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

FORM 10-K

	(Mark one)
[ X ]	Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2004
[ ]	Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ____________ to ____________.

Commission File No. 1-12508

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

Nevada
(State or other jurisdiction of
incorporation or organization)

87-0462881
(I.R.S. Employer
Identification No.)

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

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

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

Title of each class
Common Stock ($.002 par value)

Name of each exchange on which registered
New 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


	PART I

Item 1	Business	1
	The Company	1
	Recent Announcement to be Acquired by Cimarex Energy	2
	Business Strategy	3
	Properties	3
	Development and Exploration Activities	9
	Gathering and Processing of Gas	10
	Marketing of Production	11
	Petroleum Management and Consulting Services	12
	Competition	12
	Regulations	12
	Employees	14
	Facilities	14
	Risk Factors	15
Item 2	Description of Properties	21
	Oil and Gas Reserves	21
	Oil and Gas Production, Prices and Costs	23
	Drilling Activity	24
	Oil and Gas Wells	25
	Oil and Gas Acreage	25
Item 3	Legal Proceedings	26
Item 4	Submission of Matters to a Vote of Security Holders	26

	PART II

Item 5	Market for Registrant's Common Equity and Related Stockholder Matters	26
Item 6	Selected Financial Data	27
Item 7	Management Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	52
Item 8	Consolidated Financial Statements and Unaudited Supplementary Data	54
Item 9	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	55
Item 9A	Controls and Procedures	55
Item 9B	Other Information	55

	PART III

Item 10	Directors and Officers of the Registrant	56
Item 11	Executive Compensation	61
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	63
Item 13	Certain Relationships and Related Transactions	65
Item 14	Principal Accountant Fees and Services	65
	Glossary	66

	PART IV
Item 15	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	68

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Gathering Regulations

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

Environmental Regulation

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

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

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

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

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

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.

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.

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.

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.

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.

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.

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.

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,
	2004		2003		2002
Gas (per Mcf)	$	5.66	$	5.24	$	4.23
Oil (per Bbl)	$	41.66	$	31.33	$	29.99
NGL	$	29.93	$	22.96	$	17.80

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.

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)
	At December 31,
	2004		2003		2002
Net gas reserves (Mcf):
Proved developed		442,630,521		368,530,450		362,325,297
Proved undeveloped		167,487,550		125,522,024		96,318,346

Total proved gas reserves		610,118,071		494,052,474		458,643,643

Net oil reserves (Bbl):
(including condensate)
Proved developed		42,441,787		38,260,657		40,786,302
Proved undeveloped		17,302,268		13,920,319		13,885,296

Total proved oil reserves		59,744,055		52,180,976		54,671,598

Net NGL reserves (Bbl):
(including condensate)
Proved developed		5,566,810		4,728,119		7,726,147
Proved undeveloped		770,280		488,364		684,241

Total proved NGL reserves		6,337,090		5,216,483		8,410,388

Total Proved Reserves (Mcfe)		1,006,604,941		838,437,228		837,135,559

(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.

Estimated Proved Oil and Natural Gas Reserves (a)
(Through Gas Plant Ownership)
	At December 31,
	2004		2003		2002
Net gas reserves (Mcf):
Proved developed		9,418,512		9,162,200		8,030,900
Proved undeveloped		350,349		351,100		328,400

Total proved gas reserves		9,768,861		9,513,300		8,359,300

Net oil reserves (Bbl):
(including condensate)
Proved developed		126,598		166,800		121,600
Proved undeveloped		9,298		30,400		5,600

Total proved oil reserves		135,896		197,200		127,200

Net NGL reserves (Bbl)
(including condensate)
Proved developed		4,398,390		3,637,100		4,179,700
Proved undeveloped		550,016		452,600		349,100

Total proved NGL reserves		4,948,406		4,089,700		4,528,800

Total Proved Reserves (Mcfe)		40,274,673		35,234,700		36,295,300

(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
	Oil (Bbl)		Gas (Mcf)		NGL (Bbl)		Natural Gas Equivalent (Mcfe)
Mid-Continent region (a)		5,793,128		182,819,743		6,337,090		255,601,051
Permian Basin-New Mexico region (a)		8,247,951		184,159,914		--		233,647,620
Permian Basin-Texas region		40,630,590		115,364,687		--		359,148,227
Gulf Coast region (a)		1,984,696		63,696,822		--		75,604,998
Gulf of Mexico (a)		3,087,690		64,076,905		--		82,603,045

Total		59,744,055		610,118,071		6,337,090		1,006,604,941

(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.

	Year Ended December 31,
	2004		2003		2002
Oil and gas production:
Oil (Mbbl)		4,080		3,893		3,875
Gas (MMcf)		55,961		49,695		47,683
Natural Gas Equivalent (MMcfe)		80,442		73,052		70,933
Average sales price (a):
Before Hedge Contracts:
Oil (per Bbl)	$	39.62	$	29.62	$	25.18
Gas (per Mcf)		5.82		4.89		3.07
Natural Gas Equivalents (per Mcfe)		6.06		4.91		3.45
After Hedge Contracts:
Oil (per Bbl)	$	34.27	$	26.42	$	24.04
Gas (per Mcf)		5.41		3.66		3.10
Natural Gas Equivalent (per Mcfe)		5.50		3.90		3.40
Oil and gas production lifting costs (per Mcfe)	$	0.76	$	0.77	$	0.72
Production taxes and other costs (per Mcfe) (b)	$	0.54	$	0.45	$	0.40

(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)
Year	Type of Well		Total		Producing (c)		Dry (d)		Total		Producing (c)		Dry (d)
2004		Exploratory
		Texas		2		2		0		0.21		0.21		0
		Oklahoma		1		1		0		0.04		0.04		0
		New Mexico		1		1		0		0.23		0.23		0
		Offshore Gulf of Mexico		32		26		6		12.10		9.86		2.24

		Development
		Texas		89		89		0		35.19		35.19		0
		Oklahoma		9		7		2		1.21		0.97		0.24
		New Mexico		34		34		0		16.09		16.09		0
		Offshore Gulf of Mexico		7		7		0		2.35		2.35		0
2003		Exploratory
		Texas		2		1		1		0.6		0.33		0.27
		Oklahoma		0		0		0		0		0		0
		New Mexico		2		2		0		0.35		0.35		0
		Offshore Gulf of Mexico		21		14		7		8.86		6.51		2.35
		Development
		Texas		64		63		1		27.29		26.41		0.88
		Oklahoma		4		4		0		0.35		0.35		0
		New Mexico		25		25		0		12.62		12.62		0
		Offshore Gulf of Mexico		6		6		0		1.03		1.03		0
2002		Exploratory		~
		Texas		2		1		1		1.3		1		0.3
		Oklahoma		0		0		0		0		0		0
		New Mexico		6		6		0		2.05		2.05		0
		Offshore Gulf of Mexico		21		16		5		6.24		4.82		1.42
		and Other
		Development
		Texas		62		61		1		23.01		22.01		1
		Oklahoma		3		2		1		0.26		0.13		0.13
		New Mexico		16		16		0		5.20		5.20		0
		Offshore Gulf of Mexico		14		14		0		2.8		2.8		0
		and Other

(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
	Gross (a)						Net (b)
Location	Oil		Gas		Total		Oil		Gas		Total
Texas		2,295		1,228		3,523		1,644.85		867.24		2,512.09
New Mexico		421		629		1,050		292.73		378.84		671.57
Oklahoma		196		484		680		151.39		247.82		399.21
Louisiana		8		8		16		4.96		4.51		9.47
Arkansas		59		1		60		2.80		0.00		2.80
Offshore Gulf of Mexico		9		102		111		1.13		39.83		40.96
Other		1		14		15		0.06		4.87		4.93

Total		2,989		2,466		5,455		2,097.92		1,543.11		3,641.03

(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
	Gross (a)		Net (b)		Gross (a)		Net (b)
Arizona		--		--		920,217		920,217
Kansas		10,377		6,873		480		480
Louisiana		472		283		--		--
New Mexico		190,108		77,429		1,698,877		1,635,409
Oklahoma		168,149		105,098		22,042		12,873
Texas		351,694		200,588		136,585		85,897
Utah		8,063		8,063		87,106		87,106
Wyoming		25,775		25,555		2,720		2,720
Offshore Gulf of Mexico		292,903		111,368		829,877		491,375
Other		8,087		3,045		6,772		4,178

Total		1,055,628		538,302		3,704,676		3,240,255

(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.

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
2004
First Quarter	$	10.26	$	8.12	974,889
Second Quarter	$	11.40	$	9.65	633,848
Third Quarter	$	11.58	$	9.80	604,766
Fourth Quarter	$	13.82	$	11.36	1,044,278
2003
First Quarter	$	6.20	$	5.25	194,474
Second Quarter	$	8.39	$	5.32	284,457
Third Quarter	$	8.25	$	6.85	247,381
Fourth Quarter	$	9.90	$	7.98	438,031

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:

Equity Compensation Plan
	(A)		(B)		(C)
Plan Category	Number of securities to be issued upon exercise of outstanding options and warrants		Weighted-average exercise price of outstanding options and warrants		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column A).
Equity compensation plans
approved by security holders		4,719,562	$	7.85		738,674

Equity compensation plans
not approved by security
holders		1,218,540	$	8.01		--

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
Income Statement Data:
Operating revenues	$	493,726		$	325,014		$	265,869		$	152,806		$	127,510
Operating costs and expenses (a)		(287,793	)		(232,316	)		(197,000	)		(104,755	)		(77,181	)
Operating profit		205,933			92,698			68,869			48,051			50,329
Provision for impairment of investment (b)		--			--			(621	)		(7,123	)		--

Costs associated with early retirement of debt (c)		(12,250	)		(6,716	)		(1,000	)		(490	)		--
Cumulative effect on prior years of a change in accounting principle, net of tax (d)		--			399			--			--			--
Net Income		103,573			26,117			15,522			13,516			22,260
Dividends applicable to preferred shares (e)		--			--			--			--			(9,708	)
Income applicable to common shares		103,573		$	26,117		$	15,522		$	13,516		$	12,552
Income per common share before cumulative effect of a change in accounting principle
Basic (e)	$	1.35		$	0.38		$	0.25		$	0.39		$	0.60
Diluted (e)	$	1.31		$	0.38		$	0.25		$	0.36		$	0.51
Income (loss) per common share after cumulative effect of a change in accounting principle
Basic (e)	$	1.35		$	0.39		$	0.25		$	0.39		$	0.60
Diluted (e)	$	1.31		$	0.39		$	0.25		$	0.36		$	0.51

Other Data:
Proceeds from sale of assets	$	22,902		$	17,123		$	95,988		$	1,124		$	43,770
Capital expenditures (f)	$	540,010		$	175,535		$	141,046		$	204,370		$	60,830

(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
Balance Sheet Data:
Property, plant and equipment, net	$	1,496,912	$	1,095,883	$	1,001,609	$	419,837	$	260,532
Total assets		1,702,501		1,265,892		1,169,656		454,385		315,612
Total debt (a)		645,500		597,500		570,837		288,583		191,139
Total stockholders' equity	$	679,813	$	389,676	$	350,196	$	117,974	$	93,416

(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 Data:
Cash flow from operating activities	$	300,610		$	162,638		$	83,403		$	104,074		$	49,466
Cash flows from investing activities		(513,939	)		(159,675	)		(89,420	)		(203,989	)		(20,008	)
Cash flows from financing activities	$	214,978		$	12,661		$	6,331		$	102,661		$	(31,014	)

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
	First		Second		Third			Fourth
Revenues	$	100,378	$	110,036	$	128,460		$	154,852
Depreciation, depletion, amortization and accretion		25,480		27,645		35,226			38,828
Operating Profit		40,608		44,963		52,255			68,107
Cost of early debt retirement		--		--		(12,250	)		--
Net Income		19,262		23,230		18,964			42,117
Income per common share, basic		0.28		0.34		0.22			0.49
Income per common share, diluted	$	0.28	$	0.33	$	0.22		$	0.47

	2003
	First			Second			Third			Fourth
Revenues	$	80,054		$	78,438		$	82,575		$	83,947
Depreciation, depletion, amortization and accretion		21,524			24,978			26,682			26,430
Operating Profit		25,914			21,444			21,153			24,187
Cost of early debt retirement		(1,855	)		(2,211	)		(19	)		(2,631	)
Cumulative effect of accounting change		399			--			--			--
Net Income		7,990			4,170			6,669			7,288
Income per common share, basic		0.12			0.06			0.10			0.11
Income per common share, diluted	$	0.12		$	0.06		$	0.10		$	0.11

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.

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

Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes associated with them contained elsewhere in this report. This discussion should not be construed to imply that the results discussed herein will necessarily continue into the future or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment by management of the company. Throughout this document, we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section of this document for an explanation of these types of assertions.

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

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

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
	(in thousands, except for per share amounts)
Revenue	$	292,872
Total Operating Costs and Expenses		(219,575	)

Operating Profit		73,297
Interest Expense and Other		(60,202	)

Income before Tax		13,095
Benefit for Income Tax		892

Net Income	$	13,987
Net Income Per Common Share
Basic	$	0.20
Diluted	$	0.20

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.

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
	2004			2003			2002
Exploration and Production Operations

Production:
Oil (MBbls)		4,080			3,893			3,875
Gas (MMcf)		55,961			49,695			47,683
Oil and gas (MMcfe)		80,442			73,052			70,933
Equivalent daily rate (MMcfe/day)		219.8			200.1			194.3
Average sale prices (after hedging):
Oil (per Bbl)	$	34.27		$	26.42		$	24.04
Gas (per Mcf)		5.41			3.66			3.10
Oil and gas (per Mcfe)		5.50			3.90			3.40
Hedging losses (thousands)		(44,990	)		(73,833	)		(3,229	)
Effect of hedging losses (per Mcfe)		(0.56	)		(1.01	)		(0.05	)
Lease operating expense (per Mcfe):
Lifting costs		0.76			0.77			0.72
Production tax and other costs		0.54			0.45			0.40
Gross margin (per Mcfe) (a)		4.21			2.68			2.28
Depreciation, depletion, amortization and accretion
(per Mcfe)		1.54			1.32			1.17
Segment profit (thousands)	$	215,196		$	99,809		$	78,288

Gas Gathering, Marketing and Processing Operations

Throughput volumes (Mcf per day)
Gathering		17,157			15,823			15,535
Processing		25,639			24,947			22,811
Gross margin (in thousands) (a)
Gathering (per Mcf throughput)	$	0.17		$	0.14		$	0.13
Processing (per Mcf throughput)		1.21		$	0.99		$	0.55
Segment profit (thousands)	$	10,425		$	7,624		$	3,643

Oil Field Management Services

Segment profit (thousands)	$	2,262		$	1,045		$	1,115

(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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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):


Acquisition costs:
Unproved acquisitions	19,515	--	19,515
Proved acquisitions	297,957	--	297,957
Other property acquisitions	--	3,311	3,311
Development costs	166,484	--	166,484
Exploratory costs	52,743	--	52,743

Total	536,699	3,311	540,010

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
			Unproved			Proved			Other Property			Total
Acquisition Costs			$	140,312		$	453,834		$	22,826		$	616,972

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS. We have the following contractual obligations as of December 31, 2004:

	Payments Due by Period (in thousands)
	Total		Less than 1 Year		1 - 3 Years		4 - 5 Years		After 5 Years
Contractual Obligations:
Long-Term Debt		640,000		--		320,000		--		320,000
Fixed-Rate Interest Payments		140,400		18,720		37,440		37,440		46,800
Capital Leases		5,500		2,458		3,042		--		--
Commodity Derivatives		20,027		14,046		5,981		--		--
Operating Leases		6,532		2,381		2,079		1,310		762

Total Contractual Obligations		812,459		37,605		368,542		38,750		367,562

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.

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.

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.

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.

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,
	2004			2003			2002
Net income, as reported	$	103,573		$	26,117		$	15,522

Total Stock-based employee compensation expense
included in reported net income, net of income
taxes of $278 and $1,144, respectively		490			1,873			--

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		(3,298	)		(4,751	)		(3,219	)


Pro forma net income	$	100,765		$	23,239		$	12,303


Earnings per share:
Basic - as reported	$	1.35		$	0.39		$	0.25

Basic - pro forma	$	1.31		$	0.35		$	0.20

Diluted - as reported	$	1.31		$	0.39		$	0.25

Diluted - pro forma	$	1.28		$	0.34		$	0.20

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.

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.

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.

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.

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.

Expected Maturity Dates	2005		2006-2007		2012		2023		Total		Fair Value
(in thousands)
Variable Rate Debt:
Bank Debt (a)	$	--	$	320,000	$	--	$	--	$	320,000	$	320,000
Convertible Notes (b)	$	--	$	--	$	--	$	125,000	$	125,000	$	151,719
Capital Lease Obligations (c)	$	2,458	$	3,042	$	--	$	--	$	5,500	$	5,500
Fixed Rate Debt:
9.6% Senior Notes	$	--	$	--	$	195,000	$	--	$	195,000	$	221,325

(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%.

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

MANAGEMENT’S RESPONSIBILITY OVER FINANCIAL REPORTING

Board of Directors and Stockholders
Magnum 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, Texas
March 15, 2005

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Magnum Hunter Resources, Inc.

We have audited the accompanying consolidated balance sheets of Magnum Hunter Resources, Inc. and Subsidiaries (the “Company”) as of December 31, 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 LLP

Dallas, Texas
March 15, 2005

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Magnum 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 LLP

Dallas, Texas
March 15, 2005

F-3

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

	December 31,			December 31,
	2004			2003
ASSETS
Current Assets
Cash and cash equivalents	$	20,342		$	18,693
Restricted cash		212			--
Accounts receivable
Trade, net of allowance of $4,776 and $4,331, respectively		85,462			46,716
Notes receivable		1,396			1,996
Due from affiliates		768			--
Deferred income taxes, current		5,010			8,263
Deposits		3,198			2,713
Available for sale investments		6,067			7,563
Prepaid drilling costs		9,480			8,770
Other current assets		7,579			5,623

Total Current Assets		139,514			100,337
Property, Plant and Equipment
Oil and gas properties, full-cost method
Unproved		94,472			110,467
Proved		1,828,839			1,292,388
Pipelines		36,607			34,149
Other property		9,969			7,805

Total Property, Plant and Equipment		1,969,887			1,444,809
Accumulated depreciation, depletion, amortization and impairment		(472,975	)		(348,926	)

Net Property Plant and Equipment		1,496,912			1,095,883
Other assets
Deferred financing costs and other		9,608			13,205
Goodwill		56,467			56,467

Total Assets	$	1,702,501		$	1,265,892

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables	$	65,215		$	28,793
Accrued interest		5,764			8,909
Accrued liabilities		15,298			11,228
Due to affiliates		503			1,742
Other current liabilities		8,198			7,060
Revenues payable		10,871			7,860
Suspended revenue payable		22,401			16,049
Derivative liabilities, current		14,046			21,853
Current maturities of long-term debt		2,458			2,009

Total Current Liabilities		144,754			105,503
Long-Term Liabilities
Long-term debt, less current maturities		643,042			595,503
Asset retirement obligations		40,086			32,489
Derivative liabilities, noncurrent		5,981			1,198
Deferred income taxes payable		188,366			141,000
Other non-current liabilities		459			523
Stockholders' Equity
Preferred stock - $.001 par value; 10,000,000 shares authorized, 216,000
designated as Series A; 80,000 issued and outstanding, liquidation amount $0		1			1
Common Stock - $.002 par value; 200,000,000 shares authorized,
91,324,168 and 71,977,759 shares issued, respectively		183			144
Additional paid-in capital		615,046			429,446
Accumulated other comprehensive loss		(12,621	)		(13,576	)
Retained earnings		108,576			5,003
Common stock in deferred compensation plan, at cost (34,416 shares) .		(192	)		(192	)
Unearned common stock in KSOP, at cost (880,083 and 1,012,203 shares, respectively)		(6,215	)		(6,110	)

		704,778			414,716
Treasury stock, at cost (3,931,614 and 3,942,294 shares, respectively)		(24,965	)		(25,040	)

Total Stockholders' Equity		679,813			389,676

Total Liabilities and Stockholders' Equity	$	1,702,501		$	1,265,892

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,
	2004			2003			2002
Operating Revenues:
Oil and gas sales	$	443,412		$	284,929		$	240,964
Gas gathering, marketing and processing		41,900			35,317			20,809
Oil field services		8,414			4,768			4,096

Total Operating Revenues		493,726			325,014			265,869

Operating Costs and Expenses:
Oil and gas production lifting costs		60,945			56,262			51,559
Production taxes and other costs		43,704			32,772			28,167
Gas gathering, marketing and processing		29,112			25,373			15,100
Oil field services		5,016			3,119			2,474
Depreciation, depletion, amortization and accretion		127,179			99,614			86,468
Gain on sale of assets		(288	)		(171	)		(61	)
General and administrative		22,125			15,347			13,293

Total Operating Costs and Expenses		287,793			232,316			197,000

Operating Profit		205,933			92,698			68,869
Equity in (loss) earnings of affiliate		--			(162	)		792
Other income		2,584			889			452
Provision for impairment of investments		--			--			(621	)
Costs associated with early retirement of debt		(12,250	)		(6,716	)		(1,000	)
Non-cash hedging adjustments		1,124			1,482			(6,626	)
Interest expense		(38,059	)		(47,260	)		(47,935	)

Income Before Income Tax		159,332			40,931			13,931
Provision for income tax (expense) benefit
Current		(1,977	)		250			--
Deferred		(53,782	)		(15,463	)		1,591

Total Provision for Income Tax (Expense) Benefit		(55,759	)		(15,213	)		1,591

Income Before Cumulative Effect of a Change in Accounting
Principle		103,573			25,718			15,522
Cumulative effect of a change in accounting principle, net
of income tax expense of $244		--			399			--

Net Income	$	103,573		$	26,117		$	15,522

Income per Common Share – Basic
Income before cumulative effect of a change in
accounting principle	$	1.35		$	0.38		$	0.25
Cumulative effect of a change in accounting principle .		--			0.01			--

Income per Common Share – Basic	$	1.35		$	0.39		$	0.25

Income per Common Share – Diluted
Income before cumulative effect of a change in
accounting principle	$	1.31		$	0.38		$	0.25
Cumulative effect of a change in accounting principle .		--			0.01			--

Income per Common Share – Diluted	$	1.31		$	0.39		$	0.25

Common Shares Used in Per Share Calculation
Basic		76,952,204			66,191,816			61,493,428

Diluted		78,958,618			67,501,811			62,513,548

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

F-5

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)
FOR THE 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	)	$	157,836		$	(36,636	)	$	(442	)	$	(2,576	)	$	1,632		$	117,974

Issuance of 34,063 shares of common
stock and warrants pursuant to Prize
Energy Corp. merger, less fees				68					260,454															260,522
Issuance of 985 shares of common stock
pursuant to employee stock option plan				2					3,627															3,629
Deferred tax benefit on exercise of
employee stock options									859															859

Employer contribution of 158 shares to
KSOP									71									867						938

Exercise of warrants									5															5

Purchase of warrants									(128	)														(128	)

Repayment of shareholder loan															442									442

Issuance of 72 shares to KSOP for 2001
employer contribution									601															601

Purchase of 2,726 shares of treasury stock						(18,494	)																	(18,494	)

Employee salary deferrals to KSOP
representing 86 shares									39									473						512

Loan of 532 shares to KSOP																		(3,652	)					(3,652	)

Net income, net of income tax benefit
of $1,591												15,522												15,522			15,522

Reclassification adjustment related to
derivative contracts, net of deferred
income tax expense of $1,684																					2,762			2,762			2,762

Change in fair value of outstanding
hedge positions, net of deferred income
tax benefits of $19,871																					(32,593	)		(32,593	)		(32,593	)

Purchased hedge positions, net of
deferred income tax benefit of $1,508																					(2,474	)		(2,474	)		(2,474	)

Amortization of purchased hedge
positions, net of deferred income tax
expense of $2,299																					3,771			3,771			3,771

Unrealized loss on investments, net of
deferred income tax benefit of $197																					(323	)		(323	)		(323	)

Reclassification adjustment for loss on
investments, net of deferred income tax
expense of $197																					323			323			323

Balance at December 31, 2002	$	1	$	143	$	(20,408	)	$	423,364		$	(21,114	)	$	--		$	(4,888	)	$	(26,902	)	$	350,196		$	(13,012	)

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

F-6

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED 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	)	$	423,364	$	(21,114	)	$	--		$	(4,888	)	$	(26,902	)	$	350,196
Issuance of 270 shares of common stock
pursuant to employee stock option plan				1					1,244														1,245
Issuance of 548 treasury shares upon
exercise of warrants						2,728			720														3,448
Deferred tax benefit on exercise of
employee stock options									613														613
Purchase of 1,340 shares of treasury
stock						(7,413	)																(7,413	)
Loan to KSOP to purchase 486 shares																	(2,711	)					(2,711	)
Employee deferrals to KSOP to purchase
59 shares									105								380						485
Purchase 53 shares for deferred
compensation plan														(295	)								(295	)
Employer contribution of 172 shares to
KSOP									336								1,109						1,445
Stock compensation									3,017														3,017
Purchase of 18 treasury shares by
deferred compensation plan						53			47					(100	)								--
Release of 36 shares from deferred
compensation plan														203									203
Net Income, net of income tax expense
of $15,213											26,117												26,117			26,117
Reclassification adjustments related to
derivative contracts, net of deferred
income tax expense of $28,330																				46,469			46,469			46,469
Change in fair value of outstanding
hedge positions, net of deferred income
tax benefit of $19,715																				(32,338	)		(32,338	)		(32,338	)
Amortization of purchased hedge
positions, net of deferred income tax
benefit of $491																				(805	)		(805	)		(805	)

Balance at December 31, 2003	$	1	$	144	$	(25,040	)	$	429,446	$	5,003		$	(192	)	$	(6,110	)	$	(13,576	)	$	389,676		$	39,443

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	)	$	429,446	$	5,003	$	(192	)	$	(6,110	)	$	(13,576	)	$	389,676
Issuance of 2,128 shares of common
stock pursuant to employee stock option
plan				4					10,427													10,431
Issuance of 17,250 shares through
secondary offering, net of offering
costs				35					169,279													169,314
Stock compensation									768													768
Deferred tax benefit on exercise of
employee stock options									2,765													2,765
Loan to KSOP to purchase 225 shares																(2,259	)					(2,259	)
Employer contribution of 223 shares to
KSOP									1,515							1,347						2,862
Employee salary deferrals to KSOP,
representing 134 shares									776							807						1,583
Issuance of 11 shares for Directors'
compensation						75			70													145
Net Income, net of income tax expense
of $55,759											103,573											103,573			103,573
Reclassification adjustments related to
derivative contracts, net of deferred
income tax expense of $15,859																			27,950			27,950			27,950
Change in fair value of outstanding
hedge positions, net of deferred income
tax benefit of $15,038																			(26,503	)		(26,503	)		(26,503	)
Amortization of purchased hedge
positions, net of deferred income tax
benefit of $279																			(492	)		(492	)		(492	)

Balance at December 31, 2004	$	1	$	183	$	(24,965	)	$	615,046	$	108,576	$	(192	)	$	(6,215	)	$	(12,621	)	$	679,813		$	104,528

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,
	2004			2003			2002
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	103,573		$	26,117		$	15,522
Adjustments to reconcile net income to cash provided by operating activities:
Cumulative effect of a change in accounting principle		--			(399	)		--
Depreciation, depletion, amortization and accretion		127,179			99,614			86,468
Impairment of investments		--			--			621
Amortization of financing fees		2,647			2,377			2,037
Imputed interest on debt due to merger		--			--			108
Increase in allowance for doubtful accounts		841			231			206
Deferred income taxes (benefits)		53,782			15,463			(1,591	)
Equity in (income) loss of unconsolidated affiliate		--			162			(792	)
Costs associated with early extinguishment of debt		12,250			6,716			1,000
Cost of shares released from KSOP suspense		1,347			1,109			867
Minority interest in consolidated subsidiary		(64	)		89			--
Stock compensation		768			3,017			--
Non-cash directors' compensation		145			--			--
Excess of fair value over cost of shares released from KSOP suspense		2,291			441			110
Gain on sale of assets		(288	)		(171	)		(61	)
Other non-cash hedging adjustments		(1,124	)		(1,482	)		6,626
Changes in certain assets and liabilities, net of the effect of acquisitions
Accounts and notes receivable		(40,357	)		6,565			(17,429	)
Derivative assets		--			--			3,600
Deposits and other current assets		(2,872	)		(4,264	)		(9,314	)
Accounts payable and accrued liabilities		42,931			(1,081	)		(7,449	)
(Payment) refund of income taxes		(2,439	)		8,134			2,874

Net Cash Provided by Operating Activities		300,610			162,638			83,403

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets		22,902			17,123			95,988
Proceeds from sale of unconsolidated affiliate		--			5,160			--
Purchase of land to be held for sale		--			(7,563	)		--
Purchase of controlling interest in Metrix Networks, Inc., net of cash acquired		--			(253	)		--
Additions to property and equipment		(303,125	)		(175,535	)		(141,046	)
Cash paid for New Mexico property acquisition		(234,180	)		--			--
Cash paid in Prize merger net of cash acquired		--			--			(41,095	)
(Increase) decrease in other assets		(136	)		(17	)		238
Loan made for promissory note receivable		--			--			(2,596	)
Payments received on promissory note receivable		600			500			--
Distribution from unconsolidated affiliate		--			1,510			256
Investment in unconsolidated affiliate		--			(600	)		(1,165	)

Net Cash Used In Investing Activities		(513,939	)		(159,675	)		(89,420	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt		466,000			517,375			627,850
Fees paid related to financing activities		(1,011	)		(4,428	)		(11,961	)
Payments of principal on long-term debt and production payment liability		(313,012	)		(486,348	)		(591,451	)
Redemption of notes payable		(115,080	)		(134,374	)		--
Proceeds from issuance of convertible notes		--			125,000			--
Loan repaid by stockholder		--			--			742
Loan to KSOP		(2,259	)		(2,711	)		(3,652	)
Loan repaid from KSOP		807			380			473
Proceeds from issuance of common stock		10,431			1,245			3,634
Proceeds from issuance of secondary offering of common stock		169,314			--			--
Proceeds from issuance of treasury stock		--			3,448			--
Purchase of warrants		--			--			(128	)
Purchase of treasury stock		--			(7,413	)		(18,494	)
(Increase) decrease in restricted cash for payment of notes payable		(212	)		682			(682	)
Net decrease in note receivable from affiliate		--			100			--
Purchase common stock for deferred compensation plan		--			(295	)		--

Net Cash Provided by Financing Activities		214,978			12,661			6,331

NET INCREASE IN CASH AND CASH EQUIVALENTS		1,649			15,624			314
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		18,693			3,069			2,755

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	20,342		$	18,693		$	3,069

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.

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

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

	December 31, 2004 (in thousands)
	Prior		2002		2003		2004		Total
Property Acquisition Costs	$	3,585	$	54,648	$	9,279	$	19,582	$	87,094
Exploration Costs		--		--		896		6,482		7,378

Total	$	3,585	$	54,648	$	10,175	$	26,064	$	94,472

F-11

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

	December 31, 2003 (in thousands)
	Prior		2001		2002		2003		Total
Property Acquisition Costs	$	304	$	4,900	$	83,836	$	12,207	$	101,247
Exploration Costs		--		--		--		9,220		9,220

Total	$	304	$	4,900	$	83,836	$	21,427	$	110,467

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.

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.

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.

F-13

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

	Year Ended December 31,
	2004			2003			2002
Net income, as reported	$	103,573		$	26,117		$	15,522
Total Stock-based employee compensation expense
included in reported net income, net of income
taxes of $278 and $1,144, respectively		490			1,873			--
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		(3,298	)		(4,751	)		(3,219	)

Pro forma net income	$	100,765		$	23,239		$	12,303

Earnings per share:
Basic - as reported	$	1.35		$	0.39		$	0.25

Basic - pro forma	$	1.31		$	0.35		$	0.20

Diluted - as reported	$	1.31		$	0.39		$	0.25

Diluted - pro forma	$	1.28		$	0.34		$	0.20

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

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)

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.

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
	December 31, 2004						December 31, 2003								December 31, 2002
	Income (Numerator)		Shares (Denominator)		Per Share Amount		Income (Numerator)			Shares (Denominator)		Per Share Amount			Income (Numerator)		Shares (Denominator)		Per Share Amount
Income before Cumulative Effect	$	103,573		76,952	$	1.35	$	25,718			66,192	$	0.38		$	15,522		61,493	$	0.25
Add: Cumulative Effect		--		--				399					0.01			--				--

Basic EPS
Income available to common
stockholders	$	103,573		76,952	$	1.35	$	26,117			66,192	$	0.39		$	15,522		61,493	$	0.25
Effect of dilutive securities
Warrants				--							57							35
Convertible Notes				94							--							--
Options				1,913							1,253							986

Diluted EPS
Income available to common
stockholders and assumed
conversions	$	103,573		78,959	$	1.31	$	26,117			67,502	$	0.39		$	15,522		62,514	$	0.25
Less: Cumulative Effect		--				--		(399	)				(0.01	)		--				--

Income before Cumulative Effect	$	103,573			$	1.31	$	25,718				$	0.38		$	15,522			$	0.25

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 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.

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	$	292,872
Total Operating Costs and Expenses		(219,575	)

Operating Profit		73,297
Interest Expense and Other		(60,202	)

Income before Tax		13,095
Benefit for Income Tax		892

Net Income	$	13,987
Net Income Per Common Share
Basic	$	0.20
Diluted	$	0.20

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

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,
	2004		2003			2002
Net income, as reported	$	103,573	$	26,117			15,522
Pro forma adjustment to reflect retroactive
adoption of SFAS No. 143, net of related tax effects		--		(399	)		1

Pro forma net income	$	103,573	$	25,718			15,523

Earnings per share:
Basic - as reported	$	1.35	$	0.39		$	0.25

Basic - pro forma	$	1.35	$	0.38		$	0.25

Diluted - as reported	$	1.31	$	0.39		$	0.25

Diluted - pro forma	$	1.31	$	0.38		$	0.25

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	$	320,000	$	165,000
Capital lease obligations, 5.58% at December 31, 2004		5,500		7,500
Senior unsecured notes, due March 15, 2012, 9.6%		195,000		300,000
Floating rate convertible senior notes, due December 15, 2023
2.49% at December 31, 2004		125,000		125,000
Production payment liability, non-recourse		--		12

		645,500		597,512
Less current portion		2,458		2,009

Total Long-Term Debt	$	643,042	$	595,503

The following table presents the approximate annual maturities of debt:

	(in thousands)
2005	$	2,458
2006		807
2007		322,235
Thereafter		320,000

Total	$	645,500

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.

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.

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	$	55,766		$	14,550	$	4,847
State tax expense		1,912			229		403
Adjustment of deferred state tax rate		(4,811	)		--		--
Change in valuation allowance		2,042			--		(7,100	)
Other		850			434		259

Tax expense (benefit)	$	55,759		$	15,213	$	(1,591	)

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,
	2004			2003
Property and equipment, including intangible drilling costs	$	(236,580	)	$	(184,713	)
Plugging costs and other		(1,730	)		--

Total deferred tax liability	$	(238,310	)	$	(184,713	)

Allowance for doubtful accounts	$	1,294		$	1,105
Depletion carryforwards		1,147			1,200
Derivative instruments		7,175			9,570
Alternative minimum tax credit		278			--
Employee stock options		877			--
Operating loss and other carryforwards		45,849			40,073
Other		376			28

Total deferred tax assets	$	56,996		$	51,976

Valuation allowance on state NOL carryforwards		(2,042	)		--

Net Deferred Tax Liability	$	(183,356	)	$	(132,737	)

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
	Number of Warrants		Weighted Average Exercise Price		Number of Warrants			Weighted Average Exercise Price		Number of Warrants			Weighted Average Exercise Price
Outstanding - Beginning of Year		7,228,457	$	15.00		7,873,206		$	14.32		644,749		$	6.75
Issued		--		--		--			--		11,500,270			12.80
Exercised		--		--		(644,749	)		6.75		(578	)		9.12
Redeemed		--		--		--			--		--			--
Expired		--		--		--			--		(4,271,235	)		9.09

Outstanding - End of Year		7,228,457	$	15.00		7,228,457		$	15.00		7,873,206		$	14.32

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

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

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

Common Stock

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

On May 1, 2002, our Board of Directors announced an expansion of our existing stock repurchase program established in June 2001. Under this program, we and our affiliates are authorized to repurchase up to two million shares of our common stock. On October 17, 2002, our Board of Directors approved a new three million share repurchase program in addition to our June 2001 program. At December 31, 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,
	2004		2003
Allocated shares		1,289,981		1,072,128
Unreleased shares		880,083		1,012,203

Total KSOP shares		2,170,064		2,084,331
Fair value of unreleased shares at December 31, 2004
and 2003, respectively	$	11,353,071	$	9,626,051

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
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding - Beginning of Year		6,740,764		$	6.36		6,044,800		$	6.37		5,217,584		$	6.22
Granted		1,453,000			10.41		1,112,260			5.90		2,059,750			5.61
Exercised		(2,128,412	)		4.90		(269,862	)		4.46		(983,834	)		3.71
Cancelled		(127,250	)		6.28		(146,434	)		6.58		(248,700	)		7.47

Outstanding - End of Year		5,938,102		$	7.88		6,740,764		$	6.36		6,044,800		$	6.37

Exercisable - End of Year		3,483,419		$	7.29		4,624,614		$	6.21		2,775,770		$	6.04

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
5.01	46,000	7.74	26,000
5.20	9,000	7.58	3,000
5.23	2,600	7.75	--
5.38	1,190,084	7.69	555,851
5.45	100,000	7.72	80,000
5.46	3,000	8.15	--
5.61	1,800	8.22	--
5.82	3,000	7.66	1,800
5.92	547,128	1.47	547,128
6.625	8,000	0.56	8,000
7.20	3,000	8.42	--
7.51	12,000	7.30	4,000
7.55	88,700	7.21	46,500
7.57	15,000	7.42	9,000
7.75	5,000	7.22	3,000
7.90	6,000	8.48	--
7.9375	1,169,540	5.94	1,169,540
7.95	10,000	8.74	4,000
8.44	1,254,500	6.95	979,600
8.50	8,000	6.67	4,000
9.19	30,000	9.17	6,000
9.3125	20,000	0.97	20,000
10.48	1,378,250	4.50	--
11.08	20,000	6.25	16,000
12.00	1,000	1.05	--
12.89	6,500	4.88	--

	5,938,102	5.84	3,483,419

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	$	41,900	$	8,414	$	--		$	--		$	493,726
Intersegment revenues		1,972		26,275		14,700		--			(42,947	)		--
Depreciation, depletion, amortization and
accretion		123,567		2,363		1,136		113						127,179
Segment profit (loss)		215,196		10,425		2,262		(21,950	)					205,933
Equity losses of affiliates								--						--
Interest expense								(38,059	)					(38,059	)
Costs associated with early retirement of debt								(12,250	)					(12,250	)
Other income								3,708						3,708

Income before income taxes														159,332
Current income tax expense								(1,977	)					(1,977	)
Deferred income tax expense								(53,782	)					(53,782	)

Net income														103,573

Capital expenditures (net of asset sales)	$	513,844	$	2,458	$	810							$	517,112

2003:	Exploration & Production		Gas Gathering, Marketing & Processing		Oil Field Services		All Other			Elimination			Consolidated
Revenue from external customers	$	284,929	$	35,317	$	4,768	$	--		$	--		$	325,014
Intersegment revenues		1,738		23,111		13,649					(38,498	)		--
Depreciation, depletion, amortization and
accretion		96,086		2,320		604		604						99,614
Segment profit (loss)		99,809		7,624		1,045		(15,780	)					92,698
Equity losses of affiliates								(162	)					(162	)
Interest expense								(47,260	)					(47,260	)
Costs associated with early retirement
of debt								(6,716	)					(6,716	)
Other income								2,371						2,371

Income before income taxes													$	40,931
Current income tax benefit								250						250
Deferred income tax expense								(15,463	)					(15,463	)
Cumulative effect of a change in
accounting principle								399						399

Net income													$	26,117

Capital expenditures (net of asset sales)	$	157,481	$	199	$	566	$	166					$	158,412

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	$	20,809	$	4,096	$	--		$	--		$	265,869
Intersegment revenues		1,647		14,052		14,128					(29,827	)		--
Depreciation, depletion, amortization and
accretion		82,950		2,066		507		945			--			86,468
Segment profit (loss)		78,288		3,643		1,115		(14,177	)					68,869
Equity earnings of affiliates								792						792
Interest expense								(47,935	)					(47,935	)
Costs associated with early retirement
of debt								(1,000	)					(1,000	)
Provision for non-cash impairment of
investments								(621	)					(621	)
Other income (loss)								(6,174	)					(6,174	)

Income before income taxes														13,931
Deferred income tax benefit								1,591						1,591

Net income													$	15,522

Capital expenditures (net of asset sales)	$	643,683	$	21,309	$	843	$	2,153					$	667,988

	Exploration & Production		Gas Gathering, Marketing & Processing		Oil Field Services		All Other		Consolidated
As of December 31, 2004

Segment assets	$	1,616,712	$	32,346	$	18,855	$	34,588	$	1,702,501
As of December 31, 2003

Segment assets	$	1,142,621	$	30,710	$	14,917	$	77,644	$	1,265,892

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
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs		Canvasback Energy, Inc. (Non Guarantor)		Eliminations			Magnum Hunter Resources, Inc. Consolidated
ASSETS
Current assets	$	146,219	$	5,310	$	(12,015	)	$	139,514
Property and equipment
(using full-cost accounting)		1,490,881		6,031		--			1,496,912
Investment in subsidiaries
(equity method)		19,065		--		(19,065	)		--
Investment in Parent		--		34,127		(34,127	)		--
Other assets		65,924		151		--			66,075

Total Assets	$	1,722,089	$	45,619	$	(65,207	)	$	1,702,501

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities	$	144,451		12,318		(12,015	)		144,754
Long-term liabilities		863,698		14,236		--			877,934
Shareholders' equity		713,940		19,065		(53,192	)		679,813

Total Liabilities and Stockholders' Equity	$	1,722,089	$	45,619	$	(65,207	)	$	1,702,501

December 31, 2003
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs		Canvasback Energy, Inc. (Non Guarantor)		Eliminations			Magnum Hunter Resources, Inc. Consolidated
ASSETS
Current assets	$	108,801	$	18,163	$	(26,627	)	$	100,337
Property and equipment
(using full-cost accounting)		1,089,366		6,517		--			1,095,883
Investment in subsidiaries
(equity method)		17,875		--		(17,875	)		--
Investment in Parent		--		34,127		(34,127	)		--
Other assets		69,672		--		--			69,672

Total Assets	$	1,285,714	$	58,807	$	(78,629	)	$	1,265,892

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities	$	104,806	$	27,324	$	(26,627	)	$	105,503
Long-term liabilities		757,105		13,608		--			770,713
Shareholders' equity		423,803		17,875		(52,002	)		389,676

Total Liabilities and Stockholders' Equity	$	1,285,714	$	58,807	$	(78,629	)	$	1,265,892

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
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Revenues	$	486,737		$	8,002		$	(1,013	)	$	493,726
Expenses		329,060			6,187			(853	)		334,394

Income before		157,677			1,815			(160	)		159,332
Equity in net earnings of subsidiaries		1,058			--			(1,058	)		--

Income (loss) before income taxes		158,735			1,815			(1,218	)		159,332
Income tax provision		(55,162	)		(657	)		60			(55,759	)

Net Income	$	103,573		$	1,158		$	(1,158	)	$	103,573

Year Ended December 31, 2003
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Revenues	$	320,335		$	4,846		$	(167	)	$	325,014
Expenses		282,945			1,264			(126	)		284,083

Income before		37,390			3,582			(41	)		40,931
Equity in net earnings of subsidiaries		2,184			--			(2,184	)		--

Income before income taxes		39,574			3,582			(2,225	)		40,931
Income tax provision		(13,856	)		(1,357	)		--			(15,213	)

Income before extraordinary loss		25,718			2,225			(2,225	)		25,718
Cumulative effect of a change in
accounting principle		399			--			--			399

Net Income	$	26,117		$	2,225		$	(2,225	)	$	26,117

Year Ended December 31, 2002
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs		Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Revenues	$	264,152	$	1,717		$	--		$	265,869
Expenses		250,974		964			--			251,938

Income before		13,178		753			--			13,931
Equity in net earnings of subsidiaries		468		--			(468	)		--

Income before income taxes		13,646		753			(468	)		13,931
Income tax (provision) benefit		1,876		(285	)		--			1,591

Net Income	$	15,522	$	468		$	(468	)	$	15,522

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
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations		Magnum Hunter Resources, Inc. Consolidated
Cash flow from operating activities	$	312,881		$	(12,271	)	$	--	$	300,610
Cash flow used by investing activities		(513,692	)		(247	)		--		(513,939	)
Cash flow (used) provided by financing activities		214,978			--			--		214,978

Net increase (decrease) in cash		14,167			(12,518	)		--		1,649
Cash at beginning of period		3,482			15,211			--		18,693

Cash at end of period	$	17,649		$	2,693		$	--	$	20,342

Year Ended December 31, 2003
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Cash flow from operating activities	$	148,019		$	14,892		$	(273	)	$	162,638
Cash flow (used) provided by investing
activities		(160,261	)		6,008			(5,422	)		(159,675	)
Cash flow (used) provided by financing activities		13,184			(6,218	)		5,695			12,661

Net increase in cash		942			14,682			--			15,624
Cash at beginning of period		2,540			529			--			3,069

Cash at end of period	$	3,482		$	15,211		$	--		$	18,693

Year Ended December 31, 2002
Amounts in Thousands	Magnum Hunter Resources, Inc. And Guarantor Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations		Magnum Hunter Resources, Inc. Consolidated
Cash flow from operating activities	$	63,522		$	19,881		$	--	$	83,403
Cash flow used by investing activities		(85,398	)		(4,022	)		--		(89,420	)
Cash flow (used) provided by financing activities		23,686			(17,355	)		--		6,331

Net increase (decrease) in cash		1,810			(1,496	)		--		314
Cash at beginning of period		730			2,025			--		2,755

Cash at end of period	$	2,540		$	529		$	--	$	3,069

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
	First		Second		Third			Fourth
Revenues	$	100,378	$	110,036	$	128,460		$	154,852
Depreciation, depletion, amortization and
accretion		25,480		27,645		35,226			38,828
Operating Profit		40,608		44,963		52,255			68,107
Cost of early debt retirement		--		--		(12,250	)		--
Net Income		19,262		23,230		18,964			42,117
Income per common share, basic		0.28		0.34		0.22			0.49
Income per common share, diluted	$	0.28	$	0.33	$	0.22		$	0.47

	2003
	First			Second			Third			Fourth
Revenues	$	80,054		$	78,438		$	82,575		$	83,947
Depreciation, depletion, amortization and
accretion		21,524			24,978			26,682			26,430
Operating Profit		25,914			21,444			21,153			24,187
Cost of early debt retirement		(1,855	)		(2,211	)		(19	)		(2,631	)
Cumulative effect of change in accounting
principle		399			--			--			--
Net Income		7,990			4,170			6,669			7,288
Income per common share, basic		0.12			0.06			0.10			0.11
Income per common share, diluted	$	0.12		$	0.06		$	0.10		$	0.11

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.

F-39

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

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

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


December 31, 2002
Proved Reserves	63,082	458,644
Proved Developed Reserves	48,512	362,325
December 31, 2003
Proved Reserves	57,397	494,052
Proved Developed Reserves	42,989	368,530
December 31, 2004
Proved Reserves	66,081	610,118
Proved Developed Reserves	48,009	442,631

F-40

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL 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:


December 31, 2002
Proved Reserves	127	8,359	4,529
Proved Developed Reserves	122	8,031	4,180
December 31, 2003
Proved Reserves	197	9,513	4,090
Proved Developed Reserves	167	9,162	3,637
December 31, 2004
Proved Reserves	136	9,769	4,948
Proved Developed Reserves	127	9,419	4,398

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


Reserves at December 31, 2001	21,601		248,480

Purchase of minerals-in-place	45,650		275,873
Sale of minerals-in-place	(4,621	)	(75,034	)
Extensions and discoveries	2,986		53,939
Production	(4,050	)	(46,487	)
Revisions of estimates	1,516		1,873

Reserves at December 31, 2002	63,082		458,644

Purchase of minerals-in-place	26		67
Sale of minerals-in-place	(1,243	)	(13,303	)
Extensions and discoveries	1,776		86,001
Production	(3,893	)	(49,695	)
Revisions of estimates	(2,351	)	12,338

Reserves at December 31, 2003	57,397		494,052

Purchase of minerals-in-place	8,324		135,017
Sale of minerals-in-place	(196	)	(2,263	)
Extensions and discoveries	3,085		70,554
Production	(4,080	)	(55,961	)
Revisions of estimates	1,551		(31,281	)

Reserves at December 31, 2004	66,081		610,118

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	$	94,472		$	110,467		$	165,676
Proved properties		1,828,839			1,292,388			1,053,426

Gross Capitalized Costs		1,923,311			1,402,855			1,219,102
Accumulated depreciation, depletion, amortization
and impairment		(458,731	)		(338,109	)		(250,515	)

Net Capitalized Costs	$	1,464,580		$	1,064,746		$	968,587

F-41

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL 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	$	297,957	$	3,021	$	460,908
Unproved properties		19,515		12,213		147,024
Exploration costs		52,743		36,788		34,310
Development costs		166,484		125,308		91,521

Total Costs Incurred	$	536,699	$	177,330	$	733,763

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	$	443,412		$	284,929		$	240,964
Production costs		(104,649	)		(89,034	)		(79,726	)
Depreciation, depletion, amortization, impairment
and accretion		(123,567	)		(96,087	)		(83,028	)
Income taxes		(75,319	)		(34,933	)		(27,374	)

Results of Operations for Producing Activities	$	139,877		$	64,875		$	50,836

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	$	6,133,855		$	4,341,980		$	3,728,575
Future development costs		(401,540	)		(295,273	)		(178,961	)
Future production costs		(1,805,299	)		(1,318,811	)		(1,159,303	)

Future net cash flows, before income tax		3,927,016			2,727,896			2,390,311
Future income taxes		(1,050,979	)		(712,167	)		(619,850	)

Future Net Cash Flows		2,876,037			2,015,729			1,770,461

10% annual discount		(1,312,440	)		(948,041	)		(800,652	)

Standardized Measure of Discounted Future Net Cash Flows	$	1,563,597		$	1,067,688		$	969,809

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	$	356,883		$	676		$	737,736
Sales of minerals-in-place		(6,227	)		(44,759	)		(85,460	)
Extensions, discoveries and improved recovery,
less related costs		82,750			262,022			167,334
Sales of oil and gas produced, net of production costs		(338,763	)		(195,895	)		(161,238	)
Development costs incurred during the period		166,484			125,308			91,521
Revision of prior estimates:
Net change in prices and costs		353,969			(79,252	)		154,738
Change in quantity estimates		(60,379	)		(22,086	)		18,007
Accretion of discount		106,769			96,981			30,569
Net change in income taxes		(165,577	)		(45,115	)		(289,091	)

Net Change	$	495,909		$	97,880		$	664,116

F-42

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL 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

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.

Officers

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

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

Morgan F. Johnston has served as Senior Vice President, General Counsel and Secretary since January 1, 2003. He previously served as the Company’s Vice President and General Counsel since April 1997. He also served as the Company’s Secretary since May 1, 1996. Mr. Johnston was in private practice as a sole practitioner from May 1, 1996 to April 1, 1997, specializing in corporate and securities law. From February 1994 to May 1996, Mr. Johnston served as general counsel for Millennia, Inc. and Digital Communications Technology Corporation, two American Stock Exchange listed companies. He also previously served as securities counsel for Motel 6 L.P., a New York Stock Exchange listed company. Mr. Johnston graduated cum laude from Texas Tech Law School in May 1986 and was also a member of the Texas Tech Law Review. He is licensed to practice law in the State of Texas. He is a member of the American Society of Corporate Secretaries and a member of the Texas General Counsel Forum.

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

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

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

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

Earl Krieg, Jr. has served as Manager of Engineering for Gruy Petroleum Management Co. since May of 1999. Mr. Krieg became Vice President of Engineering for Magnum Hunter Production, Inc. and Gruy in January 2000. Mr. Krieg was employed by The Wiser Oil Company for the five years prior to joining the Company in various capacities, including Manager of Operations and Manager of Secondary Recovery. Mr. Krieg has 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.

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.

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.

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:


											Awards	Payout
Name, Principal Position	Year	Salary			Bonus			Other Annual Compensation (a)			Restricted Stock	Number Options SARs			LTP Payouts	All Other Compensation
Jerry Box
Chairman of the Board	2004	$	102,129


Gary C. Evans	2004	$	438,000		$	350,000	(f)	$	7,500				250,000			$	51,956	(b)
President and	2003	$	405,000		$	608,929	(e)	$	7,500				128,000			$	41,366	(b)
Chief Executive Officer	2002	$	375,000			--	(d)	$	7,500		--		250,000		--	$	35,827	(b)


Richard R. Frazier	2004	$	280,000		$	148,000	(f)	$	6,000				85,000			$	30,517	(c)
Executive V.P. and	2003	$	250,000		$	193,750	(e)	$	6,000				74,000			$	21,109	(c)
Chief Operating Officer	2002	$	205,000			--	(d)	$	6,000		--		140,000		--	$	16,570	(c)


M. Bradley Davis	2004	$	165,000		$	50,000	(f)	$	6,000				45,000			$	30,517	(c)
Senior V.P. and	2003	$	150,000		$	32,143	(e)	$	6,000				20,000			$	20,944	(c)
Chief Financial Officer	2002	$	68,750	(g)		--	(g)	$	1,750	(g)	--		150,000	(g)	--	$	5,785	(c)


Charles R. Erwin	2004	$	210,000		$	116,000	(f)	$	6,000				62,500			$	30,517	(c)
Senior V.P. of Magnum	2003	$	185,000		$	149,464	(e)	$	6,000				68,000			$	21,109	(c)
Hunter Production, Inc.	2002	$	155,000			--	(d)	$	6,000		--		125,000		--	$	16,570	(c)


R. Douglas Cronk	2004	$	185,000		$	85,000	(f)	$	6,000				45,000			$	30,517	(c)
Senior V.P. of Magnum	2003	$	167,500		$	83,036	(e)	$	6,000				46,500			$	21,109	(c)
Hunter Production, Inc.	2002	$	150,000			--	(d)	$	6,000		--		90,000		--	$	16,570	(c)


Morgan F. Johnston	2004	$	180,000		$	85,000	(f)	$	6,000				45,000			$	30,517	(c)
Senior V.P., General	2003	$	160,000		$	110,714	(e)	$	6,000				35,000			$	21,109	(c)
Counsel & Secretary	2002	$	138,000			--	(d)	$	4,800		--		65,000		--	$	14,423	(c)

(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.

Option/SAR Grants in Last Fiscal Year
	Individual Grants							Potential realizable value at assumed annual rates of stock price appreciation for option term		Alternative to (f) and (g): grant date value
Name	Number of securities underlying Options/SARs granted (#) (b)		Percent of total options SARs granted to employees in fiscal year (c)			Exercise or base price ($/Sh) (d)	Expiration date (e)	5% ($) (f)	10% ($) (g)	Grant date present value* $ (f)*
Jerry Box		7,500		0.5	%	10.48	7/1/09			$	28,350
Gary C. Evans		250,000		17.4	%	10.48	7/1/09			$	945,000
Richard R. Frazier		85,000		5.9	%	10.48	7/1/09			$	321,300
Charles R. Erwin		62,500		4.3	%	10.48	7/1/09			$	236,250
R. Douglas Cronk		45,000		3.1	%	10.48	7/1/09			$	170,100
M. Bradley Davis		45,000		3.1	%	10.48	7/1/09			$	170,100
Morgan F. Johnston		45,000		3.1	%	10.48	7/1/09			$	170,100

*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
			Number of securities underlying unexercised options/SARs at fiscal year-end (#)	Value of unexercised in- the money options/SARs at fiscal year-end ($)
Name (a)	Shares acquired on exercise (#) (b)	Value Realized ($) (c)	Exercisable/ unexercisable (d)	Exercisable/ unexercisable (e)
Jerry Box	20,000	84,000	38,100 / 14,500	$ 210,896 / $ 63,090

Gary C. Evans	250,000	1,457,500	818,000 / 410,000	$4,580,590 / $1,634,600

Richard R. Frazier	125,000	833,250	358,000 / 166,000	$2,090,450 / $ 738,320

Charles R. Erwin	66,000	290,865	273,000 / 132,500	$1,643,565 / $ 616,450

R. Douglas Cronk	140,500	673,549	70,000 / 96,000	$ 317,225 / $ 446,520

M. Bradley Davis	50,000	211,000	100,000 / 65,000	$ 735,600 / $ 257,900

Morgan F. Johnston	35,000	301,350	137,000 / 78,000	$ 836,148 / $ 335,640

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.

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

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

The following table sets forth certain information as of March 1, 2004, regarding the share ownership of the company by (i) each person known to the company to be the beneficial owner of more than 5% of the outstanding shares of Common Stock of the company, (ii) each director, (iii) the company’s Chief Executive Officer and the five other most highly compensated executive officers of the company, and (iv) all directors and executive officers of the company, as a group. None of the directors or executive officers named below, as of March 1, 2004, owned any shares of the company’s Series A Preferred Stock or its 1996 Series A convertible preferred stock. The business address of each officer and director listed below is: c/o Magnum Hunter Resources, Inc., 600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039.

	Common Stock Beneficially Owned
Name	Number of Shares			Percent of Class (m)
Directors and Executive Officers
Gary C. Evans		4,733,945	(a)	5.2%
Richard R. Frazier		539,454	(b)	*
Charles R. Erwin		348,336	(c)	*
R. Douglas Cronk		102,432	(d)	*
Morgan F. Johnston		165,134	(e)	*
Gerald W. Bolfing		439,856	(f)	*
Donald A. Erickson		37,000		*
Matthew C. Lutz		288,821	(g)	*
Jody Powers		11,710	(h)	*
John H. Trescot, Jr		137,759	(i)	*
F. Walker Tucei, Jr		2,000		*
Jerry Box		64,200	(j)
All directors and executive officers as a group
(13 persons)		6,870,647		7.8%

Beneficial owners of 5 percent or more
(excluding persons named above)

Dimensional Fund Advisors, Inc.		5,434,000	(k)	6.2%
1299 Ocean Avenue, 11th Floor
Santa Monica, CA 90401

Cimarex Energy Co.		4,733,945		5.2%
1700 Lincoln Street, Suite 1800
Denver, CO 80203-4518

Barclays Global Investors		5,374,858	(l)	6.2%
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.

(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,
	2004		2003
Audit (a)	$	725,380	$	135,000
Audit-Related Fees		86,930		94,339
Tax Fees		551		--
All Other Fees (b)		240,000		95,000

	$	1,052,861	$	324,339

(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.

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;

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

• “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.

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:



1.	Financial Statements

	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

2.	Financial Statement Schedule

	We have included on Page 71 of this Annual Report on Form 10-K, Financial Statement Schedule II,
	Valuation and Qualifying Accounts.

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).


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.

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

(in thousands)

			Additions
Classification	Balance at Beginning of Year		Charged to Costs and Expenses		Charged to Other Accounts (1)		Deductions (2)			Balance at End of Year
Year Ended December 31, 2004
Allowance for Doubtful Accounts on Trade Accounts Receivable	$	4,331	$	772	$	--	$	(327	)	$	4,776
Reserve on Current Portion of Long-term Notes Receivable		1,170		--		--	$	--		$	1,170

Year Ended December 31, 2003
Allowance for Doubtful Accounts on Trade Accounts Receivable	$	4,573	$	231	$	19	$	(492	)	$	4,331
Reserve on Current Portion of Long-term Notes Receivable		1,620		--		--		(450	)		1,170
Reserve on Investment in Unconsolidated Affiliate	$	4,527	$	--	$	--	$	(4,527	)	$	--

Year Ended December 31, 2002
Allowance for Doubtful Accounts on Trade Accounts Receivable	$	3,264	$	206	$	1,103	$	--		$	4,573
Reserve on Current Portion of Long-term Notes Receivable		1,620		--		--		--			1,620
Reserve on Investment in Unconsolidated Affiliate	$	4,527	$	--	$	--	$	--		$	4,527

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

(2) Write-offs

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

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

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

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

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

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

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

FORM 10-K

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

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

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

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