# 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, 2004                    
|[     ] | 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, 2004, 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 $876,699,492.

The number of shares outstanding of the registrant's common stock at March 7, 2005 was 88,013,002.

TABLE OF CONTENTS Securities and Exchange
Commission Item Number and
Description

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PART I SPECIAL NOTE REGARDING
FORWARD-LOOKING STATEMENTS

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

 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.

As part of this strategy, from 1996
through 2004, 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), Mallon
Resources Corporation (Mallon) and Tom Brown, Inc. (Tom Brown), a
subsidiary of EnCana Corporation. 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.

1

Additionally, we own and operate five
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, 2004, Magnum Hunter
had an interest in 6,109 wells and had estimated proved reserves of 1.01 Tcfe.
Approximately 73% of these reserves were proved developed reserves. The proved reserves
have a geographic breakdown as follows: 25% attributable to the Mid-Continent Region, 59%
attributable to the Permian Basin Region, 8% attributable to the Gulf Coast Region and 8%
attributable to the Gulf of Mexico. At December 31, 2004, our proved reserves had an
estimated reserve life of approximately 12.5 years and were 61% natural gas. The company
serves as operator for approximately 78% of our properties, based on the gross number of
wells in which we own an interest.

Recent Announcement To Be
Acquired by Cimarex Energy

On January 26, 2005, Magnum Hunter
and Cimarex Energy, Inc. (Cimarex) announced that their respective boards of
directors had approved an agreement and plan of merger that provides for the acquisition
of Magnum Hunter by Cimarex. Closing is anticipated before the end of the second quarter
in 2005, subject to customary regulatory approvals.

Under the terms of the proposed
agreement, Magnum Hunter shareholders will receive 0.415 shares of Cimarex common stock
for each share of Magnum Hunter common stock that they own. The merger is expected to be
non-taxable to the shareholders of both companies. In addition to the merger consideration
and prior to closing, Magnum Hunter intends to distribute its ownership interest in TEL
Offshore Trust to its common stockholders as a special dividend.

Cimarex Energy Co., headquartered in
Denver, CO, is an independent oil and gas exploration and production company with
operations focused in the Mid-Continent and Gulf Coast areas of the U.S. Its principal
operations offices are located in Tulsa, New Orleans and Houston.

In connection with the proposed
acquisition, Cimarex and Magnum Hunter have filed relevant materials with the SEC,
including one or more registration statement(s) that contain a prospectus and a joint
proxy statement. Investors and security holders of Cimarex and Magnum Hunter are urged to
read these documents and any other relevant documents filed with the SEC, as well as any
amendments or supplements to those documents, because they will contain important
information about Cimarex, Magnum Hunter and the merger.Investors and security holders
may obtain these documents (and any other documents filed by Cimarex and Magnum Hunter
with the SEC) free of charge at the SECs website at www.sec.gov. In addition, the
documents filed with the SEC may be obtained free of charge (i) at www.cimarex.com or
www.magnumhunter.com or (ii) by directing a request to Mary Kay Rohrer, Assistant
Corporate Secretary, Cimarex Energy Co., phone: 303-295-3995, fax: 303-295-3494; or Morgan
F. Johnston, Corporate Secretary, Magnum Hunter Resources, Inc., phone: 972-401-0752, fax:
972-443-6487. Investors and security holders are urged to read the joint proxy
statement/prospectus and the other relevant materials before making any voting or
investment decision with respect to the proposed acquisition.

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.

2

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.

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, 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 72% of
the estimated reserves are natural gas and 28% are oil and natural gas liquids located on
approximately 263,216 net mineral leasehold acres in twenty-seven counties in Oklahoma,
eleven counties in Texas and two counties in Arkansas. As of December 31, 2004, DeGolyer
and MacNaughton (D&M) and Cawley, Gillespie & Associates, Inc.
(Cawley Gillespie), independent reservoir engineers, have estimated the
Mid-Continent properties proved reserves at 12.1 MMBbl of oil and natural gas liquids and
182.8 Bcf of natural gas, or, on a natural gas equivalent basis, 255.6 Bcfe. Total net
daily production from the Mid-Continent properties for the month of December 2004 was 34.9
MMcf/d for natural gas and 1,273 Bbl/d of oil and natural gas liquids or 42.5 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 Red Deer Creek Field, the Madill Field and the Eola-Robberson Field.

Panoma.    
          The Panoma properties currently consist of approximately 544 natural gas wells
          in the 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 2004, net
          natural gas sales were approximately 9.0 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.

3

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 14 of these
          wells. For the month of December 2004, net production from the field averaged
          6,399 Mcf/d and 380 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 100%. We
          operate all but 10 of these wells. For the month of December 2004, net
          production from the field averaged 6,061 Mcf/d and 144 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 2004, net production from the
wells averaged 86 Mcf/d and 568 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 2004, net production from the
          wells averaged 1,202 Mcf/d and 56 Bbl/d.

Red Deer Creek.     The Red Deer Creek
Field and the adjoining Shriekey West Field are located in Roberts County, Texas in the
Texas Panhandle. Initial production was established in 1958 in the Lower Albany Dolomite
and subsequent successful completions were made in the Wolfcamp, Granite Wash, and Morrow.
Producing depths range from 4,100 ft. to 11,000 ft. There are currently 27 active
wellbores with working interest ownerships ranging from 53% to 100%. During 2004, these
fields benefited from 11 recompletions in the Granite Wash. The Red Deer Creek Field has
been re-spaced to 40 acres and a drilling program is slated to begin in 2005 with the
Granite Wash as its target. For the month of December 2004, net production from these
wells averaged 2,632 Mcf/d and 25 Bbl/d.

Permian Basin

The companys Permian Basin
operations include assets located in West Texas and Southeastern New Mexico with an
interest in 3,840 wells located in 240 different fields. Magnum Hunters wholly-owned
subsidiary, Gruy Petroleum, 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, 2004, the Permian Basin properties had proved reserves of 48.9 MMBbl of oil
and 299.5 Bcf of natural gas, or on a natural gas equivalent basis, 592.8 Bcfe. Total net
daily production from the Permian Basin properties for the month of December 2004 was
approximately 60,269 Mcf/d of natural gas an 7,451 Bbls/d of oil or 104.9 MMcfe/d.

4

In evaluating the Permian Basin
properties, Magnum Hunter has identified 509 drilling locations including developmental
production and injection wells. The top valued fields in the Permian Basin are Spraberry,
Westbrook, Warwink, Howard Glasscock, Jo-Mill, Kermit, Keystone, Willo, P&P and the
Southeast New Mexico area.

Spraberry.    
          The Spraberry field is located in Irion, Glasscock and Reagan Counties, Texas.
          The company owns interest in 309 oil and gas wells. Gruy Petroleum operates 98%
          of the wells in this field. The NG Tex acquisition in 2004 added several
          operated wells to the companys existing position in the Spraberry trend.
          For the month of December 2004, the companys net production in this field
          averaged 344 Bbl/d and 2,685 Mcf/d.

The wells in this field produce from
the Spraberry formation at approximately 6,000 feet D&M has identified 88 infill PUD
locations with net reserves of 30.7 Bcfe. The company has several wells budgeted for 2005
in this trend.

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 Enervest operated North Westbrook Unit. As of December 31, 2004,
          there were 122 active wells in these three leases. For the month of December
          2004, net production from the wells averaged 823 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 52 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 2004, the companys net production from these wells averaged
          324 Bbl/d and 1,003 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 175 wells, of which 93% 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 2004, the
companys net production from these wells averaged 640 Bbl/d for oil, and 109 Mcf/d
for gas.

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 5% to 33% in three different
          waterflood units. The companys net production from these three units
          averaged 671 Bbl/d and 243 Mcf/d in December of 2004.

These fields were unitized between
1963 and 1973 and were initially waterflooded on a peripheral pattern with 80 acre
spacing. From the mid 70s to the 90s, multiple infill wells were drilled to
convert the floods to a line drive pattern on 40 acre spacing. In 2000, ChevronTexaco
started drilling 20 acre infill wells in their operated Jo-Mill Unit. D&M has assigned
net proved undeveloped reserves of 8,392 MMcfe to an additional 120 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 191 oil and gas wells with a working interest varying from 21%
          to 100%. Gruy operates 89% of the wells in this field. The average December 2004
          net production from these wells was 169 Bbl/d and 3,521 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.

5

Keystone.    
          The Keystone field is located in Winkler County, Texas. The company owns an
          interest in 248 oil and gas wells of which 99.9% are operated by Gruy. These
          wells produced an average of 296 Bbl/d and 406 Mcf/d net in December 2004.

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 most parts of the field.

Willo.    
          The Willo field is located in Crockett and Val Verde Counties, Texas. The
          company owns an interest in 17 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 2004 for these wells was
          2,129 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 94% of the 8.9 MMcfe net
          proved developed producing reserves assigned to this field by D&M. Proved
          undeveloped reserves of 17.0 MMcfe net for four 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 350 Bbl/d in December of 2004. 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 1,100 wells in Chaves, Lea, and Eddy
Counties, of which 71% 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 2004 was 1,915 Bbl/d and 42,784 Mcf/d.

The company has been actively
drilling increased density wells in the Morrow formation at approximately 11,500 feet. The
company participated in 34 Morrow wells in 2004 and has 23 operated wells planned for
2005. D&M has identified 93 proved undeveloped locations for the Morrow, with net
reserves of 64.8 BCFe.

Several of the Morrow wells have
identified proved developed non-producing areas in the Atoka and Strawn formations. The
Encana acquisition that closed in 2004 greatly increased the Companys upside
potential in S. E. New Mexico.

Gulf Coast

We own an interest in 360 wells in
the Gulf Coast region, of which Gruy is the operator of approximately 71% 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, 2004, the Gulf Coast properties
had proved reserves of 2.0 MMBbl of oil and 63.7 Bcf of natural gas, or on a natural gas
equivalent basis, 75.6 Bcfe. Approximately 84% of the estimated reserves are natural gas
and 16% are oil. Total net daily production from the Gulf Coast properties for the month
of December 2004 was approximately 20.1 MMcf/d of natural gas and 566 Bbls/d of oil.

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

Buchel.    
          The company operates eight producing wells 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 1,567 Mcf/d and 17 Bbl/d in
          December 2004 net to the companys interest. Net proved reserves for this
          field were 10.4 Bcfe as of December 31, 2004.

6

Provident City.    The company owns
varying working interests, between 2% and 100%, in 15 wells in this field located in
Lavaca County, Texas. Five of the wells are company operated. Production is primarily from
the Wilcox formation at 8,500 feet to 17,500 feet. Production attributable to the
companys interest averaged 1,747 Mcf/d and 9 Bbl/d in December 2004. As of December
31, 2004, the net proved reserves assigned to this field were 5.2 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 1,925 Mcf/d and 130 Bbl/d in December 2004. As of
December 31, 2004, the net proved reserves assigned to this field were 6.5 Bcfe.

Brazil.    
          The company owns varying working interests, between 30% and 50%, in eight
          producing wells in this field located in McMullen County, Texas. Six of the
          wells are company operated. Production is primarily from the Wilcox formation at
          9,000 feet to 13,000 feet. Production attributable to the companys
          interest averaged 8,505 Mcfd and 21 Bbl/d in December 2004. The company drilled
          and completed three new wells in this area in 2004 and is in the process of
          drilling a fourth. As of December 31, 2004, the net proved reserves assigned to
          this field were 7.5 Bcfe.

Word, North.     We own varying working
interests, between 4% and 100%, in 21 wells in this field located in Lavaca County, Texas.
Eighteen of the wells are operated by the Company. Production is from the Edwards
formation at approximately 14,000 feet and averaged 1,121 Mcf/d and 17 Bbl/d in December
2004 net to our interest. Net proved reserves for this field were 9.5 Bcfe as of December
31, 2004.

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 245 blocks in the Gulf of Mexico ranging from 12.5% to 100%.
Proved reserves have been assigned in 55 blocks encompassing 85 gross wells (29.7 net
wells). The company operates 16 of these wells (10.1 net wells). According to D&M, as
of December 31, 2004, the Gulf of Mexico properties had proved reserves of 3.1 MMBbl of
oil and 64.1 Bcf of natural gas (82.6 Bcfe). Approximately 78% of the estimated reserves
are natural gas and the remaining 22% is oil. Total net daily production from the Gulf of
Mexico properties for the month of December 2004 was 53.4 MMcf/d of natural gas and 2,121
Bbls/d of oil. At December 31, 2004, the company had nine additional discoveries that
commenced production in 2005.

Ship Shoal 358.     The company owns
varying working interests, between 15% and 39.2%, in four wells operated by ATP Oil &
Gas. Production is from Upper Pliocene sands at approximately eight to nine thousand feet.
The wells are located in Federal waters south of Terrebonne Parish, Louisiana in a water
depth of 420 feet. Production from the first well was initiated in March 2004. Subsequent
wells were put on production as they were completed. Production from all the wells
attributable to the companys interest averaged 3,397 Mcfd and 270 Bbls/d in December
2004. As of December 31, 2004, the net proved reserves for Ship Shoal 358 were 5.1 Bcfe.

Vermilion 241.     Our interest in
Vermilion 241 consists of a 50% working interest in one well operated by Remington Oil
& Gas. Production is from the Bul 1 Sand at approximately 11,000 feet. The field is
located in 115 feet of water on Federal leases south of Vermilion Parish, Louisiana. First
production was established in July 2004 and averaged 1,850 Mcfd and 56 Bbls/d in December
2004, net to our interests. The net proved reserves attributable to this well were 3.7
Bcfe as of December 31, 2004.

West Cameron 458 Area.     This area
encompasses West Cameron blocks 457 and 458. We own a 40% working interest in one subsea
completion and four additional wells drilled from the platform located in Block 458.
Remington Oil & Gas operates the field which is located in 117 feet of water on
Federal leases south of Cameron Parish, Louisiana. The initial well started production in
July 2004 with the last well coming on in October 2004. Production is from the Lentic 1
and Basal Nebraskan zones ranging in depths from 7,400 feet to 12,000 feet. Net to our
interest, production averaged 7,227 Mcfd and 2 Bbls/d in December 2004. Net proved
reserves for the West Cameron 458 Area were 3.8 Bcfe as of December 31, 2004.

Main Pass 107.     Main Pass 107 is
operated by Kerr McGee and is located on Federal leases in 52 feet of water east of
Plaquemines Parish, Louisiana. The companys ownership consists of a 50% working
interest in one well producing from the Tex W 1 at approximately 11,400 feet. The well
also has numerous behind pipe recompletion opportunities in zones up to 9,800 feet. First
production was established in January 2003. In December 2004, production for the well averaged 1,776 Mcfd and 114 Bbls/d
net to our interest. As of December 31, 2004, the net proved reserves attributable to this
well were 6.0 Bcfe.

7

Eugene Island 302.     Our interest in
Eugene Island 302 consists of a 30% working interest in two producing wells and one shut
in well operated by Remington Oil & Gas. Current production is from the Basal
Nebraskan zone at approximately 9,000 to 10,000 feet. The field is located in 220 feet of
water on Federal leases south of St. Mary Parish, Louisiana. Initial production was
established in May 2002. Production attributable to the companys interest averaged
391 Mcfd and 329 Bbls/d in December 2004. Net proved reserves for this field were 3.2 Bcfe
as of December 31, 2004.

Main Pass 178 Area.     This area is
comprised of 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 an
additional well and platform in 2003, in which the company owns a 60% working interest.
First production for the area 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. A sidetrack well to the Main Pass 178 A-1 well is planned to be drilled in
2005. The company will retain a 60% interest in this well. Production to the
companys interest averaged 975 Mcfd and 29 Bbls/d in December 2004. Net proved
reserves for the Main Pass 178 Area were 7.9 Bcfe as of December 31, 2004.

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
operates eight producing wells and seven shut in wells from five platforms with interests
ranging from 40% to 100%. The company initially acquired its interest in South Timbalier
265 though a like-kind property exchange with Kerr McGee in August 2000. Additional
interests in the area were acquired from El Paso in March 21. The wells produce from
various sands ranging in depth from 4,800 feet to 16,000 feet. The company drilled the
South Timbalier 250 A-3 well in 2004 which came on production in January 2005 at an
average rate of 2,100 Mcfd net to the companys interest. Production for the area
averaged 1,287 Mcfd and 124 Bbls/d in December 2004 prior to this well coming on line. As
of December 31, 2004, the net proved reserves for the South Timbalier 265 Area were 7.5
Bcfe.

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 2004, throughput of the
plant averaged 6.5 MMcf/d with processed liquids of 426 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 2004, throughput
of the plant averaged 7.9 MMcf/d of natural gas with processed liquids of 483 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.

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 2004, throughput
of the plant net to our interest averaged 131 Mcf/d with processed liquids of 7 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.

8

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 2004 throughput averaged 10.4 MMcf/d with a
total throughput capacity of approximately 35 MMcf/d. For the month of December 2004,
throughput of the plant averaged 9.8 MMcf/d with processed liquids of 845 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 $96.8 million for exploitation and development activities for 2005 with
$67.4 million of such budget allocated to our proved undeveloped reserves. We have
identified 976 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 194
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 92 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 116 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
over two years. A third operated rig was added in September of 2004 with the closing of
the Encana acquisition. Target reservoirs are Morrow, Atoka and Strawn at depths down to
13,000 feet. The majority of the wells drilled have been increased density wells. Primary
fields drilled in 2004 and scheduled for 2005 are White City and South Carlsbad in Eddy
County and the Quail Ridge in Lea County. A total of 23 operated wells are budgeted for
2005. Magnum Hunters working interest ranges from 24% to 100%, with an average in
the 70% range. Most of the drilling through February 2005 has been on acreage acquired in
the Burlington, Mallon and Encana acquisitions. We recently have entered into two separate
agreements with ConocoPhillips which allows Magnum Hunter to participate in wells drilled
on ConocoPhillips acreage in the High Lonesome area. Additional similar farmouts are in
the various stages with other large producers in the general area.

Additional development drilling in
the Permian Basin centers around increased density drilling in the Westbrook Field in
Mitchell County, Texas, where we drilled 11 wells in 2004. Over 100 Spraberry and Canyon
locations were identified with the NG Tex acquisition that was closed in 2004. Several
well sidetrack recompletions are planned for the Brunson Ranch Field in Loving County,
Texas with one budgeted for 2005. Also numerous proven undeveloped locations have been
identified in Lea County, New Mexico targeting the shallow intervals down to approximately
3,000 feet.

9

Exploratory Drilling

We spent $52.7 million of our $540
million 2004 capital expenditures on exploratory drilling and related land and geophysical
costs. Thirty-two offshore exploratory wells were drilled in 2004, of which 26 were
completed as producing wells providing us with a 81% 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 82 completions in 104 attempts by the end of 2004,
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 66.1
MMcfe/d net to the company as of December 2004. Nine new wells scheduled to commence
production in the first half of 2005 should add to these levels. We currently own an
interest ranging from 12.5% to 100% in 245 offshore blocks and expect to add to the number
of OCS blocks in 2005. An aggressive drilling program will continue in 2005.

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 five gas gathering systems located in Oklahoma, New
Mexico, 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 compression is appropriately sized to gain compression efficiency and
to minimize compressor downtime so 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 455 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. For the year ending
December 31, 2004, gas throughput for the Panoma gas gathering system averaged 15.2
MMcf/d. The Panoma gas gathering system is connected to a third party header system which
provides access to multiple major interstate and intrastate pipelines in the area serving
Midwestern, Western and Oklahoma 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 Panoma gas gathering system. The purchase also included a 22 mile products
pipeline between the McLean Gas Plant and the Koch Pipeline at Lefors, Texas and all gas
and product purchase and sales agreements related to the plant. The McLean Gas Plant is a
modern cryogenic gas processing plant with a throughput capacity of 23.0 MMcf/d. For the
year ending December 31, 2004, throughput net to Hunter Gas Gathering, was approximately
7.01 MMcf/d with processed liquids of 468 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 is plant operator.

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. The 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. For the year
ending December 31, 2004, the plants 2004 throughput averaged 10.4 MMcf/d with 942
Bbls/d of processed liquids. The plant has a total throughput capacity of approximately 35
MMcf/d.

10

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
year ending December 31, 2004, throughput of the plant, net to Hunter Gas Gathering,
averaged 8.03 MMcf/d of natural gas with processed liquids of 493 Bbls/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 year ending
December 31, 2004, throughput of the plant, net to our interest, averaged 0.157 MMcf/d
with processed liquids of 8 Bbls/d.

In the second half of 2004, Hunter
Gas Gathering began construction of the White City Gathering System, located 5 miles
southeast of the White City Penn Field in Eddy County New Mexico. The system will
initially service a 12-section area under development by our production company, Magnum
Hunter Production, Inc. in an area previously lacking any pipeline infrastructure for
getting as to markets. This system was put into service in October 2004 and development of
this area is progressing with three wells connected and flowing and others in stages of
drilling or completion. There are 32 potential locations identified for service by the
White City System. There is no processing expected in this area due to the dry nature of
the gas. The system is currently connected to one downstream gatherer with the potential
for two interconnects to move gas into the interstate markets. For the month of December
2004, throughput on the system was 1.9 MMcf/d.

The Baker Gas Gathering System was
constructed and put into service in August 2004. Hunter Gas Gathering is the operator of
the system and owns a 50% interest with Rutherford Oil Corporation owning the remaining
interest. It consists of approximately 19,500 feet of 8 pipeline located in McMullen
County, Texas and provides an outlet for multiple wells to Houston Pipe Lines
16 line to the South. Initial production from each well is estimated in the range of
8  15 MMcf/d with 3 wells connected and flowing. For the month of December 2004,
throughput on the system, net to Hunter Gas Gathering, averaged 3.3 MMcf/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.

11

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
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.

We acquired an 80% controlling
interest in Metrix Networks, Inc. (Metrix) in December 2003. Metrix provides
equipment and monitoring services to companies in the energy industry.

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. In as much 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.

12

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.

13

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.

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, 2004, we had 262
full-time employees of which 62 were management, 118 were administrative and 82 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.

14

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
2004.

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.

15

Maintaining reserves and revenues in
the future depends on successful exploration and development and are subject to revision.

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. From time
to time, drilling on proved undeveloped properties can result in revisions to previous
estimates due to performance, without regard to product pricing. Since 1999, the revisions
to previous estimates for all properties have been a net positive reserve addition. 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 March 1, 2005, Magnum Hunter had approximately 43% of its natural gas
production and 17% of its crude oil production hedged through December 31, 2005. In
addition, at March 1, 2005, Magnum Hunter had 11% of its natural gas production and 8% of
its crude oil production hedged for calendar year 2006. 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.

16

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.

17

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 March 1, 2005, we had total indebtedness of
approximately $623.7 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 $525
million under our Facility in addition to the $195 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.

18

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 2004 we had a capital expenditures budget of $245 million for
exploration, enhancement, exploitation and drilling activities on oil and natural gas
properties. Our capital expenditures budget for 2005 is $250 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.

19

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 88,013,002 shares were outstanding as of
March 7, 2005. We are also authorized to issue, without stockholder approval, securities
convertible into shares of common stock or preferred stock.

20

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 7.8% of our outstanding common stock as of March 7, 2005.

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 and related estimated future net cash flows
for 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, 2004,
December 31, 2003 and December 31, 2002 (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. We bear complete
responsibility and liability for our reserve estimates.

Net cash flows is defined as net
revenues, after deducting production and ad valorem taxes, future capital costs and
operating expenses, but before deducting federal income taxes. Estimates have been made
using constant oil and gas prices and operating costs, at December 31, 2004, or as
otherwise indicated.

The estimates of future net cash
flows from proved reserves 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 and future net cash flows 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) |                                               
|NGL           |                                               

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.

21

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, 2004. 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 on an actual basis at December 31, 2004, 2003 and
2002. These proved reserves were determined in accordance with Regulation S-X, Rule
4-10(a) (2) (3) (4), which are the only applicable definitions of proved oil and gas
reserves.

|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)                           
|Proved developed                                 
|Proved undeveloped                               
|                                                 
|Total proved oil reserves                        
|                                                 
|Net NGL reserves (Bbl):                          
|(including condensate)                           
|Proved developed                                 
|Proved undeveloped                               
|                                                 
|Total proved NGL reserves                        
|                                                 
|Total Proved Reserves (Mcfe)                     
|                                                 

---

(a)    
          Based upon reserve reports at December 31, 2004, 2003 and 2002 prepared by
          D&M and Cawley Gillespie.

The following tables set forth the
estimated proved reserves of oil and gas included in the previous tables which are claimed
exclusively through our gas plant ownership.

22

|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)                           
|Proved developed                                 
|Proved undeveloped                               
|                                                 
|Total proved oil reserves                        
|                                                 
|Net NGL reserves (Bbl)                           
|(including condensate)                           
|Proved developed                                 
|Proved undeveloped                               
|                                                 
|Total proved NGL reserves                        
|                                                 
|Total Proved Reserves (Mcfe)                     
|                                                 

---

(a)       
          Based upon reserve reports at December 31, 2004, 2003 and 2002 prepared by
          D&M.

Significant Properties

On December 31, 2004, 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 5,455 gross (3,641 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, 2004.

|                                    | Proved Reserves
|----------------------------------- | ---------------
|
|Mid-Continent region (a)            |                
|Permian Basin-New Mexico region (a) |                
|Permian Basin-Texas region          |                
|Gulf Coast region (a)               |                
|Gulf of Mexico (a)                  |                
|                                    |                
|Total                               |                
|                                    |                

---

(a)       Based on reserve reports at December 31, 2004 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.

23

|                                                | 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.

Drilling Activity

The following table sets forth the
results of our drilling activities during the three fiscal years ended December 31, 2004,
2003 and 2002.

|     | Gross Wells (a) | Net Wells (b)
|---- | --------------- | -------------
|
|2004 |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|2003 |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|2002 |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              
|     |                 |              

---

24

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

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,
2004. All of these wells are located in the United States.

|                        | Productive Wells As of December 31, 2004
|----------------------- | ----------------------------------------
|
|
|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, 2004:

|                        | Developed | Undeveloped
|----------------------- | --------- | -----------
|
|Arizona                 |           |            
|Kansas                  |           |            
|Louisiana               |           |            
|New Mexico              |           |            
|Oklahoma                |           |            
|Texas                   |           |            
|Utah                    |           |            
|Wyoming                 |           |            
|Offshore Gulf of Mexico |           |            
|Other                   |           |            
|                        |           |            
|Total                   |           |            

---

| | (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. We anticipate no material expirations on
any of our leased acreage over the next three years.

25

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.

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 2004.

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)
|-------------- | ---- | --- | -------------------------------------
|2004           |      |     |                                      
|First Quarter  |      |     | $                                    
|Second Quarter |      |     | $                                    
|Third Quarter  |      |     | $                                    
|Fourth Quarter |      |     | $                                    
|2003           |      |     |                                      
|First Quarter  |      |     | $                                    
|Second Quarter |      |     | $                                    
|Third Quarter  |      |     | $                                    
|Fourth Quarter |      |     | $                                    

On March 7, 2005, the last reported
sale price of our common stock on the New York Stock Exchange was $17.33 per share. As of
March 9, 2005, there were 2,612 record holders of Magnum Hunter common stock.

We have not previously paid any cash
dividends on our common stock. In connection with the planned merger with Cimarex Energy
Co., we intend to distribute to our shareholders, as a dividend, our 1.3 million of units
of TEL Offshore Trust. It is the present intention of management to utilize all other
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, 2004:

26

|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.

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, 2004, 2003, 2002, 2001 and 2000, 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.

|                                                                                           | 2004 | 2003 | 2002 | 2001     | 2000
|------------------------------------------------------------------------------------------ | ---- | ---- | ---- | -------- | ----
|
|Operating revenues                                                                         |      |      | $    | 493,726  |     
|Operating costs and expenses (a)                                                           |      |      |      | (287,793 | )   
|Operating profit                                                                           |      |      |      | 205,933  |     
|Provision for impairment of investment (b)                                                 |      |      |      | --       |     
|                                                                                           |      |      |      |          |     
|Costs associated with early retirement of debt (c)                                         |      |      |      | (12,250  | )   
|Cumulative effect on prior years of a change in accounting principle, net of tax (d)       |      |      |      | --       |     
|Net Income                                                                                 |      |      |      | 103,573  |     
|Dividends applicable to preferred shares (e)                                               |      |      |      | --       |     
|Income applicable to common shares                                                         |      |      |      | 103,573  |     
|Income per common share before cumulative effect of a change in accounting principle       |      |     
|Basic (e)                                                                                  |      |      | $    | 1.35     |     
|Diluted (e)                                                                                |      |      | $    | 1.31     |     
|Income (loss) per common share after cumulative effect of a change in accounting principle |      |     
|Basic (e)                                                                                  |      |      | $    | 1.35     |     
|Diluted (e)                                                                                |      |      | $    | 1.31     |     
|                                                                                           |      |      |      |          |     
|Other Data:                                                                                |      |     
|Proceeds from sale of assets                                                               |      |      | $    | 22,902   |     
|Capital expenditures (f)                                                                   |      |      | $    | 540,010  |     

27

---

| | (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 2004 the cost of retirement of $105 million in principal of our 9.6%
               Senior Notes due March 15, 2012. 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 and
               does not include cash adjustments for liabilities assumed in the New Mexico
               property acquisition during 2004.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|                                   | 2004 | 2003 | 2002 | 2001      | 2000
|---------------------------------- | ---- | ---- | ---- | --------- | ----
|
|Property, plant and equipment, net |      |      | $    | 1,496,912 |     
|Total assets                       |      |      |      | 1,702,501 |     
|Total debt (a)                     |      |      |      | 645,500   |     
|Total stockholders' equity         |      |      | $    | 679,813   |     

---

| | (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 as of
                    December 31, 2003, 2002, 2001 and 2000, respectively. As of December 31,
                    2002 and 2000, $7.0 million and $20.6 million, respectively, of the debt was
                    non-recourse to the company.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|                                     | 2004 | 2003 | 2002 | 2001     | 2000
|------------------------------------ | ---- | ---- | ---- | -------- | ----
|
|Cash flow from operating activities  |      |      | $    | 300,610  |     
|Cash flows from investing activities |      |      |      | (513,939 | )   
|Cash flows from financing activities |      |      | $    | 214,978  |     

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.

|                                                    | 2004
|--------------------------------------------------- | ----
|
|Revenues                                            |     
|Depreciation, depletion, amortization and accretion |     
|Operating Profit                                    |     
|Cost of early debt retirement                       |     
|Net Income                                          |     
|Income per common share, basic                      |     
|Income per common share, diluted                    |     

28

|                                                    | 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                    |     
|                                                    |     

29

Item 7.  Management 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 1.0 Tcfe predominantly located in the southwestern United States
onshore, where annual production decline rates are typically less than other regions of
the country. Management believes the Company has over a five-year inventory of over 900
onshore development drilling locations and workover opportunities and 245 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 2004
growth in reserves and production was from a combination of drill bit growth and
successful acquisitions. We acquired 465 producing oil and gas wells from Encana
Corporation during August 2004. The purchase also included approximately 44,000 net acres
of undeveloped properties. The majority of these properties are located in Lea and Eddy
counties of Southeast New Mexico. We also acquired 170 producing wells in the Permian
Basin of West Texas during October 2004. The Company drilled a total of 175 wells in 2004
and completed 167 of them for an overall 95% success rate. Offshore drilling totals for
the year included 33 of 39 offshore wells drilled successfully. Since our initial entry
into the Gulf of Mexico in 1999, the Company has completed 111 of 134 wells, for an 83%
overall rate of success.

The Companys proved reserves
increased from 838 Bcfe at the end of 2003 to 1.0 Tcfe at the end of 2004. Magnum
Hunters proved reserves are predominantly long-life, stable, onshore reserves with
59% located in the Permian Basin region, 25% in the Mid-continent region, 8% on the Texas
Gulf Coast and 8% 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. Management believes weve always used the most
rigorous level of external reserve evaluation by DeGolyer & MacNaughton
(D&M) and Cawley Gillespie, which are our third party engineering firms,
and they evaluate 100% of our proved reserves.

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 $45.2 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 2004 to redeem a portion of
the Companys $300 million of outstanding High Yield Bonds that bear interest of 9.6%
in combination with the new equity placement of $169.3 million of common stock.
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 49%.
It is Managements goal to reach a debt-to-capitalization level of 40% to 45% or
better by year-end 2005.

Magnum Hunters capital
expenditure budget for 2005 is currently estimated to be $250 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. We anticipate experiencing price increases in other areas of the oil field. By
operating the majority of our properties, we are in a unique position to better control
the timing of our capital expenditure program and these expenses.

The Southeast New Mexico properties
consist of approximately 1,110 wells in Chaves, Lea, and Eddy Counties, of which 71% 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 2004
was 1,915 Bbl/d and 42,784 Mcf/d.

30

The company has been actively
drilling increased density wells in the Morrow formation at approximately 11,500 feet. The
company participated in 34 Morrow wells in 2004 and has 23 operated wells planned for
2005. D&M has identified 93 proved undeveloped locations for the Morrow, with net
reserves of 64.8 BCFe.

Several of the Morrow wells have
identified proved developed non-producing areas in the Atoka and Strawn formations. The
Encana acquisition that closed in 2004 greatly increased the Companys upside
potential in Southeast New Mexico.

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 and a significantly improved financial condition, to
continue to report record financial results over the next several years.

Recent Announcement To Be
Acquired by Cimarex Energy

On January 26, 2005, Magnum Hunter
and Cimarex Energy, Inc. (Cimarex) announced that their respective boards of
directors had approved an agreement and plan of merger that provides for the acquisition
of Magnum Hunter by Cimarex. Closing is anticipated before the end of the second quarter
in 2005, subject to customary regulatory approvals.

Under the terms of the proposed
agreement, Magnum Hunter shareholders will receive 0.415 shares of Cimarex common stock
for each share of Magnum Hunter common stock that they own. The merger is expected to be
non-taxable to the shareholders of both companies. In addition to the merger consideration
and prior to closing, Magnum Hunter intends to distribute its ownership interest in TEL
Offshore Trust to its common stockholders as a special dividend.

Cimarex Energy Co., headquartered in
Denver, CO, is an independent oil and gas exploration and production company with
operations focused in the Mid-Continent and Gulf Coast areas of the U.S. Its principal
operations offices are located in Tulsa, New Orleans and Houston.

In connection with the proposed
acquisition, Cimarex and Magnum Hunter have filed relevant materials with the SEC,
including one or more registration statement(s) that contain a prospectus and a joint
proxy statement. Investors and security holders of Cimarex and Magnum Hunter are urged to
read these documents and any other relevant documents filed with the SEC, as well as any
amendments or supplements to those documents, because they will contain important
information about Cimarex, Magnum Hunter and the merger.Investors and security holders
may obtain these documents (and any other documents filed by Cimarex and Magnum Hunter
with the SEC) free of charge at the SECs website at www.sec.gov. In addition, the
documents filed with the SEC may be obtained free of charge (i) at www.cimarex.com or
www.magnumhunter.com or (ii) by directing a request to Mary Kay Rohrer, Assistant
Corporate Secretary, Cimarex Energy Co., phone: 303-295-3995, fax: 303-295-3494; or Morgan
F. Johnston, Corporate Secretary, Magnum Hunter Resources, Inc., phone: 972-401-0752, fax:
972-443-6487. Investors and security holders are urged to read the joint proxy
statement/prospectus and the other relevant materials before making any voting or
investment decision with respect to the proposed acquisition.

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.

31

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.

On July 30, 2004, we purchased oil
and gas properties located in the state of New Mexico, primarily in Lea and Eddy counties
for $239.1 million, subject to certain purchase price adjustments. The properties include
both proved producing oil and gas wells and proved undeveloped leasehold mineral
interests. The effective date of the acquisition was May 1, 2004. We purchased additional
properties related to this acquisition during September 2004 for a purchase price of $1.4
million, net of certain purchase price adjustments. We also recorded additional asset
retirement obligations of $1.5 million as a result of the acquisition. Pro forma
information related to this acquisition has not been presented, as the effect was not
material to our historical results of operations.

On August 30, 2004, we entered into
an agreement to purchase approximately 170 producing wells located in the Permian Basin of
West Texas for $40 million, net of certain purchase price adjustments. Closing occurred on
October 29, 2004 and had an effective date of September 1, 2004. Pro forma information
related to this acquisition has not been presented, as the effect was not material to our
historical results of operations.

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.

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 includes 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 year ended December 31, 2002
as if the acquisition occurred as of the beginning of the year. The pro forma information
includes the effects of adjustments for interest expense, depreciation, depletion and
amortization, and income taxes:

|                                   | (Unaudited)
2002
|---------------------------------- | ----------------
|
|Revenue                            |                 
|Total Operating Costs and Expenses |                 
|                                   |                 
|Operating Profit                   |                 
|Interest Expense and Other         |                 
|                                   |                 
|Income before Tax                  |                 
|Benefit 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 $136 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.

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.

32

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)                               |            
|Hedging losses (thousands)                           |            
|Effect of hedging losses (per Mcfe)                  |            
|Lease operating expense (per Mcfe):                  |            
|Lifting costs                                        |            
|Production tax and other costs                       |            
|Gross margin (per Mcfe) (a)                          |            
|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) (a)                      |            
|Gathering (per Mcf throughput)                       |            
|Processing (per Mcf throughput)                      |            
|Segment profit (thousands)                           |            
|                                                     |            
|Oil Field Management Services                        |            
|                                                     |            
|Segment profit (thousands)                           |            

---

(a)       
          Excludes depletion, depreciation, amortization and accretion.

Period to Period
Comparisons

For the Years Ended
December 31, 2004 and 2003

We reported record net income of
$103.6 million for the year ended December 31, 2004 as compared to net income of $26.1
million for the same period in 2003, an increase of 297%, reflecting solid performance
growth in all of our business segments in 2004. Total operating revenues increased 52% to
$493.7 million in 2004 from $325.0 million in 2003. A 41% increase in the price received
for oil and gas sold (on a thousand cubic feet equivalent, or Mcfe, basis), combined with
a 10% 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 19% increase in revenues in
our gas gathering, marketing and processing segment due to product price increases, and a
76% increase in oil field services revenues due to the acquisition of Metrix, were
primarily responsible for the growth in revenues. Total operating costs and expenses
increased 24% to $287.8 million in 2004 from $232.3 million in 2003, principally due to
higher depreciation, depletion, amortization and accretion expense, lease operating
expense, gas gathering, marketing and processing expense, and general administrative
expense. Operating profit increased 122% to $205.9 million in 2004 from $92.7 million in
2003, due primarily to a 116% increase in our exploration and production segment profit
from $99.8 million in 2003 to $215.2 million in 2004, a 37% increase in our gas gathering,
marketing and processing segment profit from $7.6 million in 2003 to $10.4 million in
2004, and a 116% increase in our oil field management services segment profit from $1
million in 2003 to $2.3 million in 2004. Income before income tax and cumulative effect of
a change in accounting principle increased 289% to $159.3 million in 2004 from $40.9
million in 2003, due to the growth in our business segment performance discussed in detail
below. We recorded income tax expense of $55.8 million for 2004 ($53.8 million deferred),
versus an income tax expense of $15.2 million for 2003 ($15.5 million deferred), due to
the growth in pre-tax income. The 2003 period includes a gain of $399 thousand, net of
income tax, for 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. Basic and
diluted earnings per share in 2004 were $1.35 and $1.31 versus basic and diluted earnings
per share of $0.39 in the 2003 period. Diluted shares outstanding increased 17% in the
2004 period compared to the 2003 period, primarily as a result of exercise of employee
stock options and warrants, a secondary offering of 17.3 million shares of our common
stock, and the 49% increase in the average market price of our common stock in 2004
compared to 2003. The 236% gain in diluted earnings per share in 2004 compared to 2003 was
primarily the result of the increase in net income.

33

Exploration and
Production Operations:

For the year ended December 31, 2004,
we reported oil production of 4.1 million barrels and natural gas production of 56 billion
cubic feet, which represents a 5% increase in oil produced from the 3.9 million barrels
reported in 2003, and a 13% increase in natural gas produced from the 49.7 billion cubic
feet reported in 2003. Our reported equivalent daily rate of production on a million cubic
feet per day basis (MMcfe per day) increased 10% to 219.8 MMcfe per day in the 2004 period
from 200.1 MMcfe per day in the 2003 period. These increases were primarily the result of
the New Mexico and West Texas property acquisitions 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. Approximately 2.7% of
the production growth was from acquisitions and approximately 7.5% of the production
growth was from our drilling program.

Oil revenues increased 36% to $139.8
million in the 2004 period compared to $102.8 million in the 2003 period. The oil price
received, after hedging effects, was $34.27 per Bbl in the 2004 period compared to $26.42
per Bbl in the 2003 period, an increase of 30%. Gas revenues increased 67% to $302.9
million in the 2004 period versus $181.7 million in the 2003 period. The gas price
received, after hedging effects, was $5.41 per Mcf in the 2004 period compared to $3.66
per Mcf for the same period in 2003, an increase of 48%. Total oil and gas sales increased
56% to $443.4 million in 2004 from $284.9 million in 2003, including the effect of hedging
losses. We reported a loss of $45 million from hedging activities in 2004 versus a loss of
$73.8 million in 2003, a decrease of 39% due to the expiration of less favorably priced
hedges in 2004. These losses are included in our reported oil and gas sales.

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 2004 period, hedging decreased the average price we received for
oil by $5.35 per Bbl and decreased the average price we received for gas by $0.41 per Mcf.
During the 2004 period, we had approximately 86.7 Mmcf per day of gas hedged through
cost-less collars with a weighted average floor price of $3.92 per Mmbtu and a weighted
average ceiling price of $5.90 per Mmbtu. Approximately 57% of 2004 natural gas production
was hedged. On the crude side, we had approximately 5,865 Bbls per day hedged through
cost-less collars with a weighted average floor price of $23.87 per Bbl and a weighted
average ceiling price of $29.85 per Bbl. Approximately 53% of 2004 crude oil production
was hedged.

Lease operating expense consists of
lifting costs and production taxes and other costs. For the 2004 period, lifting costs
were $60.9 million versus $56.3 million in the 2003 period, an increase of 8%. Production
taxes and other costs were $43.7 million in the 2004 period versus $32.8 million in the
2003 period, an increase of 33%. The increase in lifting costs was primarily due to the
property acquisitions and to our successful drilling program which increased the number of
producing wells. The increase in production tax and other costs was primarily due to
higher oil and gas prices and to higher volumes of oil and gas sold. For the 2004 period,
lifting costs, on a unit of production basis, were $0.76 per Mcfe as compared to $0.77 per
Mcfe in the 2003 period, a decrease of 1%. Production taxes and other costs were $0.54 per
Mcfe in the 2004 period compared to $0.45 per Mcfe in the 2003 period, an increase of 20%.
The increase in production taxes and other costs per Mcfe was caused by an increase in
production taxes of $0.04 per Mcfe due to higher commodity prices received during the 2004
period, higher insurance costs of $0.02 per Mcfe, and higher overhead costs of $0.03 per
Mcfe.

34

Our gross margin realized from
exploration and production operations (oil and gas revenues less lease operating expenses)
for the 2004 period was $338.8 million, or $4.21 per Mcfe, compared to $195.9 million, or
$2.68 per Mcfe in the 2003 period, an increase of 57% on a per unit of production basis.
The gross margin increase is the result of a 41% increase in revenue per Mcfe produced,
offset by a 7% increase in lease operating expense per Mcfe produced.

Depreciation, depletion, amortization
and accretion of oil and gas properties was approximately $123.6 million in the 2004
period versus approximately $96.1 million in the 2003 period. The 2004 period included
accretion expense related to asset retirement obligations (due to the adoption in January
2003 of SFAS No. 143) of $2.9 million versus $2.5 million in 2003. On a unit of production
basis, depreciation and depletion expense (excluding accretion expense) was $1.50 per Mcfe
produced in the 2004 period versus $1.28 per Mcfe produced in the 2003 period. This 17%
increase in the equivalent unit cost was due to the effect of our New Mexico property
acquisition, an increase in development costs and shorter reserve life properties
associated with our activities in the Gulf of Mexico, and the transfer of $32.7 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 2004, as well as costs associated with leases which expired during the year.
Accretion expense was $0.04 per Mcfe in 2004 versus $0.03 in 2003. Total depreciation,
depletion, amortization and accretion for this segment was $1.54 per Mcfe in 2004 versus
$1.32 per Mcfe in 2003.

Segment profit for exploration and
production operations was $215.2 million for the 2004 period versus approximately $99.8
million for the 2003 period, an increase of 116%, due to property acquisitions, 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, 2004,
our gathering system throughput was 17.2 MMcf per day versus 15.8 MMcf per day for the
same period in 2003, an increase of 8% due to the construction and operation of two new
gathering systems.

Gas processing throughput was 25.6
MMcf per day in 2004 versus 24.9 MMcf per day in 2003, an increase of 3% due to a
combination of less downtime for unfavorable economics in 2004 and successful drilling
behind the plants.

Revenues from gathering, marketing
and processing increased 19% to $41.9 million in 2004 versus $35.3 million in 2003,
primarily due to higher realized prices for natural gas and natural gas liquids. Operating
costs for this segment increased 15% to $29.1 million in 2004 from $25.4 million in 2003
due primarily to higher costs of gas purchased. The gross margin realized from gathering,
marketing and processing for 2004 was $12.8 million versus $9.9 million in 2003, an
increase of 29%. The gathering margin was $0.17 per Mcf gathered in 2004 versus $0.14 per
Mcf in 2003 due to an increase in gathering fees and gas marketing margins. The processing
margin was $1.21 per Mcf in 2004 compared to $0.99 per Mcf in 2003 due to more favorable
processing economics.

Depreciation expense for gas
gathering, marketing and processing operations was $2.4 million for the 2004 period versus
$2.3 million for the 2003 period, an increase of 2% due to the new gathering systems.

Segment profit for gas gathering,
marketing and processing operations was $10.4 million in the 2004 period versus $7.6
million for the 2003 period, an increase of 37%, due to higher gathering and processing
throughput and improved processing economics at our natural gas processing plants.

Oil Field Management
Services Operations:

In December 2003 we increased our
equity ownership in Metrix Networks, Inc. (Metrix) to 80% and began to fully
consolidate its results of operations with our oil field management services segment. The
2004 operating results for this segment contains twelve months of Metrix operations versus
one month in 2003. Revenues from oil field management services were $8.4 million in the
2004 period versus $4.8 million in the 2003 period due to higher management and operations
services fees charged to third parties. The higher fees were primarily due to a full year
of consolidated operations of Metrix in 2004. Operating costs increased to $5.0 million in
2004 from $3.1 million in 2003 due to higher costs for labor and overhead and the
inclusion of a full year of consolidated Metrix operations in 2004. The gross margin for
this segment in 2004 increased to $3.4 million from $1.6 million in 2003, an increase of
106%, primarily due to Metrix.

35

Depreciation expense was $1.1 million
in the 2004 period versus $604 thousand in the 2003 period, an increase of 88%, due to
Metrix. Segment profit was $2.3 million in 2004 versus $1 million in 2003, an increase of
116%, due to Metrix.

Depreciation, Depletion, Amortization
and Accretion:

Total depreciation, depletion,
amortization and accretion expense was $127.2 million in the 2004 period versus $99.6
million in the 2003 period, an increase of 28%, primarily due to increased oil and gas
production and increased depletion and accretion rates per unit produced in our
exploration and production segment.

General and
Administrative Expenses:

General and administrative expenses
for 2004 increased 44% to $22.1 million from $15.3 million in 2003. The principal reasons
for this increase were higher legal, accounting and other fees of $2.5 million, Metrix
expenses (due to 12 months of Metrix consolidated in 2004 versus one month in 2003) of
$2.1 million, and employee salaries and benefit costs of $2.2 million. The number of
full-time employees at fiscal year-end 2004 and 2003 was 262 and 222, respectively. Fees
and expenses, other than employee costs, associated with Sarbanes Oxley compliance were $1
million in 2004 versus $62 thousand in 2003.

Other Income and Expenses:

We recorded a gain on sale of assets
other than oil and gas properties of $288 thousand in 2004 versus $171 thousand in 2003.

We recorded no equity in earnings of affiliate
in 2004 versus equity in loss of affiliate of $162 thousand in 2003, principally due to
the acquisition of 80% control of Metrix in December 2003. Other income was $2.6 million
for 2004 versus $889 thousand in 2003, a 191% increase, due to a settlement of a lawsuit
in favor of Magnum Hunter Resources. We recognized a $1.1 million gain in other non-cash
hedging adjustments in 2004 versus a gain of $1.5 million in 2003. In the 2004 period,
$792 thousand of the hedging gain relates to the amortization of commodity hedge
liabilities acquired in the Prize merger, while $332 thousand of the gain was due to
recording hedge ineffectiveness. 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.

We incurred costs associated with
early retirement of debt of $12.3 million in 2004 versus $6.7 million in 2003. The 2004
period debt retirement costs of were associated with the $105 million principal value
redemption of our 9.6% Senior Notes at 109.6% of par. 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.

Interest expense was $38.1 million
for 2004 versus $47.3 million for 2003, a decrease of 19%, primarily the result of
interest saved on the early redemption of our 10% and 9.6% Senior Notes and lower interest
rate hedging costs. During the 2004 period, the average interest rate on our Senior Credit
Facility (Facility) was 3.54% versus 3.4% in 2003, an increase of 4%. The
weighted average daily balance of our Facility increased 2% to $217.8 million in 2004 from
$213.7 million in 2003. In addition, we incurred no interest rate hedge expense in the
2004 period versus $961 thousand in the 2003 period. The interest rate hedge expired in
August 2003.

We recorded income tax expense of
$55.8 million in 2004 ($53.8 million of which was deferred), versus an income tax expense
of $15.2 million in 2003 ($15.5 million of which was deferred). The variance in the
effective tax rate from the statutory rate of 35% in 2004 was primarily due to state
income taxes. We reduced our blended state income tax rate from 2.875% to 1.2% due to a
change in estimate of the amount of income from our offshore properties and properties
held by a limited partnership which are not subject to state income taxes. This change in
estimate, when applied to our deferred state income tax liability, resulted in a reduction
of deferred state income tax expense of $4.8 million in 2004. We also increased our
valuation allowance for utilization of our state net operating loss carryforwards,
resulting in additional state tax expense of $2 million in 2004.

36

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 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
56% gain in diluted earnings per share in 2003 compared to 2002 was primarily the result
of the increase in net income.

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.

37

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.

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.

38

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.

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.

General and
Administrative Expenses:

General and administrative expenses
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.

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. 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.

39

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.

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 Facility 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 Facility 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 $300.6 million, $162.6 million, and $83.4
million in 2004, 2003, and 2002, respectively. Our operating cash flow for 2004 increased
over that for 2003, primarily due to substantially 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. In the 2004 period, we made income tax payments (net of current year refunds) of
$2.4 million.

Our net working capital position at
December 31, 2004 was a deficit of $5.2 million. At this date, we had $202.5 million
available under our Facility. A large factor in our negative working capital was $14.0
million in current derivative liabilities we had recorded on our 2005 hedging program due
to continued increases in commodities prices over our hedged prices. This liability is
partially offset by $5.0 million in deferred tax assets which will be released as our 2005
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 2003 operating cash flow was
higher than our 2002 operating cash flow also due to higher profits realized by our
business segments when adjusted for non-cash items. Please refer to our period to period
comparison for further explanations on the causes and amounts of the increases in
earnings. We also benefited from $8.1 million in refunds (net of 2003 payments) as well as
the return of $6.5 million in margin deposits we had posted on commodity hedge positions.

Our net working capital position at
December 31, 2003 was also a deficit of $5.2 million. At this date we had $87.5 million
available under our Facility. Again, 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 for 2004
production. The amounts paid out on these liabilities were offset by higher cash received
for the related production in 2004. This liability was also offset by $8.3 million of
current deferred tax assets which were released as the positions were settled.

40

INVESTING ACTIVITIES: Net cash used
in investing activities was $513.9 million, $159.7 million, and $89.4 million in 2004,
2003, and 2002, respectively. During July 2004 we paid $234.2 million, net of certain
purchase price adjustments, for our acquisition of New Mexico properties. In 2004, the
main source of our investing was $303.1 million spent for capital expenditures which are
discussed in the section immediately following our liquidity and capital resources
discussions. During 2004 we also received $22.9 million from the sales of non-strategic
oil and gas properties.

In 2003, the main source of our
investing was $175.5 million spent for capital expenditures. During 2003 we also received
$17.1 million from the sales of non-strategic oil and gas properties as well as $5.2
million from the sale of our 30% interest in NGTS. We spent $6.1 million to purchase land
which we currently have available for sale and $1.5 million to purchase land to be held
for geothermal development.

During 2002 we spent $141.0 million
on capital expenditures as well as $41.1 million to complete the Prize merger. These
expenditures were partially offset by $96.0 million received on sales of non-strategic oil
and gas properties acquired in the Prize merger.

FINANCING ACTIVITIES: Net cash
provided by financing activities was $215 million, $12.7 million, and $6.3 million in
2004, 2003, and 2002, respectively. During 2004, we received $169.3 million from the
issuance of common stock pursuant to our secondary offering of common stock. We also
received $10.4 million from the issuance of stock pursuant to our employee stock option
plans. We loaned $2.3 million to our KSOP to purchase approximately 225 thousand shares of
our common stock to be available for purchase by participants at future dates. KSOP
participants paid us $807 thousand to purchase approximately 134 thousand unallocated KSOP
shares of our common stock and we forgave KSOP debt of $1.3 million by contributing
approximately 223 thousand unallocated shares of our common stock to participants as our
2004 employer retirement plan contribution. At December 31, 2004, the KSOP had a loan
balance of $6.2 million. This loan carries no interest and is due December 31, 2005. We
paid $115.1 million to redeem $105 million in principal of our 9.6% Senior Notes at 109.6%
of par, borrowed approximately $466 million under our Facility, and made repayments on our
debt of $313 million. We also paid fees related to our financing activities of $1.0
million.

During 2003, we received $4.7 million
from the issuance of common stock and treasury stock pursuant to employee stock option and
warrant exercises, and paid down debt of $486.3 million. We paid $134.4 million to redeem
the outstanding $129.5 million in principal of our 10% Senior Notes and borrowed
approximately $517.4 million under our Facility. We also received $125 million from the
issuance of Convertible Notes and paid fees related to financing activities of $4.4
million. During 2003, we also spent $7.4 million to repurchase approximately 1.3 million
shares of our common stock. We loaned $2.7 million to our KSOP to purchase approximately
486 thousand shares of our common stock and forgave KSOP debt of $1.1 million by
contributing approximately 172 thousand shares of our common stock to participants. KSOP
participants paid us $380 thousand to purchase approximately 59 thousand unallocated
shares of our common stock.

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
paid off $246.8 million of long-term debt acquired in the Prize merger. During 2002, we
also 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.

CAPITAL RESOURCES: 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. In addition, 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. We currently have $23.2 million
available remaining under our current shelf registration with the Securities and Exchange
Commission.

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.

41

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 at a cost of funds based on LIBOR, yielding a weighted average rate of
5.58% per annum at December 31, 2004. This transaction was 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.

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
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.

On April 30, 2004, we amended our
Facility to receive a more favorable rate structure and to increase the borrowing base to
$275 million. We also extended the maturity date by one year, resulting in a new maturity
date of May 2, 2007. On July 15, 2004, we amended our Facility again to increase the
borrowing base to $480 million upon the consummation of our New Mexico property
acquisition, an increase of $205 million, and to allow us to use proceeds from our
secondary common stock offering to redeem and retire up to $105 million in principal value
of our 9.6% Senior Notes at 109.6% of par. On October 18, 2004, we amended our Facility to
increase the borrowing base by $45 million, from $480 million to $525 million and to
increase our maximum borrowings from $500 million to $750 million. The level of the
borrowing base is dependent on the valuation by the lenders of the assets pledged,
primarily oil and gas reserves. At December 31, 2004, we had $202.5 million of available
credit under our Facility.

Our Facility includes covenants, the
most restrictive of which requires maintenance of a 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 and 2004. 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 over a six-month period. The last redetermination date had an
effective date of June 30, 2004 and was completed on October 15, 2004. This
redetermination increased our borrowing base by $45 million up to $525 million, and the
maximum borrowings were increased from $500 million to $750 million. Our next
redetermination date will have an effective date of December 31, 2004 and will have a
completion date of no later than May 9, 2005.

On March 15, 2002, we 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. We redeemed $105 million in principal of
these notes on August 27, 2004 at a redemption price of 109.6% of par. We paid the holders
of these redeemed notes $115.1 million plus accrued and unpaid interest of $4.5 million.
We recorded $12.3 million in costs associated with this redemption comprised of $10.1
million in premiums and $2.2 million in unamortized deferred financing fees that were
written off.

42

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, a subsidiary received approximately
$10.9 million in principal and received premiums of approximately $273 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%, and the current rate is 2.49%. 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.

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.

Metrix has a $500 thousand revolving
credit facility with a lender. This facility matures on December 16, 2005 and is governed
by a borrowing base. Magnum Hunter is a guarantor to this facility. As of December 31,
2004, there were no borrowings outstanding under this facility.

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
2005.

43

CAPITAL EXPENDITURES. For the year
ended December 31, 2004, our total capital expenditures for property, plant and equipment,
were $540 million. The following summarizes our capital expenditures by cost component (in
thousands):

|                            | Oil and Gas
Properties | Other
Property | Total
|--------------------------- | ---------------------- | -------------- | -----
|Acquisition costs:          |                        |                |      
|Unproved acquisitions       |                        |                |      
|Proved acquisitions         |                        |                |      
|Other property acquisitions |                        |                |      
|Development costs           |                        |                |      
|Exploratory costs           |                        |                |      
|                            |                        |                |      
|Total                       |                        |                |      
|                            |                        |                |      

For the year 2005, we have budgeted
approximately $250 million for exploration and development activities. We anticipate that
the 2005 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, 2004:

|                              | Payments Due by Period (in thousands)
|----------------------------- | -------------------------------------
|
|Contractual Obligations:      |                                      
|Long-Term Debt                |                                      
|Fixed-Rate Interest Payments  |                                      
|Capital Leases                |                                      
|Commodity Derivatives         |                                      
|Operating Leases              |                                      
|                              |                                      
|Total Contractual Obligations |                                      
|                              |                                      

We have no off balance sheet
arrangements, variable interest 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. On
February 18, 2005 our 40% owned subsidiary, Apple Tree Holdings, LLC entered into a $20.6
million construction loan agreement (Construction Loan). The Construction Loan
provides financing for the construction of a processing plant, natural gas lateral, carbon
dioxide line and related infrastructure in Huerfano County, Colorado. The Construction
Loan bears interest at either LIBOR plus 2.25% or a base rate plus 1.25% and will mature
no later than July 31, 2006. We have provided a guaranty to the lender for this
Construction Loan. In return for our guaranty, we received an up-front cash payment as
well as a 55% distribution of cash flows from the entity until certain financial tests are
met. In the event that the Construction Loan goes into default and Magnum Hunter has to
pay on the guaranty, we will have recourse against the project and related subsidiaries.

44

Our 2005 capital expenditure budget
is $250 million. Based on our reserve report, future development costs are estimated to be
$351 million for our proved reserves and $206.8 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 $14.0 million during 2005 and $6.0 million
during 2006 related to our hedging program. These payment estimates are based on December
31, 2004 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 2004, we paid $49.7 million in interest and recorded a
liability for $5.8 million for 2004 interest which would be paid during 2005. At December
31, 2004, we had $195 million fixed rate debt and $450.5 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 $113.8 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 2012
through 2023. 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 federal taxes due with these
losses for the foreseeable future. We provided a $2 million valuation allowance for
utilization of state net operating loss carryforwards in 2004.

In relation to our oil and gas
properties, we have substantial retirement obligations. We estimate that we will have
obligations of $41.3 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.

RECENT TRENDS. The following is a
discussion of recent trends we consider important and our assessment of the impact of
these trends on our business plan.

Commodity prices. We believe that
natural gas prices (NYMEX index) will average between $4.00 and $7.00 per MCF over the
next several years and will likely remain volatile. We based our 2005 capital and
operating budgets on prices of approximately $6.22 per Mcf. Crude oil prices have
increased significantly, but in our view are much more variable due to worldwide political
and economic factors. For 2005 budgeting purposes, we have assumed crude prices will
average approximately $45.60 per Bbl (NYMEX index). Our production mix is largely natural
gas, and therefore our gross margins are largely driven by natural gas prices.

Interest rates.We have experienced
an unusually low interest rate environment for the past several years. We expect interest
rates to increase moderately over the next several years. By December 31, 2005, we expect
that approximately 39% of our debt will be fixed at 9.6% through at least 2007 and
potentially 2012, with the remaining 61% to be variable rate debt.

Depreciation, depletion, amortization
and accretion (DD&A). Our exploration and production segment DD&A rate has
increased an annual average of 15% per year since 1999. This increase is primarily
attributable to our increased capital expenditures in the offshore Gulf of Mexico region
where, typically for our industry, finding and development costs per unit are higher than
our average finding and development costs per unit have been historically onshore and our
significant New Mexico property acquisition. We expect to continue to spend a significant
percentage of our total capital expenditures budget on offshore Gulf of Mexico projects
due to economic parameters experienced in that region. Assuming similar results in our
drilling activities and reserve recognition to what we have been achieving, we would
expect our DD&A rate to continue to increase.

45

Managements assessment of the
impact of these trends on our business plan. We have concentrated our capital budget in
areas where we expect to realize the highest financial benefits, including rate of return
and return on capital deployed. As such, we have dedicated significant portions of our
capital expenditure budget to the offshore Gulf of Mexico region and onshore in the
Southeast New Mexico area over the past several years.

We have significant exploration,
development and exploitation opportunities both onshore and offshore. Management continues
to monitor commodity prices, finding and development costs and interest rates, among other
factors, to determine both the total dollars to be spent and the allocation of these
dollars among alternative projects within the capital budget. Even if DD&A rates and
interest rates continue to increase, and commodity price increases in turn offset these
expenses, then we would expect to continue our current business plan. We believe we have
significant flexibility in the management of our cash flows.

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.

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, including directly related overhead costs, are capitalized into a
full-cost pool on a country-by-country basis as incurred. Internal costs that
directly relate to acquisition, exploration and development activities totaled $1.3
million for the years ended December 31, 2004 and 2003. The balance of capitalized costs
included in oil and gas properties for the years ended December 31, 2004 and 2003 were
$6.5 million and $5.2 million, respectively. Management believes that the basis we use to
determine the amount of internal costs capitalized is appropriate.

All capitalized costs of oil and gas
properties, including the estimated future costs to develop proved reserves and estimated
dismantlement and abandonment costs, net of salvage values, are amortized on the
unit-of-production method using estimates of proved reserves. Costs directly associated
with the acquisition and evaluation of unproved properties are excluded from the
amortization base until the related properties are evaluated. Such unproved properties are
assessed for impairment quarterly 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.

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 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. We experienced no impairment in 2004, 2003, or 2002.

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

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.

46

For purposes of the ceiling test, we
remove the discounted present value included in our future development costs on our
reserve report for which we have already booked an obligation under SFAS 143. For purposes
of our depletion calculation, we include in future development costs the estimated
plugging and abandonment costs, net of estimated salvage values, for proved undeveloped
wells. For purposes of both of these calculations, we do not include plugging and
abandonment costs in our future development costs on developed proportions for which we
have booked an obligation under SFAS 143.

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.
Current revenues are accrued based on our expectation of actual deliveries and actual
prices received. Plant revenues are recognized as product is sold, and our gathering fees
are recognized as the gathering services are performed. Revenues for our oilfield
management services segment are recognized as services are performed and equipment is
delivered.

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 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.

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. 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. Changes in the fair value of derivative instruments that are
cash-flow hedges are recognized in other comprehensive income until such time as the
hedged items are recognized in net income. Ineffective portions of a derivative
instruments change in fair value are immediately recognized in net income.

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, 2004, 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.

47

Stock Compensation

At December 31, 2004, we had four
stock-based employee compensation plans, which are described more fully in Note 13 of the
Consolidated Financial Statements. We account for our employee stock option 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 years ended December 31, 2003 and 2004, we recorded stock compensation expense of
$3.0 million and $768 thousand, respectively, 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. Our future accounting for stock-based compensation will be impacted by the issuance
of SFAS No. 123(R). Please see our Recently Issued Statements discussion below for
additional information.

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 earnings per share (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 $278 and $1,144, respectively              |                        
|                                                    |                        
|Deduct:  Total  stock-based  employee  compensation |                        
|determined  under fair  value-based  method for all |                        
|awards, net of income taxes of $1,871,  $2,896, and |                        
|$1,962 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:

|                                               | 2004(a)   | 2003(b)   | 2002     
|---------------------------------------------- | --------- | --------- | ---------
|Risk-free interest rate                        | 3.38%     | 1.58%     | 3.68%    
|Expected life                                  | 4.1 years | 2.1 years | 7.4 years
|Expected volatility                            | 40.7%     | 46.3%     | 49.5%    
|Dividend yield                                 | --        | --        | --       
|Weighted average fair value of options granted | $  3.81   | $  3.03   | $  3.17  

---

| | (a) | We granted 1,403,000 options during 2004, which had a reduced term of four
               years. Prior grants have ten-year terms.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------

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

48

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. We recorded an allowance on certain state operating losses of
$2.0 million during 2004.

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 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.

Recently Issued Statements

The Financial Accounting Standards
Board (FASB) has issued FASB Staff Position (FSP) No. 142-2,
Application of FASB Statement 142, Goodwill and Other Intangible Assets, to
Oil-and-Gas Producing Entities after evaluating an issue involving the classification of
mineral rights. In June 2001, FASB issued Statement of Financial Accounting Standards
(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 was raised regarding whether these mineral
rights should be classified as tangible or intangible assets. FSP No. 142-2 addressed this
issue and supports our current accounting treatment of mineral rights and will not impact
our financial statements. This FSP is effective for reporting periods beginning after
September 2, 2004.

FASB issued FSP FAS 129-1,
Disclosure Requirements Under FASB Statement No. 129, Disclosure of Information
About Capital Structure, in April 2004. This FSP provides additional guidance on the
disclosure requirements of contingently convertible securities. We have made the required
disclosures related to the terms of our Convertible Notes in our Annual Report on Form
10-K and have provided explanations in Note 6 of this Form 10-Q about the dilutive effects
of these notes on our earnings per share (EPS).

FASBs Emerging Issues Task
Force (EITF) has issued an Abstract for EITF Issue No. 04-8, The Effect
of Contingently Convertible Debt on Diluted Earnings per Share, which addresses the
issue of when the dilutive effects of contingently convertible debt instruments should be
included in diluted earnings per share. This guidance requires companies to include the
dilutive effect of convertible debt securities in diluted earnings per share regardless of
whether or not the contingent conversion features have been triggered. The principal of
our Convertible Notes must be settled in cash, with the conversion spread settled in
stock. This EITF is effective for periods ending after December 15, 2004. We have
accordingly included approximately 94 thousand potential shares to be issued for our
Convertible Notes in our earnings per share computations for the year ending 2004 based on
the spread between our average market price during the year and the conversion price on
these notes. We did not include any potential dilution for the 2003 period because the
conversion price did not exceed our average market price during that period.

49

The SEC Staff Accounting Bulletin
(SAB) 106 was released in September 2004. SAB 106 expresses the SEC
staffs views on the interaction of SFAS No. 143 and the full cost method and
provides guidance on computing the full cost ceiling as well as depreciation, depletion,
and amortization. The SAB also requires additional disclosures regarding how the
application of SFAS No. 143 has affected the ceiling test and depreciation, depletion and
amortization. This guidance is effective for the first fiscal quarter beginning after its
publication. We implemented this guidance for our ceiling test and depletion calculations
during the fourth quarter of 2004 and experienced no significant impact.

FASB issued SFAS No. 123(R),
Share-Based Payment, during December 2004. Under this revised guidance, all
share-based equity and liability instruments will be recorded as compensation expense
based on their fair values, and all liability instruments will be remeasured each
reporting period. This guidance will be effective as of the beginning of the first annual
or interim reporting period that begins after June 15, 2005, which would cause us to adopt
this statement July 1, 2005. We currently account for our stock-based compensation under
the prospective method, under which we only record compensation expense on awards granted
after 2003. Upon adoption of this statement, we will apply the modified prospective method
to our equity instruments under which compensation expense will also be recorded on the
unvested portions of awards granted prior to 2003. At this time, we estimate the impact of
these prior years grants on 2005 earnings to be an additional pre-tax expense of
$1.2 million.

FASB also issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29", during
December 2004. SFAS No. 153 amends APB Opinion No. 29 by eliminating the exception from
fair value measurement prescribed in that statement and replaces it with an exception for
exchanges that have no significant impact on future cash flows. This statement is
effective for exchanges that take place in fiscal periods beginning after June 15, 2005.
We do not expect this statement to have an impact on our future financials.

Off Balance Sheet
Arrangements

In the past, we have provided trade
guarantees on behalf of an unconsolidated affiliate, which has since been sold. 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. On
February 18, 2005 our 40% owned subsidiary, Apple Tree Holdings, LLC entered into a $20.6
million construction loan agreement (Construction Loan). The Construction Loan
provides financing for the construction of a processing plant, natural gas lateral, carbon
dioxide line and related infrastructure in Huerfano County, Colorado. The Construction
Loan bears interest at either LIBOR plus 2.25% or a base rate plus 1.25% and will mature
no later than July 31, 2006. We have provided a guaranty to the lender for this
Construction Loan. In return for our guaranty, we received an up-front cash payment as
well as 55% distribution of cash flows from the entity until certain financial tests are
met.

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 March 1, 2005, Magnum Hunter had
approximately 43% of its natural gas production and approximately 17% of its crude oil
production hedged through December 31, 2005. In addition, Magnum Hunter had approximately
11% of its natural gas production and 8% of its crude oil production hedged for the
calendar year 2006. 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.

50

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 27 wells that
individually produce a net 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.

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.

51

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.

The company has no margin deposits
with any counter-parties as of December 31, 2004 related to hedge transactions. The
company does not intend to enter into any new hedging contracts with institutions that
require margin deposits.

At December 31, 2004, we had open
contracts with the following terms:

|Commodity   | Type   | Volume/Day   | Duration        | Wtd. Avg. Price
|----------- | ------ | ------------ | --------------- | ---------------
|Natural Gas | Collar | 60,000 MMBTU | Jan 05 - Dec 05 | $4.21 - $6.85  
|Natural Gas | Swap   | 20,000 MMBTU | Jan 05 - Dec 05 | $          6.25
|Natural Gas | Collar | 20,000 MMBTU | Jan 06 - Dec 06 | $5.25 - $6.30  
|Crude Oil   | Swap   | 1,000 BBL    | Jan 05 - Dec 05 | $         34.90
|Crude Oil   | Collar | 1,000 BBL    | Jan 05 - Dec 05 | $35.00 - $55.00
|Crude Oil   | Collar | 1,000 BBL    | Jan 06 - Dec 06 | $30.00 - $35.85

Based on future market prices at
December 31, 2004, the fair value of open contracts to the company was a net liability of
$19.8 million. If future market prices were to increase 10% from those in effect at
December 31, 2004, the fair value of our open contracts would be a liability of $39.1
million. If future market prices were to decline 10% from those at December 31, 2004, 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, 2004.

52

|Expected Maturity Dates       | 2005 | 2006-2007 | 2012 | 2023  | Total | Fair Value
|----------------------------- | ---- | --------- | ---- | ----- | ----- | ----------
|
|Variable Rate Debt:           |      |           |      |       |       |           
|Bank Debt (a)                 |      |           | $    | --    |       | $         
|Convertible Notes (b)         |      |           | $    | --    |       | $         
|Capital Lease Obligations (c) |      |           | $    | 2,458 |       | $         
|Fixed Rate Debt:              |      |          
|9.6% Senior Notes             |      |           | $    | --    |       | $         

---

| | (a) | The weighted average interest rate on the bank debt with recourse at December
               31, 2004 was 3.92%.
| | --- | ----------------------------------------------------------------------------------------------------------------

| | (b) | The interest rate on the Convertible Notes at December 31, 2004 was 2.49%. 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,
               2004 was 5.58%.
| | --- | --------------------------------------------------------------------------------------------------------------

53

Item 8.  Consolidated Financial Statements and Unaudited Supplementary Data

Index to Consolidated
Financial Statements

|                                                                                |  |  | Page |  | 
|------------------------------------------------------------------------------- |  |  | ---- |  | 
|                                                                                |  |  |      |  | 
|Management's Responsibility Over Financial Reporting                            |  |  | F-1  |  | 
|                                                                                |  |  |      |  | 
|Report of Independent Registered Public Accounting Firm                         |  |  | F-2  |  | 
|                                                                                |  |  |      |  | 
|Report of Independent Registered Public Accounting Firm                         |  |  | F-3  |  | 
|                                                                                |  |  |      |  | 
|Financial Statements:                                                           |  | 
|                                                                                |  |  |      |  | 
|Consolidated Balance Sheets at December 31, 2004 and 2003                       |  |  | F-4  |  | 
|                                                                                |  |  |      |  | 
|Consolidated Statements of Operations                                           |  | 
|For the Years Ended December 31, 2004, 2003 and 2002                            |  |  | F-5  |  | 
|                                                                                |  |  |      |  | 
|Consolidated Statements of Stockholders' Equity and Comprehensive Income (Loss) |  | 
|For the Periods Ended December 31, 2004, 2003 and 2002                          |  |  | F-6  |  | 
|                                                                                |  |  |      |  | 
|Consolidated Statements of Cash Flows                                           |  | 
|For the Years Ended December 31, 2004, 2003 and 2002                            |  |  | F-9  |  | 
|                                                                                |  |  |      |  | 
|Notes to Consolidated Financial Statements                                      |  |  | F-10 |  | 
|                                                                                |  |  |      |  | 
|Supplemental Information on Oil and Gas Producing Properties (Unaudited)        |  |  | F-40 |  | 

54

MANAGEMENTS RESPONSIBILITY
OVER FINANCIAL REPORTING

Board of Directors and
StockholdersMagnum Hunter Resources, Inc.

The following consolidated financial
statements of Magnum Hunter Resources, Inc. and its subsidiaries (Magnum
Hunter) were prepared by management, which is responsible for their integrity,
objectivity and fair presentation. The statements have been prepared in conformity with
generally accepted accounting principles and, accordingly, include some amounts that are
based on the best estimates and judgments of management.

Magnum Hunters management is
also responsible for establishing and maintaining effective internal control over
financial reporting. The system of internal control of Magnum Hunter is designed to
provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of America. This system consists of 1)
entity level controls, including written policies and guidelines relating to the ethical
conduct of business affairs, 2) general computer controls and 3) process controls over
initiating, authorizing, recording, processing and reporting transactions. Even an
effective internal control system, no matter how well designed, has inherent limitations,
including the possibility of human error and circumvention or overriding of controls and,
therefore, can provide only reasonable assurance with respect to reliable financial
reporting. Furthermore, the effectiveness of an internal control system in future periods
can change with conditions.

The adequacy of financial controls of
Magnum Hunter and the accounting principles employed in financial reporting by Magnum
Hunter are under the general oversight of the Audit Committee of the Board of Directors.
No member of this committee is an officer or employee of Magnum Hunter. The independent
public accountants and internal auditors have full, free, separate and direct access to
the Audit Committee and meet with the Committee from time to time to discuss accounting,
auditing and financial reporting matters.

Magnum Hunters management
assessed the effectiveness of our internal control over financial reporting as of December
31, 2004. In making this assessment, we used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control 
Integrated Framework. These criteria cover the control environment, risk assessment
process, control activities, information and communication systems, and monitoring
activities. Based on this assessment, management believes that, as of December 31, 2004,
Magnum Hunters internal control over financial reporting is effective based on those
criteria.

Deloitte & Touche LLP, an
independent registered public accounting firm, was engaged to audit the consolidated
financial statements and managements assessment of the effectiveness of Magnum
Hunters internal control over financial reporting, and to issue a report thereon. In
the conduct of the audit, Deloitte & Touche LLP was given unrestricted access to all
financial records and related data including minutes of all meetings of shareholders, the
Board of Directors and committees of the Board. Management believes that all
representations made to Deloitte & Touche LLP during the audit were valid and
appropriate. Their audit was made in accordance with standards of the Public Company
Accounting Oversight Board (United States) and included a review of the system of internal
controls to the extent considered necessary to determine the audit procedures required to
support their opinion on the consolidated financial statements, managements
assessment of our internal control over financial reporting and the effectiveness of
Magnum Hunters internal control over financial reporting. Their report begins on
page F-3.

|                                                           |                                                                       
|---------------------------------------------------------- | ----------------------------------------------------------------------
|/s/ Gary C. Evans  President and   Chief Executive Officer | /s/ M. Bradley Davis Senior Vice President and Chief Financial Officer

Irving, TexasMarch 15, 2005

F-1

REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and
StockholdersMagnum Hunter Resources, Inc.

We have audited the accompanying
consolidated balance sheets of Magnum Hunter Resources, Inc. and Subsidiaries (the
Company) as of December 31, 2004 and 2003, 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, 2004. Our audits
also included the financial statement schedule listed in the Index at 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 the consolidated financial statements and the financial statement schedule
based on our audits.

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

In our opinion, such consolidated
financial statements present fairly, in all material respects, the financial position of
Magnum Hunter Resources, Inc. and Subsidiaries (the Company) as of December
31, 2004 and 2003, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2004, 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
consolidated 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".

We have also audited, in accordance
with the standards of the Public Company Accounting Oversight Board (United States), the
effectiveness of the Companys internal control over financial reporting as of
December 31, 2004, based on the criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 15, 2005 expressed an unqualified opinion on managements
assessment of the effectiveness of the Companys internal control over financial
reporting and an unqualified opinion on the effectiveness of the Companys internal
control over financial reporting.

/s/ Deloitte & Touche LLPDallas, TexasMarch 15, 2005

F-2

REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and
StockholdersMagnum Hunter Resources, Inc.

We have audited managements
assessment, included in the accompanying Managements Report on Internal
Control Over Financial Reporting, included in Item 9A of this annual report on Form
10-K, that Magnum Hunter Resources, Inc. and Subsidiaries (the Company)
maintained effective internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal ControlIntegrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. The Companys
management is responsible for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on managements assessment and
an opinion on the effectiveness of the Companys internal control over financial
reporting based on our audit.

We conducted our audit in accordance
with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over financial
reporting, evaluating managements assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinions.

A companys internal control
over financial reporting is a process designed by, or under the supervision of, the
companys principal executive and principal financial officers, or persons performing
similar functions, and effected by the companys board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A companys internal control over
financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts
and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the financial statements.

Because of the inherent limitations
of internal control over financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements due to error or fraud may
not be prevented or detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods are
subject to the risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may
deteriorate.

In our opinion, managements
assessment that the Company maintained effective internal control over financial reporting
as of December 31, 2004, is fairly stated, in all material respects, based on the criteria
established in Internal ControlIntegrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2004, based on the criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission.

We have also audited, in accordance
with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements and the financial statement schedule as of and for the
year ended December 31, 2004 of the Company and our report dated March 15, 2005 expressed
an unqualified opinion on those consolidated financial statements and the financial
statement schedule.

/s/ Deloitte & Touche LLPDallas, TexasMarch 15, 2005

F-3

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

|                                                                                    | December 31, | December 31,
|----------------------------------------------------------------------------------- | ------------ | ------------
|
|ASSETS                                                                              |              |             
|Current Assets                                                                      |              |             
|Cash and cash equivalents                                                           |              |             
|Restricted cash                                                                     |              |             
|Accounts receivable                                                                 |              |             
|Trade, net of allowance of $4,776 and $4,331, respectively                          |              |             
|Notes receivable                                                                    |              |             
|Due from affiliates                                                                 |              |             
|Deferred income taxes, current                                                      |              |             
|Deposits                                                                            |              |             
|Available for sale investments                                                      |              |             
|Prepaid drilling costs                                                              |              |             
|Other current assets                                                                |              |             
|                                                                                    |              |             
|Total Current Assets                                                                |              |             
|Property, Plant and Equipment                                                       |              |             
|Oil and gas properties, full-cost method                                            |              |             
|Unproved                                                                            |              |             
|Proved                                                                              |              |             
|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                                                  |              |             
|Goodwill                                                                            |              |             
|                                                                                    |              |             
|Total Assets                                                                        |              |             
|                                                                                    |              |             
|LIABILITIES AND STOCKHOLDERS' EQUITY                                                |              |             
|Current Liabilities                                                                 |              |             
|Trade payables                                                                      |              |             
|Accrued interest                                                                    |              |             
|Accrued liabilities                                                                 |              |             
|Due to affiliates                                                                   |              |             
|Other current liabilities                                                           |              |             
|Revenues payable                                                                    |              |             
|Suspended revenue 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; 200,000,000 shares authorized,                      |              |             
|91,324,168 and 71,977,759 shares issued, respectively                               |              |             
|Additional paid-in capital                                                          |              |             
|Accumulated other comprehensive loss                                                |              |             
|Retained earnings                                                                   |              |             
|Common stock in deferred compensation plan, at cost (34,416 shares) .               |              |             
|Unearned common stock in KSOP, at cost (880,083 and 1,012,203 shares, respectively) |              |             
|                                                                                    |              |             
|                                                                                    |              |             
|Treasury stock, at cost (3,931,614 and 3,942,294 shares, respectively)              |              |             
|                                                                                    |              |             
|Total Stockholders' Equity                                                          |              |             
|                                                                                    |              |             
|Total Liabilities and Stockholders' Equity                                          |              |             
|                                                                                    |              |             

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

F-4

# MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED
STATEMENTS OF OPERATIONS (in thousands, except
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                                     |                                 
|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-5

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS) FOR THE YEAR 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-6

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS) FOR THE YEAR 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 $15,213                              |                 |              |                |                            |                                         |                       |                         |                                               |                            |                                  
|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-7

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
AND COMPREHENSIVE INCOME (LOSS) FOR THE YEAR ENDED
DECEMBER 31, 2004 (thousands)

|                                        | Preferred
Stock | Common
Stock | Treasury
Stock | Additional
Paid in
Capital | Retained
Earnings | Deferred
Compensation | Unearned
Shares
in
KSOP | Accumulated
Other
Comprehensive
Income (Loss) | Total
Stockholders'
Equity | Total
Comprehensive
Income (Loss)
|--------------------------------------- | --------------- | ------------ | -------------- | -------------------------- | ----------------- | --------------------- | ----------------------- | --------------------------------------------- | -------------------------- | ---------------------------------
|Balance at January 1, 2004              |                 |              | $              | 1                          |                   | $                     | 144                     |                                               | $                          | (25,040                          
|Issuance of 2,128 shares of common      |                 |             
|stock pursuant to employee stock option |                 |             
|plan                                    |                 |              |                |                            |                   |                       | 4                       |                                               |                            |                                  
|Issuance of 17,250 shares through       |                 |             
|secondary offering, net of offering     |                 |             
|costs                                   |                 |              |                |                            |                   |                       | 35                      |                                               |                            |                                  
|Stock compensation                      |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Deferred tax benefit on exercise of     |                 |             
|employee stock options                  |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Loan to KSOP to purchase 225 shares     |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Employer contribution of 223 shares to  |                 |             
|KSOP                                    |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Employee salary deferrals to KSOP,      |                 |             
|representing 134 shares                 |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Issuance of 11 shares for Directors'    |                 |             
|compensation                            |                 |              |                |                            |                   |                       |                         |                                               |                            | 75                               
|Net Income, net of income tax expense   |                 |             
|of $55,759                              |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Reclassification adjustments related to |                 |             
|derivative contracts, net of deferred   |                 |             
|income tax expense of $15,859           |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Change in fair value of outstanding     |                 |             
|hedge positions, net of deferred income |                 |             
|tax benefit of $15,038                  |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Amortization of purchased hedge         |                 |             
|positions, net of deferred income tax   |                 |             
|benefit of $279                         |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|                                        |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  
|Balance at December 31, 2004            |                 |              | $              | 1                          |                   | $                     | 183                     |                                               | $                          | (24,965                          
|                                        |                 |              |                |                            |                   |                       |                         |                                               |                            |                                  

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

F-8

# 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                                                              |                                 
|Non-cash directors' 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                                        |                                 
|(Payment) refund 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 for New Mexico property acquisition                                   |                                 
|Cash paid in Prize merger net of cash acquired                                  |                                 
|(Increase) 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 liability        |                                 
|Redemption of notes payable                                                     |                                 
|Proceeds from issuance of convertible notes                                     |                                 
|Loan repaid by stockholder                                                      |                                 
|Loan to KSOP                                                                    |                                 
|Loan repaid from KSOP                                                           |                                 
|Proceeds from issuance of common stock                                          |                                 
|Proceeds from issuance of secondary offering of common stock                    |                                 
|Proceeds from issuance of treasury stock                                        |                                 
|Purchase of warrants                                                            |                                 
|Purchase of treasury stock                                                      |                                 
|(Increase) decrease in restricted cash for payment of notes payable             |                                 
|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-9

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, advisory consulting and measurement
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 five gathering
systems located in Texas, Oklahoma and New Mexico 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, our 5% interest in Teal Hunter, LP
and our 40% interest in Appletree Holdings LLC. 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.

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 and Metrix,
collectively referred to as 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.

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.

We recorded an impairment on an
investment in the common stock of another entity whose stock was held by us for resale for
its full carrying value of $621 thousand during 2002. At December 31, 2003 and 2004, we
carried no value for our available-for-sale securities.

F-10

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

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

We use the full-cost method of
accounting for our investments in 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 into a full-cost
pool on a country-by-country basis as incurred. Internal costs that directly relate
to acquisition, exploration and development activities that were capitalized totaled $1.3
million for the years ended December 31, 2004 and 2003. The balance of capitalized costs
included in oil and gas properties for the years ended December 31, 2004 and 2003 were
$6.5 million and $5.2 million, respectively. Management believes that the basis we use to
determine the amount of internal costs capitalized is appropriate.

All capitalized costs of oil and gas
properties, including the estimated future costs to develop proved reserves and estimated
dismantlement and abandonment costs, net of salvage values, are amortized on the
unit-of-production method using estimates of proved reserves. Costs directly associated
with the acquisition and evaluation of unproved properties are excluded from the
amortization base until the related properties are evaluated. Such unproved properties are
assessed for impairment quarterly 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.

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.

A summary of the unproved properties
excluded from proved oil and gas properties being amortized at December 31, 2004 and 2003,
respectively, and the year in which they were incurred follows:

|                           | December 31, 2004
(in thousands)
|-------------------------- | --------------------------------
|
|Property Acquisition Costs |                                 
|Exploration Costs          |                                 
|                           |                                 
|Total                      |                                 
|                           |                                 

F-11

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

|                           | December 31, 2003
(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 capitalized costs are subject to
a ceiling test, which generally limits such costs less accumulated
amortization and related deferred income taxes to the aggregate of the estimated present
value of future net revenues from proved reserves discounted at ten percent based on
current economic and operating conditions less income tax effects related to the
differences between the book and tax basis of the oil and gas properties. The ceiling test
is performed on a quarterly basis. We experienced no impairment in 2004, 2003, or 2002.

For purposes of the ceiling test, we
remove the discounted present value included in our future development costs on our
reserve report for which we have already booked an obligation under SFAS 143. For purposes
of our depletion calculation, we include in future development costs the estimated
plugging and abandonment costs, net of estimated salvage values, for proved undeveloped
wells. For purposes of both of these calculations, we do not include plugging and
abandonment costs in our future development costs on developed proportions for which we
have booked an obligation under SFAS 143.

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

Amortization expense per thousand
cubic feet equivalent was $1.50, $1.28 and $1.17 for the years ended December 31, 2004,
2003 and 2002, respectively.

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 may utilize, from time to time,
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. 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. Changes in the fair value of derivative instruments that are
cash-flow hedges are recognized in other comprehensive income until such time as the
hedged items are recognized in net income. Ineffective portions of a derivative
instruments change in fair value are immediately recognized in net income.

F-12

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

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 three to 39 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 and monitoring services 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, 2004, we had four
stock-based employee compensation plans, which are described more fully in Note 13. We
currently account for our employee stock option 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 years ended December 31,
2003 and 2004, we recorded stock compensation expense of $3.0 million and $768 thousand,
respectively, 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. Our future accounting for
stock-based compensation will be impacted by the issuance of SFAS No. 123(R). Please see
our Recently Issued Statements discussion below for additional information.

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 earnings per share (EPS) would have been as shown in the
below pro forma tables (in thousands):

F-13

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

|                                                    | Year Ended December 31,
|--------------------------------------------------- | -----------------------
|
|Net income, as reported                             |                        
|Total  Stock-based  employee  compensation  expense |                        
|included  in  reported  net  income,  net of income |                        
|taxes of $278 and $1,144, respectively              |                        
|Deduct:  Total  stock-based  employee  compensation |                        
|determined  under fair  value-based  method for all |                        
|awards, net of income taxes of $1,871,  $2,896, and |                        
|$1,962 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:

|                                               | 2004(a)   | 2003(b)   | 2002     
|---------------------------------------------- | --------- | --------- | ---------
|Risk-free interest rate                        | 3.38%     | 1.58%     | 3.68%    
|Expected life                                  | 4.1 years | 2.1 years | 7.4 years
|Expected volatility                            | 40.7%     | 46.3%     | 49.5%    
|Dividend yield                                 | --        | --        | --       
|Weighted average fair value of options granted | $  3.81   | $  3.03   | $  3.17  

---

| | (a) | We granted 1,403,000 options during 2004, which had a reduced term of four
               years. Prior grants have ten-year terms.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------

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

Insurance Proceeds

As a result of damages incurred
during Hurricane Lili, we received proceeds of $904 thousand and $1 million, during the
years ended 2004 and 2003 respectively. We credited $608 thousand in each of the years
2004 and 2003 against proved property to represent damages paid for equipment losses. In
2004 and 2003, we included $296 thousand and $399 thousand, respectively, of these
proceeds in oil and gas sales, which represented business interruption proceeds.

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. We recorded a valuation allowance of $2.0 million on deferred
tax assets representing state operating loss carryforwards during 2004 due to
managements estimate that these operating loss carryforwards would not be realized
before their expiration.

F-14

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

Goodwill

As a result of our merger with Prize,
we currently have recorded $56.5 million of goodwill. 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, 2004, 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

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.

Recently Issued Statements

The Financial Accounting Standards
Board (FASB) has issued FASB Staff Position (FSP) No. 142-2,
Application of FASB Statement 142, Goodwill and Other Intangible Assets, to
Oil-and-Gas Producing Entities after evaluating an issue involving the classification of
mineral rights. In June 2001, FASB issued Statement of Financial Accounting Standards
(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 was raised regarding whether these mineral
rights should be classified as tangible or intangible assets. FSP No. 142-2 addressed this
issue and supports our current accounting treatment of mineral rights and will not impact
our financial statements. This FSP is effective for reporting periods beginning after
September 2, 2004.

FASB issued FSP FAS 129-1,
Disclosure Requirements Under FASB Statement No. 129, Disclosure of Information
About Capital Structure, in April 2004. This FSP provides additional guidance on the
disclosure requirements of contingently convertible securities. We have made the required
disclosures related to the terms of our Convertible Notes and have provided explanations
in Note 5 about the dilutive effects of these notes on our earnings per share.

FASBs Emerging Issues Task
Force (EITF) has issued an EITF Abstract for EITF Issue No. 04-8, The
Effect of Contingently Convertible Debt on Diluted Earnings per Share, which
addresses the issue of when the dilutive effects of contingently convertible debt
instruments should be included in diluted earnings per share. This guidance would require
companies to include the dilutive effect of convertible debt securities in diluted
earnings per share regardless of whether or not the contingent conversion features have
been triggered. This EITF is effective for periods ending after December 15, 2004. We have
accordingly included approximately 94 thousand potential shares to be issued for our
Convertible Notes in our earnings per share computations for the year ending 2004 based on
the spread between our average market price during the year and the conversion price on
these notes. We did not include any potential dilution for the 2003 period because the
conversion price did not exceed our average market price during that period.

F-15

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

The SEC Staff Accounting Bulletin
(SAB) 106 was released in September 2004. SAB 106 expresses the SEC
staffs views on the interaction of SFAS No. 143 and the full cost method and
provides guidance on computing the full cost ceiling as well as depreciation, depletion,
and amortization. The SAB also requires additional disclosures regarding how the
application of SFAS No. 143 has affected the ceiling test and depreciation, depletion and
amortization. This guidance is effective for the first fiscal quarter beginning after its
publication. We implemented this guidance for our ceiling test and depletion calculations
during the fourth quarter of 2004 and experienced no significant impact.

FASB issued SFAS No. 123(R),
Share-Based Payment, during December 2004. Under this revised guidance, all
share-based equity and liability instruments will be recorded as compensation expense
based on their fair values, and all liability instruments will be remeasured each
reporting period. This guidance will be effective as of the beginning of the first annual
or interim reporting period that begins after June 15, 2005, which would cause us to adopt
this statement July 1, 2005. We currently account for our stock-based compensation under
the prospective method, under which we only record compensation expense on awards granted
after 2003. Upon adoption of this statement, we will apply the modified prospective method
to our equity instruments under which compensation expense will also be recorded on the
unvested portions of awards granted prior to 2003. At this time, we estimate the pre-tax
impact of these prior years grants on 2005 earnings to be an additional pre-tax
expense of $1.2 million.

FASB also issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29", during
December 2004. SFAS No. 153 amends APB Opinion No. 29 by eliminating the exception from
fair value measurement prescribed in that statement and replaces it with an exception for
exchanges that have no significant impact on future cash flows. This statement is
effective for exchanges that take place in fiscal periods beginning after June 15, 2005.
We do not expect this statement to have an impact on our future financial results.

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.

F-16

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

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                        |                   
|Convertible Notes               |                   
|Options                         |                   
|                                |                   
|Diluted EPS                     |                   
|Income available to common      |                   
|stockholders and assumed        |                   
|conversions                     |                   
|Less:  Cumulative Effect        |                   
|                                |                   
|Income before Cumulative Effect |                   
|                                |                   

At December 31, 2004, we had
7,228,457 warrants outstanding at a weighted average exercise price of $15.00 per share,
5,938,102 options outstanding at a weighted average price of $7.88 per share, and no
outstanding convertible preferred stock. Warrants totaling 7,228,457 shares and options
totaling 376,125 shares were excluded from the diluted net income per share computation in
2004 because their exercise price exceeded the average market price of our stock. There
was a 93,750 share dilutive effect from our Convertible Notes for the year ending December
31, 2004. Please see Note 5 for a discussion of the conversion features of these Notes.

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 exercise 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 as the exercise price exceeded the average market price of our common stock. There
was no dilutive effect from our Convertible Notes because their conversion price exceeded
the average market price during the period, and only the conversion spread is issuable in
shares.

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.

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.
Current revenues are accrued based on expectations of actual deliveries and actual prices
received. Plant revenues are recognized as product is sold, and our gathering fees are
recognized as the gathering services are performed. Revenues for our oilfield management
services segment are recognized as services are performed and equipment is delivered.

F-17

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

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 30, 2004, we purchased oil
and gas properties located in the state of New Mexico, primarily in Lea and Eddy counties
for $239.1 million, subject to certain purchase price adjustments. The properties include
both proved producing oil and gas wells and proved undeveloped leasehold mineral
interests. The effective date of the acquisition was May 1, 2004. We purchased additional
properties related to this acquisition during September 2004 for a purchase price of $1.4
million, net of certain purchase price adjustments. We also recorded additional asset
retirement obligations of $1.5 million as a result of the acquisition. Pro forma
information related to this acquisition has not been presented, as the effect was not
material to our historical results of operations.

On August 30, 2004, we entered into
an agreement to purchase approximately 170 producing wells located in the Permian Basin of
West Texas for $40 million, net of certain purchase price adjustments. Closing occurred on
October 29, 2004 and had an effective date of September 1, 2004. Pro forma information
related to this acquisition has not been presented, as the effect was not material to our
historical results of operations.

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. Pro forma information related to this
acquisition has not been presented, as the effect was not material to our historical
results of operations.

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

F-18

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

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.

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, 2004 was $56.5 million. Also in accordance with
SFAS No. 142, we performed a goodwill impairment test at December 31, 2004. 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 taxes                |  |  |   | (40,677  | )
|Other non-current liabilities        |  |  |   | (2,548   | )
|                                     |  | 
|Historical net assets acquired       |  |  | $ | 148,272  |  
|                                     |  | 

F-19

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 and 2004, are as follows (in
thousands):

|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 |  
|Goodwill acquired                  |  |  |   | --     |  
|Purchase price adjustments         |  |  |   | --     |  
|Adjustment for divested properties |  |  |   | --     |  
|                                   |  | 
|Balance at December 31, 2004       |  |  | $ | 56,467 |  
|                                   |  | 

The following summary, prepared on a
pro forma basis, presents the results of operations for the year ended December 31, 2002,
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,
2002
|---------------------------------- | ----------------------------
|Revenue                            |                             
|Total Operating Costs and Expenses |                             
|                                   |                             
|Operating Profit                   |                             
|Interest Expense and Other         |                             
|                                   |                             
|Income before Tax                  |                             
|Benefit for Income Tax             |                             
|                                   |                             
|Net Income                         |                             
|Net Income Per Common Share        |                             
|Basic                              |                             
|Diluted                            |                             

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. We have included $1.2 million of our
asset retirement obligations in other current liabilities at December 31, 2004.

F-20

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, 2004 (in thousands):

|Beginning balance at January 1, 2004 |  |  | $ | 32,489 |  
|------------------------------------ |  |  | - | ------ | -
|Liabilities incurred                 |  |  |   | 7,260  |  
|Liabilities settled                  |  |  |   | (761   | )
|Liabilities sold/disposed            |  |  |   | (1,120 | )
|Accretion expense                    |  |  |   | 2,941  |  
|Change in retirement cost estimates  |  |  |   | 468    |  
|                                     |  | 
|Ending balance at December 31, 2004  |  |  | $ | 41,277 |  
|                                     |  | 

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, 2004 and 2003, our
note receivable from the Magnum Hunter 401(k) Employee Stock Ownership Plan (KSOP) was
$6.2 million and $6.1 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, 2005, and is secured by shares of the companys common stock which have
not been earned by participants in the KSOP. At December 31, 2004 and 2003, the number of
unearned shares in the KSOP were 880,083 and 1,012,203, respectively. The unearned shares
and their corresponding costs were reflected on our consolidated balance sheets as
reductions to stockholders equity.

There are no loans or extensions of
credit to directors and executive officers of Magnum Hunter as of December 31, 2003 or
2004.

F-21

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

NOTE 5  DEBT

Notes payable and long-term debt at
December 31, 2004 and 2003 consisted of the following (in thousands):

|                                                              | 2004 | 2003
|------------------------------------------------------------- | ---- | ----
|Long-Term Debt:                                               |      |     
|Bank debt under revolving credit agreements due May 2, 2007,  |      |     
|3.92% at December 31, 2004                                    |      |     
|Capital lease obligations, 5.58% at December 31, 2004         |      |     
|Senior unsecured notes, due March 15, 2012, 9.6%              |      |     
|Floating rate convertible senior notes, due December 15, 2023 |      |     
|2.49% at December 31, 2004                                    |      |     
|Production payment liability, non-recourse                    |      |     
|                                                              |      |     
|                                                              |      |     
|Less current portion                                          |      |     
|                                                              |      |     
|Total Long-Term Debt                                          |      |     
|                                                              |      |     

The following table presents the
approximate annual maturities of debt:

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

We have a Senior Bank Credit Facility
(Facility), which provides for total borrowings of $750 million, on which our
borrowing base was limited to $525 million at December 31, 2004. The level of the
borrowing base is dependent on the valuation by the lenders of the assets pledged, which
are primarily oil and gas reserves.

During 2004, we amended our Facility
in April, July, and October to ultimately increase the borrowing base to $525 million, up
$270 million from our previous $255 million borrowing base. We also extended the
expiration date of the Facility to May 2, 2007. The amended facility allowed us to use
proceeds from our secondary common stock offering to redeem and retire $105 million in
principal of our 9.6% Senior Notes outstanding. We used the increased borrowing base to
fund the costs of issuing our Convertible Notes and to fund the acquisitions of oil and
gas properties in New Mexico and West Texas. The Facility provides for both a LIBOR and
Base rate (Prime) interest rate option. At December 31, 2004, we had no
borrowings under the Base rate option and $320 million outstanding at LIBOR + 1.50%. 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,
2004, we had available credit under this Facility of $202.5 million.

Our Facility includes covenants, the
most restrictive of which requires maintenance of a funded debt to EBITDA ratio and an
interest coverage ratio, as defined in the loan agreement. We were in compliance with the
covenants in 2003 and 2004. 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, the partial redemption of our 9.6% 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 over the next six months. The last redetermination date had
an effective date of June 30, 2004, and was completed on October 15, 2004. This
redetermination increased our borrowing base by $45 million. Our next redetermination date
will have an effective date of December 31, 2004, and has an estimated completion date of
no later than May 9, 2005.

F-22

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

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 5.58% at December 31, 2004.

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. On August 27, 2004, we redeemed $105 million in
principal of our 9.6% Senior Notes at a redemption price of 109.6% of par. We paid the
holders of these redeemed notes $115.1 million plus accrued and unpaid interest of $4.5
million. We used a portion of the proceeds from our secondary offering to fund this
redemption. We recorded $12.3 million in costs associated with this redemption comprised
of $10.1 million in premiums and $2.2 million in unamortized deferred financing fees which
were written off.

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 rate on the Convertible Notes was
2.49% at December 31, 2004. 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. If repurchase is elected, 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 reduce borrowings under the Facility by
approximately $25 million.

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.

F-23

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

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.

Metrix has a $500 thousand revolving
credit facility with a lender. This facility matures on December 16, 2005 and is governed
by a borrowing base. Magnum Hunter is a guarantor to this facility. As of December 31,
2004, there were no borrowings outstanding under this facility.

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 at
December 31, 2003 and was paid in full in 2004.

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):

|                                      | 2004 | 2003 | 2002
|------------------------------------- | ---- | ---- | ----
|Income tax expense at statutory rates |      |      |     
|Federal tax expense                   |      |      | $   
|State tax expense                     |      |      |     
|Adjustment of deferred state tax rate |      |      |     
|Change in valuation allowance         |      |      |     
|Other                                 |      |      |     
|                                      |      |      |     
|Tax expense (benefit)                 |      |      | $   
|                                      |      |      |     

F-24

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 |             
|Plugging costs and other                                    |             
|                                                            |             
|Total deferred tax liability                                |             
|                                                            |             
|Allowance for doubtful accounts                             |             
|Depletion carryforwards                                     |             
|Derivative instruments                                      |             
|Alternative minimum tax credit                              |             
|Employee stock options                                      |             
|Operating loss and other carryforwards                      |             
|Other                                                       |             
|                                                            |             
|Total deferred tax assets                                   |             
|                                                            |             
|Valuation allowance on state NOL carryforwards              |             
|                                                            |             
|Net Deferred Tax Liability                                  |             
|                                                            |             

During 2004, an adjustment was made
to lower deferred state income taxes payable by $4.8 million to reflect a change in our
deferred state income tax rate from 2.875% to 1.2%, due to an increase in income not
subject to state income taxes. In addition, during 2004, a valuation allowance of $2
million was established for state NOL carryforwards, due primarily to a five-year state
carryforward limitation, and the likelihood that these NOLs would not be realized
before expiration.

Magnum Hunter and our subsidiaries
have net operating loss carryforwards of approximately $113.8 million that expire, if
unused, in years 2012 through 2023. 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.

F-25

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

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,
2004.

Warrants

The following is a summary of warrant
activity for the periods ended December 31, 2004, 2003 and 2002:

|                                | 2004 | 2003 | 2002
|------------------------------- | ---- | ---- | ----
|
|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.

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.

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, 2004, approximately 4.2 million shares had been repurchased under
these two programs, and approximately 818 thousand shares remained available for
repurchase.

F-26

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

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.

On June 30, 2004, we sold 15 million
shares of Magnum Hunter common stock at $10.25 per share under a previously filed
universal shelf registration statement. The proceeds from this issuance were $147.2
million, net of offering costs. We also granted the underwriters an option to purchase an
additional 2.25 million shares to cover over-allotments, which they exercised on July 2,
2004. The net proceeds from this sale were approximately $22.1 million. We used proceeds
from these issuances to finance a portion of our acquisition of oil and gas properties in
the state of New Mexico (see Note 2) and to redeem a portion of our 9.6% Senior Notes (see
Note 5).

We issued 2.1 million, 270 thousand
and 985 thousand shares pursuant to employee stock option exercises for proceeds of $10.4
million, $1.2 million and $3.6 million during 2004, 2003 and 2002, respectively. Upon the
exercise of warrants, we issued 548 thousand treasury shares for proceeds of $3.4 million
during 2003. Of the treasury shares issued for warrants in 2003, 37 thousand shares were
issued in a cashless exercise of 134 thousand warrants. No warrants were exercised in
2004.

Our KSOP purchased 225 thousand, 486
thousand and 532 thousand shares at costs of $2.3 million, $2.7 million and $3.7 million
during 2004, 2003 and 2002, respectively. During the same periods, the KSOP released
shares totaling 357 thousand, 231 thousand and 244 thousand to participants. During 2004,
2003 and 2002, we made new loans to the KSOP of $2.3 million, $2.7 million and $3.7
million and the KSOP repaid loan amounts of $2.2 million, $1.5 million, and $1.3 million,
respectively. Of the 2004 repayments, $1.3 million represented our contribution of 223
thousand shares to the plan. Of the 2003 repayments, $1.1 million represented our
contribution of 172 thousand shares to the KSOP plan. Additionally, in 2002, we
contributed 158 thousand shares to our 401(K) plan.

NOTE 8 
SUPPLEMENTAL CASH FLOW INFORMATION

During 2004, we contributed 223
thousand shares of our common stock valued at a cost of $1.3 million to our KSOP plan.
Interest paid on our outstanding indebtedness was $49.7 million. Tax payments in 2004 were
$2.6 million.

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.

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.

F-27

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

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):

|Year Ended December 31:         |  |  |   |       | 
|------------------------------- |  |  | - | ----- | 
|2005                            |  |  | $ | 2,381 | 
|2006                            |  |  |   | 1,129 | 
|2007                            |  |  |   | 950   | 
|2008                            |  |  |   | 751   | 
|2009                            |  |  |   | 559   | 
|Thereafter                      |  |  |   | 762   | 
|                                |  | 
|Total Minimum Payments Required |  |  | $ | 6,532 | 
|                                |  | 

Rental expense was $2.3 million, $2.3
million, and $2.2 million for 2004, 2003 and 2002, respectively.

In the past we have provided trade
guarantees on behalf of an unconsolidated affiliate which has since been sold. The last of
these guarantees expired in July 2003. On February 18, 2005 our 40% owned subsidiary,
Apple Tree Holdings, LLC entered into a $20.6 million construction loan agreement
(Construction Loan). The Construction Loan provides financing for the
construction of a processing plant, natural gas lateral, carbon dioxide line and related
infrastructure in Huerfano County, Colorado. The Construction loan bears interest at
either LIBOR plus 2.25% or a base rate plus 1.25% and will mature no later than July 31,
2006. We have provided a guaranty to the lender for this Construction Loan. In return for
our guaranty, we received an up-front cash payment as well as 55% distribution of cash
flows from the entity until certain financial tests are met. In the event that the
Construction Loan goes into default and Magnum Hunter has to pay on the guaranty, we will
have recourse against the project and related subsidiaries.

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, 2004, we recorded $841
thousand in additional allowances for doubtful accounts. During the year ended December
31, 2003 we recorded $231 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, 2004 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, 2004
and 2003, we provided a reserve for the carrying value of a note receivable of $1.2
million. After establishing this reserve, management believes those market values
approximate carrying values at December 31, 2004 and 2003. The market values of equity
investments are based upon quoted market prices (see Note 1). At December 31, 2004, 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 $221.3 million and the
fair value of the Convertible Notes was $151.7 million.

F-28

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

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, 2004, we had open contracts with the following
terms:

|Commodity   | Type   | Volume/Day   | Duration        | Wtd. Avg. Price
|----------- | ------ | ------------ | --------------- | ---------------
|Natural Gas | Collar | 60,000 MMBTU | Jan 05 - Dec 05 | $4.21 - $6.85  
|Natural Gas | Swap   | 20,000 MMBTU | Jan 05 - Dec 05 | $          6.25
|Natural Gas | Collar | 20,000 MMBTU | Jan 06 - Dec 06 | $5.25 - $6.30  
|Crude Oil   | Swap   | 1,000 BBL    | Jan 05 - Dec 05 | $         34.90
|Crude Oil   | Collar | 1,000 BBL    | Jan 05 - Dec 05 | $35.00 - $55.00
|Crude Oil   | Collar | 1,000 BBL    | Jan 06 - Dec 06 | $30.00 - $35.85

At December 31, 2004, based on future
market prices, the fair value of our open commodity derivative contracts were as follows
(in thousands):

|Derivative Assets            |  |  |   |         |  
|---------------------------- |  |  | - | ------- | -
|                             |  | 
|Natural gas collars          |  |  | $ | 207     |  
|                             |  | 
|Total derivative assets      |  |  | $ | 207     |  
|                             |  |  |   |         |  
|Derivative Liabilities       |  | 
|                             |  | 
|Natural gas collars          |  |  | $ | (13,847 | )
|Natural gas swaps            |  |  |   | (528    | )
|Crude oil collars            |  |  |   | (2,343  | )
|Crude oil swaps              |  |  |   | (3,310  | )
|                             |  | 
|Total derivative liabilities |  |  | $ | (20,028 | )
|                             |  | 
|Net derivative liabilities   |  |  | $ | (19,821 | )
|                             |  | 

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. The net derivative balance of $4.0
million was amortized as a charge to other non-cash hedging adjustments over the remaining
life of the derivative contracts.

At December 31, 2004, we had five
crude oil derivatives and seven natural gas derivatives, which are categorized in the
tables above. The net fair value of these derivatives was $19.8 million, recognized as a
$207 thousand derivative asset and a $20.0 million derivative liability. For the year
ended December 31, 2004, the consolidated statement of operations includes a loss of $21.8
million related to crude oil derivatives and a loss of $23.2 million related to natural
gas derivatives, including amounts reclassified out of other comprehensive income. The
consolidated statement of operations also included a non-cash hedging ineffectiveness gain
of $332 thousand related to crude oil and natural gas derivatives and a non-cash gain of
$792 million related to the amortization of hedge contracts acquired in the Prize merger.
It is estimated at this time that $8.8 million of other comprehensive loss will be
reclassified to the consolidated statement of operations during the next 12 months.

Net losses related to crude oil and
natural gas derivative transactions for the years ended December 31, 2004, 2003 and 2002
were $43.9 million, $72.4 million and $9.9 million, respectively.

NOTE 13  STOCK
COMPENSATION PLANS

We have four 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 Plan (the 1996 Option Plan), and (iii) the Magnum
Hunter Resources, Inc. 2002 Incentive Stock Option Plan (the 2002 Option
Plan). In addition, we made non-incentive stock option grants in 2004, 2003 and
2002.

F-29

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

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 2004, we loaned the KSOP $2.3
million to purchase 224,600 shares of our common stock on the open market at an average
price of $10.06 per share. During 2004, employees purchased 133,638 shares of the
KSOPs unreleased shares at an average price of $6.04 per share through salary
deferrals. Employee purchases totaled $807 thousand, which the KSOP used to repay that
portion of its outstanding loan, and 133,638 shares were allocated among the Plan
participants. We contributed $1.3 million to the KSOP in December 2004 as a discretionary
contribution under the Plan. The KSOP then repaid that portion of its outstanding loan and
223,081 shares were allocated among participants.

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 $3.7
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 $473 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.

The KSOP loan is interest-free and
due December 31, 2005. The loan was secured by 880,083 shares and 1,012,203 shares of our
common stock at December 31, 2004 and 2003, 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, 2004 |             
|and 2003, respectively                               |             
|                                                     |             

The KSOP expense for the years ending
December 31, 2004, 2003 and 2002, was $3.6 million, $1.6 million, and $997 thousand,
respectively.

F-30

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

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 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.

On July 1, 2004, the Board granted
1,336,500 new stock options to employees as part of the 2004 compensation package. These
options carry an exercise price of $10.48 and were unvested on December 31, 2004. They
will expire July 1, 2009. During 2004, we also issued 116,500 options to certain employees
and board members. These options carry a weighted average exercise price of $9.70 and have
a weighted average remaining life of 6.39 years.

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

|                                | 2004 | 2003 | 2002
|------------------------------- | ---- | ---- | ----
|
|Outstanding - Beginning of Year |      |      |     
|Granted                         |      |      |     
|Exercised                       |      |      |     
|Cancelled                       |      |      |     
|                                |      |      |     
|Outstanding - End of Year       |      |      |     
|                                |      |      |     
|Exercisable - End of Year       |      |      |     
|                                |      |      |     

F-31

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

The following is a summary of stock options
outstanding at December 31, 2004:

|Exercise
Price | Number of
Options
Outstanding | Weighted Average
Remaining Contractual
Life (Years) | Number of
Exercisable
Options
|-------------- | ----------------------------- | --------------------------------------------------- | -----------------------------
|5.01           |                               |                                                     |                              
|5.20           |                               |                                                     |                              
|5.23           |                               |                                                     |                              
|5.38           |                               |                                                     |                              
|5.45           |                               |                                                     |                              
|5.46           |                               |                                                     |                              
|5.61           |                               |                                                     |                              
|5.82           |                               |                                                     |                              
|5.92           |                               |                                                     |                              
|6.625          |                               |                                                     |                              
|7.20           |                               |                                                     |                              
|7.51           |                               |                                                     |                              
|7.55           |                               |                                                     |                              
|7.57           |                               |                                                     |                              
|7.75           |                               |                                                     |                              
|7.90           |                               |                                                     |                              
|7.9375         |                               |                                                     |                              
|7.95           |                               |                                                     |                              
|8.44           |                               |                                                     |                              
|8.50           |                               |                                                     |                              
|9.19           |                               |                                                     |                              
|9.3125         |                               |                                                     |                              
|10.48          |                               |                                                     |                              
|11.08          |                               |                                                     |                              
|12.00          |                               |                                                     |                              
|12.89          |                               |                                                     |                              
|               |                               |                                                     |                              
|               |                               |                                                     |                              
|               |                               |                                                     |                              

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, 2004, we recorded expense of $768 thousand 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. During 2003, we purchased
approximately 53 thousand shares at a cost of $295 thousand, contributed approximately 18
thousand treasury shares with a market value of $100 thousand, and released approximately
36 thousand shares of participants who elected not to defer under the plan. We were
holding approximately 34 thousand shares in the plan at December 31, 2003. During 2004, no
activity occurred in the plan; therefore, we were holding approximately 34 thousand shares
in the plan at December 31, 2004.

F-32

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

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

Mr.    
          Gary C. Evans, Mr. Richard R. Frazier, Mr. M. Bradley Davis, 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 2005 is $475,000. 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 2005 is $300,000. Mr. Davis 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. Davis salary for
          the year 2005 is $200,000. 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 2005 is $200,000. 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 2005 is $225,000. 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 2005 is $195,000. 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. Davis, 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, operation, and monitoring 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 five 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. Segment data for the three years
ended December 31, 2004, 2003 and 2002 are as follows (in thousands):

F-33

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

|2004:                                          | Exploration &
Production | Gas Gathering,
Marketing &
Processing | Oil Field
Services | All Other | Elimination | Consolidated
|---------------------------------------------- | ------------------------ | ------------------------------------- | ------------------ | --------- | ----------- | ------------
|Revenue from external customers                |                          |                                       | $                  | 443,412   |             | $           
|Intersegment revenues                          |                          |                                       |                    | 1,972     |             |             
|Depreciation, depletion, amortization and      |                          |                                      
|accretion                                      |                          |                                       |                    | 123,567   |             |             
|Segment profit (loss)                          |                          |                                       |                    | 215,196   |             |             
|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                    |                          |                                       |                    |           |             |             
|                                               |                          |                                       |                    |           |             |             
|Net income                                     |                          |                                       |                    |           |             |             
|                                               |                          |                                       |                    |           |             |             
|Capital expenditures (net of asset sales)      |                          |                                       | $                  | 513,844   |             | $           

|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 benefit                |                          |                                       |                    |           |             |             
|Deferred income tax expense               |                          |                                       |                    |           |             |             
|Cumulative effect of a change in          |                          |                                      
|accounting principle                      |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Net income                                |                          |                                       |                    |           |             |             
|                                          |                          |                                       |                    |           |             |             
|Capital expenditures (net of asset sales) |                          |                                       | $                  | 157,481   |             | $           

F-34

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

|2002:                                     | Exploration &
Production | Gas Gathering,
Marketing &
Processing | Oil Field
Services | All Other | Elimination | Consolidated
|----------------------------------------- | ------------------------ | ------------------------------------- | ------------------ | --------- | ----------- | ------------
|Revenue from external customers           |                          |                                       | $                  | 240,964   |             | $           
|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   |             | $           

|                        | Exploration &
Production | Gas Gathering,
Marketing &
Processing | Oil Field
Services | All Other | Elimination | Consolidated
|----------------------- | ------------------------ | ------------------------------------- | ------------------ | --------- | ----------- | ------------
|As of December 31, 2004 |                          |                                       |                    |           |             |             
|                        |                          |                                       |                    |           |             |             
|Segment assets          |                          |                                       | $                  | 1,616,712 |             | $           
|As of December 31, 2003 |                          |                                      
|                        |                          |                                       |                    |           |             |             
|Segment assets          |                          |                                       | $                  | 1,142,621 |             | $           

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, 2004 and 2003 and condensed consolidating statements of operations and cash
flows for the years ended December 31, 2004, 2003 and 2002 are as follows:

F-35

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

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

|December 31, 2004                         
|------------------------------------------
|
|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, 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
|                                          

F-36

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, 2004          
|--------------------------------------
|
|Revenues                              
|Expenses                              
|                                      
|Income before                         
|Equity in net earnings of subsidiaries
|                                      
|Income (loss) before income taxes     
|Income tax provision                  
|                                      
|Net Income                            
|                                      

|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                            
|                                      

F-37

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, 2004                     
|-------------------------------------------------
|
|Cash flow from operating activities              
|Cash flow used 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, 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 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-38

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

NOTE 17  SUMMARY OF
QUARTERLY DATA (Unaudited)

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

|                                          | 2004
|----------------------------------------- | ----
|
|Revenues                                  |     
|Depreciation, depletion, amortization and |     
|accretion                                 |     
|Operating Profit                          |     
|Cost of early debt retirement             |     
|Net Income                                |     
|Income per common share, basic            |     
|Income per common share, diluted          |     

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

NOTE 18  RECENT ANNOUNCEMENT
TO BE ACQUIRED BY CIMAREX ENERGY

On January 26, 2005, Magnum Hunter
and Cimarex Energy, Inc. announced that their respective boards of directors had approved
an agreement and plan of merger that provides for the acquisition of Magnum Hunter by
Cimarex. Closing is anticipated before the end of the second quarter in 2005, subject to
customary regulatory approvals.

Under the terms of the proposed
agreement, Magnum Hunter shareholders will receive 0.415 shares of Cimarex common stock
for each share of Magnum Hunter common stock that they own. The merger is expected to be
non-taxable to the shareholders of both companies. In addition to the merger consideration
and prior to closing, Magnum Hunter intends to distribute its ownership interest in TEL
Offshore Trust to its common stockholders as a special dividend.

Cimarex Energy Co., headquartered in
Denver, CO, is an independent oil and gas exploration and production company with
operations focused in the Mid-Continent and Gulf Coast areas of the U.S. Its principal
operations offices are located in Tulsa, New Orleans and Houston.

F-39

MAGNUM HUNTER
RESOURCES, INC. AND SUBSIDIARIESSUPPLEMENTAL 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, 2002, 2003 and 2004 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. During
2004, we incurred additional liabilities of $7.3 million, settled or sold liabilities of
$1.9 million, and recorded accretion expense of $2.9 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 and 2004 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 and 2004. We have included the cost
associated with the liabilities incurred during 2003 and 2004 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, 2002         |            |           
|Proved Reserves           |            |           
|Proved Developed Reserves |            |           
|December 31, 2003         |            |           
|Proved Reserves           |            |           
|Proved Developed Reserves |            |           
|December 31, 2004         |            |           
|Proved Reserves           |            |           
|Proved Developed Reserves |            |           

F-40

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

We included estimated quantities in
the above table which we claim exclusively through our gas plant ownership. The amounts
attributable to our ownership in gas plants are as follows:

|                          | Oil
(Mbbl) | Gas
(MMcf) | NGL
(Mbbl)
|------------------------- | ---------- | ---------- | ----------
|December 31, 2002         |            |            |           
|Proved Reserves           |            |            |           
|Proved Developed Reserves |            |            |           
|December 31, 2003         |            |           
|Proved Reserves           |            |            |           
|Proved Developed Reserves |            |            |           
|December 31, 2004         |            |           
|Proved Reserves           |            |            |           
|Proved Developed Reserves |            |            |           

The changes in proved reserves for
the years ended December 31, 2002, 2003 and 2004 were as follows:

|                              | Oil
(Mbbl) | Gas
(MMcf)
|----------------------------- | ---------- | ----------
|Reserves at December 31, 2001 |            |           
|                              |            |           
|Purchase of minerals-in-place |            |           
|Sale of minerals-in-place     |            |           
|Extensions and discoveries    |            |           
|Production                    |            |           
|Revisions of estimates        |            |           
|                              |            |           
|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 |            |           
|                              |            |           
|Purchase of minerals-in-place |            |           
|Sale of minerals-in-place     |            |           
|Extensions and discoveries    |            |           
|Production                    |            |           
|Revisions of estimates        |            |           
|                              |            |           
|Reserves at December 31, 2004 |            |           
|                              |            |           

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, 2004, 2003 and
2002 were as follows (in thousands):

|                                                  | 2004 | 2003 | 2002
|------------------------------------------------- | ---- | ---- | ----
|Unproved oil and gas properties                   |      |      | $   
|Proved properties                                 |      |      |     
|                                                  |      |      |     
|Gross Capitalized Costs                           |      |      |     
|Accumulated depreciation, depletion, amortization |      |     
|and impairment                                    |      |      |     
|                                                  |      |      |     
|Net Capitalized Costs                             |      |      | $   
|                                                  |      |      |     

F-41

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

Capitalized costs incurred in oil and
gas producing activities during the years ended December 31, 2004, 2003 and 2002 were as
follows (in thousands):

|                           | 2004 | 2003 | 2002
|-------------------------- | ---- | ---- | ----
|Property acquisition costs |      |      |     
|Proved properties          |      |      | $   
|Unproved properties        |      |      |     
|Exploration costs          |      |      |     
|Development costs          |      |      |     
|                           |      |      |     
|Total Costs Incurred       |      |      | $   
|                           |      |      |     

Results of operations from oil and
gas producing activities for the years ended December 31, 2004, 2003 and 2002 were as
follows (in thousands):

|                                                  | 2004 | 2003 | 2002
|------------------------------------------------- | ---- | ---- | ----
|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, 2004, 2003 and 2002 were as follows (in thousands):

|                                                         | 2004 | 2003 | 2002
|-------------------------------------------------------- | ---- | ---- | ----
|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, 2004, 2003 and 2002 were as follows (in thousands):

|                                                       | 2004 | 2003 | 2002
|------------------------------------------------------ | ---- | ---- | ----
|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                                             |      |      | $   
|                                                       |      |      |     

F-42

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

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-43

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

None.

Item 9A. Controls and
Procedures

Managements
Evaluation of Disclosure Controls and Procedures

As indicated in the certifications in
Exhibit 31 of this report, our chief executive officer and chief financial officer have
evaluated our disclosure controls and procedures as of December 31, 2004. Based on that
evaluation, these officers have concluded that our disclosure controls and procedures are
effective in ensuring that material information required to be in this annual report is
made known to them on a timely basis.

Managements Report
on Internal Control over Financial Reporting

Management, including our chief
executive officer and chief financial officer, is responsible for establishing and
maintaining adequate internal control over our financial reporting. Management conducted
an evaluation of the effectiveness of internal control over financial reporting based on
the Internal Control  Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation, management concluded
that our internal control over financial reporting was effective as of December 31, 2004.

Managements assessment of the
effectiveness of internal control over financial reporting as of December 31, 2004, was
audited by Deloitte & Touche, LLP, an independent registered public accounting firm,
as stated in their report beginning on page F-3 of the Financial Section of this report.

Changes in Internal
Control over Financial Reporting

There were no changes during our last
fiscal quarter that materially affected, or are reasonably likely to materially affect our
internal control over financial reporting.

Item 9B. Other Information

None

55

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                                                
|------------------- | --- | -----------------------------------------------------
|Jerry Box           | 66  | Chairman of the Board                                
|Gary C. Evans       | 47  | President and Chief Executive Officer                
|Richard R. Frazier  | 58  | Executive Vice President and Chief Operating Officer 
|M. Bradley Davis    | 45  | Senior Vice President and Chief Financial Officer    
|R. Douglas Cronk    | 58  | Senior Vice President of Operations of Magnum Hunter 
|                    |     | Production, Inc. and Gruy                            
|Charles R. Erwin    | 58  | Senior Vice President of Exploration of Magnum Hunter
|                    |     | Production, Inc. and Gruy                            
|Morgan F. Johnston  | 44  | Senior Vice President, General Counsel and Secretary 
|David S. Krueger    | 55  | Vice President and Chief Accounting Officer          
|Gregory L. Jessup   | 51  | Vice President Land - Offshore of Magnum Hunter      
|                    |     | Production Inc. and Gruy                             
|Richard S. Farrell  | 47  | Vice President Land - Onshore of Magnum Hunter       
|                    |     | Production, Inc. and Gruy                            
|David M. Keglovits  | 52  | Vice President and Controller                        
|Earl Krieg, Jr      | 51  | Vice President of Engineering of Magnum Hunter       
|                    |     | Production, Inc. and Gruy                            
|Howard M. Tate      | 37  | Vice President - Capital Markets                     
|Mark H. Wolf        | 42  | Vice President of Finance                            
|Donald H. Sabathier | 58  | Vice President Human Resources                       
|Gerald W. Bolfing   | 76  | Director                                             
|Donald A. Erickson  | 61  | Director                                             
|Matthew C. Lutz     | 70  | Director                                             
|Jody Powers         | 58  | Director                                             
|John H. Trescot, Jr | 80  | Director                                             
|F. Walker Tucei, Jr | 62  | Director                                             

Jerry Box has served as Chairman of
Magnum Hunter Resources since October 2004, and as director 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.

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.

56

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.

M. Bradley Davishas been appointed Senior Vice President and Chief Financial
          Officer effective January 2005. He 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).

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

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

Morgan F. Johnston has served as
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.

57

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 30 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 been appointed
Vice President of Capital Markets effective January 2005. He 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.

Mark H. Wolf was appointed Vice
President of Finance November 2004. Mr. Wolf served as a financial consultant to the
Company since August 2004. From May 1990 until December 2003, Mr. Wolf was employed by
CIBC World Markets and predecessor entities, most recently as an Executive Director in the
Leveraged Finance Group specializing in the exploration and production sector of the
energy industry. Mr. Wolf was employed as a corporate finance specialist in the Real
Estate Group of MBank in Houston, Texas from August 1987 to May 1990. He holds a Bachelor
of Arts degree in Economics and a Master of Business Administration from the University of
Texas at Austin.

58

Donald H. Sabathier has 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.

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.

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.

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.

59

F. Walker Tucei, Jr. has been elected to the companys Board of Directors
          effective November 2004. Mr. Tucei retired in 1999 after a distinguished 37-year
          career with Arthur Andersen, LLP. He was admitted to the firms partnership
          in 1972. During his career with Arthur Andersen, LLP, Mr. Tucei served as the
          New Orleans office Partner-in-Charge of the audit practice from 1975 to 1986. He
          also served as the New Orleans office Managing Partner from 1986 to 1999 and was
          responsible for the firms practice in Louisiana , Mississippi, southern
          Alabama, and western Florida. During his career with Arthur Andersen, LLP, Mr.
          Tucei served on various firm related task forces and committees. Mr. Tucei has
          been involved in numerous civic and non-profit organizations, including serving
          as President of the Southeast Louisiana Council of the Boy Scouts of America and
          the World Trade Center of New Orleans. A 1963 graduate of the University of
          Mississippi with a B.B.A. degree, Mr. Tucei is a Certified Public Accountant
          (Retired) in Louisiana and Mississippi. He is a member of both the American
          Institute and Louisiana Society of Certified Public Accountants. Mr. Tucei has
          served since 2003 as a member of the board, member of the governance and
          nominating committees and currently serves as chairman of the audit committee
          for Newpark Resources, Inc. (NYSE:NR). Since 2000 he has also been a member of
          the Audit Committee for the Archdiocese of New Orleans and currently serves as
          Chairman of that committee.

Audit Committee

The members of our Audit Committee
include Gerald W. Bolfing, Donald A. Erickson and F. Walker Tucei, Jr. Each member
possesses the required level of financial literacy and at least two members, Donald A.
Erickson and F. Walker Tucei, Jr., have 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.

60

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, 2004:

|                        | Annual Compensation | Long-Term Compensation
|----------------------- | ------------------- | ----------------------
|
|
|Jerry Box               |                     |                       
|Chairman of the Board   |                     |                       
|                        |                     |                       
|                        |                     |                       
|Gary C. Evans           |                     |                       
|President and           |                     |                       
|Chief Executive Officer |                     |                       
|                        |                     |                       
|                        |                     |                       
|Richard R. Frazier      |                     |                       
|Executive V.P. and      |                     |                       
|Chief Operating Officer |                     |                       
|                        |                     |                       
|                        |                     |                       
|M. Bradley Davis        |                     |                       
|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 or paid until March 2003.
| | --- | ------------------------------------------------------

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

| | (f) | 2004 bonuses are not earned or paid until March 2005.
| | --- | -----------------------------------------------------

| | (g) | Mr. Bradley Davis was employed on September 16, 2002.
| | --- | -----------------------------------------------------

61

|Option/SAR Grants in Last Fiscal Year
|-------------------------------------
|
|
|Jerry Box                            
|Gary C. Evans                        
|Richard R. Frazier                   
|Charles R. Erwin                     
|R. Douglas Cronk                     
|M. Bradley Davis                     
|Morgan F. Johnston                   

---

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

|Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
|--------------------------------------------------------------------------------
|
|
|Jerry Box                                                                       
|                                                                                
|Gary C. Evans                                                                   
|                                                                                
|Richard R. Frazier                                                              
|                                                                                
|Charles R. Erwin                                                                
|                                                                                
|R. Douglas Cronk                                                                
|                                                                                
|M. Bradley Davis                                                                
|                                                                                
|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, 2004, and receive
no compensation for their services as directors other than as stated below. For fiscal
year 2004, independent directors received a $26,000 retainer and $24,000 worth of
restricted stock for being a board member and received $1,000 per regular and committee
meeting attended. At December 1, 2004, the pay compensation for attending board and
committee meetings was increased to $2,000 per meeting. In addition, for the fiscal year
2004 each independent director was granted stock options to acquire 7,500 shares of our
common stock at an exercise price of $10.48 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. Upon becoming Chairman of the Board during October
2004, Jerry Box began receiving compensation of $20,000 per month. This will continue
through 2005. For fiscal year 2005, independent directors will receive a $26,000 retainer
and $24,000 worth of restricted stock for being a board member and, in addition, will
receive $2,000 per meeting attended and $2,000 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.

62

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

Mr.    
          Gary C. Evans, Mr. Richard R. Frazier, Mr. M. Bradley Davis, 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 2005 is $475,000. 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 2005 is $300,000. Mr. Davis 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. Davis salary for
          the year 2005 is $200,000. 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 2005 is $200,000. 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 2005 is $225,000. 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 2005 is $195,000. 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. Davis, 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.

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.

63

|                                                | Common Stock Beneficially Owned
|----------------------------------------------- | -------------------------------
|
|Directors and Executive Officers                |                                
|Gary C. Evans                                   |                                
|Richard R. Frazier                              |                                
|Charles R. Erwin                                |                                
|R. Douglas Cronk                                |                                
|Morgan F. Johnston                              |                                
|Gerald W. Bolfing                               |                                
|Donald A. Erickson                              |                                
|Matthew C. Lutz                                 |                                
|Jody Powers                                     |                                
|John H. Trescot, Jr                             |                                
|F. Walker Tucei, Jr                             |                                
|Jerry Box                                       |                                
|All directors and executive officers as a group |                                
|(13 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                          |                                
|                                                |                                
|Cimarex Energy Co.                              |                                
|1700 Lincoln Street, Suite 1800                 |                                
|Denver, CO 80203-4518                           |                                
|                                                |                                
|Barclays Global Investors                       |                                
|45 Fremont Street                               |                                
|San Francisco, CA 94105                         |                                

---

*
Less than one percent.

| | (a) | Includes 768,000 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 36,185 equivalent
               shares held by the trustee for the benefit of employee participants in the
               Magnum Hunter Resources, Inc. 401(K) Employee Stock Ownership Plan. Participants
               in this plan instruct the trustee as to how the participants equivalent
               shares should be voted. Also includes 17,024 shared held in the name of
               Jacquelyn Evelyn Enterprises, Inc., a corporation whose sole shareholder is Mr.
               Evans wife. Mr. Evans disclaims any ownership in such securities other
               than those in which he has an economic interest.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (b) | Includes 358,000 shares of common stock issuable upon the exercise of certain
               currently exercisable options. Also includes 29,217 equivalent shares held by
               the trustee for the benefit of employee participants in the Magnum Hunter
               Resources, Inc. 401(K) Employee Stock Ownership Plan. Participants in this plan
               instruct the trustee as to how the participants equivalent shares should
               be voted.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (c) | Includes 323,000 shares of common stock issuable upon the exercise of certain
               currently exercisable options. Also includes 25,336 equivalent shares held by
               the trustee for the benefit of employee participants in the Magnum Hunter
               Resources, Inc. 401(K) Employee Stock Ownership Plan. Participants in this plan
               instruct the trustee as to how the participants equivalent shares should
               be voted.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (d) | Includes 70,000 shares of common stock issuable upon the exercise of certain
               currently exercisable options. Also includes 29,072 equivalent shares held by
               the trustee for the benefit of employee participants in the Magnum Hunter
               Resources, Inc. 401(K) Employee Stock Ownership Plan. Participants in this plan
               instruct the trustee as to how the participants equivalent shares should
               be voted.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (e) | Includes 137,000 shares of common stock issuable upon the exercise of certain
               currently exercisable options. Also includes 23,654 equivalent shares held by
               the trustee for the benefit of employee participants in the Magnum Hunter
               Resources, Inc. 401(K) Employee Stock Ownership Plan. Participants in this plan
               instruct the trustee as to how the participants equivalent shares should
               be voted.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (f) | Includes 38,100 shares of common stock issuable upon the exercise of certain
               currently exercisable options.
| | --- | --------------------------------------------------------------------------------------------------------------------------

64

| | (g) | Includes 223,100 shares of common stock issuable upon the exercise of certain
               currently exercisable options.
| | --- | ---------------------------------------------------------------------------------------------------------------------------

| | (h) | Includes 4,000 shares of common stock issuable upon the exercise of certain
               currently exercisable options.
| | --- | -------------------------------------------------------------------------------------------------------------------------

| | (i) | Includes 38,100 shares of common stock issuable upon the exercise of certain
               currently exercisable options.
| | --- | --------------------------------------------------------------------------------------------------------------------------

| | (j) | Includes 38,100 shares of common stock issuable upon the exercise of certain
               currently exercisable options.
| | --- | --------------------------------------------------------------------------------------------------------------------------

| | (k) | Based on Schedule 13G filed by Dimensional Fund Advisors, Inc. on February 9,
               2005.
| | --- | --------------------------------------------------------------------------------------------------

| | (l) | Based on Schedule 13G filed by Barclays Global Investors on February 14, 2005.
| | --- | ------------------------------------------------------------------------------

| | (m) | Percentage is calculated on the number of shares outstanding plus those deemed
               outstanding under Rule 13d-3(d)(1) under the Exchange Act.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------

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, 2004.

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, LLP for final audits related to
          the Prize merger during 2002.
|--- | ----------------------------------------------------------------------------------------------------------------

|(b) | Consists of fees paid to Deloitte & Touche, LLP for annual audits of Teal
          Hunter, LP and Mallard Hunter, LP, of which Magnum Hunter is the 5% and 1%
          general partner, respectively. During 2004 this also contains audit fees on an
          aborted master limited partnership initial public offering.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The Audit Committee generally makes
recommendations to the Board regarding the selection of the independent registered
accounting firm, 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.

65

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;

 Bcfe means billion
cubic feet of natural gas equivalent; and

 Tcfe means
trillion 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.

66


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.

67

PART IV

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

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

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|2. |  | 
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68

PART II  OTHER
INFORMATION

Item 6. Exhibits and Reports on Form
8-K (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 | Amended and Restated By-Laws (Incorporated by reference to Form 10-Q for the period ended September   
|          | 30, 2004).                                                                                            
|3.7 & 4.7 | Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K    
|          | dated December 26, 1996, filed January 3, 1997).                                                      
|3.8 & 4.8 | 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).                                 
|4.9       | 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).                                                                                       
|4.10      | 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).                                                                        
|4.11      | Form of 9.6% Senior Note due 2007 (included in Exhibit 4.10).                                         
|4.12      | Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors    
|          | named therein and Deutsche Bank Trust Company Americas, as Trustee.                                   
|4.13      | Form of Floating Rate Convertible Senior Notes due 2023 (included in Exhibit 4.12).                   
|4.14      | 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 Form10-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 (Incorporated by reference to  
|          | Form 10-K for the year ended December 31, 2003).                                                      
|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 (Incorporated by reference to  
|          | Form 10-K for the year ended December 31, 2003).                                                      
|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 (Incorporated by reference to  
|          | Forme10-K for the year ended December 31, 2003).                                                      
|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 (Incorporated by        
|          | reference to Form 10-K for the year ended December 31, 2003).                                         
|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 (Incorporated by
|          | reference to Form 10-K for the year ended December 31, 2003).                                         
|          |                                                                                                       
|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                 
|          | (Incorporated by reference to Form 10-K for the year ended December 31, 2003).                        

69

|       |                                                                                                     
|------ | ----------------------------------------------------------------------------------------------------
|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 (Incorporated by      
|       | reference to Form 10-K for the year ended December 31, 2003).                                       
|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 (Incorporated 
|       | by reference to Form 10-K for the year ended December 31, 2003).                                    
|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 (Incorporated by      
|       | reference to Form 10-K for the year ended December 31, 2003).                                       
|10.11  | Tenth Amendment to Fourth Amended and Restated Credit Agreement, dated April 30, 2004 between Magnum
|       | Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al (Incorporated by reference to
|       | Form 10-Q for the period ended March 31, 2004).                                                     
|10.12  | Eleventh Amendment to Fourth Amended and Restated Credit Agreement, dated July 15, 2004 between     
|       | Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al (Incorporated by      
|       | reference to Form 10-Q for the period ended June 30, 2004).                                         
|10.13  | Twelfth Amendment to Fourth Amended and Restated Credit Agreement, dated October 15, 2004, between  
|       | Magnum Hunter Resources, Inc. and Deutsche Bank Trust Company Americas, et al (Incorporated by      
|       | reference to Form 10-Q for the period ended September 30, 2004).                                    
|10.14 | Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-Q for the period ended 
|       | September 30, 2004).                                                                                
|10.15 | Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-Q for the period  
|       | ended September 30, 2004).                                                                          
|10.16 | Employment Agreement for M. Bradley Davis (Incorporated by reference to Form 10-K for the fiscal    
|       | year- end December 31, 2002).                                                                       
|10.17 | Employment Agreement for R. Douglas Cronk (Incorporated by reference to Form 10-K for the fiscal    
|       | year-end December 31, 2002).                                                                        
|10.18 | Employment Agreement for Charles Erwin (Incorporated by reference to Form 10-K for the fiscal       
|       | year-end December 31, 2002).                                                                        
|10.19 | Employment Agreement for Morgan F. Johnston (Incorporated by reference to Form 10-K for the fiscal  
|       | year-end December 31, 2003).                                                                        
|10.20  | 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).                                                     
|10.21  | 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).                                                           
|10.22  | Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by       
|       | reference to Form 10-Q/A for the period ended June 30, 2000, filed November 30, 2000).              
|21     | Subsidiaries of the Registrant (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 M. Bradley Davis.    
|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 M. Bradley Davis.     

---

* Filed herewith

(a)    
          Reports on Form 8-K

During the three months ended
December 31, 2004, we furnished the following Current Reports on Form 8-K:

 Current Report furnished
October 12, 2004, reporting Items 1, 5, 7 and 9.

 Current Report furnished November
9, 2004, reporting Item 2.

Current Report furnished
November 16, 2004, reporting Item 5.

 Current Report furnished
December 3, 2004, reporting Items 5 and 7.

70

MAGNUM HUNTER
RESOURCES, INC. SCHEDULE II 
VALUATION AND QUALIFYING ACCOUNTSFOR EACH OF THE THREE YEARS IN THE PERIOD ENDED
DECEMBER 31, 2004

(in thousands)

|                                                             |  | Additions |   |      
|------------------------------------------------------------ |  | --------- | - | -----
|
|Year Ended December 31, 2004                                 |  |           |   |      
|Allowance for Doubtful Accounts on Trade Accounts Receivable |  |           | $ | 4,331
|Reserve on Current Portion of Long-term Notes Receivable     |  |           |   | 1,170
|                                                             |  |           |   |      
|Year Ended December 31, 2003                                 |  |          
|Allowance for Doubtful Accounts on Trade Accounts Receivable |  |           | $ | 4,573
|Reserve on Current Portion of Long-term Notes Receivable     |  |           |   | 1,620
|Reserve on Investment in Unconsolidated Affiliate            |  |           | $ | 4,527
|                                                             |  |           |   |      
|Year Ended December 31, 2002                                 |  |          
|Allowance for Doubtful Accounts on Trade Accounts Receivable |  |           | $ | 3,264
|Reserve on Current Portion of Long-term Notes Receivable     |  |           |   | 1,620
|Reserve on Investment in Unconsolidated Affiliate            |  |           | $ | 4,527

---

(1) Allowances acquired in Prize merger during 2002 and Metrix acquisition during
          2003.

(2) Write-offs

71

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, President and          Chief Executive Officer | March 15, 2005
|--------------------------------------------------------------------------------------------------------------------------- | --------------
|                                                                                                                            |               

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/ Jerry Box           | Chairman of the Board               | March 15, 2005
|Jerry Box               |                                     |               
|                        |                                     |               
|/s/ Gary C. Evans       | President and                       | March 15, 2005
|Gary C. Evans           | Chief Executive Officer             |               
|                        |                                     |               
|/s/ M. Bradley Davis    | Senior Vice President and           | March 15, 2005
|M. Bradley Davis        | Chief Financial Officer             |               
|                        |                                     |               
|/s/ Morgan F. Johnston  | Sr. Vice President, General Counsel | March 15, 2005
|Morgan F. Johnston      | and Secretary                       |               
|                        |                                     |               
|/s/ David S. Krueger    | Vice President and                  | March 15, 2005
|David S. Krueger        | Chief Accounting Officer            |               
|                        |                                     |               
|/s/ Gerald W. Bolfing   | Director                            | March 15, 2005
|Gerald W. Bolfing       |                                     |               
|                        |                                     |               
|/s/ Donald Erickson     | Director                            | March 15, 2005
|Donald Erickson         |                                     |               
|                        |                                     |               
|/s/ Matthew C. Lutz     | Director                            | March 15, 2005
|Matthew C. Lutz         |                                     |               
|                        |                                     |               
|/s/ Jody Powers         | Director                            | March 15, 2005
|Jody Powers             |                                     |               
|                        |                                     |               
|/s/ John H. Trescot, Jr | Director                            | March 15, 2005
|John H. Trescot, Jr     |                                     |               
|                        |                                     |               
|/s/ F. Walker Tucei, Jr | Director                            | March 15, 2005
|F. Walker Tucei, Jr     |                                     |               

72