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

FORM 10-K

Commission File No. 1-12508

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

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

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

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

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

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

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

TABLE OF CONTENTS

Securities and Exchange Commission
Item Number and Description

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:

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:

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.

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

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

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

Business Strategy

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

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.

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

Properties

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

Mid-Continent Region

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

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

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

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

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

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

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

Permian Basin

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Gulf Coast

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

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

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

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

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

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

Gulf of Mexico

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

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

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

Eugene Island 397 Area. This area encompasses Eugene Island block 397 and Green Canyon blocks 4 and 48. We own a 12.5% working interest in ten wells operated by W&T Offshore. The wells are located in Federal waters south of St. Mary Parish, Louisiana in a water depth of 404 feet. Production from the first well was initiated in April 2002. Subsequent wells were put on production as they were completed, with 3 wells having come on line in 2003. These wells produce from various sands of Lower Pleistocene to Upper Pliocene, at depths ranging from 6,500 feet to 9,700 feet. Production attributable to the company’s interest averaged 314 Mcf/d and 149 Bbl/d in December 2003. As of December 31, 2003, the net proved reserves for the Eugene Island 397 Area were 4.4 Bcfe.

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

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

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

Gas Processing Plants

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

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

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

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

Development and Exploration Activities

Overview

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

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

Development Drilling

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

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

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

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

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

Exploratory Drilling

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

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

Gathering and Processing of Gas

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

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

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

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

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

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

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

Marketing of Production

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

The market for oil and natural gas we produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, weather, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Petroleum Management and Consulting Services

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

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

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

Competition

The oil and gas industry is highly competitive. Our competitors include major oil companies, other independent oil and gas concerns, and individual producers and operators, many of which have substantially greater financial resources and larger staffs and facilities than those of the company. In addition, we frequently encounter competition in the acquisition of oil and gas properties, gas gathering systems, gas processing plants and in our management and consulting business. The principal means of such competition are the amount and terms of the consideration offered. The principal means of such competition with respect to the sale of oil and gas production are product availability and price. The price at which our products may be sold will continue to be affected by a number of factors, including the price of alternate fuels such as oil, natural gas, nuclear power, hydroelectric power and coal, and competition among various gas producers and marketers.

Regulations

General Federal and State Regulations

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

Regulation of Natural Gas and Oil Exploration and Production

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

Federal Regulation of Sales Prices and Transportation

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

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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.

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

It is not anticipated that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. There can be no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future.

Employees

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

Facilities

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

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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:

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

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

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

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

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

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.

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

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

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

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

We conduct waterflood projects and other secondary recovery operations.

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

We hedge our oil and gas production.

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

Our operations are subject to many laws and regulations.

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

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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:

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.

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Our acquisitions involve certain risks.

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

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

We are subject to substantial competition.

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

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

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

Risks related to substantial leverage

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

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

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

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

We may not be able to meet our capital requirements.

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

Item 2. Description of Properties

Oil and Gas Reserves

General

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

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

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

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

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

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

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

Company Reserves

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

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Significant Properties

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

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

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.

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Drilling Activity

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

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Oil and Gas Wells

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

Oil and Gas Acreage

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

Substantially all of our interests are leasehold working interests or overriding royalty interests (as opposed to mineral or fee interests) under standard onshore oil and gas leases. As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title examined by a landman or title attorney prior to acquisition of mineral acreage in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In certain instances, title opinions may not be obtained if, in our judgment, it would be uneconomical or impractical to do so.

Item 3. Legal Proceedings

No legal proceedings are pending other than ordinary routine litigation incidental to our business, the outcome of which management believes will not have a material adverse effect on the company.

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Item 4. Submission of Matters to a Vote of Security Holders

The company had no matters requiring a vote of security holders during the fourth quarter of 2003.

PART II

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

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

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

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

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

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.

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Item 6. Selected Financial Data

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

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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.

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

Executive Summary

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

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

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

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

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

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

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

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

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

Results of Operations

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

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

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

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

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

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

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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:

Period to Period Comparisons

For the Years Ended December 31, 2003 and 2002

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

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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.

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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.

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Oil Field Management Services Operations:

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

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

Depreciation, Depletion, Amortization and Accretion:

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

Other Income and Expenses:

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

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

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

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

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For the Years Ended December 31, 2002 and 2001

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

Exploration and Production Operations:

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

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

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

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

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

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

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

Gas Gathering, Marketing and Processing Operations:

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

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

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

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

Oil Field Management Services Operations:

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

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

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

Other Income and Expenses:

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

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

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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