Texas. The company
          owns interests in 184 oil and gas wells with a working interest varying from 21%
          to 100%. Gruy operates 87% of the wells in this field. The average December 2003
          net production from these wells was 178 Bbl/d and 4,360 Mcf/d.

The wells in this field produce from
several different horizons, including the Ellenburger, McKee, Fusselman, Devonian,
Clearfork, Holt, Colby and Yates. The majority of the wells the company has an interest in
are currently producing from the Yates gas cap.

Keystone.    
          The Keystone field is located in Winkler County, Texas. The company owns an
          interest in 233 oil and gas wells of which 99.6% are operated by Gruy. These
          wells produced an average of 259 Bbl/d and 503 Mcf/d net in December 2003.

The company owns 100% working
interests in the East Keystone Unit where waterflood operations commenced in June of 2002.
This unit is flooding the San Andres and Holt formations on a 20 acre 5 spot pattern.
Initial waterflood response has been seen in some parts of the field.

Willo.    
          The Willo field is located in Crockett and Val Verde Counties, Texas. The
          company owns an interest in 14 oil and gas wells producing from the Ellenburger,
          Strawn and Canyon/Wolfcamp formations. The companys working interest
          ranges from 23% to 100% in this field with 82% of the wells operated by Gruy.
          The companys average net production for December 2003 for these wells was
          1,908 Mcf/d. The most prolific zone in this field is the Ellenburger dolomite at
          an average depth of 14,000 feet. This zone accounts for 95% of the 10.8 MMcfe
          net proved developed producing reserves assigned to this field by D&M.
          Proved undeveloped reserves of 17.2 MMcfe net for six additional Ellenburger
          wells have been identified by D&M.

P&P.    
          The P&P field is located in Crane County, Texas producing from the Devonian
          at a depth of 5,500 feet. This field was unitized as the River Bend Devonian
          Unit for waterflood operations in 2000. Water injection was started in September
          of 2000 and the unit has experienced an increase in net oil production from 160
          Bbl/d in April of 2001 to 318 Bbl/d in December of 2003. The company owns a 47%
          working interest in 20 wells and all are operated by Gruy.

This field is located adjacent to the
Gruy operated Abell Devonian Unit that has been under waterflood operations in the
Devonian since 1961. Proved undeveloped reserves were assigned by D&M to the River
Bend Devonian Unit in contemplation of a carbon dioxide injection project that is
anticipated to follow waterflood operations.

Southeast New Mexico. The Southeast
New Mexico properties consist of approximately 760 wells in Lea and Eddy Counties, of
which 80% are operated by Gruy. Several of the companys fields in Lea County produce
from the Yates, Seven Rivers, Queen and other formations at depths generally shallower
than 3,000 feet. The average net production for the Southeast New Mexico properties for
December 2003 was 1,405 Bbl/d and 25,230 Mcf/d.

The company has been actively
drilling increased density wells in the Morrow formation at approximately 11,500 feet. The
company participated in 26 Morrow wells in 2003 and has 23 wells planned for 2004. D&M
has identified 62 proved undeveloped locations for the Morrow, with net reserves of 42.1
MMcfe.

Several of the Morrow wells have
identified behind pipe pay in the Atoka and Strawn formations. A recent recompletion to
the Strawn formation from the Morrow in the Magnum 5 Federal #2 came in flowing at rates
over 800 Bbl/d and 3,000 Mcf/d gross. The company has a 50% working interest in this well.
An offset was drilled that came in flowing at rates over 450 Bbl/d and 2,500 Mcf/d. Two
additional wells are being drilled in this area. The company has a 50% working interest in
these wells.

5

Gulf Coast

We own an interest in 416 wells in
the Gulf Coast region, of which Gruy is the operator of approximately 64% of the wells.
Magnum Hunter has received an engineering evaluation from D&M on the net reserves in
the Gulf Coast. According to D&M, as of December 31, 2003, the Gulf Coast properties
had proved reserves of 2.0 MMBbl of oil and 59.6 Bcf of natural gas, or on a natural gas
equivalent basis, 71.8 Bcfe. D&M further estimated the PV-10 for the Gulf Coast
properties to be $143.4 million as of December 31, 2003. Approximately 83% of the
estimated reserves are natural gas and 17% are oil. Total net daily production from the
Gulf Coast properties for the month of December 2003 was approximately 13.5 MMcf/d of
natural gas and 534 Bbls/d of oil.

The principal fields in the onshore
Gulf Coast region are Buchel, Provident City, Alta Loma and Word, North.

Buchel.    
          The company operates seven producing wells, one shut-in well and one salt water
          disposal well in this Dewitt County, Texas field. We have an 87.5% working
          interest in two of the wells and own a 100% working interest in the remaining
          wells. The producing interval in the Buchel field is the lower cretaceous
          Edwards formation at approximately 14,000 feet. Production averaged 1,910 Mcf/d
          and 17 Bbl/d in December 2003 net to the companys interest. Net proved
          reserves for this field were 11.0 Bcfe as of December 31, 2003.

Provident City.The company owns
varying working interests, between 1% and 100%, in 25 wells in this field located in Lavaca
County, Texas. Six of the wells are company operated. Production is primarily from the
Wilcox formation at 8,500 feet to 17,500 feet with the remaining production from the
shallow Frio and Yegua formations at 2,700 feet to 6,500 feet. Production attributable to
the companys interest averaged 2,676 Mcf/d and 12 Bbl/d in December 2003. As of
December 31, 2003, the net proved reserves assigned to this field were 7.0 Bcfe.

Alta Loma. The company owns a 41% and
a 48% working interest in two producing wells in this field. In addition, we also own and
operate a salt water disposal well. This field is located in Galveston County, Texas and
produces from the Frio formation at approximately 12,500 feet. Production attributable to
the companys interest averaged 1,103 Mcf/d and 82 Bbl/d in December 2003. As of
December 31, 2003, the net proved reserves assigned to this field were 5.8 Bcfe.

Word, North. We own varying working
interests, between 4% and 100%, in 24 wells in this field located in Lavaca County, Texas.
Eighteen of the wells are operated by us. Production is from the Edwards formation at
approximately 14,000 feet and averaged 1,345 Mcf/d and 15 Bbl/d in December 2003 net to
our interest. Net proved reserves for this field were 10.2 Bcfe as of December 31, 2003.

Gulf of Mexico

Our initial entry into the Gulf of
Mexico occurred March 27, 1998 when we acquired approximately 40% beneficial ownership
interest in TEL Offshore Trust. One year later in May 1999, we began participating as a
working interest owner in new exploratory drilling on the shallow water shelf. We
currently own an interest in 174 blocks in the Gulf of Mexico ranging from 12.5% to 100%.
Proved reserves have been assigned in 52 blocks encompassing 80 gross wells (31.1 net
wells). The company operates 20 of these wells (14.4 net wells). According to D&M, as
of December 31, 2003, the Gulf of Mexico properties had proved reserves of 3.3 MMBbl of
oil and 62 Bcf of natural gas (81.6 Bcfe) with a PV-10 value of $308 million.
Approximately 76% of the estimated reserves are natural gas and the remaining 24% is oil.
Total net daily production from the Gulf of Mexico properties for the month of December
2003 was 42.8 MMcf/d of natural gas and 1,797 Bbls/d of oil. At December 31, 2003, the
company had six additional discoveries that are scheduled to commence production in 2004.

South Marsh Island 24. Our interest
in South Marsh Island 24 consists of a 30% working interest in one well operated by
Remington Oil & Gas. Production is from the Upper Miocene Big A sand at approximately
16,500 feet. The field is located in 72 feet of water on Federal leases south of Iberia
Parish, Louisiana. First production was established in May 2003 and averaged 4,192 Mcf/d
and 166 Bbl/d in December 2003, net to our interest. The net proved reserves attributable
to this well were 5.75 Bcfe as of December 31, 2003.

6

Main Pass 178 Area. This area
comprises Main Pass blocks 163, 164 and 178 and is located in Federal waters east of
Plaquemines Parish, Louisiana in water depths of 124 feet to 150 feet. The company owns a
100% working interest and operates four existing wells from two platforms; and added a
third well and platform in 2003, in which the company owns a 60% working interest. First
production was established in December 2001. These wells produce from various sands of
Lower Pliocene to Middle Miocene age, at depths ranging from 4,800 feet to 12,000 feet.
Production attributable to the companys interest averaged 4,093 Mcf/d and 95 Bbl/d
in December 2003. Net proved reserves for the Main Pass Area were 14 Bcfe as of December
31, 2003.

Eugene Island 397 Area. This area
encompasses Eugene Island block 397 and Green Canyon blocks 4 and 48. We own a 12.5%
working interest in ten wells operated by W&T Offshore. The wells are located in
Federal waters south of St. Mary Parish, Louisiana in a water depth of 404 feet.
Production from the first well was initiated in April 2002. Subsequent wells were put on
production as they were completed, with 3 wells having come on line in 2003. These wells
produce from various sands of Lower Pleistocene to Upper Pliocene, at depths ranging from
6,500 feet to 9,700 feet. Production attributable to the companys interest averaged
314 Mcf/d and 149 Bbl/d in December 2003. As of December 31, 2003, the net proved reserves
for the Eugene Island 397 Area were 4.4 Bcfe.

Eugene Island 302. Our interest in
Eugene Island 302 consists of a 30% working interest in three wells operated by Remington
Oil & Gas. Current production is from Ang B and Basal Nebraskan zones ranging in depth
from 6,000 feet to 10,000 feet.  The field is located in 220 feet of water on Federal
leases south of St. Mary Parish, Louisiana. First production from the initial two wells
was established in May 2002, with the third well going on production in September 2003.
Production attributable to the companys interest averaged 958 Mcf/d and 440 Bbl/d in
December 2003. Net proved reserves attributable to these three wells were 4.5 Bcfe as of
December 31, 2003.

South Timbalier 265 Area. This area
encompasses South Timbalier blocks 250, 264 and 265 and is located in Federal waters south
of Terrebonne Parish, Louisiana in water depths of 185 feet to 225 feet. The company owns
working interests in sixteen wells ranging from 40% to 100%. The company operates all of
the wells from five platforms. The company initially acquired its interest in South
Timbalier 265 through a like-kind property exchange with Kerr McGee in August 2000.
Additional interests in the area were acquired from El Paso in March 2001. The wells
produce from various sands ranging in depth from 4,800 feet to 16,000 feet. The ST 264-B
platform and two new wells were put on production in November 2003. Production averaged
5,607 Mcf/d and 150 Bbl/d in December 2003 net to the companys interest. As of
December 31, 2003, the net proved reserves for the South Timbalier 265 Area were 10.8
Bcfe.

West Cameron 426. Our interest in
West Cameron consists of a 50% working interest in one well operated by Remington Oil
& Gas. Production is from the Bul 1 sand at approximately 7,100 feet. The field is
located in 102 feet of water on Federal leases south of Cameron Parish, Louisiana. First
production was established in March 2003 and averaged 3,727 Mcf/d in December 2003 net to
our interest. The net proved reserves attributable to this well were 2.4 Bcfe as of
December 31, 2003.

Gas Processing Plants

McLean Plant.In January 1997, we
complemented our Panoma acquisition by purchasing a 50% ownership interest in the McLean
Gas Plant and a related 22 mile products pipeline. This plant is a modern cryogenic plant
utilizing approximately 2,000 horsepower of high speed compression and a gas processing
capacity of approximately 23 MMcf/d. For the month of December 2003, throughput of the
plant averaged 7.35 MMcf/d with processed liquids of 518 Bbl/d. The McLean Gas plant keeps
100% of the liquids recovered through the plant and pays the producer a value per Btu for
the shrink and residue allocable to each producers production less a gathering fee,
plant and compression fuel and system loss.

Madill Plant. In December 1999, we
acquired the Madill Gas Processing Plant and associated gathering system assets from
Dynegy Midstream Services, Limited Partnership, a wholly-owned subsidiary of Dynegy Inc.
The gas processing plant and associated facilities are located in Marshall and Bryan
Counties, Oklahoma, and were acquired in conjunction with our 50% partner, Carrera Gas
Gathering Co., L.L.C., of Tulsa, Oklahoma, who acquired the other 50% of the gas plant and
associated assets. The acquisition includes over 130 miles of gas gathering pipelines.
This modern cryogenic plant has 3,350 horsepower of high speed compression and has gas
processing capacity of approximately 18 MMcf/d. For the month of December 2003, throughput
of the plant averaged 7.9 MMcf/d of natural gas with processed liquids of 494 Bbl/d. The
Madill Gas Plant processes natural gas under contracts that are primarily percent of
proceeds (POP) based contracts. The contracts percentages vary depending
on volume and producer.

7

Walker Creek Plant. In conjunction
with the Vastar acquisition, we acquired an approximate 59% ownership interest and became
the operator of the Walker Creek Plant and associated gathering system. In 2000, we sold a
44.2% interest in the Walker Creek Plant to Mallard Hunter L.P., of which we are the
general partner. This facility is located in southwest Arkansas in Lafayette and Columbia
counties. This propane refrigeration plant utilizes 3,160 horsepower of leased compression
and has a gas processing capacity of 12 Mmcf/d. For the month of December 2003, throughput
of the plant averaged 3.3 MMcf/d with processed liquids of 191 Bbl/d. The Walker Creek
Plant is run for the sole benefit of the Walker Creek Unit. No third party production is
delivered into the facility. All residue and NGL proceeds and plant costs are allocated to
the Walker Creek Unit.

Elmore City Processing Plant. We
acquired a 100% ownership interest in the Elmore City Plant in the Prize merger. This gas
processing facility and associated gathering system assets are located in Garvin County,
Oklahoma. These facilities include over 25 miles of gathering pipelines and an NGL
extraction plant consisting of a cryogenic unit and approximately 7,000 horsepower of
various types of compressors. The plants 2003 throughput averaged 10.2 MMcf/d with a
total throughput capacity of approximately 35 MMcf/d. For the month of December 2003,
throughput of the plant averaged 10.6 MMcf/d with processed liquids of 931 Bbl/d. The
Elmore City Plant processes natural gas under contracts that are solely POP contracts. The
plant receives on average approximately 20% of the residue and 40% to 45% of the recovered
liquids attributable to a producers gas delivered into the system.

Development and
Exploration Activities

Overview

We intend to continue to focus our
efforts on exploration, property acquisitions and our substantial inventory of
exploitation and development drilling projects.

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

Development Drilling

Magnum Hunters development
strategy focuses on maximizing the value and productivity of our oil and gas asset base
through development drilling and enhanced recovery projects. We have budgeted
approximately $56.5 million for exploitation and development activities for 2004 with
$43.9 million of such budget allocated to our proved undeveloped reserves. We have
identified 552 development drilling locations and workover opportunities on our properties
to which proved reserves have been attributed. In exploiting our producing properties, we
rely upon our in-house technical staff of petroleum engineering and geological
professionals and utilize the services of outside consultants on a selective basis.

Mid-Continent Region. A total of 191
development drilling locations and workover opportunities have been identified in the
Mid-Continent Region. Increased density drilling will continue to enhance the value of the
Panoma Prospect. Approximately 101 drilling locations have been identified as proven, many
of which were reclassified as proven in late 2003 when Magnum Hunter received regulatory
approval to reclassify its westernmost Panoma acreage. Spacing for those units was changed
from 640 acres to 160 acres per well.

Additional Mid-Continent development
opportunities center around recompletion opportunities in the Eola-Robberson, North
Madill, Cumberland and Walnut Bend Fields. All of these fields are large, multi-pay
fields with a large well count. Approximately 38 recompletion opportunities have been
identified in those four fields.

Permian Basin Properties. Magnum
Hunter has maintained a continuous two-rig drilling program in Southeast New Mexico for
nearly two years. Target reservoirs are Morrow, Strawn and Atoka at depths down to 13,000
feet. The majority of the wells drilled have been increased density wells. Primary fields
drilled in 2003 and scheduled for 2004 are White City and South Carlsbad in Eddy County
and the Quail Ridge in Lea County. A total of 23 wells are budgeted for 2004. Magnum
Hunters working interest ranges from 5% to 100%, with an average in the 50% to 60%
range. Most of the drilling through February 2004 has been on acreage acquired in the
Burlington, Permian and Mallon acquisitions. We recently have entered into two separate
agreements with ChevronTexaco which allows Magnum Hunter to drill on all ChevronTexaco
acreage in the White City/Carlsbad area, whether undrilled leased acreage or acreage held
by existing production. The farmouts cover approximately 14,880 acres and will allow
Magnum Hunter to drill up to 56 wells. Additional similar farmouts are in the various
stages with other large producers in the general area.

8

Additional development drilling in
the Permian Basin centers around increased density drilling in the Westbrook Field in
Mitchell County, Texas, where we drilled 12 wells in 2003 and have a similar program
scheduled for 2004. Several well sidetrack recompletions are planned for the Brunson Ranch
Field in Loving County, Texas with starting dates post 2004. Also numerous proven
undeveloped locations have been identified in Lea County, New Mexico targeting the shallow
intervals down to approximately 3,000 feet.

Exploratory Drilling

We spent $36.8 million of our $175.5
million 2003 capital expenditures on exploratory drilling and related land and geophysical
costs. Twenty offshore exploratory wells were drilled in 2003, of which 14 were completed
as producing wells providing us with a 70% success rate. We entered the Gulf of Mexico as
a working interest owner in new exploratory drilling on the shallow water shelf in May
1999. This program has yielded 76 completions in 93 attempts by the end of 2003, and as
the proved reserves associated with these new wells are developed, they have been adding
significant cash flow. Production from our producing blocks was approximately 53.6 MMcfe/d
net to the company as of December 2003. Eight new platforms scheduled to commence
production in the first half of 2004 should add to these levels. We own an interest
ranging from 12.5% to 100% in 174 offshore blocks and expect to add to the number of OCS
blocks in 2004. An aggressive drilling program will continue in 2004.

The onshore exploration program
remains active. One of the Morrow tests drilled in New Mexico was a true exploratory test
in which Magnum Hunter held a 100% working interest. The well found gas in the Morrow, as
well as from the Strawn zone. We participated in additional exploration in West Texas on
successful projects with Oxy Oil and Gas and EOG Resources.

Gathering and Processing
of Gas

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

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

The Panoma system, the largest of our
gas gathering systems, consists of approximately 449 miles of pipeline. The main trunk
lines run east to west for approximately 66 miles with the east end starting in Beckham
County, Oklahoma and the west end starting in Gray County, Texas. At December 31, 2003,
gas throughput for the Panoma gas gathering system was approximately 15.3 MMcf/d. The
Panoma gas gathering system is connected to a third party header system which
provides access to all major interstate pipelines in the area via seven pipeline
interconnects serving Midwestern, Western and Oklahoma intrastate markets. We operate
approximately 523 of the approximately 610 wells connected to the Panoma system, and are
actively seeking to add new wells to this system through acquisition, development or
arrangements with third party producers.

Effective January 1997, we purchased
a 50% ownership interest in the McLean Gas Plant, a gas processing facility located
adjacent to our gas gathering system. The purchase also included a 22 mile products
pipeline between the McLean Gas Plant and the Koch Pipeline at Lefors, Texas and all gas
and product purchase and sales agreements related to the plant. The McLean Gas Plant is a
modern cryogenic gas processing plant with a throughput capacity of 23.0 Mmcf/d. For the
month of December 2003, throughput, net to Hunter Gas Gathering, was approximately 7.35
MMcf/d with processed liquids of 518 Bbl/d. We acquired our 50% ownership interest in the
plant from Carrera Gas Company, L.L.C. (Carrera) of Tulsa, Oklahoma, which
owns the remaining 50% of the plant and operates the facility on our behalf.

9

We acquired a 100% ownership interest
in the Elmore City Plant in the Prize merger. This gas processing facility and associated
gathering system assets are located in Garvin County, Oklahoma. These facilities include
over 25 miles of gathering pipelines and an NGL extraction plant consisting of a cryogenic
unit and approximately 7,000 horsepower of various types of compression. The plants
2003 throughput has averaged 10.3 MMcf/d with 924 Bbls/d of processed liquids with a total
throughput capacity of approximately 35 MMcf/d.

In December 1999, we acquired the
Madill Gas Processing Plant and associated gathering system assets from Dynegy Midstream
Services, Limited Partnership, a wholly-owned subsidiary of Dynegy Inc. The gas processing
plant and associated facilities are located in Marshall and Bryan Counties, Oklahoma and
were acquired in conjunction with our 50% partner, Carrera. The acquisition includes over
130 miles of gas gathering pipelines. This modern cryogenic plant has 3,350 horsepower of
high speed compression and has gas processing capacity of approximately 18 MMcf/d. For the
month of December 2003, throughput of the plant, net to Hunter Gas Gathering, was
approximately 7.9 MMcf/d of natural gas with processed liquids of 494 Bbl/d.

In conjunction with the Vastar
acquisition, we acquired approximately 59% ownership interest and became the operator of
the Walker Creek Plant and associated gathering system. In 2000, we sold a 44.2% interest
in the Walker Creek Plant to Mallard Hunter L.P., of which we are the general partner.
This facility is located in southwest Arkansas in Lafayette and Columbia counties. This
propane refrigeration plant utilizes 3,160 horsepower leased compression and has a gas
processing capacity of 12 MMcf/d. The Walker Creek Plant is run for the sole benefit of
the Walker Creek Unit. There is not any third party production delivering into the
facility nor is the facility set up as a separate business unit. All residue and NGL
proceeds and plant costs are allocated to the Walker Creek Unit. For the month of December
2003, throughput of the plant was approximately 3.3 MMcf/d with processed liquids of 191
Bbl/d.

Marketing of Production

We market all of our gas production
as well as gas we purchase from third parties to gas marketing firms or end-users either
on (i) the spot market under contracts of less than one year at prevailing spot market
prices (approximately 75% of our volume) or (ii) at market responsive prices under
multi-year contracts (approximately 25% of our volume). Marketing gas for our own account
exposes the company to the attendant commodities risk which we attempt to mitigate through
various financial hedges. We normally sell our own oil under month-to-month contracts with
a variety of crude oil purchasers. Oil is usually sold for our own account through the
services of Enmark Services, a marketing agent in Dallas, Texas. While we have
historically been able to sell oil above posted prices, we are also exposed to the
commodities risk inherent in short-term contracts which we attempt to mitigate through
various financial hedges. For a discussion of our hedging activities, see
Managements Discussion and Analysis of Financial Condition and Results of
Operations  Liquidity and Capital Resources  Hedging Activity and Note
12 to our consolidated financial statements.

The market for oil and natural gas we
produce depends on factors beyond our 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

We acquired Gruy in December 1995.
Gruy, which conducts operations for both Magnum Hunter and third parties, has managed
properties for nearly half a century for financial institutions, bankruptcy trustees,
estates, individual investors, trusts and independent oil and gas companies. Gruy provides
drilling, completion and other well-site services; advice regarding environmental and
other regulatory compliance; receipt and disbursement functions, expert witness testimony
and other managerial services and petroleum engineering services. Gruy manages, operates
and provides consulting services on oil and gas properties, gathering systems and
processing plants located in Texas, Oklahoma, Mississippi, Louisiana, New Mexico and
Kansas. Gruy is an important component of our acquisition program. As the operator of

10

wells for third parties and as a
provider of consulting services for the energy industry, Gruy is often uniquely able to
identify attractive acquisition opportunities.

For additional information on our
business segments, see Note 15 to our consolidated financial statements.

Competition

The oil and gas industry is highly
competitive. Our competitors 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, we frequently encounter competition in the acquisition of oil and gas
properties, gas gathering systems, gas processing plants and in our management and
consulting business. The principal means of such competition are the amount and terms of
the consideration offered. The principal means of such competition with respect to the
sale of oil and gas production are product availability and price. The price at which our
products may be sold will continue to be affected by a number of factors, including the
price of alternate fuels such as oil, natural gas, nuclear power, hydroelectric power and
coal, and competition among various gas producers and marketers.

Regulations

General Federal and State
Regulations

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

Regulation of Natural Gas
and Oil Exploration and Production

Our operations are subject to various
types of regulation at the federal, state and local levels. Such regulation includes
requiring permits for drilling wells, maintaining bonding requirements in order to drill
or operate wells and regulating the location of wells, the method of drilling and casing
wells, the surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection with
operations. Our operations are also subject to various conservation laws and regulations.
These include the regulation of the size of drilling and spacing units or proration units
and the density of wells which may be drilled in and the unitization or pooling of oil and
gas properties. In addition, state conservation laws establish maximum rates of production
from oil and gas wells, generally prohibit the venting or flaring of gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and gas we can produce from our wells and may
limit the number of wells or the locations at which we can drill. The regulatory burden on
the oil and gas industry increases our cost of doing business and, consequently, affects
our profitability. Inasmuch as such laws and regulations are frequently expanded, amended
and reinterpreted, we are unable to predict the future cost or impact of complying with
such regulations.

Federal Regulation of
Sales Prices and Transportation

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

11

Gathering Regulations

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

Environmental Regulation

Our exploration, development, and
production of oil and gas, including our 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. Our 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. We are also subject to regulations governing the
handling, transportation, storage, and disposal of naturally occurring radioactive
materials that are found in our 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, our 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. We generate 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 our 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 our properties
by previous owners and operators, materials from these operations remain on some of the
properties and in some instances require remediation. In addition, in certain instances we
have agreed to indemnify sellers of producing properties from which we have acquired
reserves against certain liabilities for environmental claims associated with such
properties. While we do not believe that costs to be incurred by us 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.

12

Additionally, in the course of our
routine oil and gas operations, surface spills and leaks, including casing leaks, of oil
or other materials occur, and we incur costs for waste handling and environmental
compliance. Moreover, we are able to control directly the operations of only those wells
for which we act as the operator. Management believes that the company is in substantial
compliance with applicable environmental laws and regulations.

It is not anticipated that we will be
required in the near future to expend amounts that are material in relation to our total
capital expenditures program by reason of environmental laws and regulations, but inasmuch
as such laws and regulations are frequently changed, we are 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 we will not otherwise incur
material expenses in connection with environmental laws and regulations in the future.

Employees

At December 31, 2003, we had 222
full-time employees of which 51 were management, 95 were administrative and 76 were field
personnel. None of our employees are represented by a union. Management considers our
relations with employees to be very good.

Facilities

Magnum Hunter occupies approximately
23,386 square feet of office space at 600 East Las Colinas Boulevard, Suite 1100, Irving,
Texas, under a lease that expires in November 2005. We also occupy approximately 19,635
square feet of office space in Grapevine, Texas, under a lease that expires in December
2005. We own field offices and production yards in Shamrock, Gainesville and Victoria, Texas,
Cumberland and Madill, Oklahoma, Carlsbad, New Mexico and Taylor, Arkansas. We also lease field production
offices in Midland, Kermit and Abilene, Texas; Artesia and Eunice, New Mexico;
and Oklahoma City and Woodward, Oklahoma.

13

# RISK FACTORS

Risks related to the oil and gas
industry

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

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

| | relatively minor changes in the supply of, and demand for, oil and gas;
|- | -----------------------------------------------------------------------

| | market uncertainty both domestically and worldwide; and
|- | -------------------------------------------------------

| | a variety of additional factors, all of which are beyond our control.
|- | ---------------------------------------------------------------------

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

Under the full cost accounting
method, we are required to take a non-cash charge against earnings if capitalized costs of
acquisition, exploration and development, net of depletion, depreciation and amortization,
less deferred income taxes, exceed the present value of our proved reserves and the lower
of cost or fair value of unproved properties after income tax effects. Once incurred, a
write-down of oil and gas properties is not reversible at a later date even if oil and gas
prices increase. We did not incur a write-down of our oil and gas property pool during
2003.

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

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

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

| | the timing of both production and related expenses;
|- | ---------------------------------------------------

| | changes in consumption levels; and
|- | ----------------------------------

| | governmental regulations or taxation.
|- | -------------------------------------

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

14

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

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

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

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

We conduct waterflood projects and
other secondary recovery operations.

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

We hedge our oil and gas production.

Periodically, we have entered into
hedging transactions to reduce the effects of fluctuations in crude oil and natural gas
prices. At February 16, 2004, Magnum Hunter had approximately 50% of its natural gas
production and 60% of its crude oil production hedged through December 31, 2004. In
addition, at February 16, 2004, Magnum Hunter had 25% of its natural gas production and
none of its crude oil production hedged for calendar year 2005. The hedging activities of
the company, while intended to reduce sensitivity to changes in market prices of oil and
gas, are subject to a number of risks including instances in which we or the
counterparties to our hedging contracts fail to perform. Additionally, the fixed price
sales and hedging contracts limit the benefits we will realize if actual prices rise above
the contract prices. Most of our hedging contracts are in the form of collars, which limit
the benefit we would otherwise receive if actual prices exceed the collars.

Our operations are subject to many
laws and regulations.

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

15

Numerous environmental laws,
including but not limited to, those governing the management of waste, the protection of
water and air quality, the discharge of materials into the environment, and the
preservation of natural resources, impact and influence our operations. If we fail to
comply with environmental laws regarding the discharge of oil, gas, or other materials
into the air, soil or water we may be subject to liabilities to the government and third
parties, including civil and criminal penalties. These regulations may require us to incur
costs to remedy the discharge. Laws and regulations protecting the environment have become
more stringent in recent years, and may, in some circumstances, result in liability for
environmental damage regardless of negligence or fault. New laws or regulations, or
modifications of or new interpretations of existing laws and regulations, may increase
substantially the cost of compliance or adversely affect our oil and gas operations and
financial condition. From time to time, we have agreed to indemnify sellers of producing
properties against some liabilities for environmental claims associated with these
properties. Material indemnity claims may also arise with respect to properties acquired
by or from us. Additionally, as a result of our merger with Prize in 2002, we are
responsible for any environmental liabilities Prize may have had in the past or which may
occur in the future from Prizes properties. While we do not anticipate incurring
material costs in connection with environmental compliance and remediation, we cannot
guarantee that we will not incur material costs.

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

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

The oil and natural gas business
involves operating hazards such as well blowouts, craterings, explosions, uncontrollable
flows of oil, natural gas or well fluids, fires, formations with abnormal pressures,
pipeline ruptures or spills, pollution, releases of toxic gas and other environmental
hazards and risks, any of which could cause us substantial losses. In addition, we may be
liable for environmental damage caused by previous owners of property we own or lease. As
a result, we may face substantial liabilities to third parties or governmental entities,
which could reduce or eliminate funds available for exploration, development or
acquisitions or cause us to incur losses. An event that is not fully covered by insurance
 for example, losses resulting from pollution and environmental risks, which are not
fully insurable  could have a material adverse effect on our financial condition and
results of operations.

Exploratory drilling is an uncertain
process with many risks.

Exploratory drilling involves
numerous risks, including the risks that we will not find any commercially productive
natural gas or oil reservoirs. The cost of drilling, completing and operating wells is
often uncertain, and a number of factors can delay or prevent drilling operations,
including:

| | unexpected drilling conditions;
|- | -------------------------------

| | pressure or irregularities in formations;
|- | -----------------------------------------

| | equipment failures or accidents;
|- | --------------------------------

| | adverse weather conditions;
|- | ---------------------------

| | compliance with governmental requirements; and
|- | ----------------------------------------------

| | shortages or delays in the availability of drilling rigs or in the delivery of equipment.
|- | -----------------------------------------------------------------------------------------

Our future drilling activity may not
be successful, nor can we be sure that our overall drilling success rate, or our drilling
success rate for activity within a particular area, will not decline. Unsuccessful
drilling activities could have a material effect on our results of operations and
financial condition. Also, we may not be able to obtain any options or lease rights in
potential drilling locations that we identify. Although we have identified numerous
potential drilling locations, we cannot be sure that we will ever drill them or that we
will produce natural gas or oil from them or any other potential drilling locations.

16

Our acquisitions involve certain
risks.

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

As our merger with Prize in 2002
demonstrates, we have begun to focus our acquisition efforts on larger packages of oil and
gas properties. Acquisitions of larger oil and gas properties may involve substantially
higher costs and may pose additional issues regarding operations and management. We cannot
assure you that we will be able to successfully integrate all of the oil and gas
properties that we acquire into our operations or that we will achieve desired
profitability objectives.

We are subject to substantial
competition.

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

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

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

Risks related to substantial leverage

We have a significant amount of debt
that could adversely affect our financial health and prevent us from fulfilling our
obligations.

We have now and will continue to have
a significant amount of indebtedness. As of February 16, 2004, we had total indebtedness
of approximately $597.2 million.

In connection with our merger with
Prize in 2002, we issued $300 million of 9.6% Senior Notes due 2012 and established a new
credit facility (Facility) with a borrowing base of $350 million as of
December 1, 2003, that is secured by the assets of the combined company. Proceeds from the
9.6% Senior Notes offering and borrowings under the Facility were used to refinance the
outstanding indebtedness under the existing senior credit facilities of both Magnum Hunter
and Prize, fund the cash component of the merger consideration in the merger with Prize
and pay costs and fees associated with the merger. Although in December 2003 we repaid the
remaining $60 million in principal amount of our 10% Senior Notes due 2007, we incurred
$125 million of new debt through our offering of floating rate convertible senior notes
due 2023 (Convertible Notes) and we have a modified borrowing base of $255
million under our Facility in addition to the $300 million in principal amount of our 9.6%
Senior Notes due 2012. Because we must dedicate a substantial portion of our cash flow
from operations to the payment of interest on our debt, that portion of our cash flow is
not available for other purposes. The covenants contained in our Facility and the
indenture relating to our 9.6% Senior Notes require us to meet financial tests and limit
our ability to borrow additional funds or to acquire or dispose of assets. Also, our
ability to obtain additional financing in the future may be impaired by our substantial
leverage. Additionally, the senior, as opposed to subordinated, status of our 9.6% Senior
Notes due 2012 and the Convertible Notes, our high debt to equity ratio, and the pledge of
substantially all of our assets as collateral for our Facility will, for the foreseeable
future, make it difficult for us to obtain financing on an unsecured basis or to obtain
secured financing other than purchase money indebtedness collateralized by the
acquired assets.

17

Our substantial indebtedness could
make it more difficult for us to satisfy our obligations; increase our vulnerability to
general adverse economic and industry conditions; require us to dedicate a substantial
portion of our cash flow from operations to payments on our indebtedness, thereby reducing
the availability of our cash flow to fund working capital, capital expenditures and other
general corporate purposes; force us to sell assets or seek additional capital to service
our indebtedness which we may be unable to do at all or on terms favorable to us; limit
our flexibility in planning for, or reacting to, changes in our business and the industry
in which we operate; place us at a competitive disadvantage compared to our competitors
that have less debt; and limit our ability to borrow additional funds.

We may not be able to meet our
capital requirements.

We will need to continue to make
substantial capital expenditures for the acquisition, enhancement, exploitation and
production of oil and natural gas reserves. Without successful enhancement, exploitation
and acquisition activities, our reserves and revenues will decline over time due to
natural depletion. In 2003 we had a capital expenditures budget of $165 million for
exploration, enhancement, exploitation and drilling activities on oil and natural gas
properties. Our capital expenditures budget for 2004 is $185 million. We intend to finance
our capital expenditures, other than significant acquisitions, from internally generated
funds provided by operations and borrowings under our Facility. The timing of most of our
capital expenditures is discretionary, with no long-term capital commitments.
Consequently, we have a significant degree of flexibility to adjust the amounts of our
capital expenditures as circumstances may warrant. However, in the long term, if our cash
flow from operations and availability under our Facility are not sufficient to satisfy
capital expenditure requirements, there can be no assurance that additional debt or equity
financing will be available to allow us to fund our continued growth.

Our Facility and the indenture for
our 9.6% Senior Notes impose restrictions that limit our discretion in operating our
business and that could impair our ability to repay our obligations.

Our Facility and the indenture
governing our 9.6% Senior Notes impose restrictions on us that may limit the discretion of
our management in operating our business that could impair our ability to repay our
obligations.

Our Facility and the indenture
governing our 9.6% Senior Notes contain various restrictive covenants. In particular, these
covenants limit our ability to, among other things:

| | incur additional debt;
|- | ----------------------

| | make restricted payments (including paying dividends on, redeeming or repurchasing our capital stock);
|- | ------------------------------------------------------------------------------------------------------

| | make investments or acquisitions;
|- | ---------------------------------

| | grant liens on assets;
|- | ----------------------

| | sell our assets;
|- | ----------------

| | engage in transactions with affiliates; and
|- | -------------------------------------------

| | merge, consolidate or transfer substantially all of our assets.
|- | ---------------------------------------------------------------

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

Risks related to our common stock

We have never paid cash dividends on
our common stock.

We have not previously paid any cash dividends
on our common stock and we do not anticipate paying cash dividends on our common stock in
the foreseeable future. We intend to reinvest all available funds for the development and
growth of our business. In addition, our Facility and the indenture governing our 9.6%
Senior Notes restrict the payment of cash dividends on our common stock.

18

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

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

We have outstanding Convertible Notes
which are convertible into our common stock.

We have outstanding $125 million of
Convertible Notes that have a final maturity of 2023. The Convertible Notes will be
convertible into a combination of cash and common stock of Magnum Hunter upon the
happening of certain events. In general, upon conversion of a Convertible Note, the holder
would receive cash equal to the principal amount of the Convertible Note and Magnum Hunter
common stock for the Convertible Notes conversion value in excess of such principal
amount. The number of Magnum Hunter common shares into which the Convertible Notes are
convertible is dependent upon the conversion value in excess of the principal amount of
the Convertible Notes and our future common stock price. Any such conversion will be
dilutive to our existing shareholders. Please refer to Magnum Hunters Capital
Resources section of Liquidity and Capital Resources for information on the conversion
features of these notes.

Anti-takeover provisions may affect
your rights if you become a stockholder.

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

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

In addition, a change of control, as
defined under the indentures relating to our 9.6% Senior Notes and the Convertible Notes
would entitle the holders to put those notes to us under the applicable indenture and
would entitle the lenders to accelerate payment of outstanding indebtedness under our
Facility. These events could discourage takeover attempts by making such attempts
more expensive and requiring greater capital resources.

We have the ability to issue
additional equity securities, which would lead to dilution of our issued and outstanding
common stock.

The issuance of additional equity
securities or securities convertible into equity securities would result in dilution of
then existing stockholders equity interests in us. We are authorized to issue,
without stockholder approval, 10,000,000 shares of preferred stock in one or more series,
which may give other stockholders dividend, conversion, voting, and liquidation rights,
among other rights, which may be superior to the rights of holders of our common stock.
Our board of directors has the authority to issue, without vote or action of stockholders,
additional shares of preferred stock in one or more series, and has the ability to fix the
rights, preferences, privileges and restrictions of any such series. Any such series of
preferred stock could contain dividend rights, conversion rights, voting rights, terms of
redemption, redemption prices, liquidation preferences or other rights superior to the
rights of holders of our common stock. Our board of directors has no present intention of
issuing any such preferred stock, but reserves the right to do so in the future. In
addition, we are authorized to issue, without stockholder approval, up to 200,000,000
shares of common stock, of which approximately 68,903,516 shares were outstanding as of
March 5, 2004. We are also authorized to issue, without stockholder approval, securities
convertible into shares of common stock or preferred stock.

19

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

A substantial number of our shares
are issuable upon the exercise of options and warrants. A substantial number of shares
will be available for sale under Rule 144 by our management and other affiliates who
collectively owned approximately 9.7% of our outstanding common stock as of March 5, 2004.

In addition, we have outstanding a
significant number of other shares that are freely transferable without restriction. We
may, from time to time, issue and sell up to 5,000,000 additional shares of common stock
through an at the market prospectus in our shelf registration statement. The
possibility that substantial amounts of common stock may be sold in the public market may
adversely affect prevailing and future market prices for our common stock or our notes and
could impair our ability to raise capital through the sale of equity securities in the
future.

Item 2. Description of
Properties

Oil and Gas Reserves

General

All information set forth in this
Form 10-K regarding estimated proved reserves, related estimated future net cash flows and
PV-10 of our oil and gas interests is taken from reports prepared by DeGolyer and
MacNaughton of Dallas, Texas and Cawley Gillespie & Associates, Inc. of Fort Worth,
Texas, both independent petroleum engineers with respect to our interests at December 31,
2003, December 31, 2002 and December 31, 2001 (using oil and gas prices in effect on each
respective date).

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

PV-10 is the present value of proved
reserves which is an estimate of the discounted future net cash flows from each of our
properties at December 31, 2003, or as otherwise indicated. Net cash flow is defined as
net revenues, after deducting production and ad valorem taxes, future capital costs and
operating expenses, but before deducting federal income taxes. The future net cash flows
have been discounted at an annual rate of 10% to determine their present
value. The present value is shown to indicate the effect of time on the value of the
revenue stream and should not be construed as being the fair market value of the
properties. Estimates have been made using constant oil and gas prices and operating
costs, at December 31, 2003, or as otherwise indicated.

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

|              | Prices Used in Reserve Reports at December 31,
|------------- | ----------------------------------------------
|
|Gas (per Mcf) |                                               
|Oil (per Bbl) |                                               

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

20

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

Except for the effect of changes in
oil and gas prices, no major discovery or other favorable or adverse event is believed to
have caused a significant change in these estimates of our proved reserves since
December 31, 2003. No estimates of proved reserves of oil and gas have been filed by
the company with, or included in any report to, any United States authority or agency
(other than the Securities and Exchange Commission) since January 1, 2001.

Company Reserves

The following tables set forth our
estimated proved reserves of oil and gas and the PV-10 thereof on an actual basis at
December 31, 2003, 2002 and 2001.

|Estimated Proved Oil and Natural Gas Reserves (a)
|-------------------------------------------------
|
|
|Net gas reserves (Mcf):                          
|Proved developed                                 
|Proved undeveloped                               
|                                                 
|Total proved gas reserves                        
|                                                 
|Net oil reserves (Bbl):                          
|(including condensate and NGL)                   
|Proved developed                                 
|Proved undeveloped                               
|                                                 
|Total proved oil reserves                        
|                                                 
|Total Proved Reserves (Mcfe)                     
|                                                 

|Estimated PV-10 of Proved Reserves (a)
|--------------------------------------
|
|
|Estimated PV-10 (b):                  
|Proved developed                      
|Proved undeveloped                    
|                                      
|Proved Reserves PV-10 (c)             
|                                      

---

|(a) | Based upon reserve reports at December 31, 2003, 2002 and 2001 prepared by
  D&M and Cawley Gillespie.
|--- | ------------------------------------------------------------------------------------------------------

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

|(c) | The standardized measure of discounted future net cash flows related to proved
oil and gas reserves at December 31, 2003, 2002 and 2001, respectively, were as follows: $1,067,688,000, $969,809,000 and $305,693,000.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

21

Significant Properties

On December 31, 2003, 100% of our
proved reserves on a Bcfe basis were located in the Mid-Continent region, the Permian
Basin, the Gulf Coast region and the Gulf of Mexico. On such date, our properties included
working interests in 4,933 gross (3,303 net) productive oil and gas wells.

The following table sets forth
summary information with respect to our estimated proved reserves of oil and gas at
December 31, 2003.

|                         | PV-10 (a) | Proved Reserves
|------------------------ | --------- | ---------------
|
|Mid-Continent region (b) |           | $   396,811    
|Permian Basin (b)        |           | 633,118        
|Gulf Coast region (b)    |           | 143,411        
|Gulf of Mexico (b)       |           | 308,395        
|                         |           |                
|Total                    |           | $1,481,735     
|                         |           |                

---

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

|(b) | Based on reserve reports at December 31, 2003 prepared by D&M and Cawley
          Gillespie.
|--- | ---------------------------------------------------------------------------------------------

Oil and Gas Production,
Prices and Costs

The following table shows the
approximate net production attributable to our oil and gas interests, the average sales
price and the average production expense attributable to our 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.

|                                                | Year Ended December 31,
|----------------------------------------------- | -----------------------
|
|Oil and gas production:                         |                        
|Oil (Mbbl)                                      |                        
|Gas (MMcf)                                      |                        
|Natural Gas Equivalent (MMcfe)                  |                        
|Average sales price (a):                        |                        
|Before Hedge Contracts:                         |                        
|Oil (per Bbl)                                   |                        
|Gas (per Mcf)                                   |                        
|Natural Gas Equivalents (per Mcfe)              |                        
|After Hedge Contracts:                          |                        
|Oil (per Bbl)                                   |                        
|Gas (per Mcf)                                   |                        
|Natural Gas Equivalent (per Mcfe)               |                        
|Oil and gas production lifting costs (per Mcfe) |                        
|Production taxes and other costs (per Mcfe) (b) |                        

---

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

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

22

Drilling Activity

The following table sets forth the
results of our drilling activities during the three fiscal years ended December 31, 2003,
2002 and 2001.

|     | Gross Wells (a) | Net Wells (b)
|---- | --------------- | -------------
|
|2003 |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|2002 |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|2001 |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              

---

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

|(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.
|--- | ------------------------------------------------------------------------------

23

Oil and Gas Wells

The  following  table sets forth the number of oil and natural gas wells in which we had a working  interest at December 31, 2003.  All
of these wells are located in the United States.

|                        | Productive Wells As of December 31, 2003
|----------------------- | ----------------------------------------
|
|
|Texas                   |                                         
|New Mexico              |                                         
|Oklahoma                |                                         
|Louisiana               |                                         
|Arkansas                |                                         
|Offshore Gulf of Mexico |                                         
|Other                   |                                         
|                        |                                         
|Total                   |                                         

---

| | (a) | The number of gross wells is the total number of wells in which a working
               interest is owned. Well counts include wells with multiple completions.  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.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------

Oil and Gas Acreage

The following table summarizes our
developed and undeveloped leasehold acreage at December 31, 2003:

|                        | Developed | Undeveloped
|----------------------- | --------- | -----------
|
|Kansas                  |           | 10,377     
|Louisiana               |           | 472        
|New Mexico              |           | 55,992     
|Oklahoma                |           | 168,149    
|Texas                   |           | 446,134    
|Utah                    |           | 8,063      
|Wyoming                 |           | 25,775     
|Offshore Gulf of Mexico |           | 267,922    
|Other                   |           | 8,431      
|                        |           |            
|Total                   |           | 991,315    

---

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

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

Substantially all of our 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,
we generally acquire oil and gas acreage without any warranty of title except as to claims
made by, through or under the transferor. Although we have title examined by a landman or
title attorney prior to acquisition of mineral acreage in those cases in which the
economic significance of the acreage justifies the cost, there can be no assurance that
losses will not result from title defects or from defects in the assignment of leasehold
rights. In certain instances, title opinions may not be obtained if, in our 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 our business, the outcome of which
management believes will not have a material adverse effect on the company.

24

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 2003.

PART II

Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters

Our common stock began trading on the
New York Stock Exchange on June 25, 2002, under the symbol MHR. Prior to
trading on NYSE, our common stock traded on the American Stock Exchange. The following
table shows the quarterly high and low sales price per share and the average daily trading
volume for our common stock for the periods indicated.

|               | High | Low | Average Daily
Trading Volume
(Shares)
|-------------- | ---- | --- | -------------------------------------
|2003           |      |     |                                      
|First Quarter  |      |     |                                      
|Second Quarter |      |     |                                      
|Third Quarter  |      |     |                                      
|Fourth Quarter |      |     |                                      
|2002           |      |     |                                      
|First Quarter  |      |     |                                      
|Second Quarter |      |     |                                      
|Third Quarter  |      |     |                                      
|Fourth Quarter |      |     |                                      

On March 5, 2004, the last reported
sale price of our common stock on the New York Stock Exchange was $9.94 per share. As of
March 9, 2004, there were 2,630 record holders of Magnum Hunter common stock.

We have not previously paid any cash
dividends on our common stock and do not anticipate paying dividends on our common stock
in the foreseeable future. It is the present intention of management to utilize all
available funds for the development and growth of our business activities. Our existing
Facility and our indentures related to our senior unsecured notes restrict the payment of
cash dividends on our securities.

The following table sets forth
information with respect to the equity compensation plans available to our directors,
officers and employees as of December 31, 2003:

|Equity Compensation Plan    
|----------------------------
|
|Equity compensation plans   
|approved by security holders
|                            
|Equity compensation plans   
|not approved by security    
|holders                     

For those  options which were granted  under the plans not approved by our security  holders,  the options were granted by the Board of
Directors in such amounts and to such employees  whom the Board  determined in their sole  discretion.  Each option grant vested 20% at
the date of grant with the balance  vesting an additional 20% per year on the anniversary  date over the next four years.  The exercise
price was fair market value at the date of each grant.

25

Item 6.  Selected Financial Data

The selected  historical  financial data sets forth our summary  historical  consolidated  financial data as of and for the years ended
December 31, 2003,  2002,  2001, 2000 and 1999, and was derived from the audited  consolidated  financial  statements and notes thereto
for those years.  The selected  historical  financial  data is  qualified in its entirety by, and should be read in  conjunction  with,
"Management's  Discussion  and Analysis of Financial  Condition and Results of Operations"  and the financial  statements and the notes
thereto  included  elsewhere  in  this  Form  10-K.  For  additional  information  relating  to  our  operations,  see  "Business"  and
"Properties."  Certain  reclassifications  have been made to the selected  historical  financial data of the prior years, as well as to
certain quarterly financial data, to conform with the current presentation.  All data is in thousands, except per share data.

|                                             | 2003 | 2002 | 2001 | 2000     | 1999
|-------------------------------------------- | ---- | ---- | ---- | -------- | ----
|Income Statement Data:                       |      |      |      |          |     
|Operating revenues                           |      |      | $    | 325,014  |     
|Operating costs and expenses (a)             |      |      |      | (232,316 | )   
|Operating profit                             |      |      |      | 92,698   |     
|Provision for impairment of investment (b)   |      |      |      | --       |     
|Costs associated with early retirement       |      |     
|of debt (c)                                  |      |      |      | (6,716   | )   
|Cumulative effect on prior years of a change |      |     
|in accounting principle, net of tax (d)      |      |      |      | 399      |     
|Net Income (loss)                            |      |      |      | 26,117   |     
|Dividends applicable to preferred shares (e) |      |      |      | --       |     
|Income (loss) applicable to common shares    |      |      | $    | 26,117   |     
|Income (loss) per common share before        |      |     
|cumulative effect of a change in             |      |     
|accounting                                   |      |     
|principle                                    |      |     
|Basic (e)                                    |      |      | $    | 0.38     |     
|Diluted (e)                                  |      |      | $    | 0.38     |     
|Income (loss) per common share after         |      |     
|cumulative effect of a change in             |      |     
|accounting                                   |      |     
|principle                                    |      |     
|Basic (e)                                    |      |      | $    | 0.39     |     
|Diluted (e)                                  |      |      | $    | 0.39     |     
|Other Data:                                  |      |     
|Cash flow from operating activities          |      |      | $    | 162,638  |     
|Proceeds from sale of assets                 |      |      | $    | 17,123   |     
|Capital expenditures (f)                     |      |      | $    | 175,535  |     

---

| | (a) | Includes in 2001 a provision for loss of $3.2 million related to the Enron
               bankruptcy.
| | --- | -----------------------------------------------------------------------------------------------------

| | (b) | Includes in 2002 and 2001 a provision for $621 thousand and $2.1 million,
               respectively, for the impairment of available-for-sale equity securities deemed
               by management to have suffered an other than temporary impairment. The
               impairment was determined using a quoted market price at December 31, 2001 of
               $0.86 per share. We had previously reported losses in accumulated other
               comprehensive income of $507 thousand ($466 thousand net of income tax benefit)
               through December 31, 2001. Also included in 2001 was an impairment provision of
               $5.0 million due to the bankruptcy of a privately held company in which Magnum
               Hunter owned a minority interest and had invested $4.5 million in equity
               securities and $453 thousand in secured loans.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (c) | Includes in 2003 the cost of retirement of $129.5 million in principal of our
               10% Senior Notes due June 1, 2007. Includes in 2002 the costs associated with
               the amendment of our Facility in connection with the Prize merger. Includes in
               2001 the cost of retirement of $10.5 million of our 10% Senior Notes.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (d) | Includes in 2003 the cumulative effect on prior years of a change in accounting
               principle due to the adoption of SFAS No. 143 relating to asset retirement
               obligations. The cumulative effect was a gain of $399 thousand, net of income
               tax expense of $244 thousand.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

| | (f) | Capital expenditures include cash expended for acquisitions plus normal
               additions to oil and natural gas properties and other fixed assets. It does not
               include the cost of property acquired through the issuance of common stock.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

26

|                                   | 2003 | 2002 | 2001 | 2000      | 1999
|---------------------------------- | ---- | ---- | ---- | --------- | ----
|Balance Sheet Data:                |      |      |      |           |     
|Property, plant and equipment, net |      |      | $    | 1,095,883 |     
|Total assets                       |      |      |      | 1,265,892 |     
|Total debt (a)                     |      |      |      | 597,500   |     
|Total stockholders' equity         |      |      | $    | 389,676   |     

---

| | (a) | Consists of current notes payable and long-term debt, including current
               maturities of long-term debt, and excluding production payment liabilities of
               $12 thousand, $114 thousand, $203 thousand, $359 thousand, and $460 thousand as
               of December 31, 2003, 2002, 2001, 2000 and 1999, respectively. As of
               December 31, 2002, 2000 and 1999, $7.0 million, $20.6 million and $41.8 million,
               respectively, of the debt was non-recourse to the company.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The following tables set forth
unaudited summary financial results on a quarterly basis for the two most recent years.  All data is in thousands, except per share data.

|                                          | 2003
|----------------------------------------- | ----
|
|Revenues                                  |     
|Depreciation, depletion, amortization and |     
|accretion                                 |     
|Operating Profit                          |     
|Cost of early debt retirement             |     
|Cumulative effect of accounting change    |     
|Net Income                                |     
|Income per common share, basic            |     
|Income per common share, diluted          |     

|                                           | 2002
|------------------------------------------ | ----
|
|Revenues                                   |     
|Depreciation, depletion and amortization   |     
|Operating Profit                           |     
|Cost of early debt retirement              |     
|Provision for impairment of investment (a) |     
|Net Income                                 |     
|Income per common share, basic             |     
|Income per common share, diluted           |     

---

| | (a) | Includes in 2002  provision for $621 thousand for the  impairment of equity  securities  deemed by management to have suffered
         an other than temporary  impairment.  We had previously  reported  losses in accumulated  other  comprehensive  income of $507
         thousand ($466 thousand net of income tax benefit) through December 31, 2001.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

27

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

Executive Summary

Magnum Hunter  Resources,  Inc. is well positioned over the next several years to continue its growth trajectory in
reserves,  production and its financial  performance  due  principally to its large in-house  inventory of drilling
opportunities  both onshore and offshore in the Gulf of Mexico.  The Company has a proved  reserve base of 838 Bcfe
predominantly  located in the southwestern  United States onshore,  where annual production  decline rates are less
than other  regions of the  country.  Management  believes  the  Company has over a  five-year  inventory  of 2,468
onshore locations and 174 OCS Blocks in the Gulf of Mexico.  This significant  inventory of new drilling  prospects
enhances the  capability  of the Company in meeting its annual goal of replacing  reserves  and  production  in any
given year.

Magnum Hunters  drilling  success has continued to exceed 90% over the last four years.  All of the Companys 2003
growth was from the drill bit and that success  continued  from both  exploratory  and  development  projects.  The
Company  drilled a total of 124 wells in 2003 and completed  115 of them for an overall 93% success rate.  Offshore
drilling  totals for the year included 20 of 27 offshore wells drilled  successfully.  Since our initial entry into
the Gulf of Mexico in 1999, the Company has completed 76 of 93 wells, for an 82% overall rate of success.

The  Companys  proved  reserves  increased  from 837 Bcf at the end of 2002 to 838  Bcfe at the end of 2003.  This
increase,  while  small,  is  significant  in light  of the fact  that we had  non-core  property  sales in 2003 of
approximately  21 Bcfe,  in addition to the 73 Bcfe of  production.  Reserve  additions  equaled 130% of production
volumes for the year. No significant  property  acquisitions  were made during 2003.  Magnum Hunters  reserves are
predominantly  long-life,  stable,  onshore  reserves  with 52% located in the  Permian  Basin  region,  29% in the
Mid-continent  region,  9% on the Texas  Gulf  Coast and 10% from our  offshore  properties  in the Gulf of Mexico.
There has been a lot of  discussion  in the market,  as well as at our own board level,  concerning  the quality of
proved  reserves  reported by  publicly  traded oil and gas  companies.  Fortunately,  Magnum  Hunter has been very
pro-active in this area.  We believe our  petroleum  engineers  have used a very  conservative  approach in booking
proved reserves and therefore our risk in this area has been  significantly  mitigated.  Weve always used the most
rigorous level of external reserve  evaluation by DeGolyer & MacNaughton and Cawley Gillespie,  which are our third
party engineering firms, and they evaluate 100% of our proved reserves.

Finding and  development  costs from all sources for 2003 was $1.74 per Mcfe,  with 66% of our capital budget being
spent in the Gulf of Mexico, a region that typically experiences much higher finding and development costs.

Over the last several years,  Magnum Hunter has continued a significant  divestiture  program of properties  deemed
to be more expensive to operate,  environmentally  sensitive,  and having minimal,  if any,  upside  exploration or
development  potential.  Total  proceeds  received from this group of non-core  assets sold over the last two years
was $118 million,  including the sale of our ownership  interest in NGTS and TEL Offshore  Trust.  The net proceeds
received  from these  assets  sales have been used to reduce the  Companys  overall  indebtedness  and to fund the
capital expenditure program centered around activities in southeastern New Mexico and the Gulf of Mexico.

The Company has been  working over the last several  years to continue a program of reducing  overall  indebtedness
and  improving its interest  expense per Mcfe  produced.  Actions  taken during 2003 to redeem the  Companys  $140
million of  outstanding  High Yield Bonds that bear interest of 10% in  combination  with the new placement of $125
million of 20 year LIBOR priced  Convertible  Bonds,  will create interest savings  exceeding $11 million per year.
Additionally,  the Companys overall  debt-to-book  capitalization  has continued to decrease from a high of 82% at
December   31,  1999  to  a  current   level  of   approximately   60%.  It  is   Managements   goal  to  reach  a
debt-to-capitalization level of 55% or better by year-end 2004.

Magnum Hunters  capital  expenditure  budget for 2004 is currently  estimated to be $185 million.  While oil field
service  costs have  continued  to be at the lower end of previous  cycles,  we are  beginning  to see  significant
increases in certain  sectors of the  business  such as oil field pipe and  tubulars.  Should we  experience  price
increases in other areas such as drilling rigs,  completion rigs, cementing,  fracture  stimulation,  etc., we plan
to then  significantly  curtail our  activities in those regions that would be most effected by these  increases in
field  service  costs.  By operating  over 72% of our  properties,  based on the year-en  PV-10 value,  we are in a
unique position to better control the timing of our capital expenditure program and these expenses.

A new core area for the Company is located on the coal bed methane  leased  option  acreage that we announced  back
in September of 2003.  Last year,  we leased over 1.5 million  acres in northwest  New Mexico in the San Juan Basin
on extremely  favorable lease terms.  We  subsequently  negotiated an agreement with a private company to drill for
this coal bed methane  potential  on this new  acreage.  The program is designed  for a large  number of test wells
using very little of our own capital  budget to test the region.  Drilling has been  underway  since last year and,
although its been  somewhat  slower than  anticipated,  six wells have been drilled  to-date.  The first six wells
have found some thin coals,  but to-date,  we would not say anything has been found in sufficient  quantities to be
deemed commercially  productive.  However,  the conventional coal bed zones will continue to be tested.  Since only
six wells  have been  drilled  over this  entire 1.5  million  acreage  position,  were  hopeful  that some of the
remaining  wells will find coal  thickness  and gas content in  sufficient  amounts  that would allow us to justify
conducting a pilot project.  Therefore,  this is still considered a Research & Development  effort and its still
way too early to say whether or not we will have something positive or something negative from this program.

Due to an unusual  period within the energy  industry  wherein  interest rates are low, oil field service costs are
relatively  low,  and  commodity  prices for both oil and  natural  gas are at record  highs,  an  opportunity  for
unforeseen  expansion in our profit margins has occurred.  We do not anticipate any  significant  reductions in the
price of crude oil and natural gas over the next several years due to tight  supplies and increased  demand here in
North America and worldwide.  Management of Magnum Hunter believes the Company is properly  positioned  during this
period with its existing  portfolio of assets, a significantly  improved financial  condition,  and commodity hedge
protection, to continue to report record financial results over the next several years.

Results of Operations

The  following  discussion  and  analysis  should be read in  conjunction  with our  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.
Throughout  this  document,  we make  statements  that are  classified  as  "forward-looking."  Please  refer  to the  "Forward-Looking
Statements" section of this document for an explanation of these types of assertions.

Our results of operations  are  significantly  affected by our ability to maintain or increase oil and natural gas  production  through
exploration and exploitation activities.  Fluctuations in oil and gas prices also significantly affect our results of operations.

Successful  merger and acquisition  activities  also have a large impact on our results of operations by increasing  proved reserves in
our core areas which allow us greater exploration and production  potential paired with existing operation and production  expertise in
these areas.

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

On March 15,  2002,  we completed  our merger with Prize  Energy Corp.  ("Prize"),  a publicly  traded oil and gas  production  company
engaged primarily in the acquisition,  enhancement,  and exploitation of producing oil and gas properties.  For operating and financial
reporting  purposes,  the  effective  date of the merger was March 1, 2002. As such,  the results of  operations  for 2002 include ten
months of  operating  contributions  from  Prize.  The  transaction  has been  accounted  for as a purchase  of Prize by the company in
accordance  with the  provisions of SFAS No. 141. Under the terms of the merger,  we distributed  2.5 shares of common stock plus $5.20
in cash for each Prize share  outstanding.  The following  summary,  prepared on a pro forma basis,  presents the results of operations
for the years ended December 31, 2002 and 2001 as if the  acquisitions  occurred as of the beginning of the respective  years.  The pro
forma  information  includes the effects of adjustments for interest  expense,  depreciation,  depletion and  amortization,  and income
taxes:

|                                   | (Unaudited)
|---------------------------------- | -----------
|
|
|Revenue                            |            
|Total Operating Costs and Expenses |            
|                                   |            
|Operating Profit                   |            
|Interest Expense and Other         |            
|                                   |            
|Income before Tax                  |            
|Benefit (Provision) for Income Tax |            
|                                   |            
|Net Income                         |            
|Net Income Per Common Share        |            
|Basic                              |            
|Diluted                            |            

Subsequent to the Prize merger, we
sold non-strategic proved producing oil and gas reserves for total proceeds of
approximately $113.1 million, net of purchase price adjustments. Substantially all of the
properties sold were acquired in the Prize merger, and the proceeds have been used to
reduce our overall indebtedness and fund our capital expenditure program. The impact of
these non-strategic divestitures are described below in our results of operations. During
2001, we realized $1.1 million from the sale of non-strategic oil and gas reserves.

28

On July 29, 2003, we exercised our
option to sell our 30% interest in NGTS, LLC (NGTS). We reduced the carrying
value of our investment by approximately $791 thousand and recorded a charge to equity in
earnings of affiliate in that amount to state our investment at its estimated fair value.
The sale closed on September 30, 2003, and we received proceeds of $5.2 million on that
date, which were used to repay indebtedness. No gain or loss was recorded on the sale.

Our results of operations have been
significantly affected by our past success in acquiring oil and gas properties at or near
the bottom of the commodity price cycles and our ability to maintain or increase oil and
natural gas production through our exploration and exploitation activities. Fluctuations
in oil and gas prices and commodity hedging activities have also significantly affected
the results of operations.

The following table sets forth
certain information with respect to our business segments:

|                                                     | Years Ended
|---------------------------------------------------- | -----------
|
|Exploration and Production Operations                |            
|Production:                                          |            
|Oil (MBbls)                                          |            
|Gas (MMcf)                                           |            
|Oil and gas (MMcfe)                                  |            
|Equivalent daily rate (MMcfe/day)                    |            
|Average sale prices (after hedging):                 |            
|Oil (per Bbl)                                        |            
|Gas (per Mcf)                                        |            
|Oil and gas (per Mcfe)                               |            
|Effect of hedging activities (per Mcfe)              |            
|Lease operating expense (per Mcfe):                  |            
|Lifting costs                                        |            
|Production tax and other costs                       |            
|Gross margin (per Mcfe)                              |            
|Depreciation, depletion, amortization and  accretion |            
|(per Mcfe)                                           |            
|Segment profit (thousands)                           |            
|Gas Gathering, Marketing and Processing Operations   |            
|Throughput volumes (Mcf per day)                     |            
|Gathering                                            |            
|Processing                                           |            
|Gross margin (in thousands)                          |            
|Gathering (per Mcf throughput)                       |            
|Processing (per Mcf throughput)                      |            
|Segment profit (thousands)                           |            
|Oil Field Management Services                        |            
|Segment profit (thousands)                           |            

Period to Period
Comparisons

For the Years Ended
December 31, 2003 and 2002

We reported net income of $26.1
million for the year ended December 31, 2003 as compared to net income of $15.5 million
for the same period in 2002, an increase of 68%, reflecting the solid performance of both
our exploration and production segment and our gathering, marketing and processing
segment. Total operating revenues increased 22% to $325.0 million in 2003 from $265.9
million in 2002. A 15% increase in the price received for oil and gas sold (on a thousand
cubic feet equivalent, or Mcfe, basis), combined with a 3% increase in oil and gas
production (on a million cubic feet equivalent, or MMcfe, basis) in our exploration and
production segment, as well as a 70% increase in revenues in our gas gathering, marketing
and processing segment due to the Prize merger and product price increases, were primarily
responsible for the improvement in revenues. The production increase in our exploration
and production segment was impacted by the merger with Prize, the success of our drilling
program, and the sale of non-strategic oil and gas properties. Total operating costs and
expenses increased 18% to $232.3 million in 2003 from $197.0 million in 2002, principally
due to higher depreciation, depletion, amortization and accretion expense, lease operating
expense, gas gathering, marketing and processing expense, and general administrative
expense due to the merger with Prize. Operating profit increased 35% to $92.7 million in
2003 from $68.9 million in 2002, due primarily to a 27% increase in our exploration and
production segment profit from $78.3 million in 2002 to $99.8 million in 2003 and a 109%
increase in our gas gathering, marketing and processing segment profit from $3.6 million
in 2002 to $7.6 million in 2003. Segment profit for our oil field management service
segment declined approximately 6% from $1.1 million in 2002 to $1 million in 2003 due to
higher depreciation expense. Net income before income tax and cumulative effect of a
change in accounting principle increased 194% to $40.9 million in 2003 from $13.9 million
in 2002, primarily due to the Prize merger and the increase in crude oil, natural gas, and
natural gas liquids prices in the 2003 period compared to the 2002 period. Additionally,
the 2003 period included costs associated with early retirement of debt of $6.7 million
from the redemption of our 10% Senior Notes, discussed in further detail below in
Other Income and Expenses. We recorded income tax expense of $15.2 million for
2003, of which $15.5 million was deferred tax expense, versus a deferred tax benefit of
$1.6 million for 2002. The 2002 period income tax benefit resulted from the elimination of
the $7.1 million valuation allowance that had been carried against deferred tax assets
derived from net operating loss carryovers generated by Magnum Hunter in prior years. As a
result of the Prize merger, we believe that this tax asset can be fully realized.
Additionally, the 2003 period includes the cumulative effect on prior years of a change in
accounting principle due to the adoption of SFAS No. 143 relating to asset retirement
obligations. The cumulative effect was a gain of $399 thousand, net of income tax expense
of $244 thousand, or $0.01 per share, both basic and diluted. Basic and diluted earnings
per share in 2003 were $0.39 and $0.38, respectively, versus basic and diluted earnings
per share of $0.25 in the 2002 period. Basic and diluted shares outstanding increased 8%
in the 2003 period compared to the 2002 period, primarily as a result of new shares issued
in the Prize merger. The 52% gain in diluted earnings per share in 2003 compared to 2002
was primarily the result of the increase in net income.

29

Exploration and
Production Operations:

For the year ended December 31, 2003,
we reported oil production of approximately 3.9 million barrels and natural gas production
of approximately 49.7 billion cubic feet, which represents no change in oil produced and
an increase of 4% in natural gas produced from the 47.7 billion cubic feet reported in the
2002 period. Our reported equivalent daily rate of production on a million cubic feet per
day basis (MMcfe per day) increased 3% to 200.1 MMcfe per day in the 2003 period from
194.3 MMcfe per day in the 2002 period. These increases were primarily the result of the
Prize merger and the success of our drilling program offsetting both normal production
declines and the effect of the sale of non-strategic oil and gas properties subsequent to
the Prize merger. The impact of these non-strategic property sales on reported production
was a decrease of 27.1 Mmcfe per day in the 2003 period compared to the 2002 period.
Removing the effect of sold properties from both the 2003 and 2002 periods, our daily
equivalent production grew 15.9% from 2002 to 2003.

Oil revenues increased 10% to $102.8
million in the 2003 period compared to $93.2 million in the 2002 period. The oil price
received, after hedging effects, was $26.42 per Bbl in the 2003 period compared to $24.04
per Bbl in the 2002 period, an increase of 10%. Gas revenues increased 23% to $181.7
million in the 2003 period versus $147.8 million in the 2002 period. The gas price
received, after hedging effects, was $3.66 per Mcf in the 2003 period compared to $3.10
per Mcf for the same period in 2002, an increase of 18%. We also recorded $398 thousand in
oil and gas sales in the 2003 period from business interruption insurance proceeds
resulting from claims filed in 2002 due to Hurricane Lili. Total oil and gas sales
increased 18% to $284.9 million in 2003 from $241 million in 2002.

From time to time, we enter into
various commodity hedging contracts in order to reduce our exposure to the possibility of
declining oil and gas prices which provide a basic level of cash flow to fund capital
expenditures. During the 2003 period, hedging decreased the average price we received for
oil by $3.20 per Bbl and decreased the average price we received for gas by $1.23 per Mcf.
During the 2003 period, we had approximately 35.0 Mmcf per day of gas hedged through fixed
price swaps with a weighted average price of $3.10 per Mmbtu and approximately 55.0 Mmcf
per day of gas hedged through cost-less collars with a weighted average floor price of
$2.91 per Mmbtu and a weighted average ceiling price of $3.97 per Mmbtu. Approximately 60%
of 2003 natural gas production was hedged. On the crude side, we had approximately 1,000
Bbls per day hedged through fixed price swaps with a weighted average price of $21.25 per
barrel and approximately 6,000 Bbls per day hedged through cost-less collars with a
weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of
$27.00 per Bbl. Approximately 66% of 2003 crude oil production was hedged.

30

Lease operating expense consists of
lifting costs and production taxes and other costs. For the 2003 period, lifting costs
were $56.3 million versus $51.6 million in the 2002 period, an increase of 9%. Production
taxes and other costs were $32.8 million in the 2003 period versus $28.2 million in the
2002 period, an increase of 16%. Both increases were primarily attributable to the Prize
merger. For the 2003 period, lifting costs, on a unit of production basis, were $0.77 per
Mcfe as compared to $0.72 per Mcfe in the 2002 period, an increase of 7%. The increase in
lifting costs per Mcfe produced in the 2003 period was due to higher power and fuel costs
and increased remedial and workover expense. The increased workover expense is due to
remedial work on older properties acquired in the Prize merger as well as workovers done
at our discretion to enhance current production. Production taxes and other costs were
$0.45 per Mcfe produced in the 2003 period compared to $0.40 per Mcfe produced in the 2002
period, an increase of 13%. The increase in production taxes per Mcfe produced was caused
by an increase in crude oil and natural gas prices received during the 2003 period.

Our gross margin realized from
exploration and production operations (oil and gas revenues less lease operating expenses)
for the 2003 period was $195.9 million, or $2.68 per Mcfe, compared to $161.2 million, or
$2.28 per Mcfe in the 2002 period, an increase of 18% on a per unit of production basis.
The gross margin increase is the result of a 15% increase in revenue per Mcfe produced,
offset by a 9% increase in lease operating expense per Mcfe produced.

Depreciation, depletion, amortization
and accretion of oil and gas properties was $96.1 million in the 2003 period versus $83
million in the 2002 period. The 2003 period included accretion expense related to asset
retirement obligations (due to the adoption in January 2003 of SFAS No. 143) of $2.5
million versus none in 2002. On a unit of production basis, depreciation and depletion
expense (excluding accretion expense) was $1.28 per Mcfe produced in the 2003 period
versus $1.17 per Mcfe produced in the 2002 period. This 10% increase in the equivalent
unit cost was due primarily to an increase in development costs and shorter reserve life
properties associated with our activities in the Gulf of Mexico as well as the transfer of
$75.0 million of costs from unproved properties to the full cost pool. The costs which
were transferred related to unproved property costs associated with properties which were
sold or proved during 2003, as well as costs associated with leases which expired during
the year. Accretion expense was $0.03 per Mcfe in 2003 versus none in 2002. Total
depreciation, depletion, amortization and accretion for this segment was $1.32 per Mcfe in
2003 versus $1.17 per Mcfe in 2002.

Segment profit for exploration and
production operations was $99.8 million for the 2003 period versus $78.3 million for the
2002 period, an increase of 27%, principally due to properties acquired in the Prize
merger, the success of our drilling program, and higher realized crude oil and natural gas
prices.

Gathering, Marketing and
Processing Operations:

For the year ended December 31, 2003,
our gathering system throughput was 15.8 MMcf per day versus 15.5 MMcf per day for the
same period in 2002, an increase of 2% due to successful drilling behind the system. Gas
processing throughput was 24.9 MMcf per day in 2003 versus 22.8 MMcf per day in 2002, an
increase of 9%, due primarily to the effect of the Prize merger.

Revenues from gathering, marketing
and processing increased 70% to $35.3 million in 2003 versus $20.8 million in 2002,
primarily due to higher realized prices for natural gas and natural gas liquids. The gross
margin realized from gathering, marketing and processing for 2003 was $9.9 million versus
$5.7 million in 2002, an increase of 74%. The gathering margin was $0.14 per Mcf gathered
in 2003 versus $0.13 per Mcf in 2002 due to an increase in gathering fees. The processing
margin was $0.99 per Mcf in 2003 compared to $0.55 per Mcf in 2002 due to more favorable
processing economics.

Depreciation expense for gas
gathering, marketing and processing operations was $2.3 million for the 2003 period versus
$2.1 million for the 2002 period, due to the Prize merger.

Segment profit for gas gathering,
marketing and processing operations was $7.6 million in the 2003 period versus $3.6
million for the 2002 period, an increase of 109%, principally due to higher throughput and
improved processing economics at our natural gas processing plants.

31

Oil Field Management
Services Operations:

Revenues from oil field management
services were $4.8 million in the 2003 period versus $4.1 million in the 2002 period due
to higher management and operations services fees charged to third parties. Operating
costs increased to $3.1 million in 2003 from $2.5 million in 2002 due to higher costs for
labor and overhead. The gross margin for this segment in 2003 compared to 2002 was
unchanged at $1.6 million.

Depreciation expense was $604
thousand in the 2003 period versus $507 thousand in the 2002 period, an increase of 19%,
due to capital additions. Segment profit was $1 million in 2003 versus $1.1 million in
2002, a decrease of 6%, due to the increase in depreciation expense.

Depreciation, Depletion,
Amortization and Accretion:

Total depreciation, depletion,
amortization and accretion expense was $99.6 million in the 2003 period versus $86.5
million in the 2002 period, an increase of 15%, primarily as a result of increased
production and increased depletion and accretion rates in our exploration and production
segment.

Other Income and Expenses:

We recorded a gain on sale of assets
other than oil and gas properties of $171 thousand in 2003 versus $61 thousand in 2002.
General and administrative expense for 2003 increased 15% to $15.3 million from $13.3
million in 2002. The principal reason for this increase was the $3.0 million cost of
expensing employee stock options recorded in the 2003 period as a result of the adoption
of SFAS No. 123 in June 2003, with an effective date of January 1, 2003. The number of
full-time employees at fiscal year-end 2003 and 2002 was 222 and 221 respectively. We
recorded equity in loss of affiliate of $162 thousand in 2003 versus equity in earnings of
affiliate of $792 thousand in 2002, principally due to the reduction of the carrying value
of our investment in NGTS by $791 thousand to state it at its estimated fair value prior
to sale, as well as our equity in losses generated by Metrix Networks, Inc.
(Metrix) prior to our acquisition of 80% control of Metrix in December 2003.
Other income was $889 thousand for 2003 versus $452 thousand in 2002, a 97% increase, due
to an increase in interest income. In 2002, we recorded an impairment of $621 thousand on
an investment in a company that declared bankruptcy. We recognized a $1.5 million gain in
other non-cash hedging adjustments in 2003 versus a loss of $6.6 million in 2002. In the
2003 period, $1.3 million of the hedging gain relates to the amortization of commodity
hedge liabilities acquired in the Prize merger, while $186 thousand of the gain was due to
recording hedge ineffectiveness. In the 2002 period, a loss of $6.1 million relates to the
amortization of commodity hedge assets acquired in the Prize merger, and a loss of $500
thousand was due to recording hedge ineffectiveness.

We incurred costs associated with
early retirement of debt of $6.7 million in 2003 versus $1 million in 2002. The 2003
period costs were associated with the $30 million, $50 million, and $60 million
redemptions in principal value of our 10% Senior Notes at 105% of par, 103.333% of par,
and 103.333% of par in January, June and December 2003, respectively, as well as a
subsidiarys August 2003 purchase of $381 thousand in principal value of our 10%
Senior Notes at 103.75% of par. Of the $140 million in principal value of 10% Senior Notes
redeemed in 2003, a subsidiary received $10.9 million in principal value. The 2002 period
debt retirement costs of $1 million were associated with the amendment of our Facility in
connection with the Prize merger.

Interest expense was $47.3 million
for 2003 versus $47.9 million for 2002, a decrease of 1%, primarily as a result of lower
interest rates on our Senior Credit Facility (Facility), lower interest rate
hedging costs, and interest saved on the early redemption of our 10% Senior Notes. During
the 2003 period, the average interest rate on our Facility was 3.4% versus 4.0% in 2002, a
decline of 15%. The weighted average daily balance of our Facility increased 17% to $213.7
million in 2003 from $182.9 million in 2002. By December 31, 2003, the level of our
Facility had been reduced to $165 million through sales of non-strategic oil and gas
properties and the issuance in December 2003 of $125 million of floating rate convertible
senior notes (Convertible Notes), which have a floating interest rate based on
three-month LIBOR (initially set at 1.17%). In addition, we incurred interest rate hedge
expense of $961 thousand in the 2003 period versus $1.2 million in the 2002 period. The
interest rate hedge expired in August 2003.

We recorded income tax expense of
$15.2 million in 2003 ($15.5 million of which was deferred), versus a deferred income tax
benefit of $1.6 million in 2002. The 2002 period benefited from the release of the $7.1
million valuation allowance on previously reserved deferred tax assets as a result of the
increased likelihood (due to the Prize merger) that the tax assets generated from prior
net operating losses will be realized in the future. The 2002 period was also impacted by
a $2.3 million deferred tax provision from the adjustment of goodwill due to sales of
non-strategic oil and gas properties. The effective tax rate for 2003 and 2002 was 37.2%
and (11.4%), respectively. The variance in the effective tax rate from the statutory rate
of 35% was due to state income taxes in the 2003 period and the release of the valuation
allowance on our previously reserved deferred tax assets in the 2002 period.

32

For the Years Ended
December 31, 2002 and 2001

We reported net income of $15.5
million for the year ended December 31, 2002 as compared to net income of $13.5 million
for the same period in 2001, an increase of 15%. The 2002 period results include a
provision for impairment of investments of $621 thousand and a loss from early retirement
of debt of $1.0 million. The 2001 period results include a loss on Enron related assets of
$3.2 million, a provision for impairment of investments of $7.1 million, and a loss from
early retirement of debt of $490 thousand from the repurchase of $10.5 million in
principal value of our 10% Senior Notes. Total operating revenues increased 74% to $265.9
million in 2002 from $152.8 million in 2001 and operating profit increased 44% to $68.9
million in 2002 from $48.0 million in 2001. A 15% decrease in the price received for oil
and gas sold (on a thousand cubic feet equivalent, or Mcfe, basis), combined with a 113%
increase in oil and gas production (on a million cubic feet equivalent, or MMcfe, basis)
in our oil and gas exploration and production segment, was primarily responsible for the
improvement in revenues. The production increase was primarily due to the merger with
Prize. Total operating costs and expenses increased 88% to $197.0 million in 2002 from
$104.8 million in 2001, principally due to higher depreciation, depletion and amortization
expense, lease operating expenses, and general administrative expenses due to the merger
with Prize. Income before income tax decreased 36% to $13.9 million in 2002 from $21.9
million in 2001, primarily due to higher interest expense and non cash hedging losses due
to the Prize merger. Income per common share-diluted was $0.25 per share in the 2002
period compared to $0.36 per share in the 2001 period, a decrease of 31%, due to a 68%
increase in diluted shares, principally as a result of the Prize merger. The effect of the
extraordinary loss in the 2002 and 2001 periods was $0.01 per share, basic and diluted. No
dividends were recorded in the 2002 or 2001 periods due to the conversion of $25.0 million
(liquidation value) of our 1999 Series A 8% convertible preferred stock on January 1, 2001
into approximately 4.8 million shares of our common stock.

Exploration and
Production Operations:

For the year ended December 31, 2002,
we reported oil production of 3.9 MMbbls (million barrels) and gas production of 47.7 MMcf
(million cubic feet), which represents an increase of 175% in oil and an increase of 92%
in gas produced from the comparable period in 2001. Our reported equivalent daily rate of
production on a million cubic feet per day basis (MMcfe/day) increased 113% to 194.3
MMcfe/day in the 2002 period from 91.3 MMcfe/day in the 2001 period. These increases were
primarily the result of the Prize merger and the success of our drilling program
offsetting normal production declines.

Prices realized in the 2002 period
averaged $24.04 per barrel of oil and $3.10 per Mcf of gas. This represents a 15% decrease
on a thousand cubic feet of gas equivalent (Mcfe) basis over the 2001 period average
realized prices of $24.53 per barrel of oil and $3.96 per Mcf of gas. The unit prices
realized include the effects of hedging. During the 2002 period, hedging decreased the
average price we received for oil by $1.14 per barrel and increased the average price we
received for gas by $0.03 per Mcf. Excluding the effects of hedging, oil prices increased
7% and natural gas prices decreased 20% in 2002 from those received in 2001.

As a result of higher production
levels, partially offset by lower realized prices, oil and gas revenues increased 81% to
$241.0 million in the 2002 period compared to $133.1 million in the 2001 period.

For the 2002 period, oil and gas
production lifting costs, on a unit of production basis, were $0.72 per Mcfe as compared
to $0.61 per Mcfe in the 2001 period, an increase of 18% due to the relatively higher cost
per unit of the Prize properties. Production tax and other costs were $0.40 per Mcfe in
the 2002 period compared to $0.39 per Mcfe in the 2001 period, an increase of 3%
principally due to higher ad valorem taxes.

Gross margin for exploration and
production operations for the 2002 period was $161.2 million, or $2.28 per Mcfe, compared
to $99.7 million, or $2.99 per Mcfe in the 2001 period, a decrease of 24% on a per unit of
production basis, primarily as a result of the decrease in oil and gas prices realized and
the increase in lifting costs per unit.

Depreciation, depletion, and
amortization of oil and gas properties was $83 million in the 2002 period versus $42.7
million in the 2001 period, an increase of 94% due primarily to the Prize merger. On a
unit of production basis, depreciation and depletion expense was $1.17 per Mcfe produced
in the 2002 period versus $1.28 per Mcfe produced in the 2001 period. This 9% decrease in
the equivalent unit cost was due primarily to the merger with Prize which added proved
reserves at a cost of approximately $0.84 per Mcfe.

33

Segment profit for exploration and
production operations was $78.3 million for the 2002 period versus $57 million for the
2001 period, an increase of 37%, principally due to the Prize merger.

Gas Gathering, Marketing
and Processing Operations:

For the year ended December 31, 2002,
our gathering system throughput was 15.5 MMcf per day versus 16.1 MMcf per day for the
same period in 2001, a decline of 4% due to normal production declines behind the system.
Gas processing throughput was 22.8 MMcf per day in 2002 versus 13.3 MMcf per day in 2001,
an increase of 72%. Our reported processing throughput in the 2001 period was reduced due
to (i) the sale in September 2001 of a substantial ownership interest in oil and gas
properties supplying one of our plants, (ii) the voluntary shutdown of two gas processing
plants for approximately two months of the 2001 period due to adverse processing economics
as a result of high natural gas prices and (iii) normal production declines on properties
supplying the plants. Our processing throughput in the 2002 period was increased due to
the acquisition of a processing plant in the merger with Prize.

Revenues from gathering, marketing
and processing increased 16% to $20.8 million in 2002 versus $17.9 million in 2001,
primarily due to the acquisition of a processing plant in the merger with Prize. The gross
margin realized from gathering, marketing and processing for 2002 was $5.7 million versus
$1.8 million in 2001, an increase of 218%. Gathering margin was $0.13 per Mcf gathered in
2002 versus $0.04 per Mcf in 2001 due to an increase in marketing spreads. In the 2000
period, losses were incurred on pipeline imbalance positions. Processing margin was $0.55
per Mcf in 2002 compared to $0.27 per Mcf in 2001 due to more favorable processing
economics because of the decline in natural gas prices and the temporary shutdown of two
plants for a portion of the 2001 period.

Depreciation expense for gas
gathering, marketing and processing operations was $2.1 million in the 2002 period versus
$883 thousand in the 2001 period, an increase of 127%, due to the Prize merger.

Segment profit for gas gathering,
marketing and processing operations was $3.6 million in the 2002 period versus $911
thousand in the 2001 period, an increase of 300%, principally due to the Prize merger.

Oil Field Management
Services Operations:

Revenues from oil field management
services were $4.1 million in the 2002 period versus $1.8 million in the 2001 period due
to higher management and operations services fees charged to third parties as a result of
the Prize merger.

Operating costs increased to $2.5
million in 2002 from $1.3 million in 2001 due to higher costs for labor and overhead. The
gross margin for this segment in 2002 was $1.6 million versus $551 thousand in 2001, an
increase of 194%.

Depreciation expense was $507
thousand in the 2002 period versus $394 thousand in the 2001 period, an increase of 29%
due to capital additions. Segment profit was $1.1 million in 2002 versus $157 thousand in
2001.

Other Income and Expenses:

Depreciation and depletion expense
was $86.5 million in the 2002 period versus $44.0 million in the 2001 period, an increase
of 97% due to higher production levels as a result of the Prize merger. General and
administrative expense for 2002 increased 93% to $13.3 million from $6.9 million in 2001.
The principal cause of this increase was an increase in salary, benefits and retirement
plan expenses and an increase in our overall headcount associated with the Prize merger.
The numbers of employees at fiscal year-end 2002 and 2001 were 221 and 105, respectively.
We recorded equity in earnings of affiliate of $792 thousand in 2002 versus income of $1.1
million in 2001, a 27% decrease, due to an operating loss recorded by one of the
affiliates. Other income was $452 thousand for 2002 versus $283 thousand in 2001, a 60%
increase, due to an increase in interest income. We recognized a $6.6 million loss in
other non-cash hedging adjustments in 2002 versus a gain of $52 thousand in 2001. In the
2002 period, $6.1 million relates to the amortization of commodity hedge assets acquired
in the Prize merger, while $500 thousand was due to recording hedge ineffectiveness. In
the 2001 period, the $52 thousand gain was due to interest rate swaps.

34

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

We had equity and debt investments in
a privately held entity which declared bankruptcy subsequent to December 31, 2001, and we
provided an impairment charge against earnings of $5.0 million at December 31, 2001.
Additionally, we had an investment in available-for-sale securities of another entity of
$2.7 million at December 31, 2001. Because of the deteriorating financial condition of
this entity, we reported an other than temporary impairment of $2.1 million as a charge
against earnings at December 31, 2001, based on the entitys reported market value on
that date. In 2002, this entity declared bankruptcy and we recorded a further impairment
of $621 thousand on this investment.

Interest expense was $47.9 million
for 2002 versus $19.9 million for 2001, an increase of 141%, primarily as a result of
higher debt levels due to the Prize merger. On March 15, 2002 we issued $300 million in
9.6% Senior Notes due in 2012. During the 2002 period, the interest rate on our Facility
was 4.0% versus 6.3% in 2001, a decline of 36%. The weighted average daily balance of bank
debt increased 96% to $182.9 million in 2002 from $93.3 million in 2001. By December 31,
2002, the level of debt under our Facility had been reduced to $125 million through sales
of non-strategic oil and gas properties. In addition, interest expense was reduced in the
2001 period by $744 thousand as a result of interest rate derivatives versus an increase
in interest expense of $1.2 million from interest rate derivatives in the 2002 period.

We recorded an income tax benefit of
$1.6 million in 2002 versus income tax expense of $8.4 million in 2001. The 2002 period
benefited from a $7.1 million reduction in the valuation allowance charged against
deferred tax assets as a result of the increased likelihood (due to the Prize merger) that
the tax assets generated from prior net operating losses will be realized in the future.
The 2002 period was also impacted by a $2.3 million deferred tax provision from the
adjustment of goodwill due to sales of non-strategic oil and gas properties. The effective
tax rate for 2002 and 2001 was (8.1%) and 38%, respectively. The variance in the effective
tax rate from the statutory rate of 35% was due to the release of the valuation allowance
on our previously reserved deferred tax assets in 2002.

Liquidity and Capital
Resources

Our liquidity is primarily dependent
upon our ability to generate cash flow from operations and from external sources such as
our commercial banks or the bond market. One of the most significant items that can impact our internally
generated funds and availability under our line of credit is commodity prices. Should oil
and gas prices decline significantly, our cash flow would be negatively impacted. If
commodity prices declined and were perceived by our lenders to be more than temporary, the
amount available under our bank line of credit would be reduced. Reductions in our
borrowing capacity could cause us to have to pay down our bank debt, reduce our drilling
activities and possibly sell oil and gas properties.

Increases in interest rates could
also negatively impact our liquidity, as more cash flow would have to be directed toward
the payment of interest. Because Magnum Hunter is leveraged, interest expense is a
significant financial obligation.

We attempt to mitigate the impact of
decreases in commodity prices and increases in interest rates by the use of hedging
contracts; however, we do not hedge all of our commodity price or interest rate risks.
Instead, management judges the likelihood of changes in commodity prices and interest
rates and considers other factors such as the amount of debt and estimated cash flow under
various scenarios. Hedges are then considered and entered into as deemed appropriate.

CASH FLOW AND WORKING CAPITAL. Net
cash provided by operating activities was $162.6 million, $83.4 million, and $104.1
million in 2003, 2002, and 2001, respectively. Our operating cash flow for 2003 increased
over that for 2002, primarily due to higher operating profits realized by our business
segments when adjusted for non-cash items. Please see the period to period comparisons for
further explanations on the causes and amounts of the increases in our earnings. We also
benefited in the 2003 period from $8.1 million in income tax refunds (net of current year
payments) as well as the return of $6.5 million in margins we had posted on commodity
hedge positions. Our 2002 operating cash flow was lower than our 2001 operating cash flow
due to higher receivables balances carried at year end, large margins posted on our hedge
positions, and cash used to reduce current liabilities acquired in the Prize merger. These
decreases in cash flows were partially offset by increases in cash flows due to tax
refunds received and cash received on hedge positions acquired in the Prize merger which
were closed during 2002.

35

Our net working capital position at
December 31, 2003 was a deficit of $5.2 million. At this date, we had $87.5 million
available under our Facility. A large factor in our negative working capital was $21.9
million in current derivative liabilities we had recorded on our 2004 hedging program due
to continued increases in commodities prices over our hedged prices. This liability is
partially offset by $8.3 million in deferred tax assets which will be released as our 2004
hedges are settled. If actual commodities prices realized on our production remain higher
than our hedged prices, our resulting higher proceeds from oil and gas sales will offset
any actual amounts paid out on this liability.

Our net working capital position at
December 31, 2002 was a deficit of $31.0 million. At this date we had $122.0 million
available under our Facility. Again, a large factor in our negative working capital was
$42.8 million in current derivative liabilities we had recorded on our 2003 hedging
program due to continued increases in commodities prices over our hedged prices for 2003
production. The amounts paid out on these liabilities were offset by higher cash received
for the related production in 2003. This liability was also offset by $15.5 million of
current deferred tax assets which were released as the positions were settled.

INVESTING ACTIVITIES: Net cash used
in investing activities was $159.7 million, $89.4 million, and $204.0 million in 2003,
2002, and 2001, respectively. In 2003, the main source of our investing was $175.5 million
spent for capital expenditures which are discussed in the section immediately following
our liquidity and capital resources discussions. During 2003 we also received $17.1
million from the sales of non-strategic oil and gas properties as well as $5.1 million from
the sale of our 30% interest in NGTS. We spent $7.6 million to purchase land which we
currently have available for sale. We expect to sell these properties during 2004.

During 2002 we spent $141.0 million
on capital expenditures as well as $41.1 million to complete the Prize merger. Both of
these items are discussed in detail in separate sections following our liquidity and
capital resources discussions. These expenditures were partially offset by $96.0 million
received on sales of non-strategic oil and gas properties acquired in the Prize merger.

We used $204.0 million on investing
activities during 2001. Capital expenditures of $204.4 million accounted for most of the
spending. Again, please see the capital expenditures section for additional details on our
capital expenditure program. We also received distributions of $1.6 million from NGTS
which partially offset the $2.5 million which we invested in another affiliate.

FINANCING ACTIVITIES: Net cash
provided by financing activities was $12.7 million, $6.3 million, and $102.7 million in
2003, 2002, and 2001, respectively. During 2003, we received $4.7 million from the
issuance of common stock and treasury stock pursuant to employee stock option and warrant
programs. We repurchased approximately 1.3 million common shares at a cost of $7.4 million
under our existing share repurchase programs. We loaned $2.7 million to our KSOP to
purchase approximately 486 thousand shares of our common stock to be available for
purchase by participants at future dates. KSOP participants paid us $380 thousand to
purchase approximately 59 thousand unallocated KSOP shares of our common stock and we
forgave KSOP debt of $1.1 million by contributing approximately 172 thousand unallocated
shares of our common stock to participants as our 2003 employer retirement plan
contribution. At December 31, 2003, the KSOP had a loan balance of $6.1 million. This loan
carries no interest and is due December 31, 2004. We paid $134.4 million to redeem the
outstanding $129.5 million in principal of our 10% Senior Notes, borrowed approximately
$517.4 million under our Facility, and made repayments on our debt of $486.3 million. We
also received $125 million from the issuance of Convertible Notes and paid fees related to
our financing activities of $4.4 million.

During 2002, we received $300 million
from the issuance of our 9.6% Senior Notes due 2012 and paid down debt of $30 million. We
also paid off $246.8 million of long-term debt acquired in the Prize merger. During 2002,
we spent $18.0 million to repurchase approximately 2.7 million shares of our common
stock. We loaned $3.7 million to our KSOP to purchase approximately 532 thousand
shares of our common stock and forgave KSOP debt of $1.3 million by releasing
approximately 244 thousand shares of our common stock to participants. We also received
$3.6 million from the exercise of employee stock options.

Net cash provided by financing
activities in 2001 was $102.7 million. We borrowed $262.5 million under our Facility as
well as $4.0 million through vendor-provided financing of several offshore platforms. We
repaid borrowings under our Facility of $158.6 million and purchased $10.5 million in
principal of our 10% Senior Notes for $10.8 million. We received $5.8 million from the
issuance of common stock. We also purchased treasury shares for $1.0 million, loaned the
KSOP $898 thousand, and forgave KSOP debt of $1.1 million in lieu of a cash contribution
to the plan.

36

BLUEBIRDS AND CANVASBACKS
CAPITAL RESOURCES: On March 1, 2002, we created two wholly-owned subsidiaries, Canvasback
Energy, Inc. and Redhead Energy, Inc. During March 2003, Canvasback Energy, Inc. became
the controlling shareholder of Metrix, resulting in its full consolidation with a
minority interest. These three entities will collectively be referred to as Canvasback.
Like Bluebird, these entities are not guarantors of any of our issued debt, and they
cannot be included in debt compliance calculations. On March 15, 2002, Bluebird, an
unrestricted subsidiary, transferred all of its assets to Canvasback.

During 2003, Canvasback received
proceeds of $10.9 million in principal value from the redemption of its investment in
Magnum Hunters 10% Senior Notes. It also received $259 thousand in premiums in
addition to the principal value. It also repaid their $7 million term loan and
terminated the agreement. Canvasback purchased 916,000 shares of Magnum Hunter common
stock during 2003 at a cost of $5.1 million and $381 thousand in principal of Magnum
Hunters 10% Senior Notes. Canvasback also received $2.6 million from sales of units of
their investment in TEL Offshore Trust. At December 31, 2003, Canvasback had no
contractual obligations or spending plans.

During 2002, Canvasback purchased $12
million of Magnum Hunter common stock, borrowed $7 million under its own note agreement,
and repurchased $5.8 million in principal of Magnum Hunters 10% Senior Notes.

On May 17, 2001, Bluebird sold all of
its proved and unproved oil and gas properties, except for its investment in TEL Offshore
Trust, and all of its pipelines and other fixed asset property to Magnum Hunter
Production, Inc. for $17.7 million in cash and $10 million of our 1996 Series A
convertible preferred stock. Bluebird used the sales proceeds to retire its $17.7 million
of debt. The effective date of the sale was May 1, 2001. On June 25, 2001, Canvasback
purchased $4.7 million in principal of Magnum Hunters 10% Senior Notes on the open
market.

MAGNUM HUNTERS CAPITAL
RESOURCES: The following discussion of Magnum Hunters capital resources refers to
the company and its affiliates other than Canvasback and Bluebird, whose capital resources
are discussed separately above. Internally generated cash flow from operations and
borrowings under our Facility are our major sources of liquidity. From time to time, we
may also sell investments and oil and gas properties to increase our liquidity. We also
may use other sources of capital, such as issuances of additional debt or equity
securities to fund acquisitions or other specific needs. In the past, we have accessed
both public and private capital markets to obtain capital for specific activities as well
as general corporate purposes.

On May 1, 2002, our Board of
Directors announced an expansion of our existing stock repurchase program originally
established in June 2001. Under the program, the company or our affiliates are authorized
to repurchase up to two million shares of our common stock. On October 17, 2002, our Board
of Directors approved a new three million share repurchase program. Approximately 4.2
million shares have been repurchased through these programs, and approximately 818
thousand remain available for repurchase.

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

On January 15, 2002, we entered into
a sale-leaseback transaction on three newly constructed offshore production platforms and
associated pipelines. We received a total of $11.2 million in new funding which was used
for general corporate purposes, including a voluntary reduction under our Facility. The
production platforms are being leased from a syndicate group of lenders over a term of
three to five years and at a cost of funds of approximately 4.2% per annum, based on
current interest rates. This transaction is accounted for as a capital lease.

On March 15, 2002, we amended and
restated our Facility in conjunction with the merger with Prize. The amended Facility
provided for total borrowings of $500 million, up from $225 million, and raised the
borrowing base limit from $160 million to $300 million. Additionally, we amended and
extended the expiration date of the Facility to March 2005. After March 15, 2002, the
Facility was used  i) to fund the cash component of the Prize merger, ii) to pay certain costs
associated with the merger, and iii) for general corporate purposes. In connection with
certain oil and gas property divestitures, the borrowing base was reduced to $250 million
on September 3, 2002.

37

During 2003, we amended our Facility
in May and October to increase the borrowing base to $350 million, up $100 million from
our previous $250 million borrowing base. We also extended the expiration date of the
Facility to May 2, 2006. The increased borrowing base was used to fund the redemptions of
our 10% Senior Notes which were completed prior to the issuance of our Convertible Notes
in December 2003. We also used the increased borrowing base to fund the costs of issuing
our Convertible Notes. Upon the issuance of our Convertible Notes, we repaid approximately
$144 million of our borrowings on this Facility, and the borrowing base was reduced $95
million to $255 million. At December 31, 2003, we had available credit under this Facility
of $87.5 million.

Our Facility includes covenants, the
most restrictive of which requires maintenance of a minimum funded debt to EBITDA ratio
and an interest coverage ratio, as defined in the loan agreement. We were not in
compliance with the funded debt to EBITDA ratio required under the covenants at March 31,
2002. The lender provided us with a waiver as of that date, and we negotiated a less
restrictive funded debt to EBITDA ratio for the next four successive quarters until March
31, 2003. We were in compliance with the covenants for the remainder of 2002 and have been
in compliance with the revised covenants for all of 2003. We expect to be able to comply
with these covenants in the future.

On a semi-annual basis, our borrowing
base under our Facility is redetermined by the financial institutions who have committed
to the company based on their review of our proved oil and gas reserves and other assets.
If the outstanding balance on the Facility exceeds the redetermined borrowing base, we
must repay the excess immediately. The last redetermination date had an effective date of
June 30, 2003 and was completed on October 31, 2003. This redetermination increased our
borrowing base by $50 million. Our next redetermination date will have an effective date
of December 31, 2003 and will have an estimated completion date of May 31, 2004.

On March 15, 2002, we also completed
a private placement of $300 million of Senior Notes (the Private Placement)
due 2012 that are unsecured. The Senior Notes bear an annual interest rate of 9.6% due
semi-annually, commencing September 15, 2002.

With the funds provided by the new
Facility in 2002 and the Private Placement of the 9.6% Senior Notes, we repaid
indebtedness on our old Facility of $155.7 million, retired the long-term debt acquired in
the Prize merger for $246.8 million, funded the cash component of the merger for $70.9
million ($41.1 million net of cash acquired), and paid approximately $12.2 million for
fees and expenses related to the merger. In connection with the Prize merger, we issued
34,062,963 shares of our common stock to Prize shareholders, increasing our total shares
outstanding by 96%.

During 2003, we paid $145.2 million
to redeem the $140 million in principal of our 10% Senior Notes. This redemption was
funded by borrowings under our Facility as well as the issuance of $125 million in
Convertible Notes during December 2003. We paid approximately $5.2 million in premiums to
redeem the 10% Senior Notes. Of the notes redeemed, Canvasback received approximately
$10.9 million in principal and received premiums of approximately $259 thousand.

During December of 2003, we issued
$125 million in face value of Convertible Notes. These Convertible Notes bear interest
equal to the three-month LIBOR, to be adjusted quarterly. The initial rate set on issuance
of the Convertible Notes was 1.17%. The Convertible Notes are convertible into a
combination of cash and Magnum Hunter common stock upon certain events. The initial
conversion price is $12.19, subject to adjustment under certain conditions. The
Convertible Notes are due December 2023, but can be put by the holders on December 15,
2008, 2013, and 2018. We have the right to call these Convertible Notes at any time after
December 22, 2008. The proceeds from these Convertible Notes were used to repay borrowings
under the Facility.

Holders may surrender Convertible
Notes for conversion into cash and shares of our common stock prior to the Convertible
Notes maturity date in the following circumstances: i) during any calendar quarter
commencing after the issuance of the Convertible Notes, if our common stock price for at
least 20 trading days in the period of 30 consecutive trading days ending on the last
trading day of the calendar quarter preceding the quarter in which the conversion occurs
is more than 110% of the conversion price per share of our common stock in effect on that
30th trading day; ii) if we have called the particular Convertible Notes for redemption
and the redemption has not yet occurred; iii) during the five trading day period after any
five consecutive trading day period in which the trading price of $1,000 principal amount
of the Convertible Notes for each day of such five-day period was less than 95% of the
product of the closing sale price of our common stock on that day multiplied by 82.0345
(the Conversion Rate); or iv) upon the occurrence of specified corporate
transactions.

38

Upon the occurrence of the
circumstances described above, holders may convert any outstanding notes into cash and
shares of our common stock at an initial conversion price per share of $12.19. Subject to
certain exceptions, at the time notes are tendered for conversion, the value (the
Conversion Value) of the cash and shares of our common stock, if any, to be
received by a holder converting $1,000 principal amount of the notes will be determined by
multiplying the Conversion Rate by the ten-day average closing stock price of our common
stock. We will deliver the Conversion Value to holders as follows: i) an amount in cash
(the Principal Return) equal to the lesser of (a) the Conversion Value and (b)
the principal amount of the notes to be converted and, if the Conversion Value is greater
than the Principal Return, ii) an amount in shares equal to the Conversion Value less the
Principal Return (the Net Share Amount). The number of Net Shares to be paid
will be determined by dividing the Net Share Amount by the ten day average closing stock
price of our common stock.

Our internally generated cash flows,
results of operations, and financing of our operations are substantially dependent on oil
and gas prices. To the extent that oil and gas prices decline, our earnings and cash flows
may be adversely affected regardless of our commodity hedging programs. We believe that
our cash flows from operations, existing working capital, and availability under our
Facility will be sufficient to meet interest payments and fund capital expenditures during
2004.

CAPITAL EXPENDITURES. For the year
ended December 31, 2003, our total capital expenditures for property, plant and equipment,
were $175.5 million. The following summarizes our capital expenditures by cost component
(in thousands):

|                          
|--------------------------
|
|Acquisition costs:        
|Unproved acquisition      
|Proved acquisition        
|Other property acquisition
|Development costs         
|Exploratory costs         
|                          
|Total                     
|                          

For the year 2004, we have budgeted
approximately $185 million for exploration and development activities. We anticipate that
the 2004 capital expenditure budget will be funded by cash flow from operations and
Facility utilization. We are not contractually obligated to proceed with any of our
material budgeted capital expenditures. The amount and allocation of future capital
expenditures will depend on a number of factors that are not entirely within our control
or ability to forecast, including drilling results, oilfield costs, and changes in oil and
gas prices. As a result, actual capital expenditures may vary significantly from current
expectations.

In the normal course of business, we
review opportunities for the possible acquisition of oil and gas reserves and activities
related thereto. When potential acquisition opportunities are deemed consistent with our
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 we may submit from time
to time, will be acceptable to the sellers. In the event of a future significant
acquisition, we may require additional financing in connection therewith. We do not budget
for acquisition expenditures.

The following summarizes the oil and
gas properties acquired in the Prize merger (in millions):

|Oil & Gas Properties
|--------------------
|
|Acquisition Costs   

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS.  We have the following contractual obligations as of December 31, 2003:

|                              | Payments Due by Period (in thousands)
|----------------------------- | -------------------------------------
|
|Long-Term Debt                |                                      
|Capital Leases                |                                      
|Operating Leases              |                                      
|                              |                                      
|Total Contractual Obligations |                                      
|                              |                                      
|                              |                                      

39

We have no off balance sheet  arrangements,  special  purpose  entities or financing  partnerships.  In the past we have provided trade
guarantees on behalf of our formerly 30% owned affiliate,  NGTS. The last of these guarantees  expired in July 2003.  Further,  we have
sold our 30% ownership  interest in NGTS, and,  therefore,  no longer maintain any equity interest in this affiliate.  We have no other
guarantees on behalf of any entities and do not intend to issue any at this time.

Our 2004 capital  expenditure  budget is $185  million.  Based on our reserve  report,  future  development  costs are  estimated to be
$194.9 million for our proved reserves and $113.9 million for our probable reserves.

In relation to our hedging  programs,  we could have  significant  cash  payments  related to current  derivative  positions.  Based on
current  pricing,  we will make  payments of $21.9  million  during 2004 and $1.2 million  during 2005 related to our hedging  program.
These payment  estimates are based on December 31, 2003 commodity prices,  and will vary in the future.  Please see Item 7A and Note 12
to the Consolidated Financial Statements for additional information related to our derivatives and market risk.

We make significant  interest  payments each year on our debt.  During 2003, we paid $55.2 million in interest and recorded a liability
for $8.9 million for 2003  interest  which would be paid during 2004.  At December  31, 2003,  we had $300 million  fixed rate debt and
$297.5 million in variable rate debt;  interest payments are made at least  semi-annually  under all of our debt agreements.  We expect
debt levels in the future to decrease  over time,  unless we complete a  significant  acquisition.  With respect to the  variable  rate
debt, we are exposed to interest rate risk.  Please see Item 7A and Note 5 to our  Consolidated  Financial  Statements  for  additional
information about our debt.

We currently have $106 million in federal and state income tax net operating loss  carryforwards,  which, for the most part, prevent us
from paying  income  taxes.  These losses will expire,  if unused,  in years 2009 through  2022.  Approximately  $51.4 million of these
losses are limited to $7.8  million per year.  We expect we will be able to continue to offset any current  period taxes due with these
losses for the foreseeable future.

In relation to our oil and gas properties,  we have substantial  retirement  obligations.  We estimate that we will have obligations of
$32.5 million in plugging and abandonment  costs related to our current  properties.  While we do not anticipate  material  payments in
relation to our plugging  obligations  until 2017 and beyond,  the timing of these costs is not subject to our  control.  Please see Note 3 to the
Consolidated Financial Statements for additional information on our asset retirement obligations.

Critical Accounting Policies and Other

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

The accompanying  consolidated  financial statements include the accounts of Magnum Hunter and our existing wholly-owned  subsidiaries.
We also  consolidate  on a pro rata basis our  approximately  29%  ownership,  as of December 31, 2003, of TEL Offshore  Trust,  our 1%
ownership of Mallard  Hunter,  LP and our 5% ownership of Teal Hunter,  LP. Prior to December  2003, we accounted  for our  approximate
32% interest in Metrix under the equity method.  In December,  we acquired an 80%  controlling  interest in that company;  thus, we now
consolidate  Metrix with a minority  interest for the outside  owners' 20%. We accounted  for our  investment  in NGTS under the equity
method prior to its sale during  September  2003.  All  significant  intercompany  transactions  and balances  have been  eliminated in
consolidation.  Certain items in prior periods have been reclassified to conform with the current presentation.

Magnum Hunter is a holding  company with no  significant  assets or operations  other than our  investments  in our  subsidiaries.  Our
wholly-owned  subsidiaries,  except for  Canvasback  Energy,  Inc.,  Redhead  Energy,  Inc.  and  Metrix,  collectively  referred to as
("Canvasback"),  are direct guarantors of our Facility, 9.6% Senior Notes and our Convertible 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 Canvasback),  and we have presented separate  condensed  consolidating  financial  statements and other disclosures
concerning  each  guarantor and  Canvasback  (See Note 16 to the  Consolidated  Financial  Statements).  There is no restriction on the
ability of consolidated or unconsolidated  subsidiaries,  except for Canvasback, to transfer funds to Magnum Hunter in the form of cash
dividends and loans or advances.

40

Oil and Gas Properties

We use the full cost method of accounting  for our  investment  in oil and gas  properties.  Under the full cost method of  accounting,
all costs of acquisition,  exploration and  development of oil and gas proved  reserves are  capitalized  into a "full-cost  pool" on a
country-by-country  basis as incurred,  and properties in the pool, less their associated  salvage values,  are depleted and charged to
operations  using the  unit-of-production  method based on the ratio of current  production  to total proved oil and gas  reserves,  as
determined by independent petroleum engineers.  To the extent that such capitalized costs (net of accumulated  depreciation,  depletion
and  amortization)  less deferred taxes exceed the PV-10 of estimated future net cash flow from proved reserves of oil and gas, and the
lower of  unamortized  cost or fair  value of  unproved  properties  after  income  tax  effects,  such  excess  costs are  charged  to
operations.  Once  incurred,  a  write-down  of oil and gas  properties  is not  reversible  at a later  date even if oil or gas prices
subsequently  increase.  Our  capitalized  costs did not exceed the PV-10  limitation  using  prices in effect at  December  31,  2003.
Significant  downward  revisions of quantity  estimates,  declines in oil and gas prices,  higher operating costs or additional capital
costs which are not offset by incremental  increases in oil and gas reserves or other factors could  possibly  result in write-down for
impairment of oil and gas properties in the future.

In accordance with SFAS 143, "Accounting for Asset Retirement  Obligations",  we carry a liability for any legal retirement obligations
on our oil and gas  properties.  The associated  asset  retirement  costs are capitalized as part of the full-cost pool and depleted on
the unit of production basis.

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

Revenue Recognition

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

Inflation and Changes in Prices

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

We market oil and gas for our own  account,  which  exposes us to the  attendant  commodities  risk. A  significant  portion of our gas
production is currently sold to end-users either (i) on the spot market on a month-to-month basis at prevailing
spot  market  prices  or (ii)  under  long-term  contracts  based on  current  spot  market  prices.  We  normally  sell our oil  under
month-to-month contracts to a variety of purchasers.

Derivative Instruments

Our product price and interest hedging activities are described in Note 12 to the consolidated  financial  statements.  Periodically we
enter into  derivative  instruments  such as futures,  swaps and options  contracts to reduce the adverse  effects of  fluctuations  in
natural gas and crude oil prices.  Under our risk  management  policy,  at inception,  commodity  hedge positions may not exceed 75% of
natural  gas and 90% of crude oil current  forecasted  (18 months)  commodity  production.  For  non-current  (greater  than 18 months)
commodity  production,  at  inception,  commodity  hedge  positions  for  natural  gas and crude oil may not exceed  75% of  forecasted
production for each product. We also utilize,  from time to time,  financial  derivative  instruments to hedge the risk associated with
interest on our outstanding debt.  Generally, the cash  settlement of all  derivative  instruments  is recognized as income or expense in the period in which the hedged  transaction  is
recognized.

41

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

Goodwill

As a result of our merger with Prize,  we currently have $56.5 million of goodwill  recorded on our books.  Under SFAS No. 142, we will
not amortize any of the goodwill  acquired in the merger.  All goodwill has been allocated to the Exploration and Production  reporting
unit. We test our goodwill for  impairment  on an annual basis or whenever  indicators  of  impairment  exist.  We performed our annual
impairment  test at December 31, 2003, and determined that no impairment  existed.  The annual  impairment test requires  management to
make  significant  estimates  and  judgments.  If  impairment  is  determined  to exist,  we will  measure  our  impairment  based on a
comparison  of the  carrying  value of goodwill  to the  implied  fair value of that  goodwill.  The implied  fair value of goodwill is
determined by allocating the fair value of the Exploration  and Production  reporting unit to all of the assets and liabilities of that
unit.  The excess of the fair value of the reporting unit over the amounts  assigned to its assets and  liabilities is the implied fair
value of goodwill.  If the carrying amount of goodwill exceeds the implied fair value of that goodwill, impairment will be recognized in the
income statement.

Stock Compensation

At  December  31,  2003,  we had four  stock-based  employee  compensation  plans,  which are  described  more  fully in Note 13 of the
Consolidated  Financial  Statements.  We account for these  plans  under SFAS No.  148,  "Accounting  for  Stock-Based  Compensation  -
Transition and  Disclosure,  an Amendment to FASB Statement No. 123," in December 2002.  SFAS No. 148 provides  alternative  methods of
transition  for a  voluntary  change to the fair value  method of  accounting  for  stock-based  employee  compensation  and amends the
disclosure  requirements  of SFAS No. 123. On June 1, 2003, and effective  January 1, 2003, we began expensing the fair market value of
stock options newly granted,  modified or settled pursuant to SFAS No. 123,  "Accounting for Stock-Based  Compensation," and as allowed
under the  prospective  method of SFAS No. 148. The fair value of each option  granted  after  December  31, 2002,  is estimated on the
grant date,  using the  Black-Scholes  option-pricing  model.  For the year ended  December 31, 2003,  we recorded  stock  compensation
expense of $3.0  million,  which is reflected  in our general and  administrative  expenses.  For options  granted  prior to January 1,
2003,  we  continue  to use  the  intrinsic  method  under  APB  No.  25,  "Accounting  for  Stock  Issued  to  Employees  and  Related
Interpretations,"  whereby no  compensation  expense is recognized for stock options granted with an exercise price equal to the market
value of our stock on the grant date.

Asset Retirement Obligations

Statement of Financial  Accounting  Standards ("SFAS") No. 143 - SFAS No. 143,  "Accounting for Asset Retirement  Obligations,"  became
effective  beginning  January 1, 2003. SFAS No. 143 requires the  recognition of a fair value  liability for any retirement  obligation
associated  with  long-lived  assets in the period in which it is incurred  if a  reasonable  estimate  of fair value can be made.  The
associated  asset  retirement  costs are  capitalized as part of the carrying amount of the long-lived  asset and depreciated  over the
asset's  useful  life.  See Note 3 of the  Consolidated  Financial  Statements  for  additional  information  on our  asset  retirement
obligations.  Upon adoption of SFAS No. 143, we recorded an addition to oil and gas  properties of $25.4 million,  an asset  retirement
obligation  of $30.4  million,  a reduction  of  accumulated  depletion  of $5.6  million,  and a pre-tax  gain of $643  thousand.  The
retirement  obligation  requires  management to make  significant  estimates and judgments  regarding our expected  plugging  costs and
retirement dates.

42

Recently Issued Statements

SFAS No. 145 - SFAS No. 145  "Recission  of FASB  Statements  No. 4, 44, and 64,  Amendment  of FASB  Statement  No. 13, and  Technical
Corrections,"  became effective beginning January 1, 2003. The Statement rescinds,  updates,  clarifies and simplifies various existing
accounting  pronouncements.  SFAS No.  145  rescinds  SFAS No. 4,  "Reporting  Gains and Losses  from  Extinguishment  of Debt,"  which
required all gains and losses from  extinguishment of debt to be aggregated and, if material,  classified as an extraordinary item, net
of related income tax effect. As a result,  SFAS No. 145 requires us to reclassify as additional  expense any  extraordinary  items for
debt  extinguishment  costs which did not meet the criteria as described in APB Opinion No. 30,  "Reporting the Results of Operations -
Reporting the Effects of Disposal of a Business,  and  Extraordinary,  Unusual and Infrequently  Occurring Events and Transactions," as
additional  expense.  As a result,  for the years ended  December 31, 2002 and 2001,  we  reclassified  our  previously  reported  $621
thousand and $304 thousand  extraordinary  losses as costs  associated  with early  retirement of debt of $1 million and $490 thousand,
and decreased our deferred income tax expense by $379 thousand and $186 thousand, respectively.

SFAS No. 146 - In July 2002, the Financial Accounting  Standards Board,  ("FASB") issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal  Activities."  SFAS No. 146 requires  companies to recognize costs  associated  with exit or disposal  activities
when they are incurred  rather than at the date of a commitment to an exit or disposal  plan.  SFAS No. 146  supercedes  EITF Issue No.
94-3,  "Liability  Recognition for Certain Employee  Termination  Benefits and Other Costs to Exit an Activity (including Certain Costs
Incurred in a Restructuring)."  Statement 146 is to be applied  prospectively to exit or disposal  activities  initiated after December
31, 2002, and there was no effect on our financial statements under this statement.

SFAS No. 148 - The FASB issued SFAS No. 148,  "Accounting  for Stock-Based  Compensation - Transition and  Disclosure,  an Amendment to
FASB  Statement No. 123," in December  2002.  SFAS No. 148 provides  alternative  methods of transition  for a voluntary  change to the
fair value method of accounting  for  stock-based  employee  compensation  and amends the disclosure  requirements  of SFAS No. 123. On
June 1, 2003,  and effective  January 1, 2003, we began  expensing  the fair market value of stock options newly  granted,  modified or
settled pursuant to SFAS No. 123,  "Accounting for Stock-Based  Compensation,"  and as allowed under the prospective method of SFAS No.
148,  "Accounting  for  Stock-Based  Compensation  - Transition and  Disclosure,  an amendment to SFAS No. 123." The fair value of each
option granted after December 31, 2002, is estimated on the grant date,  using the  Black-Scholes  option-pricing  model.  For the year
ended December 31, 2003, we recorded stock compensation  expense of $3.0 million,  which is reflected in our general and administrative
expenses.  For options  granted  prior to January 1, 2003, we continue to use the intrinsic  method under APB No. 25,  "Accounting  for
Stock Issued to Employees and Related  Interpretations,"  whereby no compensation  expense is recognized for stock options granted with
an exercise price equal to the market value of our stock on the grant date.

43

If we had recorded  stock option  expense  under the fair value  provisions of SFAS No. 123 for all prior and current  grants,  our net
income and EPS would have been as shown in the below pro forma tables (in thousands, except per share data):

|                                                    | Year Ended December 31,
|--------------------------------------------------- | -----------------------
|
|Net income, as reported                             |                        
|                                                    |                        
|Total  Stock-based  employee  compensation  expense |                        
|included  in  reported  net  income,  net of income |                        
|taxes of $1,144                                     |                        
|                                                    |                        
|Deduct:  Total  stock-based  employee  compensation |                        
|determined  under fair  value-based  method for all |                        
|awards,  net of income taxes of $2,896,  $1,962 and |                        
|$1,563, respectively                                |                        
|                                                    |                        
|                                                    |                        
|Pro forma net income                                |                        
|                                                    |                        
|                                                    |                        
|Earnings per share:                                 |                        
|Basic - as reported                                 |                        
|                                                    |                        
|Basic - pro forma                                   |                        
|                                                    |                        
|Diluted - as reported                               |                        
|                                                    |                        
|Diluted - pro forma                                 |                        
|                                                    |                        
|                                                    |                        

FIN No. 45 - FIN No. 45,  "Guarantor's  Accounting and  Disclosure  Requirements  for  Guarantees,"  was issued in November 2002.  This
interpretation  addresses  the  disclosures  to be made by a  guarantor  in its  interim  and  annual  financial  statements  about its
obligations  under  guarantees.  It also  clarifies the  requirements  related to the  recognition of a liability by a guarantor at the
inception of a guarantee for the  obligations the guarantor has undertaken in issuing that  guarantee.  We adopted this  interpretation
in January 2003.

In the past, we have provided  trade  guarantees on behalf of NGTS.  The last of these  guarantees  expired in July 2003.  Further,  we
have sold our 30% ownership interest in NGTS, and, therefore, no longer maintain any equity interest in this
former  affiliate  (see Note 2 to our  Consolidated  Financial  Statements).  We have  provided  no other  guarantees  on behalf of any
unconsolidated entities and do not intend to issue any at this time.

FIN No. 46 - FIN No. 46,  "Consolidation of Variable Interest Entities,"  addresses  consolidation by business  enterprises of variable
interest  entities  with certain  defined  characteristics.  This  interpretation  applies to the first  fiscal year or interim  period
ending after December 15, 2003, to variable  interest  entities  created or obtained  before  February 1, 2003.  For variable  interest
entities  created  after  January 31, 2003,  the  consolidated  provisions  apply  immediately.  We do not have any  variable  interest
entities that would be subject to these provisions and, accordingly, FIN 46 will not have an impact on our financial statements.

FIN No. 46R - In January  2003,  the FASB issued FIN 46. In December  2003,  FASB revised FIN 46, which  clarifies the  application  of
Accounting  Research  Bulletin No. 5l,  "Consolidated  Financial  Statements" ("ARB 51"). As per ARB 51, a general rule for preparation
of  consolidated  financial  statements of a parent and its subsidiary is ownership by the parent,  either  directly or indirectly,  of
over  fifty  percent  of the  outstanding  voting  shares of a  subsidiary.  However,  application  of the  majority  voting  interest
requirement  of ARB 51 to certain  types of entities may not  identify  the party with a  controlling  financial  interest  because the
controlling  financial  interest  may be  achieved  through  arrangements  that  do  not  involve  voting  interest.  FIN 46  clarifies
applicability of ARB 51 to entities in which the equity investors do not have the  characteristics of a controlling  financial interest
or do not have sufficient equity at risk for the entity to finance its activities  without additional  subordinated  financial support.
FIN 46 requires an entity to consolidate a variable  interest  entity even though the entity does not,  either  directly or indirectly,
own over fifty  percent of the  outstanding  voting  shares.  We do not have any variable  interest  entities  that would be subject to
these provisions, and, accordingly, FIN 46R also will not have an impact on our financial statements.

SFAS 150 - In May 2003, the FASB issued SFAS No. 150,  "Accounting  for Certain  Financial  Instruments  with  Characteristics  of both
Liabilities  and  Equity"  (SFAS 150).  SFAS 150  establishes  standards  for how an issuer of  financial  instruments  classifies  and
measures in its statement of financial  position certain  instruments  with  characteristics  of both liabilities and equity.  SFAS 150
modifies the accounting and financial  statement  disclosures of certain financial  instruments that, under previous guidance,  issuers
could account for as equity.  SFAS 150 affects the issuer's  accounting for three types of financial  instruments  that are required to
be accounted for as  liabilities.  We did not have any financial  instruments  outstanding  to which the  provisions of SFAS 150 apply;
therefore, the initial adoption of SFAS 150 did not have any impact on the results of operations or equity of the company.

44

In June 2001,  FASB issued SFAS No. 141,  "Business  Combinations,"  which  requires the  purchase  method of  accounting  for business
combinations  initiated  after June 30, 2001 and eliminates the pooling-of  interests  method.  In July 2001, the FASB also issued SFAS
No. 142,  "Goodwill  and Other  Intangible  Assets,"  which  discontinues  the practice of  amortizing  goodwill and  indefinite  lived
intangible  assets and initiates an annual review of impairment.  Intangible  assets with a  determinable  useful life will continue to
be amortized  over that period.  The  amortization  provisions  apply to goodwill and intangible  assets  acquired after June 30, 2001.
SFAS No. 141 and 142 clarify that more assets should be  distinguished  and  classified  between  tangible and  intangible.  We did not
change or  reclassify  contractual  mineral  rights  included in proved and unproved oil and gas  properties  on our balance sheet upon
adoption  of SFAS No.  142.  We  believe  the  treatment  of such  mineral  rights as  tangible  assets  under the full cost  method of
accounting  for oil and gas  properties is  appropriate.  An issue has been raised  regarding  whether  these mineral  rights should be
classified as tangible or  intangible  assets.  If it is  determined  that  reclassification  is  necessary,  we will reduce our proven
properties by $352.7 million,  decrease unproved  properties by $154.5 million and report  intangible  mineral rights related to proved
properties of $352.7  million and intangible  mineral rights related to unproved  properties of $154.5 million at December 31, 2002. At
December 31, 2003, we will reduce our proven  properties  by $408.1  million,  reduce our unproved  properties  by $94.4  million,  and
report  intangible  mineral  rights related to proved  properties of $408.1  million and intangible  mineral rights related to unproved
properties of $94.4 million.  These  reclassifications  represent the cost of acquiring proved and unproved mineral use rights from the
effective  date of June 30, 2001.  The  provisions  of SFAS No. 141 and SFAS No. 142 impact only the balance  sheet and any  associated
footnote disclosures.  Any reclassifications potentially required would not impact our cash flows or statements of income.

Off Balance Sheet Arrangements

We have provided  trade  guarantees  on behalf of NGTS in the past.  The last of these  guarantees  expired in July 2003.  Further,  we
sold our 30% ownership  interest in NGTS and,  therefore,  no longer maintain any equity interest in this former affiliate.  We have no
other guarantees on behalf of any entities and do not intend to issue any in the future at this time.

We had equity and debt  investments in a privately  held entity which  declared  bankruptcy on March 4, 2002, and for which we recorded
an impairment  charge against  earnings of $5.0 million at December 31, 2001. We are not responsible  for any debts of this entity.  We
had an  investment  in  available-for-sale  securities  of  another  entity of $2.8  million  at  December  31,  2001.  Because  of the
deteriorating  financial  condition of this entity, we recorded an other than temporary  impairment of $2.1 million as a charge against
earnings at December 31, 2001,  and we recorded an additional  impairment  for the remaining  carrying  value of this asset at June 30,
2002.  We are not responsible for any debts of this entity.

Other

At February  16, 2004,  Magnum  Hunter had  approximately  50% of its natural gas  production  and  approximately  60% of its crude oil
production  hedged through December 31, 2004. In addition,  Magnum Hunter had  approximately 25% of its natural gas production and none
of its crude oil production  hedged for the calendar year 2005.  Unless we enter into additional  hedging  transactions,  the remainder
of our hydrocarbon  volumes will be sold at market prices.  Future  commodity  price declines will negatively  impact future income and
cash flow to the extent of any production  sold at market prices.  These  declines could  ultimately  affect the quantity of proved oil
and gas reserves and cost center  ceiling  values.  These  results,  individually  or  collectively,  could result in bank debt default
and/or debt  acceleration,  restrict our ability to attract qualified  personnel or cause further industry  consolidation.  There is no
requirement from any of our lenders to hedge our products.

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

45

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

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

46

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

Our  operations  are exposed to market risks  primarily as a result of changes in commodity  prices and interest  rates.  We do not use
derivative financial instruments for speculative or trading purposes.

Energy swap agreements.  We produce,  purchase,  and sell crude oil,  natural gas,  condensate,  and natural gas liquids.  As a result,
our financial  results can be significantly  impacted as these commodity prices fluctuate widely in response to changing market forces.
We have  previously  engaged in oil and gas hedging  activities  and intend to continue to consider  various  hedging  arrangements  to
realize  commodity  prices which we consider  favorable and to reduce  volatility.  We engage in futures  contracts with certain of our
oil and gas  production  through  various  contracts  ("Swap  Agreements").  The primary  objective of these  activities  is to protect
against significant decreases in price during the term of the hedge.

The Swap Agreements  provide for separate  contracts tied to the New York Mercantile  Exchange  ("NYMEX") light sweet crude oil futures
and Henry Hub natural gas futures,  and to the Inside FERC  natural gas index price  postings  ("Index").  We have  combined  contracts
which have agreed upon price floors and ceilings  ("Costless  Collars").  When the Index price exceeds the contract ceiling, we pay the
spread  between the ceiling and the Index price applied to the related  contract  volumes.  When the contract  floor exceeds the Index,
we  receive the spread between the contract floor and the Index price applied to the related contract volumes.

To the extent we receive the spread  between the contract  floor and the Index price  applied to related  contract  volumes,  we have a
credit risk in the event of  nonperformance  of the  counterparty  to the agreement.  We do not  anticipate any material  impact to our
results of operations as a result of nonperformance by these counterparties.

Due to hedge contracts  acquired in the Prize merger,  we were  contractually  obligated to a counter-party to provide a margin deposit
in the form of cash or bank letter of credit should the aggregate fair value of hedge  contracts held with the  counter-party  exceed a
predetermined  value.  Margins  posted at December 31, 2003 totaled $1.5 million.  Subsequent to December 31, 2003,  the only remaining
contract with this  counter-party  was novated to another  counter-party  that does not require margin  deposits to be maintained,  and
previously  posted  margins  were  recovered.  The  company has not and does not intend to enter into any new  hedging  contracts  with
institutions that require margin deposits.

At December 31, 2003, we had open contracts with the following terms:

|Commodity   | Type | Volume/Day | Duration | Wtd. Avg. Price
|----------- | ---- | ---------- | -------- | ---------------
|Natural Gas |      |            | Collar   |                
|Natural Gas |      |            | Collar   |                
|Crude Oil   |      |            | Collar   |                
|Crude Oil   |      |            | Collar   |                
|Crude Oil   |      |            | Collar   |                

Based on future  market  prices at December 31,  2003,  the fair value of open  contracts  to the company was a net  liability of $23.0
million.  If future  market  prices  were to  increase  10% from  those in effect at  December  31,  2003,  the fair  value of our open
contracts  would be a liability of $41.4  million.  If future  market  prices were to decline 10% from those at December 31, 2003,  the
fair value of our open contracts would be a liability of $6.5 million.

At  inception,  commodity  hedge  positions  may not exceed 75% of natural  gas and 90% of crude oil  forecasted  current  (18  months)
commodity  production.  For non-current  (greater than 18 months)  commodity  production,  at inception,  commodity hedge positions for
natural  gas and crude oil may not exceed 75% of  forecasted  production  for each  product.  Unhedged  portions of our natural gas and
crude oil production will be subject to market price fluctuations.

Fixed and Variable Debt.

We use fixed and  variable  debt to partially  finance  budgeted  expenditures.  These  agreements  expose us to market risk related to
changes in interest rates.

The following  table  presents the carrying and fair value of our debt along with average  interest  rates.  Fair values are calculated
as the net  present  value  of the  expected  cash  flows of the  financial  instruments,  except  for the 9.6%  Senior  Notes  and the
Convertible Notes, which are valued at their last traded value before December 31, 2003.

47

|Expected Maturity Dates       | 2004 | 2005-2007 | 2012 | 2023  | Total | Fair Value
|----------------------------- | ---- | --------- | ---- | ----- | ----- | ----------
|
|Variable Rate Debt:           |      |           |      |       |       |           
|Bank Debt with Recourse (a)   |      |           | $    | --    |       | $         
|Convertible Notes (b)         |      |           | $    | --    |       | $         
|Capital Lease Obligations (c) |      |           | $    | 2,009 |       | $         
|Fixed Rate Debt:              |      |          
|9.6% Senior Notes             |      |           | $    | --    |       | $         
|Other                         |      |           | $    | 12    |       | $         

---

| | (a) | The weighted average interest rate on the bank debt with recourse at December 31, 2003 is 3.1021%.
| | --- | --------------------------------------------------------------------------------------------------

| | (b) | The interest rate on the Convertible Notes at December 31, 2003 is 1.17%.  The rate on these Convertible   Notes is equal to
the three month LIBOR, adjusted quarterly.  A holder of these notes has the right to require us to repurchase all or a portion of the notes on December 15, 2008, 2013, and 2018.  The repurchase price will be
equal to the face value of the notes plus accrued and unpaid interest up to the date of repurchase.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (c) | The weighted average interest rate on capital lease obligations at December 31, 2003 is 4.1985%.
| | --- | ------------------------------------------------------------------------------------------------

48

Item 8.  Financial Statements and Unaudited Supplementary Data

Index to Consolidated Financial Statements

|                                                                                                                                            | Page
|------------------------------------------------------------------------------------------------------------------------------------------- | ----
|Independent Auditors' Report                                                                                                                | F- 1
|Financial Statements:                                                                                                                       |     
|Consolidated Balance Sheets at December 31, 2003 and 2002                                                                                   | F- 2
|Consolidated Statements of Operations     For the Years Ended December 31, 2003, 2002 and 2001                                              | F- 3
|Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss)      For the Periods Ended December 31, 2003, 2002 and 2001 | F- 4
|Consolidated Statements of Cash Flows     For the Years Ended December 31, 2003, 2002 and 2001                                              | F- 7
|Notes to Consolidated Financial Statements                                                                                                  | F- 8
|Supplemental Information on Oil and Gas Producing Properties (Unaudited)                                                                    | F-38

49

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 (the
Company), as of December 31, 2003 and 2002, and the related consolidated statements
of operations, stockholders equity and comprehensive income (loss) and cash flows
for each of the three years in the period ended December 31, 2003. Our audits also
included the financial statement schedule included in Item 15. These consolidated
financial statements and the financial statement schedule are the responsibility of the
companys management. Our responsibility is to express an opinion on these
consolidated financial statements and the financial statement schedule based on our
audits.

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

In our opinion, the consolidated
financial statements referred to above present fairly, in all material respects, the
financial position of Magnum Hunter Resources, Inc. and Subsidiaries as of December 31,
2003 and 2002, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2003, in conformity with accounting
principles generally accepted in the United States of America. Also, in our opinion, the
financial statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all material respects, the
information set forth therein.

As discussed in Note 1 to the
financial statements, the company changed its method of accounting for asset retirement
obligations in 2003 as required by Statement of Financial Accounting Standard No. 143,
Accounting for Asset Retirement Obligations, and changed its method of
accounting for employee stock-based option grants in 2003 by adopting the prospective
method specified by Statement of Financial Accounting Standards No. 148, Accounting
for Stock-Based Compensation  Transition and Disclosure, and Amendment to FASB
Statement No. 123.

Deloitte & Touche LLP

Dallas, Texas March 9, 2004

F-1

# MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
 CONSOLIDATED BALANCE SHEETS(in thousands of dollars)

|                                                                       | December 31,
2003 | December 31,
2002
|---------------------------------------------------------------------- | ----------------- | -----------------
|ASSETS                                                                 |                   |                  
|Current Assets                                                         |                   |                  
|Cash and cash equivalents                                              |                   |                  
|Restricted cash                                                        |                   |                  
|Accounts receivable                                                    |                   |                  
|Trade, net of allowance of $4,331 and $4,573, respectively             |                   |                  
|Notes receivable                                                       |                   |                  
|Notes receivable from affiliate                                        |                   |                  
|Income tax refund receivable                                           |                   |                  
|Derivative assets, current                                             |                   |                  
|Deferred income taxes, current                                         |                   |                  
|Deposits                                                               |                   |                  
|Land held for sale                                                     |                   |                  
|Prepaid drilling costs                                                 |                   |                  
|Other current assets                                                   |                   |                  
|                                                                       |                   |                  
|Total Current Assets                                                   |                   |                  
|Property, Plant and Equipment                                          |                   |                  
|Oil and gas properties, full-cost method                               |                   |                  
|Unproved                                                               |                   |                  
|Proved                                                                 |                   |                  
|Gas processing plants and pipelines                                    |                   |                  
|Other property                                                         |                   |                  
|                                                                       |                   |                  
|Total Property, Plant and Equipment                                    |                   |                  
|Accumulated depreciation, depletion, amortization and impairment .     |                   |                  
|                                                                       |                   |                  
|Net Property Plant and Equipment                                       |                   |                  
|Other assets                                                           |                   |                  
|Deferred financing costs and other                                     |                   |                  
|Investment in unconsolidated affiliates                                |                   |                  
|Goodwill                                                               |                   |                  
|                                                                       |                   |                  
|Total Assets                                                           |                   |                  
|                                                                       |                   |                  
|LIABILITIES AND STOCKHOLDERS' EQUITY                                   |                   |                  
|Current Liabilities                                                    |                   |                  
|Trade payables and accrued liabilities                                 |                   |                  
|Accrued interest                                                       |                   |                  
|Suspended revenue payable                                              |                   |                  
|Due to affiliates                                                      |                   |                  
|Taxes payable                                                          |                   |                  
|Derivative liabilities, current                                        |                   |                  
|Current maturities of long-term debt                                   |                   |                  
|                                                                       |                   |                  
|Total Current Liabilities                                              |                   |                  
|Long-Term Liabilities                                                  |                   |                  
|Long-term debt, less current maturities                                |                   |                  
|Asset retirement obligations                                           |                   |                  
|Derivative liabilities, noncurrent                                     |                   |                  
|Deferred income taxes payable                                          |                   |                  
|Other non-current liabilities                                          |                   |                  
|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                                                  |                   |                  
|Common Stock - $.002 par value; 100,000,000 shares authorized,         |                   |                  
|71,977,759 and 71,707,897 shares issued, respectively                  |                   |                  
|Additional paid-in capital                                             |                   |                  
|Accumulated other comprehensive loss                                   |                   |                  
|Retained earnings (accumulated deficit)                                |                   |                  
|Common stock in deferred compensation plan, at cost (34,416 shares)    |                   |                  
|Unearned common stock in KSOP, at cost (1,012,203 and 757,246 shares,  |                   |                  
|respectively)                                                          |                   |                  
|                                                                       |                   |                  
|                                                                       |                   |                  
|Treasury stock, at cost (3,942,294 and 3,168,013 shares, respectively) |                   |                  
|                                                                       |                   |                  
|Total Stockholders' Equity                                             |                   |                  
|                                                                       |                   |                  
|Total Liabilities and Stockholders' Equity                             |                   |                  
|                                                                       |                   |                  

The accompanying notes are an integral part of these consolidated financial statements.

F-2

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands of
dollars, except for share and per share amounts)

|                                                          | For the Years Ended December 31,
|--------------------------------------------------------- | --------------------------------
|
|Operating Revenues:                                       |                                 
|Oil and gas sales                                         |                                 
|Gas gathering, marketing and processing                   |                                 
|Oil field services                                        |                                 
|                                                          |                                 
|Total Operating Revenues                                  |                                 
|                                                          |                                 
|Operating Costs and Expenses:                             |                                 
|Oil and gas production lifting costs                      |                                 
|Production taxes and other costs                          |                                 
|Gas gathering, marketing and processing                   |                                 
|Oil field services                                        |                                 
|Depreciation, depletion, amortization and accretion       |                                 
|Gain on sale of assets                                    |                                 
|Loss on Enron related assets                              |                                 
|General and administrative                                |                                 
|                                                          |                                 
|Total Operating Costs and Expenses                        |                                 
|                                                          |                                 
|Operating Profit                                          |                                 
|Equity in (loss) earnings of affiliate                    |                                 
|Other income                                              |                                 
|Provision for impairment of investments                   |                                 
|Costs associated with early retirement of debt            |                                 
|Non-cash hedging adjustments                              |                                 
|Interest expense                                          |                                 
|                                                          |                                 
|Income Before Income Tax                                  |                                 
|Provision for income tax (expense) benefit                |                                 
|Current                                                   |                                 
|Deferred                                                  |                                 
|                                                          |                                 
|Total Provision for Income Tax (Expense) Benefit          |                                 
|                                                          |                                 
|Income Before Cumulative Effect of a Change in Accounting |                                 
|Principle                                                 |                                 
|Cumulative effect of a change in accounting principle,    |                                 
|net of income tax expense of $244                         |                                 
|                                                          |                                 
|Net Income                                                |                                 
|                                                          |                                 
|Income per Common Share - Basic                           |                                 
|Income before cumulative effect of a change in            |                                 
|accounting principle                                      |                                 
|                                                          |                                 
|Cumulative effect of a change in accounting principle     |                                 
|                                                          |                                 
|Income per Common Share - Basic                           |                                 
|                                                          |                                 
|Income per Common Share - Diluted                         |                                 
|Income before cumulative effect of a change in            |                                 
|accounting principle                                      |                                 
|Cumulative effect of a change in accounting principle     |                                 
|                                                          |                                 
|Income per Common Share - Diluted                         |                                 
|                                                          |                                 
|Common Shares Used in Per Share Calculation               |                                 
|Basic                                                     |                                 
|                                                          |                                 
|Diluted                                                   |                                 
|                                                          |                                 

The accompanying notes are an integral part of these consolidated financial statements.

F-3

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS) FOR THE PERIODS ENDED DECEMBER 31, 2001 (thousands)

|                                         | Preferred
Stock | Common
Stock | Treasury
Stock | Additional
Paid in
Capital | Accumulated
Deficit
|---------------------------------------- | --------------- | ------------ | -------------- | -------------------------- | -------------------
|Balance at January 1, 2001               |                 |              | $              | 1                          |                    
|                                         |                 |              |                |                            |                    
|Conversion of 25 shares of Series A 8%   |                 |             
|convertible preferred stock into 4,762   |                 |             
|shares  of common stock                  |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Issuance of 1,068 shares of common       |                 |             
|stock and 56 shares of treasury stock    |                 |             
|pursuant to employee stock option plan   |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Deferred tax benefit on exercise of      |                 |             
|employee stock options                   |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Contribution of 52 shares to 401(K) plan |                 |             
|and other                                |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Issuance of 73 shares of treasury stock  |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Purchase of 116 shares of treasury stock |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Employee salary deferrals to ESOP        |                 |             
|representing 317 shares                  |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Loan of 105 shares to ESOP               |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Net income, net of income tax expense of |                 |             
|$8,422                                   |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Cumulative effect on prior years of a    |                 |             
|change in accounting principle, net of   |                 |             
|deferred income tax benefits of $1,071   |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Gain on hedges, net of deferred income   |                 |             
|tax expense of $2,156                    |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Unrealized gain on investments, net of   |                 |             
|deferred income tax expense of $284      |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Reclassification adjustment related to   |                 |             
|derivative assets, net of deferred       |                 |             
|income tax benefit of $90                |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    
|Balance at December 31, 2001             |                 |              | $              | 1                          |                    
|                                         |                 |              |                |                            |                    
|                                         |                 |              |                |                            |                    

|                                         | Receivable
from
Stockholder | Unearned
Shares
in
KSOP | Accumulated
Other
Comprehensive
Income (Loss) | Total
Stockholders'
Equity | Total
Comprehensive
Income
(Loss)
|---------------------------------------- | --------------------------- | ----------------------- | --------------------------------------------- | -------------------------- | ---------------------------------
|Balance at January 1, 2001               |                             |                         | $                                             | (442                       | )                                
|                                         |                             |                         |                                               |                            |                                  
|Conversion of 25 shares of Series A 8%   |                             |                        
|convertible preferred stock into 4,762   |                             |                        
|shares  of common stock                  |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Issuance of 1,068 shares of common       |                             |                        
|stock and 56 shares of treasury stock    |                             |                        
|pursuant to employee stock option plan   |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Deferred tax benefit on exercise of      |                             |                        
|employee stock options                   |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Contribution of 52 shares to 401(K) plan |                             |                        
|and other                                |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Issuance of 73 shares of treasury stock  |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Purchase of 116 shares of treasury stock |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Employee salary deferrals to ESOP        |                             |                        
|representing 317 shares                  |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Loan of 105 shares to ESOP               |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Net income, net of income tax expense of |                             |                        
|$8,422                                   |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Cumulative effect on prior years of a    |                             |                        
|change in accounting principle, net of   |                             |                        
|deferred income tax benefits of $1,071   |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Gain on hedges, net of deferred income   |                             |                        
|tax expense of $2,156                    |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Unrealized gain on investments, net of   |                             |                        
|deferred income tax expense of $284      |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Reclassification adjustment related to   |                             |                        
|derivative assets, net of deferred       |                             |                        
|income tax benefit of $90                |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  
|Balance at December 31, 2001             |                             |                         | $                                             | (442                       | )                                
|                                         |                             |                         |                                               |                            |                                  
|                                         |                             |                         |                                               |                            |                                  

The accompanying notes are an integral part of these consolidated financial statements.

F-4

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS) FOR THE PERIODS ENDED DECEMBER 31, 2002 (thousands)

|                                        | Preferred
Stock | Common
Stock | Treasury
Stock | Additional
Paid in
Capital | Accumulated
Deficit | Receivable
from
Stockholder | Unearned
Shares
in
KSOP | Accumulated
Other
Comprehensive
Income (Loss) | Total
Stockholders'
Equity | Total
Comprehensive
Income
(Loss)
|--------------------------------------- | --------------- | ------------ | -------------- | -------------------------- | ------------------- | --------------------------- | ----------------------- | --------------------------------------------- | -------------------------- | ---------------------------------
|Balance at January 1, 2002              |                 |              | $              | 1                          |                     | $                           | 73                      |                                               | $                          | (1,914                           
|Issuance of 34,063 shares of common     |                 |             
|stock and warrants pursuant to Prize    |                 |             
|Energy Corp. merger, less fees          |                 |              |                |                            |                     |                             | 68                      |                                               |                            |                                  
|Issuance of 985 shares of common stock  |                 |             
|pursuant to employee stock option plan  |                 |              |                |                            |                     |                             | 2                       |                                               |                            |                                  
|Deferred tax benefit on exercise of     |                 |             
|employee stock options                  |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Employer contribution of 158 shares to  |                 |             
|KSOP                                    |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Exercise of warrants                    |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Purchase of warrants                    |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Repayment of shareholder loan           |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Issuance of 72 shares to KSOP for 2001  |                 |             
|employer contribution                   |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Purchase of 2,726 shares of treasury    |                 |             
|stock                                   |                 |              |                |                            |                     |                             | (18,494                 | )                                             |                            |                                  
|Employee salary deferrals to KSOP       |                 |             
|representing 86 shares                  |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Loan of 532 shares to KSOP              |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Net income, net of income tax benefit   |                 |             
|of $1,591                               |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Reclassification adjustment related to  |                 |             
|derivative contracts, net of deferred   |                 |             
|income tax expense of $1,684            |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Change in fair value of outstanding     |                 |             
|hedge positions, net of deferred income |                 |             
|tax benefits of $19,871                 |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Purchased hedge positions, net of       |                 |             
|deferred income tax benefit of $1,508   |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Amortization of purchased hedge         |                 |             
|positions, net of deferred income tax   |                 |             
|expense of $2,299                       |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Unrealized loss on investments, net of  |                 |             
|deferred income tax benefit of $197     |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Reclassification adjustment for loss on |                 |             
|investments, net of deferred income tax |                 |             
|expense of  $197                        |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|                                        |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  
|Balance at December 31, 2002            |                 |              | $              | 1                          |                     | $                           | 143                     |                                               | $                          | (20,408                          
|                                        |                 |              |                |                            |                     |                             |                         |                                               |                            |                                  

The accompanying notes are an integral part of these consolidated financial statements.

F-5

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS) FOR THE PERIODS ENDED DECEMBER 31, 2003 (thousands)

|                                        | Preferred
Stock | Common
Stock | Treasury
Stock | Additional
Paid in
Capital | Retained
Earnings
(Accumulated
Deficit) | Deferred
Compensation | Unearned
Shares
in
KSOP | Accumulated
Other
Comprehensive
Income (Loss) | Total
Stockholders'
Equity | Total
Comprehensive
Income
(Loss)
|--------------------------------------- | --------------- | ------------ | -------------- | -------------------------- | --------------------------------------- | --------------------- | ----------------------- | --------------------------------------------- | -------------------------- | ---------------------------------
|Balance at January 1, 2003              |                 |              | $              | 1                          |                                         | $                     | 143                     |                                               | $                          | (20,408                          
|Issuance of 270 shares of common stock  |                 |             
|pursuant to employee stock option plan  |                 |              |                |                            |                                         |                       | 1                       |                                               |                            |                                  
|Issuance of 548 treasury shares upon    |                 |             
|exercise of warrants                    |                 |              |                |                            |                                         |                       |                         |                                               |                            | 2,728                            
|Deferred tax benefit on exercise of     |                 |             
|employee stock options                  |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Purchase of 1,340 shares of treasury    |                 |             
|stock                                   |                 |              |                |                            |                                         |                       |                         |                                               |                            | (7,413                           
|Loan to KSOP to purchase 486 shares     |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Employee deferrals to KSOP to purchase  |                 |             
|59 shares                               |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Purchase 53 shares for deferred         |                 |             
|compensation plan                       |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Employer contribution of 172 shares to  |                 |             
|KSOP                                    |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Stock compensation                      |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Purchase of 18 treasury shares by       |                 |             
|deferred                                |                 |             
|compensation plan                       |                 |              |                |                            |                                         |                       |                         |                                               |                            | 53                               
|Release of 36 shares from deferred      |                 |             
|compensation plan                       |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Net Income, net of income tax expense   |                 |             
|of $15,916                              |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Reclassification adjustments related to |                 |             
|derivative contracts, net of deferred   |                 |             
|income tax expense of $28,330           |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Change in fair value of outstanding     |                 |             
|hedge positions, net of deferred income |                 |             
|tax benefit of $19,715                  |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Amortization of purchased hedge         |                 |             
|positions, net of deferred income tax   |                 |             
|benefit of $491                         |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|                                        |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|Balance at December 31, 2003            |                 |              | $              | 1                          |                                         | $                     | 144                     |                                               | $                          | (25,040                          
|                                        |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  

The accompanying notes are an integral part of these consolidated financial statements.

F-6

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands of
dollars)

|                                                                                | For the Years Ended December 31,
|------------------------------------------------------------------------------- | --------------------------------
|
|CASH FLOW FROM OPERATING ACTIVITIES:                                            |                                 
|Net Income                                                                      |                                 
|Adjustments to reconcile net income to cash provided by operating  activities:  |                                 
|Cumulative effect of a change in accounting principle                           |                                 
|Depreciation, depletion, amortization and accretion                             |                                 
|Impairment of investments                                                       |                                 
|Amortization of financing fees                                                  |                                 
|Imputed interest on debt due to merger                                          |                                 
|Increase in allowance for doubtful accounts                                     |                                 
|Deferred income taxes (benefits)                                                |                                 
|Equity in (income) loss of unconsolidated affiliate                             |                                 
|Costs associated with early extinguishment of debt                              |                                 
|Cost of shares released from KSOP suspense                                      |                                 
|Minority interest in consolidated subsidiary                                    |                                 
|Stock compensation                                                              |                                 
|Excess of fair value over cost of shares released from KSOP suspense            |                                 
|Gain on sale of assets                                                          |                                 
|Other non-cash hedging adjustments                                              |                                 
|Changes in certain assets and liabilities, net of the effect of  acquisitions   |                                 
|Accounts and notes receivable                                                   |                                 
|Derivative assets                                                               |                                 
|Deposits and other current assets                                               |                                 
|Accounts payable and accrued liabilities                                        |                                 
|Refund (payment) of income taxes                                                |                                 
|                                                                                |                                 
|Net Cash Provided by Operating Activities                                       |                                 
|                                                                                |                                 
|CASH FLOWS FROM INVESTING ACTIVITIES:                                           |                                 
|Proceeds from sale of assets                                                    |                                 
|Proceeds from sale of unconsolidated affiliate                                  |                                 
|                                                                                |                                 
|Purchase of land to be held for sale                                            |                                 
|Purchase of controlling interest in Metrix Networks, Inc., net of cash acquired |                                 
|Additions to property and equipment                                             |                                 
|Cash paid in Prize merger net of cash acquired                                  |                                 
|Decrease in other assets                                                        |                                 
|Loan made for promissory note receivable                                        |                                 
|Payments received on promissory note receivable                                 |                                 
|Distribution from unconsolidated affiliate                                      |                                 
|Investment in unconsolidated affiliate                                          |                                 
|                                                                                |                                 
|Net Cash Used In Investing Activities                                           |                                 
|                                                                                |                                 
|CASH FLOWS FROM FINANCING ACTIVITIES:                                           |                                 
|Proceeds from issuance of debt                                                  |                                 
|Fees paid related to financing activities                                       |                                 
|Payments of principal on long-term debt and production payment                  |                                 
|Receipts from short-term notes receivable                                       |                                 
|Loan repaid by (made to) stockholder                                            |                                 
|Loan to KSOP                                                                    |                                 
|Loan repaid from KSOP                                                           |                                 
|Proceeds from issuance of common stock                                          |                                 
|Proceeds from issuance of treasury stock                                        |                                 
|Redemption of notes payable                                                     |                                 
|Proceeds from issuance of convertible notes                                     |                                 
|Purchase of warrants                                                            |                                 
|Purchase of treasury stock                                                      |                                 
|Decrease (increase) in restricted cash for payment of notes payable             |                                 
|Dividends paid                                                                  |                                 
|Net decrease in note receivable from affiliate                                  |                                 
|Purchase common stock for deferred compensation plan                            |                                 
|                                                                                |                                 
|Net Cash Provided by Financing Activities                                       |                                 
|                                                                                |                                 
|NET INCREASE IN CASH AND CASH EQUIVALENTS                                       |                                 
|CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR                                  |                                 
|                                                                                |                                 
|CASH AND CASH EQUIVALENTS AT END OF YEAR                                        |                                 
|                                                                                |                                 
|                                                                                |                                 

The accompanying notes are an integral part of these consolidated financial statements.

F-7

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.
(Magnum Hunter), is incorporated under the laws of the state of Nevada. The
company and our subsidiaries are engaged in the acquisition, operation and development of
oil and gas properties, the gathering, processing, transmission, and marketing of natural
gas and natural gas liquids and providing management and advisory consulting services on
oil and gas properties for third parties. In conjunction with the above activities, we own
and operate oil and gas properties in twelve states, predominantly in the Southwest region
of the United States. In addition, we own and operate three gathering systems located in
Texas and Oklahoma and own an interest in four natural gas processing plants located in
Texas, Oklahoma and Arkansas.

Consolidation

The accompanying consolidated
financial statements include the accounts of Magnum Hunter and our existing wholly-owned
subsidiaries, Gruy Petroleum Management Co., Magnum Hunter Production, Inc., ConMag Energy
Corporation, Trapmar Properties, Inc., Hunter Gas Gathering, Inc. (Hunter),
Canvasback Energy, Inc., Pintail Energy, Inc., Redhead Energy, Inc. (Redhead),
Prize Operating Co., PEC (Delaware), Inc., Oklahoma Gas Processing, Inc., and Prize Energy
Resources, LP. We consolidate on a pro rata basis our approximately 29% ownership of TEL
Offshore Trust, our 1% interest in Mallard Hunter, LP and our 5% interest in Teal Hunter,
LP. Prior to December 2003, we accounted for our approximately 32% interest in Metrix
Networks, Inc. (Metrix) under the equity method. We acquired an 80%
controlling interest in Metrix during December 2003, and thus fully consolidate them with
a minority interest for the outside owners 20%. Prior to its sale in September 2003,
we also accounted for our investment in NGTS, LLC (NGTS) 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 years to conform to the current presentation.

Bluebird Energy, Inc.
(Bluebird) was formed in December 1998. As part of the capitalization of
Bluebird, we contributed to Bluebird 1,840,271 units of TEL Offshore Trust. Bluebird was
an unrestricted subsidiary as defined under certain credit agreements, and was
neither a guarantor of our 10% Senior Notes due 2007, or our 9.6% Senior Notes due 2012,
nor was it included in determining compliance with certain financial covenants under our
credit agreements.

On March 1, 2002, we created two
unrestricted, wholly-owned subsidiaries, Canvasback Energy, Inc. and Redhead. During 2003,
Canvasback Energy, Inc. became the controlling shareholder of Metrix, resulting in their
full consolidation with a minority interest. These three subsidiaries are referred to as
Canvasback since Redhead is a wholly-owned subsidiary and Metrix is a majority-owned
subsidiary of Canvasback Energy, Inc. On March 15, 2002, Bluebird transferred all of its
assets to Canvasback, which effectively capitalized Canvasback. Upon completion of this
transfer, Bluebird was merged into Magnum Hunter Production, Inc. Canvasback is neither a
guarantor of our 9.6% Senior Notes due 2012, or our floating rate convertible senior notes
(Convertible Notes) due 2023; nor can it be included in determining compliance
with our debt covenants.

Magnum Hunter is a holding company
with no significant assets or operations other than our investments in our subsidiaries.
Our wholly-owned subsidiaries, except for Canvasback, are direct guarantors of our 9.6%
Senior Notes and our Convertible Notes, and have fully and unconditionally guaranteed
these notes on a joint and several basis. The guarantors comprise all of our direct and
indirect subsidiaries (other than Canvasback), and we have presented separate condensed
consolidating financial statements and other disclosures concerning each guarantor and
Canvasback (See Note 16). Except for Canvasback, there is no restriction on the ability of
consolidated or unconsolidated subsidiaries to transfer funds to Magnum Hunter in the form
of cash dividends, loans, or advances.

F-8

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

Cash and Cash Equivalents

We consider all highly liquid debt
instruments purchased with an original maturity of three months or less to be cash
equivalents. We have cash deposits in excess of federally insured limits.

Investments

We follow accounting procedures
according to Statement of Financial Accounting Standards (SFAS) No. 115,
Accounting for Certain Investments in Debt and Equity Securities. Under this
standard, all of our equity securities that have readily determinable fair values are
classified as current or non-current assets, available-for-sale and are measured at fair
value and are recognized as either current or non-current assets. Unrealized gains and
losses for these investments are reported as comprehensive income and accumulated as a
separate component of stockholders equity. Realized gains and losses are calculated
based on the specific identification method.

At December 31, 2001, our
available-for-sale securities were classified as non-current assets and included in
deposits and other assets. The securities had a cost basis of $2.7 million, gross and a
fair market value of $621 thousand, based on the quoted market price. During 2001, we
determined that the securities had suffered an other than temporary impairment as a result
of the deteriorating financial condition of the entity and a steadily declining market
value of the securities. As a result, at December 31, 2001, we also reported a provision
for impairment of investments of $2.1 million, as a charge against earnings and a
reclassification in accumulated other comprehensive income of $507 thousand ($466 thousand
net of income tax). Due to continued deterioration of the entitys financial
condition and market value of their stock, we recorded an impairment on this investment
for its full carrying value of $621 thousand during 2002. At December 31, 2002 and 2003,
we carried no value for our available-for-sale securities.

During 2000, we acquired a minority
ownership interest in a privately held entity that provides remote data collection and
web-based monitoring services for the company and other entities operating in the energy
industry. The total we invested in 2000 was $2.5 million, and the investment was carried
at cost on the balance sheet at December 31, 2000. During 2001, we made an additional
equity investment of $2 million as well as secured loans totaling $453 thousand, including
accrued interest. At December 31, 2001, our total equity investment of $4.5 million
represented less than 10% of the entitys common equity. As a result of the
entitys inability to obtain additional anticipated equity financing from third
parties at the end of 2001, the entity subsequently declared bankruptcy. We reported a
provision for impairment of investments of $5.0 million as a charge against earnings at
December 31, 2001.

KSOP

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

Suspended Revenues

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

Oil and Gas Properties

Magnum Hunter follows the full-cost
method of accounting for oil and gas properties. Accordingly, all costs associated with
acquisition, exploration and development of oil and gas reserves, including directly
related overhead costs, are capitalized. Internal costs that directly relate to
acquisition, exploration and development activities that were capitalized totaled $1.3
million for the year ended December 31, 2003 and $600 thousand for each of the years ended
December 31, 2002 and 2001. The balance of capitalized costs included in oil and gas
properties for the years ended December 31, 2003 and 2002 were $5.2 million and $3.9
million, respectively. Management believes that the basis we use to determine the amount
of internal costs capitalized is appropriate.

F-9

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

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

In accordance with SFAS 143,
Accounting for Asset Retirement Obligations, we carry a liability for any
legal retirement obligations on our oil and gas properties. The associated asset
retirement costs are capitalized as part of the full cost pool. We adopted SFAS 143 on
January 1, 2003 and recorded proved property additions of $30.4 million in relation to the
transition entry. See Note 3 for additional information on our asset retirement
obligations.

A summary of the unproved properties
excluded from proved oil and gas properties being amortized at December 31, 2003 and 2002,
respectively, and the year in which they were incurred follows:

|                           | December 31, 2003
(in thousands)
|-------------------------- | --------------------------------
|
|Property Acquisition Costs |                                 
|Exploration Costs          |                                 
|                           |                                 
|Total                      |                                 
|                           |                                 

|                           | December 31, 2002
(in thousands)
|-------------------------- | --------------------------------
|
|Property Acquisition Costs |                                 
|Exploration Costs          |                                 
|                           |                                 
|Total                      |                                 
|                           |                                 

Costs are transferred into the
amortization base on an ongoing basis as the projects are evaluated and proved reserves
are established or impairment determined. Pending determination of proved reserves
attributable to the above costs, we cannot assess the future impact on the amortization
rate. The Prize merger accounted for $140,312 thousand of the unproved property
acquisition costs in 2002. See Note 2 for additional information on the Prize merger.

The capitalized costs are subject to
a ceiling test, which generally limits such costs less accumulated
amortization and related deferred income taxes to the aggregate of the estimated present
value of future net revenues from proved reserves discounted at ten percent (PV-10) based
on current economic and operating conditions less income tax effects related to the
differences between the book and tax basis of the oil and gas properties. The ceiling test
is performed on a quarterly basis. At December 31, 2001, the capitalized costs of our oil
and gas properties exceeded the PV-10 limitation using prices in effect at December 31,
2001 by $75,984,000. However, no write-down for impairment of oil and gas properties was
required as a result of the increase in oil and gas prices subsequent to December 31,
2001. We experienced no impairment in 2003 or 2002.

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

Amortization expense per thousand
cubic feet equivalent was $1.28, $1.17 and $1.28 for the years ended December 31, 2003,
2002 and 2001, respectively.

F-10

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

Derivative Instruments

Our product price and interest
hedging activities are described in Note 12 to the consolidated financial statements.
Periodically we enter into derivative instruments such as futures, swaps and options
contracts to reduce the adverse effects of fluctuations in natural gas and crude oil
prices. Under our risk management policy, at inception, commodity hedge positions may not
exceed 75% of natural gas and 90% of crude oil current forecasted (18 months) commodity
production. For forecasted non-current (greater than 18 months) commodity production, at
inception, commodity hedge positions for both natural gas and crude oil may not exceed 75%
of forecasted production for each product. We also utilize financial derivative
instruments to hedge the risk associated with interest on our outstanding variable-rate
debt. Generally, the cash settlement of all derivative instruments is recognized as income
or expense in the period in which the hedged transaction affects earnings.

All freestanding financial derivative
instruments, including certain derivative instruments embedded in other contracts if
certain criteria are met, are recognized at estimated fair value on our balance sheet. We
determine our fair values based on market values obtained from our counterparties.
Derivative instruments that are not designated as hedges must be adjusted to fair value
through net income (loss). Changes in the fair value of derivative instruments that are
fair value hedges are offset against changes in the fair value of the hedged items, and
are recognized in net income (loss). Changes in the fair value of derivative instruments
that are cash-flow hedges are recognized in other comprehensive income (loss) until such
time as the hedged items are recognized in net income (loss). Ineffective portions of a
derivative instruments change in fair value are immediately recognized in net income
(loss).

Gas Processing Plants and
Pipelines

Gas processing plants and pipelines
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. We review the
carrying value of pipelines and processing plants and other long-lived assets (other than
oil and gas assets accounted for under the full-cost method) for impairment whenever
events and circumstances indicate that the carrying value of an asset may not be
recoverable from the estimated future cash flows expected to result from its use and
eventual disposition. In cases where the undiscounted expected future cash flows are less
than the carrying value, an impairment loss is recognized equal to an amount by which the
carrying value exceeds the fair value of assets. The fair value is determined using the
discounted cash flows method.

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 our operation of oil and gas properties for third
parties. Such fees are recognized in the month the service is provided.

Magnum Hunter does not recognize
income in connection with drilling, well service or other services provided in connection
with oil and gas properties in which we hold an ownership or other economic interest to
the extent of our interest. Any proceeds received for services performed that are not
recognized as income are credited to the full cost pool.

Stock Compensation

At December 31, 2003, we had four
stock-based employee compensation plans, which are described more fully in Note 13. We
account for these plans under SFAS No. 148, Accounting for Stock-Based Compensation
 Transition and Disclosure, an Amendment to FASB Statement No. 123, in
December 2002. SFAS No. 148 provides alternative methods of transition for a voluntary
change to the fair value method of accounting for stock-based employee compensation and
amends the disclosure requirements of SFAS No. 123. On June 1, 2003, and effective January
1, 2003, we began expensing the fair market value of stock options newly granted, modified
or settled pursuant to SFAS No. 123, Accounting for Stock-Based Compensation,
and as allowed under the prospective method of SFAS No. 148. The fair value of each option
granted after December 31, 2002, is estimated on the grant date, using the Black-Scholes
option-pricing model. For the year ended December 31, 2003, we recorded stock compensation
expense of $3.0 million, which is reflected in our general and administrative expenses.
For options granted prior to January 1, 2003, we continue to use the intrinsic method
under APB No. 25, Accounting for Stock Issued to Employees and Related
Interpretations, whereby no compensation expense is recognized for stock options
granted with an exercise price equal to the market value of our stock on the grant date.

F-11

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

If we had recorded stock option
expense under the fair value provisions of SFAS No. 123 for all prior and current grants,
our net income and EPS would have been as shown in the below pro forma tables (in
thousands):

|                                                    | Year Ended December 31,
|--------------------------------------------------- | -----------------------
|
|Net income, as reported                             |                        
|Total  Stock-based  employee  compensation  expense |                        
|included  in  reported  net  income,  net of income |                        
|taxes of $1,144                                     |                        
|Deduct:  Total  stock-based  employee  compensation |                        
|determined  under fair  value-based  method for all |                        
|awards,  net of income taxes of $2,896,  $1,962 and |                        
|$1,563, respectively                                |                        
|                                                    |                        
|Pro forma net income                                |                        
|                                                    |                        
|Earnings per share:                                 |                        
|Basic - as reported                                 |                        
|                                                    |                        
|Basic - pro forma                                   |                        
|                                                    |                        
|Diluted - as reported                               |                        
|                                                    |                        
|Diluted - pro forma                                 |                        
|                                                    |                        

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

|                                               | 2003(a)   | 2002      | 2001     
|---------------------------------------------- | --------- | --------- | ---------
|Risk-free interest rate                        | 1.58%     | 3.68%     | 4.39%    
|Expected life                                  | 2.1 years | 7.4 years | 7.4 years
|Expected volatility                            | 46.3%     | 49.5%     | 52.6%    
|Dividend yield                                 | --        | --        | --       
|Weighted average fair value of options granted | $  3.03   | $  3.17   | $  5.06  

---

|(a) | We granted 999,260 options during 2003, which had a reduced term of three years.  Prior grants have ten-year terms.
|--- | -------------------------------------------------------------------------------------------------------------------

Insurance Proceeds

During 2003,  we received  total  proceeds of $1.0 million  related to damages we incurred as a result of Hurricane  Lili.  We credited
$608 thousand against proved property to represent  damages paid for equipment  losses.  We included $399 thousand of these proceeds in
oil and gas sales, which represented business interruption proceeds.

F-12

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

Income Taxes

We file 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.

Goodwill

As a result of our merger with Prize,  we currently have $56.5 million of goodwill  recorded on our books.  Under SFAS No. 142, we will
not amortize any of the goodwill  acquired in the merger.  All goodwill has been allocated to the Exploration and Production  reporting
unit. We test our goodwill for  impairment  on an annual basis or whenever  indicators  of  impairment  exist.  We performed our annual
impairment  test at December 31, 2003, and determined that no impairment  existed.  The annual  impairment test requires  management to
make  significant  estimates  and  judgments.  If  impairment  is  determined  to exist,  we will  measure  our  impairment  based on a
comparison  of the  carrying  value of goodwill  to the  implied  fair value of that  goodwill.  The implied  fair value of goodwill is
determined by allocating the fair value of the Exploration  and Production  reporting unit to all of the assets and liabilities of that
unit.  The excess of the fair value of the reporting unit over the amounts  assigned to its assets and  liabilities is the implied fair
value of goodwill.  If the carrying amount of goodwill  exceeds the implied fair value of that goodwill,  impairment will be recognized in the income statement.

Asset Retirement Obligations

Statement of  Financial  Accounting  Standards  ("SFAS")  No. 143 - SFAS No. 143,  "Accounting  for Asset  Retirement  Obligations,"  became
effective  beginning  January 1, 2003.  SFAS No. 143  requires the  recognition  of a fair value  liability  for any  retirement  obligation
associated  with  long-lived  assets in the  period  in which it is  incurred  if a  reasonable  estimate  of fair  value  can be made.  The
associated  asset  retirement  costs are capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset's
useful life.  See Note 3 for  additional  information  on our asset  retirement  obligations.  Upon adoption of SFAS No. 143, we recorded an
addition to oil and gas properties of $25.4 million, an asset retirement  obligation of $30.4 million, a reduction of accumulated  depletion
of $5.6 million,  and a pre-tax gain of $643 thousand.  The retirement  obligation  requires  management to make  significant  estimates and
judgments regarding our expected plugging costs and retirement dates.

New Accounting Standards

SFAS No.  145 - SFAS No.  145  "Recission  of FASB  Statements  No. 4, 44,  and 64,  Amendment  of FASB  Statement  No.  13,  and  Technical
Corrections,"  became  effective  beginning  January 1, 2003. The Statement  rescinds,  updates,  clarifies and simplifies  various existing
accounting  pronouncements.  SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from  Extinguishment of Debt," which required all
gains and losses from  extinguishment of debt to be aggregated and, if material,  classified as an extraordinary item, net of related income
tax effect.  As a result,  SFAS No. 145 requires us to reclassify  as additional  expense any  extraordinary  items for debt  extinguishment
costs which did not meet the criteria as described in APB Opinion No. 30,  "Reporting  the Results of  Operations - Reporting the Effects of
Disposal of a Business,  and  Extraordinary,  Unusual and  Infrequently  Occurring Events and  Transactions,"  as additional  expense.  As a
result,  for the years ended  December  31,  2002 and 2001,  we  reclassified  our  previously  reported  $621  thousand  and $304  thousand
extraordinary  losses as costs associated with early  retirement of debt of $1 million and $490 thousand,  and decreased our deferred income
tax expense by $379 thousand and $186 thousand, respectively.

F-13

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

SFAS No. 146 - In July 2002, the Financial Accounting  Standards Board,  ("FASB") issued SFAS No. 146, "Accounting for Costs Associated with
Exit or Disposal  Activities."  SFAS No. 146 requires  companies to recognize costs  associated  with exit or disposal  activities when they
are incurred rather than at the date of a commitment to an exit or disposal plan.  SFAS No. 146 supercedes  EITF Issue No. 94-3,  "Liability
Recognition  for  Certain  Employee  Termination  Benefits  and Other  Costs to Exit an  Activity  (including  Certain  Costs  Incurred in a
Restructuring)."  Statement 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

FIN No. 45 - FIN No.  45,  "Guarantor's  Accounting  and  Disclosure  Requirements  for  Guarantees,"  was  issued in  November  2002.  This
interpretation  addresses the  disclosures to be made by a guarantor in its interim and annual  financial  statements  about its obligations
under guarantees.  It also clarifies the requirements related to the recognition of a liability by a guarantor
at the  inception  of a  guarantee  for  the  obligations  the  guarantor  has  undertaken  in  issuing  that  guarantee.  We  adopted  this
interpretation in January 2003.

In the past, we have provided  trade  guarantees on behalf of NGTS.  The last of these  guarantees  expired in July 2003.  Further,  we have
sold our 30% ownership  interest in NGTS, and,  therefore,  no longer maintain any equity interest in this former affiliate (see Note 2). We
have provided no other guarantees on behalf of any unconsolidated entities and do not intend to issue any at this time.

FIN No. 46 - FIN No. 46,  "Consolidation  of Variable  Interest  Entities,"  addresses  consolidation  by business  enterprises  of variable
interest  entities with certain  defined  characteristics.  This  interpretation  applies to the first fiscal year or interim  period ending
after  December 15, 2003,  to variable  interest  entities  created or obtained  before  February 1, 2003.  For variable  interest  entities
created after January 31, 2003 the  consolidation  provisions apply  immediately.  We do not have any variable  interest entities that would
be subject to these provisions and, accordingly, FIN 46 will not have an impact on our financial statements.

FIN No. 46R - In January  2003,  the FASB issued FIN 46. In  December  2003,  FASB  revised  FIN 46,  which  clarifies  the  application  of
Accounting  Research  Bulletin No. 5l,  "Consolidated  Financial  Statements"  ("ARB 51"). As per ARB 51, a general rule for  preparation of
consolidated  financial statements of a parent and its subsidiary is ownership by the parent,  either directly or indirectly,  of over fifty
percent of the outstanding  voting shares of a subsidiary.  However,  application of the majority  voting interest  requirement of ARB 51 to
certain types of entities may not identify the party with a controlling  financial  interest because the controlling  financial interest may
be achieved  through  arrangements  that do not involve voting interest.  FIN 46 clarifies  applicability of ARB 51 to entities in which the
equity  investors do not have the  characteristics  of a controlling  financial  interest or do not have  sufficient  equity at risk for the
entity to finance its activities without  additional  subordinated  financial  support.  FIN 46 requires an entity to consolidate a variable
interest  entity even though the entity does not, either  directly or indirectly,  own over fifty percent of the outstanding  voting shares.
We do not have any variable  interest entities that would be subject to these provisions,  and,  accordingly,  FIN 46R also will not have an
impact on our financial statements.

SFAS 150 - In May 2003,  the FASB  issued  SFAS No.  150,  "Accounting  for  Certain  Financial  Instruments  with  Characteristics  of both
Liabilities  and Equity" (SFAS 150). SFAS 150 establishes  standards for how an issuer of financial  instruments  classifies and measures in
its  statement of financial  position  certain  instruments  with  characteristics  of both  liabilities  and equity.  SFAS 150 modifies the
accounting and financial  statement  disclosures of certain financial  instruments that, under previous guidance,  issuers could account for
as equity.  SFAS 150 affects the issuer's  accounting  for three types of  financial  instruments  that are required to be accounted  for as
liabilities.  We did not have any  financial  instruments  outstanding  to which the  provisions of SFAS 150 apply;  therefore,  the initial
adoption of SFAS 150 did not have any impact on the results of operations or equity of the company.

In June 2001,  FASB  issued  SFAS No.  141,  "Business  Combinations,"  which  requires  the  purchase  method of  accounting  for  business
combinations  initiated  after June 30, 2001 and eliminates  the  pooling-of-interests  method.  In July 2001, the FASB also issued SFAS No.
142, "Goodwill and Other Intangible  Assets," which discontinues the practice of amortizing  goodwill and indefinite lived intangible assets
and initiates an annual review of  impairment.  Intangible  assets with a  determinable  useful life will continue to be amortized over that
period.  The  amortization  provisions  apply to goodwill and intangible  assets  acquired after June 30, 2001. SFAS No. 141 and 142 clarify
that more assets should be  distinguished  and  classified  between  tangible and  intangible.  We did not change or reclassify  contractual
mineral  rights  included in proved and unproved oil and gas  properties  on our balance sheet upon adoption of SFAS No. 142. We believe the
treatment of such mineral  rights as tangible  assets under the full cost method of accounting  for oil and gas  properties is  appropriate.
An issue has been  raised  regarding  whether  these  mineral  rights  should be  classified  as  tangible or  intangible  assets.  If it is
determined that  reclassification  is necessary,  we will reduce our proven properties by $352.7 million,  decrease  unproved  properties by
$154.5 million and report  intangible  mineral rights related to proved  properties of $352.7 million and intangible  mineral rights related
to unproved  properties  of $154.5  million at December 31,  2002.  At December 31,  2003,  we will reduce our proven  properties  by $408.1
million,  reduce our unproved  properties by $94.4 million,  and report  intangible  mineral  rights related to proved  properties of $408.1
million and intangible  mineral  rights  related to unproved  properties of $94.4  million.  These  reclassifications  represent the cost of
acquiring  proved and unproved  mineral use rights from the  effective  date of June 30, 2001.  The  provisions of SFAS No. 141 and SFAS No.
142 impact only the balance sheet and any associated  footnote  disclosures.  Any  reclassifications  potentially  required would not impact
our cash flows or statements of income.

F-14

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

Income or Loss Per Common Share

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

The following table  reconciles the numerators and  denominators  used in the computations of both basic and diluted EPS (in thousands,
except for per share amounts):

|                                | For the Year Ended
|------------------------------- | ------------------
|
|
|Income before Cumulative Effect |                   
|Add:  Cumulative Effect         |                   
|                                |                   
|Basic EPS                       |                   
|Income available to common      |                   
|stockholders                    |                   
|Effect of dilutive securities   |                   
|Warrants                        |                   
|Options                         |                   
|                                |                   
|Diluted EPS                     |                   
|Income available to common      |                   
|stockholders and assumed        |                   
|conversions                     |                   
|Less:  Cumulative Effect        |                   
|                                |                   
|Income before Cumulative Effect |                   
|                                |                   

At December 31, 2003, we had
7,228,457 warrants outstanding at a weighted average exercise price of $15.00 per share,
6,740,764 options outstanding at a weighted average price of $6.36 per share, and no
outstanding convertible preferred stock. Warrants totaling 7,550,832 shares and options
totaling 2,299,300 shares were excluded from the diluted net income per share computation
in 2003 because their exercise price exceeded the average market price of our stock. There
was no dilutive effect from our Convertible Notes at December 31, 2003, because their
conversion price exceeded the average market price of our stock. Please see Note 5 for a
discussion of the conversion features of these Notes.

At December 31, 2002, we had
7,873,206 warrants outstanding at a weighted average exercise price of $14.32 per share,
6,044,800 options outstanding at a weighted average exercise price of $6.37 per share, and
no outstanding convertible preferred stock. Warrants totaling 7,838,600 shares and options
totaling 5,059,286 shares were excluded from the diluted net income per share computation
in 2002 as the exercise price exceeded the average market price of our common stock.

At December 31, 2001, we had 644,749
warrants outstanding at a weighted average exercise price of $6.75 per share, 5,217,584
options outstanding at a weighted average exercise price of $6.22 per share, and no
outstanding convertible

F-15

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

preferred stock. Warrants totaling
432,237 shares and options totaling 3,140,734 shares were excluded from the diluted net
income per share computation in 2001 as the exercise price exceeded the average market
price of our common stock.

Revenue Recognition

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

Inflation and Changes in
Prices

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

We market oil and gas for our own
account, which exposes us to the attendant commodities risk. A significant portion of our
gas production is currently sold to end-users either (i) on the spot market on a
month-to-month basis at prevailing spot market prices or (ii) under long-term contracts
based on current spot market prices. We normally sell our oil under month-to-month
contracts to a variety of purchasers.

Use of Estimates and
Certain Significant Estimates

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

Treasury Stock

We may repurchase shares of common
stock in stock repurchase programs. Our repurchases of shares of common stock are recorded
as treasury stock at cost and result in a reduction of stockholders equity. When
treasury shares are reissued, we use a first-in first-out method and the difference
between repurchase cost and reissuance price is treated as an adjustment to paid-in
capital.

NOTE 2 
ACQUISITIONS AND DISPOSITIONS

On July 29, 2003, we exercised our
option to sell our 30% interest in NGTS. At that date, we reduced the carrying value and
recorded a charge to equity in earnings of affiliate of approximately $791 thousand to
state our investment at its estimated fair value. The sale closed on September 30, 2003,
and we received proceeds of $5.2 million on that date which we used to repay indebtedness.
No gain or loss was recorded at the time of sale.

On November 19, 2003, we acquired an
80% controlling ownership interest in Metrix, an internet-based field marketing service
company, through the settlement of outstanding litigation in our favor as well as the
conversion of our $325 thousand loan to Metrix into equity of that company. As a result of
the settlement, we have fully consolidated Metrix, effective December 1, 2003. Prior to
this acquisition, we accounted for our approximate 32% ownership interest in Metrix as an
equity investment. No goodwill was recorded on this acquisition. Pro forma information
related to this acquisition has not been presented, as the effect was not material to our
historical results of operations.

F-16

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

On March 15, 2002, we merged with
Prize Energy Corp. (Prize), a publicly traded independent oil and gas
development and production company. The transaction was accounted for by us as a purchase
of Prize in accordance with the provisions of SFAS No. 141 Business
Combinations. As a result of our merger with Prize, we acquired oil and gas
properties located in three of our core operating areas: the Permian Basin of West Texas
and Southeast New Mexico, the onshore Gulf Coast area of Texas and Louisiana and the
Mid-Continent area of Oklahoma and the Texas Panhandle. This allowed us to meet our goal
of increasing reserves in geographic regions similar to our own which allows us to achieve
operating synergies and production enhancements. Under the terms of the merger, we
distributed 2.5 shares of common stock plus $5.20 in cash for each Prize share
outstanding. The purchase price, computed from the equity and cash consideration given at
the time of the merger, was allocated to the fair value of the net assets acquired. The
amount of purchase price in excess of the fair value of Prizes net assets was
assigned to goodwill. We assigned the goodwill to our exploration and production segment
when the purchase price allocation was finalized in June 2003. The following table
summarizes the total assumed purchase price and related final allocation to the net assets
acquired (amounts in thousands) as of June 30, 2003:

|Total Purchase Price:                                       |  |  |   |          |  
|----------------------------------------------------------- |  |  | - | -------- | -
|Fair Value of 34,062,963 shares of Magnum Hunter            |  | 
|common stock                                                |  |  | $ | 257,175  |  
|Cash consideration                                          |  |  |   | 70,851   |  
|Fair Value of Prize warrants                                |  |  |   | 3,416    |  
|                                                            |  | 
|Total                                                       |  |  | $ | 331,442  |  
|                                                            |  | 
|Net Preliminary Purchase Price Allocation:                  |  | 
|Net purchase price                                          |  |  | $ | 331,442  |  
|Historical net assets acquired                              |  |  |   | (148,272 | )
|                                                            |  | 
|Excess purchase price                                       |  |  |   | 183,170  |  
|Adjustment of proved oil and gas properties to fair value   |  |  |   | (63,915  | )
|Adjustment of unproved oil and gas properties to fair value |  |  |   | (139,395 | )
|Adjustment of gas plant to fair value                       |  |  |   | (18,856  | )
|Write-off of historical Prize deferred financing costs      |  |  |   | 2,363    |  
|Other fair value adjustments                                |  |  |   | 1,436    |  
|Imputed interest on debt due to merger                      |  |  |   | (108     | )
|Additional deferred income taxes                            |  |  |   | 91,865   |  
|                                                            |  | 
|Excess purchase price allocated to goodwill                 |  |  | $ | 56,560   |  
|                                                            |  | 

During the third and fourth  quarters of 2003, we divested of a number of oil and gas  properties.  In accordance with SFAS No. 142, we
attached $93 thousand of goodwill to the divested  properties.  Proceeds  (net of goodwill) of  approximately  $17 million were applied
against the full cost pool. The remaining  goodwill  balance at December 31, 2003 was $56.5 million.  Also in accordance  with SFAS No.
142, we performed a goodwill  impairment  test at December  31,  2003.  Test results  showed no  impairment  of goodwill.  The goodwill
acquired is not deductible for tax purposes.

Historical net assets acquired in the merger were as follows (in thousands):

|Current assets                       |  |  | $ | 78,440   |  
|------------------------------------ |  |  | - | -------- | -
|Properties, plant and equipment, net |  |  |   | 398,409  |  
|Other assets                         |  |  |   | 3,093    |  
|Current liabilities                  |  |  |   | (42,626  | )
|Long-term debt                       |  |  |   | (245,819 | )
|Deferred income                      |  |  |   | (40,677  | )
|taxes                                |  |  |   | (40,677  | )
|Other non-current liabilities        |  |  |   | (2,548   | )
|                                     |  | 
|Historical net assets acquired       |  |  | $ | 148,272  |  
|                                     |  | 

F-17

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

Changes to the carrying value of
goodwill during the twelve months ended December 31, 2003, are as follows (in thousands):

|Balance at December 31, 2001       |  |  | $ | --     |  
|---------------------------------- |  |  | - | ------ | -
|Goodwill acquired                  |  |  |   | 52,902 |  
|Purchase price adjustments         |  |  |   | (2,192 | )
|                                   |  | 
|Balance at December 31, 2002       |  |  |   | 50,710 |  
|Goodwill acquired                  |  |  |   | --     |  
|Purchase price adjustments         |  |  |   | 5,850  |  
|Adjustment for divested properties |  |  |   | (93    | )
|                                   |  | 
|Balance at December 31, 2003       |  |  | $ | 56,467 |  
|                                   |  | 

The following  summary,  prepared on a pro forma basis,  presents the results of operations  for the years ended  December 31, 2002 and
2001, as if the acquisition of Prize occurred as of the beginning of the respective  periods.  The pro forma  information  includes the
effects of adjustments for interest  expense,  depreciation,  depletion and  amortization,  and income taxes. The pro forma results are
not  necessarily  indicative of what actually  would have occurred if the  acquisition  had been  completed as of the beginning of each
period presented,  nor are they necessarily  indicative of future consolidated results.  Prize was included in our consolidated results
of operations beginning March 1, 2002.

Pro Forma Results of Operations (Unaudited) (in thousands of dollars, except for per share amounts)

|                                   | Year Ended
December 31,
|---------------------------------- | -----------------------
|
|Revenue                            |                        
|Total Operating Costs and Expenses |                        
|                                   |                        
|Operating Profit                   |                        
|Interest Expense and Other         |                        
|                                   |                        
|Income before Tax                  |                        
|Benefit (Provision) for Income Tax |                        
|                                   |                        
|Net Income                         |                        
|Net Income Per Common Share        |                        
|Basic                              |                        
|Diluted                            |                        

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

NOTE 3 - ASSET RETIREMENT OBLIGATIONS

SFAS No. 143,  "Accounting for Asset Retirement  Obligations,"  became effective  beginning  January 1, 2003. SFAS No. 143 requires the
recognition of a fair value liability for any legal  retirement  obligations  associated with long-lived  assets in the period in which
it is incurred if a reasonable  estimate of fair value can be made. The associated  asset  retirement  costs are capitalized as part of
the carrying  amount of the long-lived  asset and depreciated  over the asset's useful life.  Prior to adopting SFAS No. 143 on January
1, 2003, we accounted for asset retirement obligations in accordance with SFAS No. 19.

Our long-lived  assets captured under SFAS No. 143 are developed oil and gas properties,  production and distribution  facilities,  and
natural gas processing plants.  Our asset retirement obligations include plugging, abandonment, decommission, and remediation costs.

F-18

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

The following is a reconciliation of the asset retirement obligation liability at December 31, 2003 (in thousands):

|Beginning balance at January 1, 2003 |  |  | $ | --     |  
|------------------------------------ |  |  | - | ------ | -
|Cumulative effect adjustment         |  |  |   | 30,391 |  
|Liabilities incurred                 |  |  |   | 2,686  |  
|Liabilities settled                  |  |  |   | (1,759 | )
|Liabilities sold                     |  |  |   | (1,232 | )
|Accretion expense                    |  |  |   | 2,478  |  
|Change in retirement cost estimates  |  |  |   | (75    | )
|                                     |  | 
|Ending balance at December 31, 2003  |  |  | $ | 32,489 |  
|                                     |  | 

The following pro forma data
summarizes our net income and net income per share as if we had adopted SFAS No. 143 on
January 1, 2002. The associated pro forma asset retirement obligation was $16.9 million on
January 1, 2002, and an additional asset retirement obligation of $12.9 million would have
been recorded at March 1, 2002, in conjunction with the Prize merger. The balance at
December 31, 2002 would have been $30.4 million. Values in the pro forma summary are in
thousands, except for the per share amounts.

|                                                     | Year Ended
December 31,
|---------------------------------------------------- | -----------------------
|
|Net income, as reported                              |                        
|Pro forma adjustment to reflect retroactive          |                        
|adoption of SFAS No. 143, net of related tax effects |                        
|                                                     |                        
|Pro forma net income                                 |                        
|                                                     |                        
|Earnings per share:                                  |                        
|Basic - as reported                                  |                        
|                                                     |                        
|Basic - pro forma                                    |                        
|                                                     |                        
|Diluted - as reported                                |                        
|                                                     |                        
|Diluted - pro forma                                  |                        
|                                                     |                        

NOTE 4  RELATED
PARTY TRANSACTIONS

At December 31, 2003 and 2002, our
note receivable from the Magnum Hunter 401(k) Employee Stock Ownership Plan (KSOP) was
$6.1 million and $4.9 million, respectively. The purpose of the loan is to allow the KSOP
to purchase Magnum Hunter common stock on the open market. The loan is interest free, due
December 31, 2004, and is secured by shares of the companys common stock which have
not been earned by participants in the KSOP. At December 31, 2003 and 2002, the number of
unearned shares in the KSOP were 1,012,203 and 757,246, respectively. The unearned shares
and their corresponding costs were reflected on our consolidated balance sheets as
reductions to stockholders equity.

During 1998, our 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, and recorded as a receivable from
stockholder. We had the right to cause Mr. Evans to repurchase the shares back from Magnum
Hunter at the equivalent price that we 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. Mr. Evans repurchased the shares for $442,019 during December 2002,
eliminating the receivable from stockholder.

During December 1998, our Board of
Directors authorized a loan of up to $300,000 be made available to Mr. Evans. On December
28, 2000, Mr. Evans borrowed $294,938, which was included in notes receivable from
affiliate. On January 15, 2001, Mr. Evans repaid $295,261, including accrued interest,
bringing the balance to zero. On April 16, 2001, the company loaned Mr. Evans $300,000,
under an authorization by the Board of Directors, on a note with an interest rate of 10%
and due December 31, 2001, which was classified as a note receivable from affiliate.
During 2001, Mr. Evans repaid $328,931, including accrued interest, bringing the principal
and interest balance to zero.

F-19

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

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

There are no loans or extensions of
credit to directors and executive officers of Magnum Hunter as of December 31, 2003.

NOTE 5  DEBT

Notes payable and long-term debt at
December 31, 2003 and 2002 consisted of the following (in thousands):

|                                                              | 2003 | 2002
|------------------------------------------------------------- | ---- | ----
|Long-Term Debt:                                               |      |     
|Bank debt under revolving credit agreements due May 2, 2006,  |      |     
|3.10% at December 31, 2003                                    |      |     
|Bank debt under revolving credit agreement due May 31, 2005,  |      |     
|(non-recourse)                                                |      |     
|Capital lease obligations                                     |      |     
|Senior unsecured notes, due June 1, 2007, 10%                 |      |     
|Senior unsecured notes, due March 15, 2012, 9.6%              |      |     
|Floating rate convertible senior notes, due December 15, 2023 |      |     
|1.17% at December 31, 2003                                    |      |     
|Production payment liability, non-recourse                    |      |     
|                                                              |      |     
|                                                              |      |     
|Less current portion                                          |      |     
|                                                              |      |     
|Total Long-Term Debt                                          |      |     
|                                                              |      |     

The following table presents the approximate annual maturities of debt:

|           | (in thousands)
|---------- | --------------
|2004       |               
|2005       |               
|2006       |               
|2007       |               
|Thereafter |               
|           |               
|Total      |               
|           |               

We have a Senior Bank Credit Facility  ("Facility"),  which provides for total borrowings of $500 million,  on which our borrowing base
was limited to $255  million at December  31,  2003.  The level of the  borrowing  base is  dependent  on the  valuation  of the assets
pledged, primarily oil and gas reserve values.

During 2003, we amended our Facility in May and October to  ultimately  increase the  borrowing  base to $350 million,  up $100 million
from our previous  $250 million  borrowing  base. We also extended the  expiration  date of the Facility to May 2, 2006.  The increased
borrowing  base was used to fund the  redemptions  of our 10% Senior Notes which were  completed  prior to the issuance of our floating
rate convertible notes  ("Convertible  Notes").  We also used the increased borrowing base to fund the costs of issuing our Convertible
Notes. Upon the issuance of our Convertible  Notes, we repaid  approximately  $144 million of our borrowings on this Facility,  and our
borrowing base was reduced to $255 million.  The Facility  provides for both a LIBOR and "Base rate" (Prime)  interest rate option.  At
December 31,  2003,  we had no  borrowings  under the Base rate option and $165 million  outstanding  at LIBOR + 1.75%.  We also have a
letter of credit  posted  against  our  borrowing  base of $2.5  million.  While we have no actual  borrowings  against  this letter of
credit,  it  reduces  our funds  available  under the  borrowing  base.  The  letter of credit  was  posted to cover any  plugging  and
abandonment costs, as well as potential  environmental  remediation costs after the property is plugged, of a property previously owned
by Prize.  We have entered  non-binding  arbitration to attempt to eliminate the need for this letter of credit.  At December 31, 2003,
we had available credit under this Facility of $87.5 million.

F-20

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

Our Facility  includes  covenants,  the most restrictive of which requires  maintenance of a minimum funded debt to EBITDA ratio and an
interest  coverage  ratio,  as defined in the loan  agreement.  We were not in compliance with the funded debt to EBITDA ratio required
under the covenants as of March 31, 2002. The lender  provided us with a waiver as of this date,  and we negotiated a less  restrictive
funded debt to EBITDA ratio for the next four  successive  quarters until March 31, 2003. We were in compliance  with the covenants for
the  remainder of 2002 and have been in  compliance  with the revised  covenants  for all of 2003.  We expect to be able to comply with
these  covenants in the future.  The lenders to the Facility must approve all dividends paid on common stock,  other than those paid in
common stock, and have approved both the redemption of our 10% Senior Notes and the issuance of our Convertible Notes.

On a semi-annual  basis, our borrowing base under our Facility is redetermined by the financial  institutions who have committed to the
company  based on their  review of our  pledged  proved  oil and gas  reserves  and other  assets.  If the  outstanding  balance on the
Facility  exceeds  the  redetermined  borrowing  base,  we must  repay the excess  immediately.  The last  redetermination  date had an
effective  date of June 30, 2003,  and was completed on October 31, 2003.  This  redetermination  increased  our borrowing  base by $50
million.  Our next  redetermination  date will have an effective date of December 31, 2003, and has an estimated completion date of May
31, 2004.

On March 15,  2002,  Canvasback  entered  into a $10  million  revolving  credit  agreement  with a financial  institution.  The credit
agreement  provided for both LIBOR and prime based  interest  rate options.  On June 30, 2002,  we converted  the $5.8 million  balance
under this  agreement  to a term loan due March 7, 2004.  Proceeds  from the loan were used to purchase  $5.8 million of our 10% Senior
Notes from Magnum  Hunter,  which had been  purchased by Magnum  Hunter  during 2001 and held for  investment.  These 10% Senior Notes,
along with $4.7 million in 10% Senior Notes  contributed to Canvasback  from Bluebird,  served as the only collateral for this loan. We
borrowed  additional  funds of $1.2 million  during the fourth  quarter of 2002,  increasing  the balance to $7 million.  This loan was
non-recourse  to Magnum  Hunter.  In conjunction  with the  redemption of our 10% Senior Notes during 2003,  this loan was paid in full
and the agreement was terminated.

On January 15, 2002, we entered into a  sale-leaseback  transaction  on three  newly-constructed  production  platforms and  associated
pipelines  located in the Gulf of Mexico that had already been placed into  service.  We received  total  proceeds of $11.2  million in
new funding,  which we used for general  corporate  purposes.  The  production  platforms  are being  leased from a syndicate  group of
lenders  over terms from three to five years at a cost of funds based on LIBOR,  yielding a weighted  average  rate of 4.2% at December
31, 2003.

On May 29, 1997, we completed a private placement of $140 million in unsecured 10% Senior Notes, due June 1, 2007.
During 2003, we paid $145.2  million to redeem the $140 million in principal of our 10% Senior  Notes.  This  redemption  was funded by
borrowings  under  our  Facility  as well as the  issuance  of  $125  million  in  Convertible  Notes  during  December  2003.  We paid
approximately $5.2 million in premiums to redeem these notes. Of the notes redeemed,  Canvasback  received  approximately $10.9 million
in principal and received premiums of approximately $273 thousand.

We  completed a private  placement of $300  million in  unsecured  9.6% Senior  Notes on March 15, 2002.  The 9.6% Senior Notes are due
March  15,  2012,  with  interest  payable  semi-annually  on March 15 and  September  15.  We used the  funds  received  to: i) retire
outstanding  indebtedness  under the Prize  commercial  bank credit  facility,  ii) pay fees  related to the issuance of the new Senior
Notes, and iii) for general corporate purposes.

During December 2003, we issued $125 million in face value of Convertible  Notes.  These  Convertible  Notes bear interest equal to the
three-month  LIBOR, to be adjusted  quarterly.  The initial rate set on the Convertible  Notes was 1.17%.  They are convertible  into a
combination  of cash and Magnum  Hunter  common  stock  upon  certain  events.  The  initial  conversion  price is  $12.19,  subject to
adjustment  under  certain  conditions.  The  Convertible  Notes are due  December  2023,  but holders of these notes have the right to
require us to repurchase  all or a portion of the notes on December 15, 2008,  2013,  and 2018. We will  repurchase  these notes for an
amount of cash equal to 100% of the principal  plus accrued but unpaid  interest up to but not including  the date of  repurchase.  The
repurchase  notice given by each holder  electing  repurchase may be withdrawn by the holder by written notice of withdrawal  delivered
prior to the close of business on the date of  repurchase.  The proceeds  from these  Convertible  Notes were used to repay  borrowings
under the Facility used to fund the 10% Senior Note redemptions  during the year as well as to reduce  borrowings under the Facility by
approximately $25 million.

F-21

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

Holders may  surrender  Convertible  Notes for  conversion  into cash and shares of our common  stock prior to the  Convertible  Notes'
maturity date in the following  circumstances:  i) during any calendar quarter  commencing after the issuance of the Convertible Notes,
if our common stock price for at least 20 trading days in the period of 30  consecutive  trading days ending on the last trading day of
the calendar  quarter  preceding the quarter in which the conversion  occurs is more than 110% of the conversion price per share of our
common  stock in effect on that 30th  trading  day;  ii) if we have called the  particular  Convertible  Notes for  redemption  and the
redemption  has not yet occurred;  iii) during the five trading day period after any five  consecutive  trading day period in which the
trading  price of $1,000  principal  amount of the  Convertible  Notes for each day of such  five-day  period  was less than 95% of the
product of the closing  sale price of our common  stock on that day  multiplied  by 82.0345 (the  "Conversion  Rate");  or iv) upon the
occurrence of specified corporate transactions.

Upon the  occurrence  of the  circumstances  described  above,  holders may convert any  outstanding  notes into cash and shares of our
common stock at an initial  conversion  price per share of $12.19.  Subject to certain  exceptions,  at the time notes are tendered for
conversion,  the value (the  "Conversion  Value")  of the cash and  shares of our common  stock,  if any,  to be  received  by a holder
converting  $1,000  principal  amount of the notes will be determined by multiplying the Conversion Rate by the ten-day average closing
stock price of our common  stock.  We will deliver the  Conversion  Value to holders as follows:  i) an amount in cash (the  "Principal
Return")  equal to the  lesser of (a) the  Conversion  Value and (b) the  principal  amount of the notes to be  converted  and,  if the
Conversion  Value is greater than the  Principal  Return,  ii) an amount in shares  equal to the  Conversion  Value less the  Principal
Return ("the Net Share  Amount").  The number of Net Shares to be paid will be  determined  by dividing the Net Share Amount by the ten
day average closing stock price of our common stock.

In November  1996,  we entered into a production  payment  conveyance.  We received a production  payment  amount of $750  thousand and
agreed to make  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 $12 thousand and $114 thousand at December 31,
2003 and 2002,  respectively.  The  production  payment  bears  interest at the rate of 13.5% per annum and is  non-recourse  to Magnum
Hunter.

NOTE 6 - INCOME TAXES

We account 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 (in thousands):

|                                                 | 2003 | 2002 | 2001
|------------------------------------------------ | ---- | ---- | ----
|Income tax expense at statutory rates            |      |      | $   
|State tax expense                                |      |      |     
|Increase in operating loss and other carry-overs |      |      |     
|Change in valuation allowance                    |      |      |     
|Other                                            |      |      |     
|                                                 |      |      |     
|Tax expense (benefit)                            |      |      | $   
|                                                 |      |      |     

F-22

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

The tax effects of significant
temporary differences and carryforwards are as follows (in thousands):

|                                                            | December 31,
|----------------------------------------------------------- | ------------
|
|Property and equipment, including intangible drilling costs |             
|Goodwill impairment on divested properties                  |             
|Other                                                       |             
|                                                            |             
|Total deferred tax liability                                |             
|                                                            |             
|Allowance for doubtful accounts                             |             
|Reserves                                                    |             
|Depletion carryforwards                                     |             
|Derivative instruments                                      |             
|Alternative minimum tax credit                              |             
|Employee stock options                                      |             
|Operating loss and other carryforwards                      |             
|Other                                                       |             
|                                                            |             
|Total deferred tax assets                                   |             
|                                                            |             
|Valuation allowance                                         |             
|                                                            |             
|Net Deferred Tax Liability                                  |             
|                                                            |             

Magnum Hunter and our  subsidiaries  have net operating loss  carryforwards of approximately  $106 million that expire,  if unused,  in
years 2009 through 2022.  Current tax laws and  regulations  relating to specified  changes in ownership  limit the  utilization of our
net  operating  loss and tax credit  carryforwards.  A change in  ownership of greater  than 50% of a  corporation  within a three-year
period causes the annual  limitations to be placed in effect.  Such a change is deemed to have occurred  February 3, 1999 in connection
with the purchase of preferred stock by ONEOK Resources  Company,  which has  subsequently  been either redeemed or converted to common
stock.  Approximately  $51.4  million of the net  operating  losses are subject to a limitation  of $7.8 million per year. We also have
$9.5  million of net  operating  losses  subject to a  limitation  of $3.7 million per year as a result of the merger with Prize Energy
Corp. on March 15, 2002.  In addition, we have depletion carryforwards of $3.2 million with no expiration period.

NOTE 7 - STOCKHOLDERS' EQUITY

Preferred Stock

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

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

On December 23, 1996, we issued  1,000,000  shares of new Series A Preferred  Stock,  known as the 1996 Series A convertible  preferred
stock,  in a private  placement,  resulting in net proceeds after  offering costs of $9.3 million.  Dividends of $438 thousand and $875
thousand were declared in 2000 and 1999,  respectively.  On June 30, 2000 the holders of the 1996 Series A convertible  preferred stock
agreed to exchange the convertible  preferred  securities for 900 thousand  warrants to purchase  restricted common shares of our stock
at an  exercise  price of $5.25 per  share  with an  expiration  date of June 3,  2003 and  payment  of $10  million.  The  convertible
preferred shares are currently listed as issued but held by Canvasback as of December 31, 2003.

F-23

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

Warrants

The following is a summary of warrant activity for the periods ended December 31, 2003, 2002 and 2001:

|                                | 2003 | 2002 | 2001
|------------------------------- | ---- | ---- | ----
|
|Outstanding - Beginning of Year |      |      |     
|Issued                          |      |      |     
|Exercised                       |      |      |     
|Redeemed                        |      |      |     
|Expired                         |      |      |     
|                                |      |      |     
|Outstanding - End of Year       |      |      |     
|                                |      |      |     

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

On December 5, 2001, we announced
that a distribution of one warrant for every five shares of common stock owned on January
10, 2002. 7,228,457 warrants were distributed on March 21, 2002. Each new warrant entitles
the holder to purchase one share of common stock at $15. The warrants will expire three
years from the date of distribution, unless extended by the Board of Directors.

We also converted outstanding Prize
warrants into Magnum Hunter stock warrants pursuant to the merger (see Note 2). We
distributed 4,271,813 of these warrants on March 15,2002, at a weighted average exercise
price of $9.09. These warrants expired in June and November 2002.

Common Stock

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

On May 1, 2002, our Board of
Directors announced an expansion of our existing stock repurchase program established in
June 2001. Under this program, we and our affiliates are authorized to repurchase up to
two million shares of our common stock. On October 17, 2002, our Board of Directors
approved a new three million share repurchase program in addition to our June 2001
program. At December 31, 2003, approximately 4.2 million shares had been repurchased under
these two programs, and approximately 818 thousand shares remained available for
repurchase.

On March 15, 2002, we issued 34.1
million shares at a value of $257.2 million pursuant to our merger with Prize. See Note 2
for further discussion on the Prize merger.

We issued 270 thousand, 984 thousand
and 1.1 million shares pursuant to employee stock option exercises for proceeds of $1.2
million, $3.6 million and $4.9 million during 2003, 2002 and 2001, respectively. Upon the
exercise of warrants, we issued 548 thousand treasury shares and 578 shares for proceeds
of $3.4 million and $5.2 thousand during 2003 and

F-24

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

2002, respectively. Of the treasury
shares issued for warrants in 2003, 37 thousand shares were issued in a cashless exercise
of 134 thousand warrants.

Our KSOP purchased 486 thousand, 532
thousand and 105 thousand shares at costs of $2.7 million, $3.7 million and $890 thousand
during 2003, 2002 and 2001, respectively. During the same periods, the KSOP released
shares totaling 231 thousand, 244 thousand and 346 thousand to participants. During 2003,
2002 and 2001, we made new loans to the KSOP of $2.7 million, $3.7 million and $898
thousand and the KSOP repaid loan amounts of $1.5 million, $1.3 million, and $1.1 million,
respectively. Of the 2003 repayments, $1.1 million represented our contribution of 172
thousand shares to the plan. Of the 2002 repayments, $866 thousand represented our
contribution of 158 thousand shares to the KSOP plan. Additionally, in 2001, we
contributed 52 thousand shares to our 401(K) plan.

We issued 73 thousand shares to the
public in 2001 for net proceeds of $734 thousand.

NOTE 8 
SUPPLEMENTAL CASH FLOW INFORMATION

During 2003, we contributed 172
thousand shares of our common stock valued at a cost of $1.1 million to our KSOP plan.
Interest paid on our outstanding indebtedness was $55.2 million. Tax refunds received in
2003 were $8.1 million, net of payments.

During 2002, we contributed 158
thousand shares at a cost of $867 thousand to our KSOP plan. Interest paid on our
outstanding indebtedness was $48.4 million. Taxes paid in 2002 were $666 thousand. We also
completed the Prize merger by issuing 34.1 million shares of common stock valued at $257.2
million and 4.3 million warrants valued at $3.4 million.

During 2001, we contributed 52
thousand shares valued at $151 thousand to our 401(K) plan. In accordance with SFAS No.
115, we increased the carrying costs of our marketable investments by $507 thousand ($466
thousand after income tax expense). Interest paid on our outstanding indebtedness during
2001 was $19 million. Taxes paid in 2001 were $716 thousand.

NOTE 9 
ENVIRONMENTAL ISSUES

We 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 our acquisition of existing or previously drilled well bores, we 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,
we have received contractual warranties that no such violations exist, while in other
acquisitions, we have waived our rights to pursue a claim for such violations from the
selling party. No claim has been made nor has a claim been asserted. We are not aware of
the existence of any material liability relating to any environmental clean-up,
restoration or the violation of any rules or regulations relating thereto.

NOTE 10 
COMMITMENTS AND CONTINGENCIES

We have certain lease agreements for
the use of office space, office equipment, and vehicles. The Irving, Texas office space
lease extends through November 2005, with an option to renew the lease for a three-year
term, and the Grapevine, Texas office lease extends through December 2005. The various
office equipment leases extend until 2007. The various vehicle leases extend until 2012.
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 (in
thousands):

F-25

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

|Year Ended December 31:         |  |  |   |       | 
|------------------------------- |  |  | - | ----- | 
|2004                            |  |  | $ | 2,303 | 
|2005                            |  |  |   | 2,171 | 
|2006                            |  |  |   | 870   | 
|2007                            |  |  |   | 639   | 
|2008                            |  |  |   | 397   | 
|Thereafter                      |  |  |   | 1,023 | 
|                                |  | 
|Total Minimum Payments Required |  |  | $ | 7,403 | 
|                                |  | 

Rental expense was $2.3 million, $2.2
million, and $1.1 million for 2003, 2002 and 2001, respectively.

In the past we have provided trade
guarantees on behalf of NGTS. The last of these guarantees expired in July 2003. Further,
we have sold our 30% ownership interest in NGTS and, therefore, no longer maintain any
equity interest in this former affiliate. We have no other guarantees on behalf of any
unconsolidated entities and do not intend to issue any at this time.

NOTE 11  FINANCIAL
INSTRUMENTS AND CONCENTRATION OF CREDIT RISK

Financial instruments that subject
Magnum Hunter 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 region of
the United States. No single receivable is considered to be sufficiently material as to
constitute a concentration. During the year ended December 31, 2003, we recorded $231
thousand in additional allowances for doubtful accounts. During the year ended December
31, 2002 we recorded $206 thousand in additional allowances for doubtful accounts. We do
not ordinarily require collateral, but in the case of receivables for joint operations, we
often have the ability to offset amounts due against the participants share of
production from the related property. We believe the allowance for doubtful accounts at
December 31, 2003 is adequate.

Under our hedging programs, to the
extent we receive the spread between the contract floor and the index price applied to
related contract volumes, we have a credit risk in the event of nonperformance of the
counterparty to the agreement. We do not anticipate any material impact to our 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, 2003
and 2002, we provided a reserve for the carrying value of a note receivable of $1,620,000.
After establishing this reserve, management believes those market values approximate
carrying values at December 31, 2003 and 2002. The market values of equity investments are
based upon quoted market prices (see Note 1). At December 31, 2003, the fair value of our
debt was equal to its carrying value, except for the 9.6% Senior Notes and Convertible
Notes. The fair value of the 9.6% Senior Notes was $340.5 million and the fair value of
the Convertible Notes was $134.1 million.

NOTE 12  COMMODITY
DERIVATIVES AND HEDGING ACTIVITIES

Crude Oil and Natural Gas
Hedges

Periodically, we enter into futures,
options, and swap contracts to mitigate the effects of significant fluctuations in crude
oil and natural gas prices. At December 31, 2003, we had open contracts with the following
terms:

|Commodity   | Type   | Volume/Day   | Duration        | Wtd. Avg. Price
|----------- | ------ | ------------ | --------------- | ---------------
|Natural Gas | Collar | 85,000 MMBTU | Jan 04 - Dec 04 | $3.76 - $5.78  
|Natural Gas | Collar | 40,000 MMBTU | Jan 05 - Dec 05 | $4.00 - $6.25  
|Crude Oil   | Collar | 8,500 BBL    | Jan 04 - Mar 04 | $24.71 - $31.02
|Crude Oil   | Collar | 7,000 BBL    | Apr 04 - Jun 04 | $23.57 - $30.16
|Crude Oil   | Collar | 4,000 BBL    | Jul 04 - Dec 04 | $23.25 - $28.36

F-26

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

At December 31, 2003, based on future
market prices, the fair value of our open commodity derivative contracts were as follows
(in thousands):

|                             |           
|---------------------------- | ----------
|Derivative Assets            |           
|                             |           
|Crude oil collars            | $       35
|                             |           
|Total derivative assets      | $       35
|Derivative Liabilities      
|                             |           
|Natural gas collars          | $17,806   
|Crude oil collars            | 5,245     
|                             |           
|Total derivative liabilities | $23,051   
|                             |           
|Net derivative liabilities   | $23,016   
|                             |           

In conjunction with the Prize merger
in March 2002, we acquired ten natural gas derivative contracts for the periods April 2002
through December 2004. We also acquired seven crude oil derivative contracts for the
periods March 2002 through December 2003. We recorded a derivative asset of $7.6 million
to reflect the fair value of these contracts at the merger date. In June 2002, we closed
one of the derivative contracts procured in the Prize merger, realizing proceeds of $3.6
million, which were charged against derivative assets. Consequently, the net derivative
balance of $4.0 million will be amortized as a charge to other non-cash hedging
adjustments over the remaining life of the derivative contracts.

At December 31, 2003, we had ten
crude oil derivatives and ten natural gas derivatives, which are categorized in the tables
above. The net fair value of these derivatives was $23.0 million, recognized as a $35
thousand derivative asset and a $23.1 million derivative liability. For the year ended
December 31, 2003, the income statement includes a loss of $12.5 million related to crude
oil derivatives and a loss of $61.4 million related to natural gas derivatives, including
amounts reclassified out of other comprehensive income. The income statement also included
a non-cash hedging ineffectiveness gain of $186 thousand related to crude oil and natural
gas derivatives and a non-cash gain of $1.3 million related to the amortization of hedge
contracts acquired in the Prize merger. The remaining amortization amount relating to
hedge contracts acquired in the Prize merger that will be reclassified into the income
statement in 2004 is an $800 thousand gain. It is estimated at this time that $12.8
million of other comprehensive loss will be reclassified to the income statement during
the next 12 months.

Net gains (losses) related to crude
oil and natural gas derivative transactions for the years ended December 31, 2003, 2002
and 2001 were ($72.4 million), ($9.9 million) and $4.6 million, respectively.

Interest Rate Swaps

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

|Type              | Notional Amount | Termination Date | Pay Rate   | Receive Rate
|----------------- | --------------- | ---------------- | ---------- | ------------
|Pay Fixed/Receive | $50,000,000     | 8/23/03 4        | .25% Fixed | 3 month     
|Variable          |                 |                  |            | LIBOR rate  

The rate we received was reset every
three months to match exactly the rate paid on $50.0 million of our outstanding
LIBOR-based debt under our Facility.

Net gains (losses) related to
interest rate derivative transactions for the years ended December 31, 2003, 2002 and 2001
were ($1.0 million), ($1.2 million) and $0.7 million, respectively.

NOTE 13  STOCK
COMPENSATION PLANS

e have three stock  compensation  plans for our employees  and  directors,  (i) the Magnum  Hunter  Resources  401(k)  Employee  Stock
Ownership Plan, (the "KSOP"), (ii) the Magnum Hunter Resources, Inc. 1996 Incentive Stock Option

F-27

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

Plan (the "1996  Option  Plan"),  and (iii) the Magnum  Hunter  Resources,  Inc.  2002  Incentive  Stock  Option Plan (the "2002 Option
Plan").  In addition, we have made non-incentive stock option grants in 2003, 2002 and 2001.

KSOP

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

During 2003, we loaned the KSOP $2.7
million to purchase 485,622 shares of our common stock on the open market at an average
price of $5.58 per share. During 2003, employees purchased 58,797 shares of the
KSOPs unreleased shares at an average price of $6.46 per share through salary
deferrals. Employee purchases totaled $380 thousand, which the KSOP used to repay that
portion of its outstanding loan, and 58,797 shares were allocated among the Plan
participants. We contributed $1.1 million to the KSOP in December 2003 as a discretionary
contribution under the Plan. The KSOP then repaid that portion of its outstanding loan and
171,868 shares were allocated among participants.

During 2002, we loaned the KSOP $3.6
million to purchase 532,400 shares of our common stock on the open market at an average
price of $6.86 per share. During 2002, employees purchased 86,147 shares of the
KSOPs unreleased shares at an average price of $5.50 per share through salary
deferrals. Employee purchases totaled $474 thousand, which the KSOP used to repay that
portion of its outstanding loan, and 86,147 shares were allocated among the Plan
participants. We contributed $867 thousand to the KSOP in December 2002, as a
discretionary contribution under the Plan. The KSOP then repaid that portion of its
outstanding loan and 157,659 shares were allocated among participants.

During 2001, we loaned the KSOP $898
thousand to purchase 105,450 shares of our common stock on the open market at an average
price of $8.44 per share. During 2001, employees purchased 346,084 shares of the
KSOPs unreleased shares at an average price of $3.18 per share through salary
deferrals and transfers from the 401(k). Employee purchases totaled $1.1 million, which
the KSOP used to repay that portion of its outstanding loan, and 346,084 shares were
allocated among the Plan participants.

The KSOP loan is interest-free and
due December 31, 2004. The loan was secured by 1,012,203 shares and 757,246 shares of our
common stock at December 31, 2003 and 2002, respectively.

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

The KSOP shares are summarized as
follows:

|                                                     | December 31,
|---------------------------------------------------- | ------------
|
|Allocated shares                                     |             
|Unreleased shares                                    |             
|                                                     |             
|Total KSOP shares                                    |             
|Fair value of unreleased shares at December 31, 2003 |             
|and 2002, respectively                               |             
|                                                     |             

F-28

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

The KSOP expense for the years ending
December 31, 2003, 2002 and 2001, was $1.6 million, $997 thousand, and $1.7 million,
respectively.

Stock Option Plans

Incentive Stock Option
Plan

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

Non-Incentive Stock
Option Grants

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

During 2002, the Board granted
2,059,750 new stock options to employees at a weighted average price of $5.61 per share,
of which 20% vested at the date of grant, with the balance vesting an additional 20% per
year on the anniversary date, with a weighted average term of 9.9 years. The exercise
price was the fair market value on the date of grant.

On June 20, 2003, the Board granted
999,260 new stock options to employees as part of the 2003 compensation package. These
options carry an exercise price of $5.92 and were fully vested on December 31, 2003. They
will expire June 20, 2006. During 2003, we also issued 113,000 options to certain
employees and board members. These options carry a weighted average exercise price of
$5.675 and have a weighted average remaining life of 8.2 years.

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

|                                | 2003 | 2002 | 2001
|------------------------------- | ---- | ---- | ----
|
|Outstanding - Beginning of Year |      |      |     
|Granted                         |      |      |     
|Exercised                       |      |      |     
|Cancelled                       |      |      |     
|                                |      |      |     
|Outstanding - End of Year       |      |      |     
|                                |      |      |     
|Exercisable - End of Year       |      |      |     
|                                |      |      |     

F-29

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

The following is a summary of stock options
outstanding at December 31, 2003:

|Exercise Price | Number of
Options
Outstanding | Weighted Average
Remaining Contractual
Life (Years) | Number of
Exercisable
Options
|-------------- | ----------------------------- | --------------------------------------------------- | -----------------------------
|$              | 2.50                          |                                                     |                              
|               | 3.75                          |                                                     |                              
|               | 5.01                          |                                                     |                              
|               | 5.20                          |                                                     |                              
|               | 5.23                          |                                                     |                              
|               | 5.25                          |                                                     |                              
|               | 5.38                          |                                                     |                              
|               | 5.45                          |                                                     |                              
|               | 5.61                          |                                                     |                              
|               | 5.82                          |                                                     |                              
|               | 5.92                          |                                                     |                              
|               | 6.62                          | 5                                                   |                              
|               | 6.68                          | 75                                                  |                              
|               | 7.51                          |                                                     |                              
|               | 7.55                          |                                                     |                              
|               | 7.57                          |                                                     |                              
|               | 7.75                          |                                                     |                              
|               | 7.93                          | 75                                                  |                              
|               | 7.95                          |                                                     |                              
|               | 8.44                          |                                                     |                              
|               | 8.50                          |                                                     |                              
|               | 9.31                          | 25                                                  |                              
|               | 11.08                         |                                                     |                              
|$              | 12.00                         |                                                     |                              
|               |                               |                                                     |                              
|               |                               |                                                     |                              
|               |                               |                                                     |                              

Effective  January 1, 2003, we adopted the  prospective  method for expensing  stock option grants under SFAS No. 148 and SFAS No. 123.
For the year ended  December 31, 2003,  we recorded  expense of $3.0 million for our current  year's  grants.  For grants made prior to
January 1, 2003,  we continue to follow the  disclosures  only portion of SFAS No. 123 and continue to apply the  provisions of APB No.
25, which applies the  intrinsic  value method of  accounting  for  stock-based  compensation.  See Note 1 for  disclosure of pro forma
earnings assuming adoption of SFAS No. 123.

Deferred Compensation Plan

In March 2003, the company  implemented and adopted the 2003 Bonus Deferral Plan.  This plan allows eligible  participants to defer all
or a portion of their  annual  bonuses  until a later  date.  The  Compensation  Committee  of the Board of  Directors  determines  the
participants  who are eligible to make deferral  elections  under the plan.  The bonuses that are subject to the plan are those bonuses
determined  by or under the  authority  of the Board of Directors  and are based upon the  performance  of the company  during a fiscal
year.  The  amount to be  deferred,  as  specified  by any  participant,  shall be  invested  solely in  common  stock of the  company.
Participants  may designate  the date on which shares of common stock covered by a deferral  election  shall be  distributed,  provided
that such  distribution  date is at least twelve months after the date such deferral  election was made. We purchased  approximately 53
thousand  shares at a cost of $295  thousand and  contributed  approximately  18 thousand  treasury  shares with a market value of $100
thousand.  Approximately  36  thousand  shares  were  released to  participants  who  elected to not defer under the plan,  and we were
holding approximately 35 thousand shares in the plan at December 31, 2003.

NOTE 14 - EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL ARRANGEMENTS

Mr. Gary C. Evans,  Mr. Richard R. Frazier,  Mr. Chris Tong, Mr. R. Douglas Cronk, Mr. Charles R. Erwin and Mr. Morgan F. Johnston each
have  employment  agreements  with the  company.  Mr.  Evans'  agreement  terminates  January  1, 2006 and  continues  thereafter

F-30

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

on a
year-to-year  basis and provides for a salary of $300,000 per annum,  unless  increased by the Board.  Mr.  Evans'  salary for the year
2004 is $438,000.  Mr. Frazier's  agreement  terminates  January 1, 2006 and continues  thereafter on a year-to-year basis and provides
for a salary of $175,000 per annum unless  increased  by the Board.  Mr.  Frazier's  salary for the year 2004 is $280,000.  Mr.  Tong's
agreement  terminates  January 1, 2006 and  continues  thereafter  on a  year-to-year  basis and  provides for a salary of $190,000 per
annum,  unless increased by the Board. Mr. Tong's salary for the year 2004 is $210,000.  Mr. Cronk's  agreement  terminates  January 1,
2006 and  continues  thereafter  on a  year-to-year  basis and  provides for a salary of $167,500  per annum,  unless  increased by the
Board. Mr. Cronk's salary for the year 2004 is $185,000.  Mr. Erwin's  agreement  terminates  January 1, 2006 and continues  thereafter
on a  year-to-year  basis and provides for a salary of $185,000 per annum unless  increased by the Board.  Mr.  Erwin's  salary for the
year 2004 is $210,000.  Mr.  Johnston's  agreement  terminates  January 1, 2006 and continues  thereafter on a  year-to-year  basis and
provides for a salary of $180,000 per annum unless increased by the Board.  Mr.  Johnston's  salary for the year 2004 is $180,000.  All
of the  agreements  provide  that the same  benefits  supplied to other  company  employees  shall be available  to the  employee.  The
employment  agreements  also contain,  among other  things,  covenants by the employee  that in the event of  termination,  he will not
compete  with the company in certain  geographical  areas or hire any of our  employees  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,  the employee's  position is terminated,  or the
employee  leaves for "good cause",  the employee is entitled to receive  immediately,  in one lump sum,  certain  compensation.  In the
case of Mr. Evans and Mr.  Frazier,  the employee  shall receive  three times the  employee's  current base salary and bonus,  plus any
other  compensation  received by him in the last fiscal year.  In the case of Mr. Tong,  Mr.  Cronk,  Mr. Erwin and Mr.  Johnston,  the
employee shall receive two times the employee's base salary and bonus, plus any other  compensation  received by him in the last fiscal
year.  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.  We also have key man life insurance on Mr. Evans in the amount of $12,000,000.

NOTE 15 - SEGMENT DATA

We have 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.

Our 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 three  gathering
systems and four natural gas liquids  processing  plants in two geographic  areas that are aggregated.  The Oil Field Services  segment
has six geographic areas that are aggregated.  The
reason for aggregating the segments, in each case, was due to the similarity in nature of the products,  the production processes,  the
type of customers, the method of distribution, and the regulatory environments.

The accounting  policies of the segments are the same as those  described in Note 1 - Summary of Significant  Accounting  Policies.  We
evaluate  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.

F-31

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

Segment data for the three years ended December 31, 2003, 2002 and 2001 are as follows (in thousands):

|2003:                                     | Exploration &
Production | Gas Gathering,
Marketing &
Processing | Oil Field
Services | All Other | Elimination | Consolidated
|----------------------------------------- | ------------------------ | ------------------------------------- | ------------------ | --------- | ----------- | ------------
|Revenue from external customers           |                          |                                       | $                  | 284,929   |             | $           
|Intersegment revenues                     |                          |                                       |                    | 1,738     |             |             
|Depreciation, depletion, amortization and |                          |                                      
|accretion                                 |                          |                                       |                    | 96,086    |             |             
|Segment profit (loss)                     |                          |                                       |                    | 99,809    |             |             
|Equity losses of affiliates               |                          |                                       |                    |           |             |             
|Interest expense                          |                          |                                       |                    |           |             |             
|Costs associated with early retirement of |                          |                                      
|debt                                      |                          |                                       |                    |           |             |             
|Other income                              |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Income before income taxes                |                          |                                       |                    |           |             |             
|Current income tax expense                |                          |                                       |                    |           |             |             
|Deferred income tax expense               |                          |                                       |                    |           |             |             
|Cumulative effect of a change in          |                          |                                      
|accounting principle                      |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Net income                                |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Capital expenditures (net of asset sales) |                          |                                       | $                  | 157,481   |             | $           

|2002:                                     | Exploration &
Production | Gas Gathering,
Marketing &
Processing | Oil Field
Services | All Other | Elimination | Consolidated
|----------------------------------------- | ------------------------ | ------------------------------------- | ------------------ | --------- | ----------- | ------------
|Revenue from external customers           |                          |                                       | $                  | 240,963   |             | $           
|Intersegment revenues                     |                          |                                       |                    | 1,647     |             |             
|Depreciation, depletion, amortization and |                          |                                      
|accretion                                 |                          |                                       |                    | 82,950    |             |             
|Segment profit (loss)                     |                          |                                       |                    | 78,288    |             |             
|Equity earnings of affiliates             |                          |                                       |                    |           |             |             
|Interest expense                          |                          |                                       |                    |           |             |             
|Costs associated with early retirement    |                          |                                      
|of debt                                   |                          |                                       |                    |           |             |             
|Provision for non-cash impairment of      |                          |                                      
|investments                               |                          |                                       |                    |           |             |             
|Other income (loss)                       |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Income before income taxes                |                          |                                       |                    |           |             |             
|Deferred income tax benefit               |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Net income                                |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Capital expenditures (net of asset sales) |                          |                                       | $                  | 643,683   |             | $           

F-32

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

|2001:                                     | Exploration &
Production | Gas Gathering,
Marketing &
Processing | Oil Field
Services | All Other | Elimination | Consolidated
|----------------------------------------- | ------------------------ | ------------------------------------- | ------------------ | --------- | ----------- | ------------
|Revenue from external customers           |                          |                                       | $                  | 133,083   |             | $           
|Intersegment revenues                     |                          |                                       |                    | --        |             |             
|Depreciation, depletion, amortization and |                          |                                      
|accretion                                 |                          |                                       |                    | 42,703    |             |             
|Segment profit (loss)                     |                          |                                       |                    | 56,998    |             |             
|Equity earnings of affiliates             |                          |                                       |                    |           |             |             
|Interest expense                          |                          |                                       |                    |           |             |             
|Costs associated with early retirement    |                          |                                      
|of debt                                   |                          |                                       |                    |           |             |             
|Provision for non-cash impairment of      |                          |                                      
|investments                               |                          |                                       |                    |           |             |             
|Other income                              |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Income before income taxes                |                          |                                       |                    |           |             |             
|Current income tax expense                |                          |                                       |                    |           |             |             
|Deferred income tax expense               |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Net income                                |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Capital expenditures (net of asset sales) |                          |                                       | $                  | 202,063   |             | $           

|                              | Exploration &
Production | Gas Gathering,
Marketing &
Processing | Oil Field
Services | All Other | Elimination | Consolidated
|----------------------------- | ------------------------ | ------------------------------------- | ------------------ | --------- | ----------- | ------------
|As of December 31, 2003       |                          |                                       |                    |           |             |             
|                             
|Segment assets                |                          |                                       | $                  | 1,142,621 |             | $           
|Equity subsidiary investments |                          |                                       |                    |           |             |             
|As of December 31, 2002       |                          |                                      
|                             
|Segment assets                |                          |                                       | $                  | 1,041,577 |             | $           
|Equity subsidiary investments |                          |                                       |                    |           |             |             

NOTE 16  CONDENSED
CONSOLIDATING FINANCIAL STATEMENTS

The company and its subsidiaries,
except Canvasback and certain inconsequential subsidiaries, are direct guarantors of our
9.6% Senior Notes and our Convertible Notes, and have fully and unconditionally guaranteed
these notes on a joint and several basis. In addition to not being a guarantor of these
notes, Canvasback cannot be included in determining compliance with certain financial
covenants under our credit agreements. Management has determined that separate financial
statements relating to the Guarantors are not material to investors. Condensed
consolidating balance sheets for Magnum Hunter Resources, Inc. and subsidiaries as of
December 31, 2003 and 2002 and condensed consolidating statements of operations and cash
flows for the years ended December 31, 2003, 2002 and 2001 are as follows:

F-33

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

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

|December 31, 2003                         
|------------------------------------------
|
|ASSETS                                    
|Current assets                            
|Property and equipment                    
|(using full-cost accounting)              
|Investment in subsidiaries                
|(equity method)                           
|Investment in Parent                      
|Other assets                              
|                                          
|Total Assets                              
|                                          
|LIABILITIES AND STOCKHOLDERS' EQUITY      
|Current liabilities                       
|Long-term liabilities                     
|Shareholders' equity                      
|                                          
|Total Liabilities and Stockholders' Equity
|                                          

|December 31, 2002                         
|------------------------------------------
|
|ASSETS                                    
|Current assets                            
|Property and equipment                    
|(using full-cost accounting)              
|Investment in subsidiaries                
|(equity method)                           
|Investment in Parent                      
|Other assets                              
|                                          
|Total Assets                              
|                                          
|LIABILITIES AND STOCKHOLDERS' EQUITY      
|Current liabilities                       
|Long-term liabilities                     
|Shareholders' equity                      
|                                          
|Total Liabilities and Stockholders' Equity
|                                          

F-34

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

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

|Year Ended December 31, 2003          
|--------------------------------------
|
|Revenues                              
|Expenses                              
|                                      
|Income before                         
|Equity in net earnings of subsidiaries
|                                      
|Income before income taxes            
|Income tax provision                  
|                                      
|Income before extraordinary loss      
|Cumulative effect of a change in      
|accounting principle                  
|                                      
|Net Income                            
|                                      

|Year Ended December 31, 2002          
|--------------------------------------
|
|Revenues                              
|Expenses                              
|                                      
|Income before                         
|Equity in net earnings of subsidiaries
|                                      
|Income before income taxes            
|Income tax (provision) benefit        
|                                      
|Net Income                            
|                                      

|Year Ended December 31, 2001          
|--------------------------------------
|
|Revenues                              
|Expenses                              
|                                      
|Income before                         
|Equity in net earnings of subsidiaries
|                                      
|Income (loss) before income taxes     
|Income tax provision                  
|                                      
|Net Income                            
|                                      

F-35

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

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

|Year Ended December 31, 2003          
|--------------------------------------
|
|Cash flow from operating activities   
|Cash flow (used) provided by investing
|activities                            
|Cash flow (used) provided by financing
|activities                            
|                                      
|Net increase in cash                  
|Cash at beginning of period           
|                                      
|Cash at end of period                 
|                                      

|Year Ended December 31, 2002          
|--------------------------------------
|
|Cash flow from operating activities   
|Cash flow (used) provided by investing
|activities                            
|Cash flow (used) provided by financing
|activities                            
|                                      
|Net increase (decrease) in cash       
|Cash at beginning of period           
|                                      
|Cash at end of period                 
|                                      

|Year Ended December 31, 2001          
|--------------------------------------
|
|Cash flow from operating activities   
|Cash flow (used) provided by investing
|activities                            
|Cash flow (used) provided by financing
|activities                            
|                                      
|Net increase (decrease) in cash       
|Cash at beginning of period           
|                                      
|Cash at end of period                 
|                                      

F-36

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

NOTE 17  SUMMARY OF
QUARTERLY DATA

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

|                                          | 2003
|----------------------------------------- | ----
|
|Revenues                                  |     
|Depreciation, depletion, amortization and |     
|accretion                                 |     
|Operating Profit                          |     
|Cost of early debt retirement             |     
|Cumulative effect of accounting change    |     
|Net Income                                |     
|Income per common share, basic            |     
|Income per common share, diluted          |     

|                                           | 2002
|------------------------------------------ | ----
|
|Revenues                                   |     
|Depreciation, depletion and amortization   |     
|Operating Profit                           |     
|Cost of early debt retirement              |     
|Provision for impairment of investment (a) |     
|Net Income                                 |     
|Income per common share, basic             |     
|Income per common share, diluted           |     

---

|(a) | Includes in 2002  provision for $621 thousand for the  impairment of equity  securities  deemed by management to have suffered
         an other than temporary  impairment.  We had previously  reported  losses in accumulated  other  comprehensive  income of $507
         thousand ($466 thousand net of income tax benefit) through December 31, 2001.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

F-37

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

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

Estimates of petroleum  reserves have been made by independent  engineers and company  employees.  These estimates  include reserves in
which we hold an economic interest under  production-sharing  and other types of operating  agreements.  These estimates do not include
probable or possible reserves.  The estimated net interests in Proved Reserves are based upon subjective  engineering judgments and may
be affected by the limitations  inherent in such  estimation.  The process of estimating  reserves is subject to continual  revision as
additional  information becomes available as a result of drilling,  testing,  reservoir studies and production history. There can be no
assurance  that such  estimates  will not be materially  revised in  subsequent  periods.  The  revisions of previous  estimates of our
proved oil and gas reserves  were  primarily  due to changes in commodity  prices at December  31,  2001,  2002 and 2003 that  impacted
whether such reserves were  economically  recoverable.  The impact of price changes  disproportionately  affects our long life reserves
because of the more gradual decline curve of the applicable production.

We adopted FASB Statement 143,  "Accounting for Asset  Retirement  Obligations"  ("FAS 143") January 1, 2003.  Among other things,  FAS
143 requires the  recognition of a liability for legal  obligations  associated with the retirement of long-lived  assets.  The initial
recognition of a liability for an asset  retirement  obligation  increases the carrying amount of the related  long-lived  asset by the
same amount as the  liability.  In periods  subsequent  to the  initial  measurement,  period-to-period  changes in the  liability  are
recognized  for passage of time in the form of accretion  expense as well as revisions to the original  estimate.  In  accordance  with
FAS 143, we recorded a liability of $30.4  million,  increased  costs  carried for our oil and gas  properties  by $25.4  million,  and
reduced our accumulated  depletion by $5.6 million.  During 2003, we incurred additional  liabilities of $2.7 million,  settled or sold
liabilities  of $1.2  million,  and recorded  accretion  expense of $2.5  million.  We have  included the initial  costs  recorded upon
adoption of FAS 143 as well as the costs  associated  with the  liabilities  incurred  during 2003 in the carrying value of our oil and
gas properties.  Our accumulated  depletion also reflects  initial  reduction as well as the depletion of these retirement costs during
2003. We have included the cost  associated with the liabilities  incurred during 2003 in our costs incurred  analysis.  Our results of
operations  include depletion on these retirement costs as well as the accretion  expense related to the liability,  and our discounted
cash flows presented include our estimated futures costs of retiring our oil and gas properties.

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

|                          | Oil
(Mbbl) | Gas
(MMcf)
|------------------------- | ---------- | ----------
|December 31, 2001         |            |           
|Proved Reserves           |            |           
|Proved Developed Reserves |            |           
|December 31, 2002         |            |           
|Proved Reserves           |            |           
|Proved Developed Reserves |            |           
|December 21, 2003         |            |           
|Proved Reserves           |            |           
|Proved Developed Reserves |            |           

F-38

The changes in proved reserves for
the years ended December 31, 2001, 2002 and 2003 were as follows:

|                              | Oil
(Mbbl) | Gas
(MMcf)
|----------------------------- | ---------- | ----------
|Reserves at December 31, 2000 |            |           
|                              |            |           
|Purchase of minerals-in-place |            |           
|Sale of minerals-in-place     |            |           
|Extensions and discoveries    |            |           
|Production                    |            |           
|Revisions of estimates        |            |           
|                              |            |           
|Reserves at December 31, 2001 |            |           
|                              |            |           
|Purchase of minerals-in-place |            |           
|Sale of minerals-in-place     |            |           
|Extensions and discoveries    |            |           
|Production                    |            |           
|Revisions of estimates        |            |           

|                              | Oil
(Mbbl) | Gas
(MMcf)
|----------------------------- | ---------- | ----------
|Reserves at December 31, 2002 |            |           
|                              |            |           
|Purchase of minerals-in-place |            |           
|Sale of minerals-in-place     |            |           
|Extensions and discoveries    |            |           
|Production                    |            |           
|Revisions of estimates        |            |           
|                              |            |           
|Reserves at December 31, 2003 |            |           
|                              |            |           

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, 2003, 2002 and
2001 were as follows (in thousands):

|                                                  | 2003 | 2002 | 2001
|------------------------------------------------- | ---- | ---- | ----
|Unproved oil and gas properties                   |      |      | $   
|Proved properties                                 |      |      |     
|                                                  |      |      |     
|Gross Capitalized Costs                           |      |      |     
|Accumulated depreciation, depletion, amortization |      |     
|and impairment                                    |      |      |     
|                                                  |      |      |     
|Net Capitalized Costs                             |      |      | $   
|                                                  |      |      |     

Capitalized  costs  incurred in oil and gas  producing  activities  during the years ended  December  31,  2003,  2002 and 2001 were as
follows (in thousands):

|                           | 2003 | 2002 | 2001
|-------------------------- | ---- | ---- | ----
|Property acquisition costs |      |      |     
|Proved properties          |      |      | $   
|Unproved properties        |      |      |     
|Exploration costs          |      |      |     
|Development costs          |      |      |     
|                           |      |      |     
|Total Costs Incurred       |      |      | $   
|                           |      |      |     

F-39

Results of operations from oil and
gas producing activities for the years ended December 31, 2003, 2002 and 2001 were as
follows (in thousands):

|                                                  | 2003 | 2002 | 2001
|------------------------------------------------- | ---- | ---- | ----
|Oil and gas production  revenue .                 |      |      | $   
|Production costs                                  |      |      |     
|Depreciation, depletion, amortization, impairment |      |     
|and accretion                                     |      |      |     
|Income taxes                                      |      |      |     
|                                                  |      |      |     
|Results of Operations for Producing Activities    |      |      | $   
|                                                  |      |      |     

The  standardized  measure of discounted  estimated  future net cash flows related to proved oil and gas reserves at December 31, 2003,
2002 and 2001 were as follows (in thousands):

|                                                         | 2003 | 2002 | 2001
|-------------------------------------------------------- | ---- | ---- | ----
|Future cash flows                                        |      |      | $   
|Future development costs                                 |      |      |     
|Future production costs                                  |      |      |     
|                                                         |      |      |     
|Future net cash flows, before income tax                 |      |      |     
|Future income taxes                                      |      |      |     
|                                                         |      |      |     
|Future Net Cash Flows                                    |      |      |     
|                                                         |      |      |     
|10% annual discount                                      |      |      |     
|                                                         |      |      |     
|Standardized Measure of Discounted Future Net Cash Flows |      |      | $   
|                                                         |      |      |     

The primary changes in the  standardized  measure of discounted  estimated future net cash flows for the years ended December 31, 2003,
2002 and 2001 were as follows (in thousands):

|                                                       | 2003 | 2002 | 2001
|------------------------------------------------------ | ---- | ---- | ----
|Purchases of minerals-in-place                         |      |      | $   
|Sales of minerals-in-place                             |      |      |     
|Extensions, discoveries and improved recovery,         |      |     
|less related costs                                     |      |      |     
|Sales of oil and gas produced, net of production costs |      |      |     
|Development costs incurred during the period           |      |      |     
|Revision of prior estimates:                           |      |     
|Net change in prices and costs                         |      |      |     
|Change in quantity estimates                           |      |      |     
|Accretion of discount                                  |      |      |     
|Net change in income taxes                             |      |      |     
|                                                       |      |      |     
|Net Change                                             |      |      | $   
|                                                       |      |      |     

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 our 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-40

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

None.

Item 9A. Controls and
Procedures

As of December 31, 2003, with the
participation of our management, our President and Chief Executive Officer and our Senior
Vice President and Chief Financial Officer carried out an evaluation of the effectiveness
of the design and operation of our disclosure controls and procedures pursuant to Rule
13a-15(b) of the Securities Exchange Act of 1934, as amended. Based upon that evaluation,
our President and Chief Executive Officer and our Senior Vice President and Chief
Financial Officer concluded that our disclosure controls and procedures were operating
effectively as of December 31, 2003.

There have been no changes in our
internal control over financial reporting, as defined in Rule 13a-15(f) of the Securities
Exchange Act, that occurred during the fiscal quarter ended December 31, 2003 that have materially
affected or are reasonably likely to affect our internal control over financial reporting.

50

PART III

Item 10. Directors and
Officers of the Registrant

The following table sets forth the
directors, executive officers and other significant employees, their ages, and all offices
and positions within the company. Our Bylaws divide the Board of Directors into three (3)
classes of directors serving staggered three-year terms, with one class to be elected at
each annual meeting.

|Name                  | Age | Title                                                                          
|--------------------- | --- | -------------------------------------------------------------------------------
|Gary C. Evans         | 46  | Chairman, President and Chief Executive Officer                                
|Richard R. Frazier    | 57  | Executive Vice President and Chief Operating Officer                           
|Chris Tong            | 47  | Senior Vice President and Chief Financial Officer                              
|R. Douglas Cronk      | 57  | Senior Vice President of Operations of Magnum Hunter Production, Inc. and Gruy 
|Charles R. Erwin      | 57  | Senior Vice President of Exploration of Magnum Hunter Production, Inc. and Gruy
|M. Bradley Davis      | 44  | Senior Vice President - Capital Markets & Corporate  Development               
|Morgan F. Johnston    | 43  | Senior Vice President, General Counsel and Secretary                           
|David S. Krueger      | 54  | Vice President and Chief Accounting Officer                                    
|Gregory L. Jessup     | 50  | Vice President Land - Offshore of Magnum Hunter  Production Inc. and Gruy      
|Richard S. Farrell    | 46  | Vice President Land - Onshore of Magnum Hunter  Production, Inc. and Gruy      
|David M. Keglovits    | 51  | Vice President and Controller                                                  
|Earl Krieg, Jr.       | 50  | Vice President of Engineering of Magnum Hunter   Production, Inc. and Gruy     
|Howard M. Tate        | 36  | Vice President of Finance                                                      
|Donald H. Sabathier   | 57  | Vice President Human Resources                                                 
|Gerald W. Bolfing     | 75  | Director                                                                       
|Jerry Box             | 65  | Director                                                                       
|Donald A. Erickson    | 60  | Director                                                                       
|James R. Latimer, III | 57  | Director                                                                       
|Matthew C. Lutz       | 69  | Director                                                                       
|Jody Powers           | 57  | Director                                                                       
|John H. Trescot, Jr.  | 79  | Director                                                                       
|James E. Upfield      | 83  | Director                                                                       

Gary C. Evans has served as President,  Chief Executive Officer and a director of Magnum Hunter  Resources,  Inc. since December 1995 and
Chairman and Chief Executive Officer of all of the Magnum Hunter  subsidiaries  since their formation or acquisition.  In 1985, Mr. Evans
formed the predecessor  company,  Hunter  Resources,  Inc., that was merged into and formed Magnum Hunter some ten years later. From 1981
to 1985,  Mr. Evans was  associated  with the  Mercantile  Bank of Canada where he held various  positions  including  Vice President and
Manager of the Energy  Division of the  Southwestern  United  States.  From 1978 to 1981, he served in various  capacities  with National
Bank of Commerce  (now  BancTexas,  N.A.)  including  Credit  Manager and Credit  Officer.  Mr. Evans serves on the Board of Directors of
Novavax,  Inc., a NASDQ listed  pharmaceutical  company. He additionally  serves on the board of two private  Texas-based  companies that
Magnum  Hunter owns an interest in,  including  (i) Swanson  Consulting  Services,  Inc., a  geological  consulting  firm and (ii) Metrix
Networks,  Inc., a company that provides web-enabled  automation to the oil and natural gas industry.  He also serves as a Trustee of TEL
Offshore Trust, a NASDQ listed oil and gas trust of which Magnum Hunter owns an approximate 29% interest.  Mr. Evans also serves on the Board
of Advisors of the Maguire Energy Institute at Southern Methodist University.

51

Officers

Richard R. Frazierhas served as Executive  Vice  President and Chief  Operating  Officer of Magnum Hunter since January 1, 2003. He also
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 EOG Resources) in Midland,  Texas. Mr. Frazier's  initial  employment,  from 1968 to 1971, was with Amerada Hess Corporation
as a petroleum  engineer  involved in numerous  projects in Oklahoma and Texas.  Mr.  Frazier  graduated in 1970 from the  University  of
Tulsa with a Bachelor of Science  Degree in  Petroleum  Engineering.  He is a registered  Professional  Engineer in Texas and a member of
the Society of Petroleum Engineers and many other professional organizations.

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

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

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

M. Bradley Davis has served as Senior Vice President - Capital  Markets & Corporate  Development  since  September 2002. Mr. Davis has 21
years of experience  and direct  involvement  in all facets of the energy  industry,  including  nine years as a Senior  Equity  Research
Analyst,  specializing in the  small-to-mid  capitalization  independent  exploration and production  sector.  Previously,  Mr. Davis was
Senior Vice President and Senior Energy Analyst for SWS Securities  (formerly Southwest  Securities),  a Dallas, Texas based full-service
investment  banking  firm.  Mr.  Davis also has been  affiliated  as a Senior  Energy  Analyst with CIBC World  Markets,  BT. Alex Brown,
Williams MacKay Jordan and Fitch Investors  Service.  Mr. Davis'  professional  background also includes ten years as an energy corporate
finance  specialist  with The Bank of New York and Texas  Commerce  Bancshares.  Mr.  Davis began his career in the  management  training
program of an internationally  focused offshore drilling contractor.  A native of Odessa,  Texas, Mr. Davis received his Bachelor of Arts
degree from Baylor University in 1981, majoring in Business Administration and Political Science (International Relations).

52

Morgan F. Johnston has served as Senior Vice  President,  General  Counsel and Secretary  since January 1, 2003. He previously  served as
the Company's  Vice  President and General  Counsel since April 1997. He also 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. and Digital  Communications  Technology
Corporation,  two American Stock Exchange  listed  companies.  He also  previously  served as 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.  He is a member of the  American  Society of Corporate
Secretaries and a member of the Texas General Counsel Forum.

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.  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.

Gregory L. Jessup has been Vice President Land - Offshore 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.

Richard S. Farrell  serves as Vice  President  Land - Onshore for Magnum  Hunter  Production,  Inc.,  a  wholly-owned  subsidiary  of the
company,  and Gruy since March  2002.  Mr.  Farrell  oversees a staff  responsible  for all of the  corporations  onshore  land,  A & D,
administrative  and some litigation  functions.  Prior to Magnum Hunter,  Mr. Farrell served as Land Manager,  then Vice President - Land
for Prize Energy Corp.  from July 1999 until March 2002.  From 1996 until  joining Prize Energy Corp.,  he was the Sr.  Division  Landman
and Team Leader for the South Texas  Business  Unit of Pioneer  Natural  Resources  USA,  Inc.  Prior to that time,  he held various land
related  positions  in both  large and small oil  companies,  including  Vice  President  - Land for  Rancho  Resources  Corporation  (an
independent oil and gas  exploration  company) and as Executive Vice President for its parent company,  Solaris Energy  Corporation.  Mr.
Farrell earned his Bachelor's Degree in marketing from the University of Richmond.

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

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

Howard M. Tate has served as Vice  President of Finance for the company since April 2002.  From 1999 until  joining  Magnum  Hunter,  Mr.
Tate had been at Marine Drilling  Companies,  Inc., and its successor Pride  International,  Inc.,  located in Houston,  Texas, where Mr.
Tate last  served as  Treasurer.  During the period  from  September  1995 until  August  1999,  Mr.  Tate served as Director - Corporate
Finance and other various  treasury  department  positions with Tejas Energy,  LLC (formerly Tejas Gas Corporation) and from January 1991
through September 1995, he worked as a Senior Project Finance Analyst with Tenneco Gas. Mr. Tate holds a Bachelor of Science  degree in Accounting  and Finance from Oklahoma  State  University  and a
Master of Business Administration from the University of Houston.

53

Donald H. Sabathierhas served as Vice  President of Human  Resources for the company since June 19, 2003.  From June 1998 until joining
Magnum Hunter,  Mr.  Sabathier was the director of Human Resources at North Western Energy.  Mr. Sabathier has also served as the Manager
for Compensation and Benefits for Helmerich & Payne, Inc., and as a Senior Internal  Compensation and International  Benefits  Consultant
for Occidental  Petroleum.  Mr. Sabathier holds a Bachelor of Science degree in Business  Administration from William Carey College and a
Master of  Business  Administration  from  Nicholls  State  University.  Mr.  Sabathier  is a member of the  Society  for Human  Resource
Management, the Dallas Human Resource Management Association and the SMU HR Roundtable.

Directors

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

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

Donald A.  Erickson has served as a Director of Magnum Hunter since  February 3, 2004.  Mr.  Erickson  spent nearly 20 years with Ernst &
Young,  LLC in their  corporate  finance  group.  During his career at Ernst & Young,  he was the National  Director of Valuation and the
market  leader for the  Southwest  Region  Valuation  Practice.  Mr.  Erickson's  responsibilities  included  the  valuation  of business
interests and intangible  assets.  Prior to his tenure at Ernst & Young.  Mr.  Erickson was a Vice  President for two national  valuation
firms and served as an officer in the United  States Army.  He retired from Ernst & Young in June 2003.  Currently,  Mr.  Erickson is the
President of Erickson  Partners,  LLC, a valuation  consulting and financial  advisory  firm. A 1965 graduate of Santa Clara  University,
with a B.S.C.  degree,  Mr. Erickson holds an M.B.A.  degree from the University of Oregon.  He is a graduate of the Ernst & Young Kellog
Executive  Program at  Northwestern  University.  Mr.  Erickson is an  Accredited  Senior  Appraiser  (ASA) with the American  Society of
Appraisers and has served as the National Chairman of its Business Valuation Committee.

James R.  Latimer,  IIIwas a director of Prize from October 2000 until the merger with Magnum  Hunter,  when he was elected to our board
of  directors.  Over the past  eight  years,  Mr.  Latimer  has been the  chairman  and chief  executive  officer  of  Explore  Horizons,
Incorporated,  a privately held exploration and production  company based in Dallas,  Texas.  Previously,  Mr. Latimer was co-head of the
regional  office of what is now The  Prudential  Capital  Group in  Dallas,  Texas,  which  handled  energy and other  financing  for The
Prudential  Insurance Company.  In addition,  Mr. Latimer's prior experience has included senior executive positions with several private
energy  companies,  consulting  with the firm of  McKinsey & Co.,  service as an officer in the United  States Army  Signal  Corps.,  and
several  directorships.  Mr. Latimer received a B.A. degree in economics from Yale University and an M.B.A. from Harvard  University.  He
is a Chartered Financial Analyst.

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

54

Jody  Powers  has  served as a  Director  of Magnum  Hunter  since  September  of 2003.  Mr.  Powers  spent 34 years of his  career  with
Halliburton  Company and  various  subsidiaries  with  increasing  levels of  domestic  and  international  management  responsibilities,
culminating  with his  retirement  in May 2002,  holding the  executive  position of President of  Halliburton  Energy  Services.  A 1968
graduate of the University of Houston,  Mr. Powers is a current member of the Society of Petroleum  Engineers and the 25 Year Club of the
Petroleum Industry.

John H.  Trescot,  Jr.  has served as a director  of Magnum  Hunter  since June 1997.  Mr.  Trescot is the  principal  of AWA  Management
Corporation,  a consulting firm specializing in project  evaluation.  Mr. Trescot began his professional career as an engineer with Shell
Oil Company.  Later,  Mr. Trescot joined Hudson Pulp & Paper Corp.  (now a part of  Georgia-Pacific  Corp.),  where he served 19 years in
various positions in woodlands and pulp and paper,  advancing to the position of senior vice president for its Southern  Operations.  Mr.
Trescot then became vice president of The Charter Company,  a multi-billion  dollar  corporation  with operations in oil,  communications
and  insurance.  In 1979,  Mr.  Trescot became the chief  executive  officer of JARI, a timber,  pulp and mining  operation in the Amazon
Basin of Brazil.  From 1982 through 1989,  while he was the chief executive  officer of TOT Drilling  Corp.,  TOT drilled many deep wells
in West Texas and New Mexico for major and  independent  oil  companies.  Mr. Trescot served as an officer in the United States Navy. Mr.
Trescot received his BME degree from Clemson University and his M.B.A. from Harvard University.

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

Audit Committee

The  members of our Audit  Committee  include  James R.  Latimer,  III,  Chairman,  James E.  Upfield,  Gerald W.  Bolfing  and Donald A.
Erickson.  Each member  possesses the required  level of financial  literacy and at least one member,  James R. Latimer,  III,  has been
determined by the Board to meet the
current  standards of the "audit  committee  financial  expert"  required by  applicable  rules and  regulations.  No member of the Audit
Committee  has any  relationship  to the company that may  interfere  with the exercise of their  independence  from  management  and the
company.

The Audit Committee selects the independent public accountants,  reviews
the independence of such accountants,  approves the scope of the annual audit,  approves the rendering of any material non-audit services
by the  independent  accountants,  approves  the fee payable to the  independent  accountants  and reviews the audit  results.  The Audit
Committee approves all fees paid to our principal accountants.

Code of Business Conduct and Ethics for Directors and Employees

We have adopted a code of business ethics for directors and employees (Code of Ethics),  and a separate code of financial  responsibility
for employees  responsible  for compiling our financial  statements,  including  our principal  executive  officer,  principal  financial
officer,  principal  accounting officer and persons  performing  similar  functions.  We have posted a copy of both of these codes on the
"Corporate  Governance"  section of our  Internet  website at  www.magnumhunter.com.  Any  waivers of these  codes must be  approved,  in
advance,  by our full Board of  Directors.  Any  amendments  to, or waivers from, these codes that apply to our  executive  officers  and
directors will be posted on the "Corporate Governance" section of our Internet website located at www.magnumhunter.com.

55

Item 11.  Executive Compensation

The following table contains  information with respect to all cash  compensation we paid or accrued during the past three fiscal years to
our Chief Executive Officer and each named person serving as an executive officer on December 31, 2003:

|Annual Compensation     | Long-Term Compensation
|----------------------- | ----------------------
|
|
|Gary C. Evans           |                       
|Chairman, President     |                       
|and CEO                 |                       
|Richard R. Frazier      |                       
|Executive V.P. and      |                       
|Chief Operating Officer |                       
|Chris Tong              |                       
|Senior V.P. and         |                       
|Chief Financial Officer |                       
|Charles R. Erwin        |                       
|Senior V.P. of Magnum   |                       
|Hunter Production, Inc. |                       
|R. Douglas Cronk        |                       
|Senior V.P. of Magnum   |                       
|Hunter Production, Inc. |                       
|Morgan F. Johnston      |                       
|Senior V.P., General    |                       
|Counsel & Secretary     |                       

---

|(a) | Consists of a vehicle allowance paid to the employee.
|--- | -----------------------------------------------------

|(b) | Consists of compensation for acting as an individual Trustee for the TEL Offshore Trust and employer contributions to the KSOP Plan.
|--- | ------------------------------------------------------------------------------------------------------------------------------------

|(c) | Consists of employer contributions to the KSOP Plan.
|--- | ----------------------------------------------------

|(d) | 2002 bonuses were not earned until March 2003.
|--- | ----------------------------------------------

|(e) | 2003 bonuses are not earned or paid until March 2004.
|--- | -----------------------------------------------------

|Option/SAR Grants in Last Fiscal Year
|-------------------------------------
|
|
|Gary C. Evans                        
|Richard R. Frazier                   
|Charles R. Erwin                     
|R. Douglas Cronk                     
|Chris Tong                           
|Morgan F. Johnston                   

---

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

56

|Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
|--------------------------------------------------------------------------------
|
|
|Gary C. Evans                                                                   
|Richard R. Frazier                                                              
|Charles R. Erwin                                                                
|R. Douglas Cronk                                                                
|Chris Tong                                                                      
|Morgan F. Johnston                                                              
|                                                                                

Compensation of Directors

We have nine individuals who serve as directors,  eight of which have
been determined by the Board to be independent.  One director  receives  compensation with respect to
his services and in his capacities as an executive  officer of the company,  and no additional  compensation has historically been paid
for his services as a director.  The other eight  directors  were not employees at December 31, 2003, and receive no  compensation  for
their services as directors other than as stated below.  For fiscal year 2003,  independent  directors  received a $20,000 retainer for
being a board  member and received  $1,000 per regular and  committee  meeting  attended.  In  addition,  for the fiscal year 2003 each
independent  director was granted stock  options to acquire  5,100 shares of our common stock at an exercise  price of $5.92 per share.
Finally,  all  chairpersons of our board of directors'  committees  received an annual retainer of $2,500 for acting as chairman of his
respective  committee.  For fiscal year 2004,  independent  directors  will receive a $26,000  retainer  (pro-rated)  for being a board
member and, in addition,  will receive $1,000 per meeting attended and $1,000 per committee meeting  attended.  All chairpersons of our
board of directors'  committees  will receive an annual  retainer of $2,500 for acting as chairman of his respective  committee.  Other
than the compensation  stated herein, we have not entered into any arrangement,  including  consulting  contracts,  in consideration of
the director's service on the board.

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

Mr. Gary C. Evans,  Mr. Richard R. Frazier,  Mr. Chris Tong, Mr. R. Douglas Cronk, Mr. Charles R. Erwin and Mr. Morgan F. Johnston each
have  employment  agreements  with the  company.  Mr.  Evans'  agreement  terminates  January  1, 2006 and  continues  thereafter  on a
year-to-year  basis and provides for a salary of $300,000 per annum,  unless  increased by the Board.  Mr.  Evans'  salary for the year
2004 is $438,000.  Mr. Frazier's  agreement  terminates  January 1, 2006 and continues  thereafter on a year-to-year basis and provides
for a salary of $175,000 per annum unless  increased  by the Board.  Mr.  Frazier's  salary for the year 2004 is $280,000.  Mr.  Tong's
agreement  terminates  January 1, 2006 and  continues  thereafter  on a  year-to-year  basis and  provides for a salary of $190,000 per
annum,  unless increased by the Board. Mr. Tong's salary for the year 2004 is $210,000.  Mr. Cronk's  agreement  terminates  January 1,
2006 and  continues  thereafter  on a  year-to-year  basis and  provides for a salary of $167,500  per annum,  unless  increased by the
Board. Mr. Cronk's salary for the year 2004 is $185,000.  Mr. Erwin's  agreement  terminates  January 1, 2006 and continues  thereafter
on a  year-to-year  basis and provides for a salary of $185,000 per annum unless  increased by the Board.  Mr.  Erwin's  salary for the
year 2004 is $210,000.  Mr.  Johnston's  agreement  terminates  January 1, 2006 and continues  thereafter on a  year-to-year  basis and
provides for a salary of $180,000 per annum unless increased by the Board.  Mr.  Johnston's  salary for the year 2004 is $180,000.  All
of the  agreements  provide  that the same  benefits  supplied to other  company  employees  shall be available  to the  employee.  The
employment  agreements  also contain,  among other  things,  covenants by the employee  that in the event of  termination,  he will not
compete  with the company in certain  geographical  areas or hire any of our  employees  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,  the employee's  position is terminated,  or the
employee  leaves for "good cause",  the employee is entitled to receive  immediately,  in one lump sum,  certain  compensation.  In the
case of Mr. Evans and Mr.  Frazier,  the employee  shall receive  three times the  employee's  current base salary and bonus,  plus any
other  compensation  received by him in the last fiscal year.  In the case of Mr. Tong,  Mr.  Cronk,  Mr. Erwin and Mr.  Johnston,  the
employee shall receive two times the employee's base salary and bonus, plus any other  compensation  received by him in the last fiscal
year.  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.  We also have key man life insurance on Mr. Evans in the amount of $12,000,000.

57

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The  following  table sets forth certain  information  as of March 1, 2004,  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 five 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 1, 2004,  owned any shares of the company's  Series A Preferred  Stock or its 1996 Series A  convertible  preferred
stock.  The business  address of each officer and director  listed below is: c/o Magnum Hunter  Resources,  Inc.,  600 East Las Colinas
Blvd., Suite 1100, Irving, Texas 75039.

|                                                | Common Stock Beneficially Owned
|----------------------------------------------- | -------------------------------
|
|Directors and Executive Officers                |                                
|Gary C. Evans                                   |                                
|Richard R. Frazier                              |                                
|Chris Tong                                      |                                
|Charles R. Erwin                                |                                
|R. Douglas Cronk                                |                                
|Morgan F. Johnston                              |                                
|Gerald W. Bolfing                               |                                
|Jerry Box                                       |                                
|Donald A. Erickson                              |                                
|James R. Latimer, III                           |                                
|Matthew C. Lutz                                 |                                
|Jody Powers                                     |                                
|John H. Trescot, Jr                             |                                
|James E. Upfield                                |                                
|All directors and executive officers as a group |                                
|(14 persons)                                    |                                
|Beneficial owners of 5 percent or more          |                                
|(excluding persons named above)                 |                                
|Dimensional Fund Advisors, Inc.                 |                                
|1299 Ocean Avenue, 11th Floor                   |                                
|Santa Monica, CA 90401                          |                                

---

* Less than one percent.

|(a) | Includes 898,000 shares of common stock issuable upon the exercise of certain
currently exercisable options.  Also includes 790,151 common stock purchase warrants, which are currently exercisable.  Also includes 17,024 Jacquelyn
Evelyn Enterprises, Inc., a corporation whose sole shareholder is Mr. Evans' wife.  Mr. Evans disclaims any ownership in such securities other than those in which he has an
economic interest.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(b) | Includes 410,000 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | ------------------------------------------------------------------------------------------------------------

|(c) | Includes 214,500 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | ------------------------------------------------------------------------------------------------------------

|(d) | Includes 274,000 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | ------------------------------------------------------------------------------------------------------------

|(e) | Includes 167,500 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | ------------------------------------------------------------------------------------------------------------

|(f) | Includes 145,000 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | ------------------------------------------------------------------------------------------------------------

|(g) | Includes 40,100 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | -----------------------------------------------------------------------------------------------------------

|(h) | Includes 36,100 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | -----------------------------------------------------------------------------------------------------------

|(i) | Includes 13,100 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | -----------------------------------------------------------------------------------------------------------

|(j) | Includes 178,100 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | ------------------------------------------------------------------------------------------------------------

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

|(l) | Includes 36,100 shares of common stock issuable upon the exercise of certain currently exercisable options.Also includes 4,833 shares held in the name of Nancy J. Trescot, Mr. Trescot's wife.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(m) | Includes 36,100 shares of common stock issuable upon the exercise of certain currently exercisable options.
|--- | -----------------------------------------------------------------------------------------------------------

58

|(n) | Percentage is  calculated on the number of shares  outstanding  plus those shares deemed  outstanding  under Rule 13d-3(d) (l) under the Exchange Act.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------

|(o) | Based on Schedule 13G filed by Dimensional Fund Advisors, Inc. on February 6, 2004.
|--- | -----------------------------------------------------------------------------------

Item 13.  Certain Relationships and Related Transactions

There are no loans or extensions of credit to directors and executive officers of Magnum Hunter as of December 31, 2003.

Item 14.  Principal Accountant Fees and Services

|                   | For the Year Ended December 31,
|------------------ | -------------------------------
|
|Audit(a)           |                                
|Audit-Related Fees |                                
|Tax Fees           |                                
|All Other Fees (b) |                                
|                   |                                
|                   |                                
|                   |                                

---

|(a) | Includes fees paid to Deloitte&Touche for final audits related to the Prize merger during 2002.
|--- | -----------------------------------------------------------------------------------------------

|(b) | Consists of fees paid to Deloitte &Touche for annual audits of Teal Hunter, LP and Mallard Hunter, LP, of which Magnum Hunter is
the 5% and 1% general partner, respectively.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The Audit Committee generally makes  recommendations to the Board regarding the selection of the independent public accountants,  reviews
the independence of such accountants,  approves the scope of the annual audit,  approves the rendering of any material non-audit services
by the  independent  accountants,  approves  the fee payable to the  independent  accountants  and reviews the audit  results.  The Audit
Committee approves all fees paid to our principal accountants.

59

GLOSSARY

As used in this document:

| |  | "Mcf" means thousand cubic feet;
| | - | --------------------------------

| |  | "MMcf" means million cubic feet;
| | - | --------------------------------

| |  | "Bcf" means billion cubic feet;
| | - | -------------------------------

| |  | "Bbl" means barrel;
| | - | -------------------

| |  | "MBbls" means thousand barrels;
| | - | -------------------------------

| |  | "MMBbls" means million barrels;
| | - | -------------------------------

| |  | "BOE" means barrel of oil equivalent;
| | - | -------------------------------------

| |  | "MMBOE" means million barrels of oil equivalent;
| | - | ------------------------------------------------

| |  | "Btu" or  "British  Thermal  Unit"  means the  quantity of heat  required  to raise the  temperature  of one pound of water by
       one degree Fahrenheit;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  | "MMBtu" means million British Thermal Units;
| | - | --------------------------------------------

| |  | "Mcfe" means thousand cubic feet of natural gas equivalent;
| | - | -----------------------------------------------------------

| |  | "MMcfe" means million cubic feet of natural gas equivalent; and
| | - | ---------------------------------------------------------------

| |  | "Bcfe" means billion cubic feet of natural gas equivalent.
| | - | ----------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

60

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

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

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

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

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

61

Item 15.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K

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

|                                                                                                 | 
|------------------------------------------------------------------------------------------------ | 
|1      Financial Statements                                                                      | 
|Independent Auditors' Report                                                                     | 
|Financial Statements:                                                                            | 
|Consolidated Balance Sheets at December 31, 2003 and 2002                                        | 
|Consolidated Statements of Operations                                                            | 
|For the Years Ended December 31, 2003, 2002 and 2001                                             | 
|Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss)                  | 
|For the Periods Ended December 31, 2003, 2002 and 2001                                           | 
|Consolidated Statements of Cash Flows                                                            | 
|For the Years Ended December 31, 2003, 2002 and 2001                                             | 
|Notes to Consolidated Financial Statements                                                       | 
|Supplemental Information on Oil and Gas Producing Properties (Unaudited)                         | 
|2     Financial Statement Schedule                                                               | 
|We have included on Page 65 of this Annual Report on Form 10-K, Financial Statement Schedule II, | 
|Valuation and Qualifying Accounts                                                                | 

62

(a) Exhibits

|Number    | Description of Exhibit                                                                                                                                                                                                                          
|--------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1 & 4.1 | Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-18, File No. 33-30298-D).                                                                                                                              
|3.2 & 4.2 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year ended December 31, 1990).                                                                                                               
|3.3 & 4.3 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on Form SB-2, File No. 33-66190).                                                                                                       
|3.4 & 4.4 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453).                                                                                                       
|3.5 & 4.5 | Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year ended December 31, 2001).                                                                                                               
|3.6 & 4.6 | By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File No. 33-66190).                                                                                                                                      
|3.7 & 4.7 | Amendment to By-Laws (Incorporated by reference to Registration Statement on Form S-4, File No. 333-76774).                                                                                                                                     
|3.8 & 4.8 | Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated December 26, 1996, filed January 3, 1997).                                                                                             
|3.9 & 4.9 | Amendment to Certificate of Designation for 1996 Series A Convertible Preferred Stock (Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453).                                                                    
|4.10      | Form of Warrant Agreement by and between Magnum Hunter Resources, Inc. and American Stock Transfer & Trust Company, as warrant agent (Incorporated by reference to Registration Statement on Form S-3, File No. 333-82552).                     
|4.11      | Indenture, dated March 15, 2002, between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Bankers Trust Company, as Trustee (Incorporated by reference to Form 10-K for the year ended December 31, 2001).            
|4.12      | Form of 9.6% Senior Note due 2007 (included in Exhibit 4.11).                                                                                                                                                                                   
|4.13*     | Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as Trustee.                                                                          
|4.14*     | Form of Floating Rate Convertible Senior Notes due 2023 (included in Exhibit 4.13).                                                                                                                                                             
|4.15      | Shareholder Rights Agreement dated as of January 6, 1998 by and between Magnum Hunter Resources, Inc. and Securities Transfer Corporation, as Rights Agent (Incorporated by reference to Form 8-K dated January 7, 1998, filed January 9, 1998).
|10.1      | Fourth Amended and Restated Credit Agreement dated March 15, 2002, as amended, between Magnum Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the year ended December 31, 2001).            
|10.2*     | First Amendment to Fourth Amended and Restated Credit Agreement, dated April 19, 2002 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                                    
|10.3*     | Second Amendment to Fourth Amended and Restated Credit Agreement, dated July 3, 2002 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                                     
|10.4*     | Third Amendment to Fourth Amended and Restated Credit Agreement, dated August 28, 2002 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                                   
|10.5*     | Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated September 6, 2002 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                                
|10.6*     | Waiver and Fifth Amendment to Fourth Amended and Restated Credit Agreement, dated November 20, 2002 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                      
|10.7*     | Waiver and Sixth Amendment to Fourth Amended and Restated Credit Agreement, dated May 2, 2003 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                            
|10.8*     | Seventh Amendment to Fourth Amended and Restated Credit Agreement, dated August 8, 2003 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                                  
|10.9*     | Waiver and Eighth Amendment to Fourth Amended and Restated Credit Agreement, dated October 31, 2003 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                      
|10.10*    | Ninth Amendment to Fourth Amended and Restated Credit Agreement, dated December 10, 2003 between Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al.                                                                 

63

|10.11  | Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1999, filed March 30, 2000).                                                                                               
|------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.12  | Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1999, filed March 30, 2000).                                                                                          
|10.13  | Employment Agreement for Chris Tong (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 2002)                                                                                                                         
|10.14  | Employment Agreement for R. Douglas Cronk (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 2002).                                                                                                                  
|10.15  | Employment Agreement for Charles Erwin (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 2002).                                                                                                                     
|10.16* | Employment Agreement for Morgan F. Johnston.                                                                                                                                                                                                   
|10.17   | Purchase and Sale Agreement, dated February 27, 1997 among Burlington Resources Oil and Gas Company, Glacier Park Company and Magnum Hunter Production, Inc. (Incorporated by reference to Form 8-K, dated April 30, 1997, filed May 12, 1997).
|10.18   | Purchase and Sale Agreement dated November 25, 1998, between Magnum Hunter Production, Inc. and Unocal Oil Company of California (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1998, filed April 14, 1999).     
|10.19   | Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by reference to Form 10-Q/A for the period ended June 30, 2000, filed November 3j0, 2000).                                                          
|21      | Subsidiaries of the Registrant (Incorporated by reference to Form 10-K for the period ended December 31, 2001.                                                                                                                                 
|23.1*   | Consent of Deloitte & Touche LLP                                                                                                                                                                                                               
|31.1*   | Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Gary C. Evans                                                                                                                                                   
|31.2*   | Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Chris Tong                                                                                                                                                      
|32.1*   | Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002 signed by Gary C. Evans                                                                                                                                                    
|32.2*   | Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002 signed by Chris Tong                                                                                                                                                       

---

* Filed herewith

 Management contract or compensatory plan identified as required by Item 15(a)(3) of Form 10-K.

(a)         Reports on Form 8-K

During the three months ended December 31, 2003, we furnished the following Current Report on Form 8-K:

| |  | Current Report furnished November 4, 2003, reporting Items 7 and 12.
| | - | --------------------------------------------------------------------

| |  | Current Report furnished December 10, 2003, reporting Items 5 and 7.
| | - | --------------------------------------------------------------------

| |  | Current Report furnished December 11, 2003, reporting Items 5 and 7.
| | - | --------------------------------------------------------------------

| |  | Current Report furnished December 17, 2003, reporting Items 5 and 7.
| | - | --------------------------------------------------------------------

| |  | Current Report furnished December 22, 2003, reporting Items 5 and 7.
| | - | --------------------------------------------------------------------

64

MAGNUM HUNTER RESOURCES, INC.
     SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTSFOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2003
      (in thousands)

|                                                             | Additions | 
|------------------------------------------------------------ | --------- | 
|
|Year Ended December 31, 2003                                 |           | 
|Allowance for Doubtful Accounts on Trade Accounts Receivable |           | 
|Reserve on Current Portion of Long-term Notes Receivable     |           | 
|Reserve on Investment in Unconsolidated Affiliate            |           | 
|Year Ended December 31, 2002                                 |           | 
|Allowance for Doubtful Accounts on Trade Accounts Receivable |           | 
|Reserve on Current Portion of Long-term Notes Receivable     |           | 
|Reserve on Investment in Unconsolidated Affiliate            |           | 
|Year Ended December 31, 2001                                 |           | 
|Allowance for Doubtful Accounts on Trade Accounts Receivable |           | 
|Reserve on Current Portion of Long-term Notes Receivable     |           | 
|Reserve on Investment in Marketable Securities               |           | 
|Reserve on Investment in Unconsolidated Affiliate            |           | 

---

(1)    
          Allowances acquired in Prize merger during 2002 and Metrix acquisition during
          2003. (2)     Write-offs

65

SIGNATURES

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

|MAGNUM HUNTER RESOURCES, INC.By:   /s/ Gary C. Evans      Gary C.  Evans, Chairman, President      and Chief Executive Officer | March 15, 2004
|------------------------------------------------------------------------------------------------------------------------------ | --------------

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

|Signature                 | Title                               | Date          
|------------------------- | ----------------------------------- | --------------
|/s/ Gary C. Evans         | Chairman, President and             | March 15, 2004
|Gary C. Evans             | Chief Executive Officer            
|/s/ Chris Tong            | Senior Vice President and           | March 15, 2004
|Chris Tong                | Chief Financial Officer            
|/s/ Morgan F. Johnston    | Sr. Vice President, General Counsel | March 15, 2004
|Morgan F. Johnston        | and Secretary                      
|/s/ David S. Krueger      | Vice President and                  | March 15, 2004
|David S. Krueger          | Chief Accounting Officer           
|/s/ Gerald W. Bolfing     | Director                            | March 15, 2004
|Gerald W. Bolfing        
|/s/ Jerry Box             | Director                            | March 15, 2004
|Jerry Box                
|/s/ Donald A. Erickson    | Director                            | March 15, 2004
|Donald A. Erickson       
|/s/ James R. Latimer, III | Director                            | March 15, 2004
|James R. Latimer, III    
|/s/ Matthew C. Lutz       | Director                            | March 15, 2004
|Matthew C. Lutz          
|/s/ Jody Powers           | Director                            | March 15, 2004
|Jody Powers              
|/s/ John H. Trescot, Jr.  | Director                            | March 15, 2004
|John H. Trescot, Jr      
|/s/ James E. Upfield      | Director                            | March 15, 2004
|James E. Upfield         

66