UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D C 20549

Form 10-K

(Mark One)

ý        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

o        Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934

Commission file number 001-31446

CIMAREX ENERGY CO.

(Exact name of registrant as specified in its charter)

1700 Lincoln Street, Suite 1800, Denver, Colorado 80203

(Address of principal executive offices including ZIP code)

(303) 295-3995

(Registrant’s telephone number)

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ý NO o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES o NO ý

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 ý NO o

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 the 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. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act of 1934). (Check One):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act. YES o NO ý

Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2005 was approximately $3,189,959,000.

Number of shares of Cimarex Energy Co. common stock outstanding as of February 28, 2006 was 82,828,642.

Documents Incorporated by Reference:  Portions of the Registrant’s Proxy Statement for its 2006 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K

TABLE OF CONTENTS

DESCRIPTION

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GLOSSARY

Bbl/d– Barrels (of oil) per day

Bbls – Barrels (of oil)

Bcf – Billion cubic feet

Bcfe – Billion cubic feet equivalent

MBbls – Thousand barrels

Mcf – Thousand cubic feet (of natural gas)

Mcfe – Thousand cubic feet equivalent

MMBbls – Million barrels

MMBtu – Million British Thermal Units

MMcf – Million cubic feet

MMcf/d– Million cubic feet per day

MMcfe – Million cubic feet equivalent

MMcfe/d– Million cubic feet equivalent per day

Net Acres – Gross acreage multiplied by working interest percentage

Net Production – Gross production multiplied by net revenue interest

NGL – Natural gas liquids

Tcf– Trillion cubic feet

Tcfe– Trillion cubic feet equivalent

One barrel of oil is the energy equivalent of six Mcf of natural gas.

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PART I

Forward-Looking Statements

Throughout this Form 10-K, we make statements that may be deemed “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, that address activities, events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking statements include statements with respect to, among other things:

•                  amount, nature and timing of capital expenditures;

•                  drilling of wells;

•                  reserve estimates;

•                  timing and amount of future production of oil and natural gas;

•                  operating costs and other expenses;

•                  cash flow and anticipated liquidity;

•                  estimates of proved reserves, exploitation potential or exploration prospect size; and

•                  marketing of oil and natural gas.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures and other risks described herein.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties above or elsewhere in this Form 10-K cause our underlying assumptions to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and Exchange Commission, except as required by law

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ITEM 1.                             BUSINESS

General

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico, Louisiana and the Gulf of Mexico. Proved oil and gas reserves as of year-end 2005 totaled nearly 1.4 Tcfe, consisting of 1.0 Tcf of gas and 64.7 million barrels of oil and natural gas liquids. Of total proved reserves, 72 percent are gas and more than 81 percent are classified as proved developed. We operate the wells that account for 77 percent of our total proved reserves and approximately 70 percent of production.

Cimarex was formed in February 2002 and began trading on the New York Stock Exchange (NYSE:  XEC) on October 1, 2002 following the merger of Denver-based Key Production Company, Inc. (NYSE:  KP) and the exploration and production assets of Tulsa-based Helmerich & Payne, Inc. Our chairman of the board of directors and each of our executive officers are former executives of Key.

On June 7, 2005, Cimarex acquired Dallas-based Magnum Hunter Resources, Inc. in a stock-for-stock merger with a total transaction value of approximately $2.4 billion (excluding $426 million of deferred taxes). Proved reserves acquired totaled 886.7 billion cubic feet equivalent (Bcfe), of which 60 percent were gas and 73 percent proved developed. The transaction effectively tripled our proved reserves and doubled our production.

Our corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is (303) 295-3995.

Our Web site address is www.cimarex.com. There you will find our news releases, annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary.

Business Approach

Our basic business approach is centered on profitable reinvestment of the cash flow generated by our producing properties in drilling new wells that have the potential to grow our production and proved reserves and to add value for the benefit of our investors. A cornerstone to our approach is detailed evaluation of each drilling decision based on its risk-adjusted discounted after-tax cash flow rate of return on investment. Our analysis includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs and future production profiles.

During 2005, we drilled 382 gross wells and invested $642 million on exploration and development. Our integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback about drilling results to the originating exploration teams in order to help them improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined risk assessment is a competitive advantage and best positions us to continue to achieve attractive economic rates of return and consistent increases in proved reserves and production.

While our primary focus is drilling, we often consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to add new areas. Prior to the Magnum Hunter acquisition, our operations were concentrated in the Mid-continent and onshore Gulf

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Coast regions and we had a small but growing program in the Permian Basin. Magnum Hunter’s operations were focused in the Permian Basin and the Gulf of Mexico, and they had a small position in certain Mid-Continent and Gulf Coast plays. The primary driver of acquisition was their position in the Permian Basin, which now ranks as our largest region in terms of proved reserves and is second only to our Mid-Continent operations measured by production volumes.

Business Segments

In 2005, we merged our wholly owned gas marketing subsidiary Cimarex Energy Services, Inc., into Cimarex because we no longer deemed it necessary to manage these activities separately from our exploration and production operations. Due to the modification of our business activities in 2005, we have only one reportable segment (exploration and production) and segment information for 2004 and 2003 periods has been omitted. As a result of the elimination of the segment, certain amounts have been reclassified to conform to the current year presentation. See Revenue Recognition in Note 4 to the Consolidated Financial Statements.

Exploration and Development

Our operations are currently focused in the Mid-Continent region which consists of Oklahoma, the Texas Panhandle and southwest Kansas; the Permian Basin region of west Texas and southeast New Mexico; the upper Gulf Coast areas of Texas, south Louisiana and Mississippi; and the Gulf of Mexico. We also have smaller projects underway in Michigan, North Dakota, and California.

A summary of our 2005 exploration and development activity by region is as follows.

Company-wide, we participated in drilling 382 gross wells during 2005, with an overall success rate of 88 percent. On a net basis, 178 of 210 total wells drilled during 2005 were successful.

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Our 2005 exploration and development expenditures totaled $642 million and resulted in 237 Bcfe of proved reserve additions. Of total expenditures, 37 percent was invested in projects located in the Mid-Continent area; 23 percent in the Permian Basin; 26 percent in our Gulf Coast focus areas; and 10 percent in the Gulf of Mexico.

Permian Basin

Our Permian Basin operations cover both west Texas and southeast New Mexico. Our presence in this area was greatly expanded by the Magnum Hunter acquisition and we believe that this increased size and scope provides a solid platform for maintaining a multi-year drilling program and places us in a strong competitive position for capturing new opportunities. Since the acquisition, we have increased the number of drilling rigs we had operating in this area from two to nine. In total, we drilled 117 gross wells in the Permian Basin during 2005 with an 87 percent success rate.

The majority of our 2005 Permian Basin drilling occurred in southeast New Mexico where we completed 74 gross wells and achieved a 95 percent success rate. Drilling targets are principally comprised of Pennsylvanian-aged Morrow and Atoka sandstones and conglomerate gas reservoirs at depths ranging from 11,000-13,000 feet. We plan to keep nine to 11 operated rigs running in the Permian Basin throughout 2006 and further expect that the combination of our large base of producing properties and significant undeveloped acreage position will result in the Permian Basin being an important growth area for the foreseeable future.

Mid-Continent

In the Mid-Continent our operations cover the Anadarko and Arkoma basins of central and southeastern Oklahoma, the Hugoton Basin of southwest Kansas and the Texas Panhandle.

We drilled 185 Mid-Continent gross wells during 2005, realizing a 96 percent success rate. The bulk of this activity occurred in the Texas Panhandle and the Anadarko Basin. We drilled 36 gross (27.5 net) Texas Panhandle wells with a 100 percent success rate. Most of these wells targeted the Granite Wash formation in Roberts and Hemphill counties at depths ranging from 11,000-14,000 feet. Gross proved reserves for these wells averaged 1.0 Bcfe. Drilling activity in the Granite Wash remains active with over 50 wells planned for 2006.

We drilled 106 (40.2 net) Anadarko Basin wells realizing a 96 percent success rate. The drilling activity mainly targets the Red Fork and Clinton Lake/Atoka formations at depths ranging from 12,000-15,000 feet. Gross proved reserves for these wells averaged 1.3 Bcfe. We expect to continue an active program in this area, drilling a similar number of wells in 2006 as in 2005.

We have also identified a large inventory of potential recompletions and new drills in several exploitation projects, including the Eola Robberson field in southern Oklahoma and the Panoma field in the Texas Panhandle. Eola Robberson is a geologically complex, multi-pay field with reservoirs at depths ranging from 5,000-11,500 feet. New wells will test the Woodford shale, Hunton, Sycamore, and Viola formations. With success, we have four additional fields in southern Oklahoma with similar characteristics and exploitation potential. The Panoma field area targets the Brown Dolomite formation at depths of approximately 2,200 feet. In addition to an active vertical drilling and recompletion program we are also evaluating the potential for horizontal drilling.

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Gulf Coast

Our Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and southern Mississippi. Compared to our Mid-Continent and Permian drilling programs, our Gulf Coast effort is generally characterized by a greater reliance on 3-D seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success rates.

During 2005 we drilled 44 gross (27.7 net) Gulf Coast wells, realizing a 66 percent success rate. A significant portion of the drilling occurred in Liberty County, Texas. Targeting the Yegua and Cook Mountain formations at 10,500 feet, we drilled 14 gross (9.3 net) Liberty County wells with a success rate of 50 percent. As a result of this drilling, gross production increased to 72 MMcfe per day in 2005, an 80 percent increase over 2004.

In the fourth quarter of 2005, Cimarex drilled a discovery well in Vermilion Parish, Louisiana. The Donald Harrington #1 (100 percent working interest) at the Cherokee prospect was drilled to a total depth of 16,200 feet and was brought on production in mid-January 2006 at a rate of 26 MMcf per day of gas and 150 barrels per day of condensate.

Gulf of Mexico

Our Gulf of Mexico operations are concentrated in shallow waters (less than 300 feet) offshore Louisiana. In total, we own an interest in 252 federal offshore blocks consisting of approximately 1.2 million gross acres. We obtained all of our offshore position through the Magnum Hunter acquisition.

Hurricanes Katrina and Rita caused devastating damage to this area in 2005 and significantly impaired the industry’s ability to produce and deliver oil and natural gas. Our production was negatively impacted by approximately 35 MMcfe per day in the second half of 2005. Because our facilities suffered minor damage, the shut-in production was only deferred into future periods and was not lost. By year-end 2005 the amount of production curtailed was approximately 20-25 MMcfe per day, the majority of which is expected to be restored by the end of the first quarter 2006.

Drilling activity in the Gulf was also sharply reduced because of hurricanes Katrina and Rita. Nonetheless, including wells drilled by Magnum Hunter prior to closing, we participated in 31 gross (11.1 net) wells during 2005, realizing a 65 percent success rate. We drilled ten operated wells located primarily in the Main Pass and West Cameron Federal Planning areas and participated in 21 non-operated wells in East Cameron, West Cameron and South Timbalier. At year-end 2005 two operated wells were drilling.

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Production and Pricing Information

The following table sets forth certain information regarding the company’s production volumes and the average oil and gas prices received:

Combined oil and gas production volumes increased 63 percent to 353.7 MMcfe per day. Gas production in 2005 rose 58 percent to 274.7 MMcf per day and oil production increased 82 percent to 13,162 barrels per day. The increase in volumes primarily stems from favorable drilling results and the inclusion of production from Magnum Hunter operations beginning June 7, 2005.

The weighted-average gas price we received during 2005 was $8.05 per Mcf, which was 40 percent higher than the $5.76 per Mcf average price we received during 2004. Our annual average realized oil price during 2005 increased by 37 percent to $55.25 per barrel from $40.19 per barrel in 2004. The increase in the prices we received during 2005 was the result of tighter market conditions for oil and gas.

Cimarex assumed Magnum Hunter’s oil and gas commodity swap and collar contracts as part of the merger. These instruments did not qualify for hedge accounting treatment. As these were not treated as hedges, the above average sales prices do not include the effect of these instruments. For a discussion of derivatives, see Note 5 of Notes to Consolidated Financial Statements contained herein.

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The following table summarizes Cimarex’s daily production by region for the second-half of 2005 and the full-year 2005. The second-half 2005 volumes reflect the production increases as a result of the Magnum Hunter acquisition.

Our largest producing area is the Mid-Continent region which averaged 156.5 MMcfe per day making-up 44 percent of our total 2005 production. After closing the Magnum Hunter acquisition our second-half 2005 Mid-Continent volumes increased to 175.3 MMcfe per day.

The Permian Basin contributed 82.7 MMcfe per day in 2005, which was 23 percent of our total production for this period. After closing the Magnum Hunter acquisition, our second-half 2005 Permian Basin volumes increased to 130.1 MMcfe per day.

Gulf Coast production was 80.3 MMcfe per day during 2005, or 23 percent of total production.

Production from the Gulf of Mexico totaled 23.6 MMcfe per day, or seven percent of our total 2005 production. Our second-half 2005 production rate of 37.9 MMcfe per day was negatively impacted by hurricanes.

We have field offices located near our major concentrations of operated properties and have a centralized production management team in our Tulsa office. We have implemented management systems over our production operations that closely monitor actual results against plan.

Acquisitions and Divestitures

Cimarex completed its acquisition of Magnum Hunter Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and southeast New Mexico and in the Gulf of Mexico. Magnum’s oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves (73 percent proved developed).

Various interests in oil and gas properties were sold during 2005, with proceeds totaling $149 million. Current income taxes payable of $30.2 million resulted from these sales. Proceeds from the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method of accounting. Proved reserves associated with the sold properties approximated 62.5 billion cubic feet equivalent, and related production was 13 MMcf equivalent per day.

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Marketing

Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at various prices directly or indirectly tied to field postings and monthly futures contract prices on the New York Mercantile Exchange (NYMEX). Our gas is sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the daily spot market. Revenues are recognized as gas is delivered and are reflected net of gas purchases in the Consolidated Statement of Operations included in this report.

We sell our oil and gas to a broad portfolio of customers. Our largest customer accounted for eight percent of 2005 revenues. Because over two-thirds of our gas production is from wells in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.

In prior years, Cimarex’s wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI) marketed and sold a majority of our production along with gas of our working interest partners who elected to have us sell their gas for a fee under short-term sales arrangements. In 2005, CESI was merged into Cimarex because we no longer deemed it necessary to manage the gas marketing and sales activities separate from the exploration and production operations. Gas gathering, marketing and processing activities are no longer managed separately, nor is the performance of such activities evaluated separately. Due to the modification of our business activities in 2005, the Company has only one reportable segment. As such, segment information for 2004 and 2003 periods has been omitted. As a result of the elimination of the segment, certain amounts have been reclassified to conform to the current year presentation, see Revenue Recognition in Note 4 to the Consolidated Financial Statements.

Employees

We employed 689 people on December 31, 2005. None of our employees are subject to collective bargaining agreements.

Competition

The oil and gas industry is highly competitive. Competition is particularly intense for prospective undeveloped leases and purchases of proved oil and gas reserves. There is also competition for rigs and related equipment we use to drill for and produce oil and gas. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We compete for prospects, proved reserves, oil-field services and qualified oil and gas professionals with major and diversified energy companies and other independent operators that have larger financial, human and technological resources than we do.

We compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have financial and human resources substantially larger than those of Cimarex. The effect of these competitive factors on Cimarex cannot be predicted.

Title to Oil and Gas Properties

We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a prospect or acquire proved properties. We believe that the titles to our properties are good and defensible, and are in accordance with industry standards. Our oil and gas properties are subject to customary royalty interests contracted for in connection with the acquisition of

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title, liens incidental to operating agreements, tax liens and other burdens and minor encumbrances, easements and restrictions.

Government Regulation

Oil and gas production and transportation is subject to many varying and complex federal and state regulations. In recent years, we have been most directly affected by federal and state environmental regulations and energy conservation rules. We are indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems. Compliance with such laws and regulations increases our overall cost of business, but has not had a material adverse effect on our operations or financial condition.

Most of the states in which we conduct operations regulate the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws establish limits on the maximum rate of production from wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to often limit the amounts of oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill.

Environmental Regulation. Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas. To date, we have not expended any material amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations.

 We are committed to environmental protection and believe we are in substantial compliance with applicable environmental laws and regulations. We routinely obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations. We have made, and will continue to make, expenditures in our efforts to comply with environmental regulations and requirements. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

Gas Gathering and Transportation. The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open access transportation. Interstate pipelines have implemented this requirement by modifying their tariffs and implementing new services and rates. These changes have provided us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines.

Under the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional “gathering” systems under the NGPA and that our facilities are not subject to federal

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regulations. Although exempt from federal regulatory oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state agencies.

Additional proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, state legislatures, state agencies and the courts. We cannot predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state and local laws, rules or regulations will have a material adverse effect upon our capital expenditures, earnings or competitive position.

In addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship our gas to markets.

Federal and State Income Taxation

Cimarex and the petroleum industry in general are affected by both federal and state income tax laws. We have considered the effects of these provisions on our operations and do not anticipate that there will be any undisclosed impact on our capital expenditures, earnings or competitive position.

Certain Risks

The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our business, financial condition or results of operations and could negatively impact the value of our common stock.

Low oil and gas prices could adversely affect our financial results and future rate of growth in proved reserves and production.

Our revenues and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Historically, oil and gas prices have fluctuated widely. For example, in 2005 we sold our gas at an average price of $8.05 per Mcf, which was 40 percent higher than our 2004 average sales price of $5.76 per Mcf. Similarly, our average 2005 oil price of $55.25 per barrel was 37 percent higher than the price we received in 2004 of $40.19 per barrel.

In recent years, oil prices have responded to changes in supply and demand stemming from actions taken by the Organization of Petroleum Exporting Countries, worldwide economic conditions, growing transportation and power generation needs, and other events. Factors affecting gas prices have included domestic supplies; the level and price of natural gas imports into the U.S.; weather conditions; the economy and the price and level of alternative sources of energy such as nuclear power, hydroelectric power, coal, and other petroleum products.

Our proved oil and gas reserves and production volumes will decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Because low oil and gas prices would negatively affect the amount of cash flow available to fund these capital investments, they could also affect our future rate of growth. Low prices may also reduce the amount of oil and gas that we can economically produce and may cause us to curtail, delay or defer certain exploration and development projects. We may be required under accounting rules

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to write down the carrying value of our properties or impair goodwill when gas and oil prices are low. Moreover, our ability to borrow under our bank credit facility and to raise additional debt or equity capital to fund acquisitions would also be impacted.

Failure of our exploration and development program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth.

Most of our wells produce from reservoirs characterized by high levels of initial production and declines which stabilize within three to five years. In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas reserves or acquire producing properties from others. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations and reduce our ability to raise capital.

Exploration and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit.

We often are uncertain as to the future cost or timing of drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in the availability of, drilling rigs and related equipment.

The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves.

Unless we conduct successful development activities or acquire properties containing proved reserves, our proved reserves will decline as they are produced. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Because of the high-rate production profiles of our properties, replacing produced reserves is more difficult for us than for companies whose reserves have longer-life production profiles. This imposes greater reinvestment risk for our company as we may not be able to continue to economically replace our reserves.

Our proved reserve estimates may be inaccurate and future net cash flows are uncertain.

Estimates of proved oil and gas reserves and their associated future net cash flow necessarily depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause estimates to vary considerably from actual results:

•                  production rates, reservoir pressure, and other subsurface information;

•                  future oil and gas prices;

•                  assumed effects of governmental regulation;

•                  future operating costs;

•                  future property, severance, excise and other taxes incidental to oil and gas operations;

•                  capital expenditures;

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•                  workover and remedial costs; and

•                  Federal and state income taxes.

Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P. and DeGolyer and MacNaughton, independent petroleum engineers, collectively reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2005.

The values referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash flow from proved reserves is based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.

We deliver oil and gas through pipelines that we do not own. The marketability of our production depends in part upon the availability, proximity and capacity of these pipelines. These facilities may not always be available to us in the future. The lack of availability of these facilities for an extended period of time could negatively affect revenues.

Competition in our industry is intense and many of our competitors have greater financial and technological resources.

We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations.

Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control.

Other companies operate approximately 30 percent of our net production. Our success in properties operated by others depends upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental

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standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.

Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures or cement failures, and environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, regulatory investigations and penalties, suspension of our operations and repair and remediation costs. In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease.

We maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.

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

We have outstanding $125 million of Convertible Notes (face value) that mature on December 15, 2023. The Convertible Notes will be convertible into a combination of cash and common stock of Cimarex 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 Cimarex common stock for the Convertible Note’s conversion value in excess of such principal amount. The number of Cimarex 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.

Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

 We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If we do complete an acquisition, we must anticipate difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses.

Competition for experienced, technical personnel may negatively impact our operations.

Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could

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have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.

There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected.

While Cimarex has taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in its ability to control all circumstances. On June 6, 2005, Cimarex Management met and recommended to the Audit Committee the exclusion of Magnum Hunter assets from the scope of Cimarex’s Sarbanes-Oxley Section 404 report on internal controls over financial reporting for the year ended December 31, 2005. See Item 9A of this report for a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected.

The Cimarex certificate of incorporation, by-laws and stockholders’ rights plan include provisions that could discourage an unsolicited corporate takeover and could prevent stockholders from realizing a premium on their investment.

The certificate of incorporation and by-laws of Cimarex provide for a classified board of directors with staggered terms, restrict the ability of stockholders to take action by written consent and prevent stockholders from calling a meeting of the stockholders. In addition, Delaware General Corporation Law imposes restrictions on business combinations with interested parties. Cimarex also has adopted a stockholders’ rights plan. The stockholders’ rights plan, the certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to Cimarex stockholders.

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ITEM 2.                             PROPERTIES

Oil and Gas Properties and Reserves

All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 77 percent of our proved reserves.

Our engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. Ryder Scott Company, L.P. and DeGolyer and MacNaughton, independent petroleum engineers, collectively reviewed our reserve estimates for those properties that comprised at least 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, 2005. All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 17, Supplemental Oil and Gas Disclosures, to Notes to Consolidated Financial Statements for further information. The following table sets forth the present value and estimated volume of our oil and gas proved reserves:

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Significant Properties

As of December 31, 2005, 95 percent of proved reserves were located in the Mid-Continent, Permian Basin, Gulf Coast and Gulf of Mexico regions. In total we owned an interest in 12,878 gross (4,297.7 net) productive oil and gas wells.

The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2005.

Our ten largest fields hold 29 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except Jo-Mill). The table below summarizes certain key statistics about these properties.

Acreage

The following table sets forth as of December 31, 2005, the gross and net acres of both developed and undeveloped leases held by Cimarex. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest.

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Gross Wells Drilled

We participated in drilling the following number of gross wells during calendar years 2005, 2004 and 2003:

We were in the process of drilling 24 gross (16 net) wells at December 31, 2005.

Net Wells Drilled

The number of net wells we drilled during calendar years 2005, 2004 and 2003 are shown below:

Productive Wells

We have working interests in the following productive wells as of December 31, 2005:

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ITEM 3.                             LEGAL PROCEEDINGS

As of December 31, 2005, we have accrued for a mediated $6.5 million litigation settlement pertaining to post-production deductions on properties operated by Cimarex. The proposed settlement will be reviewed by the court in the first quarter of 2006 for approval. Cimarex has other various litigation related matters in the normal course of business, none of which are material, individually or in aggregate.

ITEM 4.                             SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted for a vote of security holders during the fourth quarter of 2005.

ITEM 4A.                    EXECUTIVE OFFICERS

The executive officers of Cimarex as of February 28, 2006 were:

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There are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an executive officer.

F.H. MERELLI was elected chairman of the board, chief executive officer and president on September 30, 2002. Prior to September 2002 and since September 1992, Mr. Merelli served as chairman and chief executive officer of Key Production Company, Inc. From June 1988 to July 1991 he was president and chief operating officer of Apache Corporation.

THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources.

JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. From 1994 until September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering.

PAUL KORUS was elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice president and chief financial officer of Key Production Company, Inc. from September 1999 to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research analyst with Petrie Parkman & Co., an investment banking firm.

STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with Cimarex, Mr. Bell had been with Key Production Company, Inc. since February 1994. In September 1999, he was appointed senior vice president-business development and land. From February 1994 to September 1999, he served as vice president-land.

RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production Company, Inc. in March 2002 as its director of human resources and continued in that position with Cimarex commencing in September 2002. Prior to joining Key and since February 1999, Mr. Dinkins was with Sprint.

GARY R. ABBOTT was elected vice president of corporate engineering on March 1, 2005. Since January 2002, Mr. Abbott served as manager-corporate reservoir engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc.

JAMES H. SHONSEY was elected chief accounting officer and controller on May 28, 2003. From 2001 to May 2003 Mr. Shonsey was chief financial officer of The Meridian Resource Corporation; and from 1997 to 2001, he served as the chief financial officer of Westport Resources Corporation.

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PART II

ITEM 5.                             MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

Cimarex’s $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. In December 2005 the Board of Directors declared the Company’s first quarterly dividend of $.04 per share payable to shareholders of record as of February 15, 2006.

Stock Prices and Dividends by Quarters. The following table sets forth, for the periods indicated, the high and low sales price per share of Common Stock on the NYSE and the quarterly dividends paid per share.

The closing price of Cimarex stock as reported on the New York Stock Exchange on February 28, 2006, was $42.66. At December 31, 2005, Cimarex’s 82,377,463 shares of outstanding common stock were held by approximately 5,760 stockholders of record.

ITEM 5C.                    STOCK REPURCHASES.

In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. Through December 31, 2005, 68,000 shares had been repurchased.

Since December 31, 2005 and through February 2006, an additional 140,100 shares have been repurchased for an average price of $45.12 per share.

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ITEM 6.                             SELECTED FINANCIAL DATA

The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto provided in Item 8 of this Form 10-K.

ITEM 7.                             MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are presently focused primarily in Oklahoma, Texas, New Mexico, Kansas, Louisiana, and the Gulf of Mexico. We also have smaller projects underway in Michigan, North Dakota and California.

Our primary focus is to explore for and discover new reserves. To supplement our growth, we also consider mergers and acquisitions. On June 7, 2005, Cimarex acquired Magnum Hunter Resources, Inc, a Dallas-based independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Hunter’s common stockholders (excluding 2.5 million shares held in treasury) and assumed $633 million of debt. The merger was

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accounted for as a purchase of Magnum Hunter by Cimarex. Results of operations from Magnum Hunter’s properties are included in our consolidated statements of operations beginning June 7, 2005.

As a result of the merger, our proved reserves tripled and production doubled. Our common shares outstanding increased by 93 percent to 82.4 million and we went from having no debt to taking on $633 million of debt. Using proceeds from property sales and cash flow in excess of second-half 2005 capital investments, we reduced our debt to $352 million by year end. Operationally we now have a large base of properties in the Permian Basin with operational characteristics similar to our Mid-Continent assets. The merger also extended our onshore Gulf Coast activities into the Gulf of Mexico. Overall, about 44 percent of our proved reserves are in the Permian Basin and 39 percent are in our Mid-Continent region. Our onshore Gulf Coast and Gulf of Mexico operations collectively make up 12 percent of our proved reserves.

Industry and Economic Factors

In managing our business we must deal with many factors inherent in our industry. First and foremost is wide fluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile, with future price movements difficult to predict. While our revenues are a function of both production and prices, wide swings in prices often have the greatest impact on our results of operations.

Our operations entail significant complexities. Advanced technologies requiring highly trained personnel are utilized in both exploration and production. Even when the technology is properly used, the interpreter still may not know conclusively if hydrocarbons will be present or the rate at which they will be produced. Exploration is a high-risk activity, often times resulting in no commercially productive reservoirs being discovered. Moreover, costs associated with operating within the industry are substantial and usually move up and down together with prices.

The oil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and gas companies, and individual operators. In addition, the industry as a whole competes with other businesses that supply energy to industrial, commercial and residential end users.

Extensive federal, state and local regulation of the industry significantly affects our operations. In particular, our activities are subject to comprehensive environmental regulations. Compliance with these regulations increases the cost of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.

Approach to the Business

Profitable growth of our assets will largely depend upon our ability to successfully find and develop new proved reserves. To achieve an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate and higher risk exploration and development projects. We believe that this approach allows for consistent increases in our oil and gas reserves, while minimizing the chance of failure. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We may also consider the use of transaction-specific hedging of oil and gas prices to reduce price risk. To date the use of hedging has not been implemented by Cimarex. However, in connection with the acquisition of Magnum Hunter, we acquired existing commodity derivatives as discussed more fully below.

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities, periodic sales of non-core properties and external sources of capital.

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We project that 2006 exploration and development expenditures will approximate $1 billion, up from the $642 million invested in 2005. Approximately 30 percent of the expenditures will be in the Permian Basin, 29 percent in the Mid-Continent area, 22 percent in the Gulf Coast area and 15 percent in the Gulf of Mexico.

Cash flow from operating activities for 2005 totaled $705 million, which more than funded our drilling program. Proceeds from properties sold during 2005 totaled $149 million. We used the proceeds from property sales and cash flow in excess of capital investment to eliminate all of the $270 million of bank debt that Magnum Hunter had outstanding immediately prior to our merger.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 4 to our Consolidated Financial Statements included in this report. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure about Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements.

Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production. We market and sell natural gas for working interest partners under short term sales and supply agreements and earn a fee for such services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the accompanying consolidated statement of operations.

Oil and Gas Reserves

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. For 2005, revisions of reserve estimates resulted in an increase of 270 MBbls of oil and an increase of 9.5 Bcf of gas, representing less than half of a percent and one percent of proved oil and gas reserves, respectively, as of December 31, 2005. See Note 17, Supplemental Oil and Gas Disclosures for reserve data.

We use the units-of-production method to amortize our oil and gas properties. Changes in reserve quantities will cause corresponding changes in depletion expense in periods subsequent to the

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quantity revision or, in some cases, a full cost ceiling limitation charge in the period of the revision. To date, changes in expense resulting from changes in previous estimates of reserves have not been material.

Full Cost Accounting

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized.

Under full cost accounting rules, capitalized costs, less accumulated amortization and related deferred income taxes and excluding costs not subject to amortization, may not exceed an amount equal to the sum of the present value discounted at ten percent of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Cash flows used in the calculation of the full cost ceiling limitation are determined based upon estimates of proved oil and gas reserves, future prices, and the costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil and gas prices could cause us to reduce the carrying value of our oil and gas properties. If capitalized costs exceed this limit and excluding costs not subject to amortization, the excess must be charged to expense. This is referred to as the “full cost ceiling limitation.”  The expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation. At the end of each quarter, a full cost ceiling limitation calculation is made.

Goodwill

We account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. These factors are each individually weighted to estimate the total fair value of goodwill. If the estimated fair value exceeds its carrying amount, goodwill is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. We recorded $45.0 million of goodwill in the purchase of Key on September 30, 2002 and $685.4 million of goodwill in the purchase of Magnum Hunter on June 7, 2005. To date, no related impairment has been recorded.

Allocation of Purchase Price

The allocation of the Magnum Hunter purchase price to oil and gas properties utilized prevailing oil and gas prices at the time of negotiations and announcement of the merger. The overall allocation of the purchase price is preliminary because certain items such as the determination of the final fair value of certain assets and liabilities as of the acquisition date have not been finalized. The goodwill amount related to the Magnum Hunter purchase as of December 31, 2005 has been adjusted downward to $672.4 million from the original amount recorded of $685.4 million, as the valuation process continues.

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Derivatives

SFAS No.133, Accounting for Derivative Instruments and Hedging activities, requires that all derivatives be recorded on the balance sheet at fair value. We generally determine the fair value of futures contracts and swap contracts based on the difference between the derivative’s fixed contract price and the underlying market price at the determination date using information we obtain from counter parties. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recorded as an expense. In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million net liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments have not been designated for hedge accounting treatment. As a result, Cimarex recognized in earnings during 2005 a net loss of $67.8 million. This charge includes both non-cash mark-to-market derivative losses as well as cash settlements. Cash payments related to these contracts that settled in 2005 totaled $64.3 million. The net derivative liability at December 31, 2005 equals $41.9 million. Cimarex will continue to recognize gains and losses in future earnings until the derivative instruments mature on December 31, 2006.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us. As of December 31, 2005, we have accrued for a mediated $6.5 million litigation settlement pertaining to post-production deductions on properties operated by Cimarex. The proposed settlement will be reviewed by the court in the first quarter of 2006 for approval. See Note 15 of Notes to Consolidated Financial Statements.

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability upon acquiring or drilling a well.

Recent Accounting Developments

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share-Based Payment, requiring companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation to employees for fiscal periods after June 15, 2005. This Statement amends SFAS No. 123, Accounting for Stock Based Compensation. We adopted the provisions of SFAS No. 123R in the first quarter of 2005. See Note 9 of Notes to Consolidated Financial Statements.

In September 2005, the FASB proposed new Staff Positions on applying Statement of Financial Accounting Standards (“SFAS”) No 123R, Share-Based Payment. The proposed rules establish that determining the grant date of a share-based payment is presumed to be satisfied at the date the award is approved under relevant corporate governance requirements, as long as the recipient is unable to negotiate the key terms and conditions of the award, and the award’s key terms are expected to be communicated to the recipient within a relatively short period of time after the date of approval. The new rule would become effective when an entity adopts 123R, or, if already adopted, in

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the first reporting period beginning after the Staff Position is finalized. The FASB also proposed a simpler alternative to the calculation of the amount of excess tax benefits available in additional-paid-in capital (“APIC”) to absorb tax deficiencies that occur after adopting 123R. Companies would have up to one year after adopting 123R to decide whether to elect the alternative computation method.

OVERVIEW

Our results of operations are primarily impacted by changes in oil and gas prices and changes in our production volumes. Realized oil and gas prices increased from $40.19 per barrel and $5.76 per Mcf in 2004 to $55.25 per barrel and $8.05 per Mcf in 2005.

Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that are incidental to sales of our own production. Sales and costs associated with our production are reflected in gas sales and transportation expense.

We also own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.

Transportation expenses are comprised of costs paid to carry and deliver oil and gas to a specified delivery point. In some cases we receive a payment from purchasers which is net of transportation costs, and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and expenses, respectively.

Production costs are composed of lease operating expenses, which generally consist of pumpers’ salaries, utilities, water disposal, maintenance and other costs necessary to operate our producing properties.

Taxes, other than income, are taxes assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad valorem and excise taxes.

Depreciation, depletion and amortization of our producing properties is computed using the units-of-production method. Because the economic life of each producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion. In addition, changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion.

General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices. While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth. Expenses related to the merger are costs associated with the Magnum Hunter transaction.

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees and the expensing of stock options resulting from the adoption of SFAS No. 123R.

BASIS OF PRESENTATION

Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). As a result of a dividend declared and paid by H&P on September 30, 2002, in the form of Cimarex common stock, Cimarex was spun-off and became a stand-alone company. Also on

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September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange.

In June 2005, Cimarex acquired Magnum Hunter Resources, Inc, by issuing 0.415 shares of Cimarex common stock for each share of outstanding Magnum Hunter common stock, resulting in the issuance of 39.7 million Cimarex common shares. At December 31, 2005, Cimarex had 82.4 million shares outstanding. The merger was accounted for as a purchase of Magnum Hunter by Cimarex. The results of operations of Magnum Hunter were included in our consolidated statements of operations beginning June 7, 2005.

Certain amounts in prior years’ financial statements have been reclassified to conform to the 2005 financial statement presentation. Most notably, the presentation of gas marketing and sales activities as discussed under revenue recognition in Note 4 to the Consolidated Financial Statements.

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RESULTS OF OPERATIONS

Year Ended December 31, 2005 Compared with Year Ended December 31, 2004:

SUMMARY DATA:

Net income for the year of 2005 was $328.3 million, or $4.90 per diluted share, compared to net income of $153.6 million, or $3.59 per diluted share in 2004. The change in net income results from the effect of changes in revenues and costs, as discussed further. The results of operations of Magnum Hunter are included in our consolidated statements of operations only for the period since the acquisition on June 7, 2005.

Oil and gas sales for the year of 2005 totaled $1.1 billion, compared to $472.4 million for 2004. The $600.0 million increase in sales between the two periods results from $302.0 million related to higher commodity prices and $298.0 million due to higher production volumes (due primarily to increased production resulting from the acquisition of Magnum Hunter).

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Realized gas prices averaged $8.05 per Mcf for 2005, compared to $5.76 per Mcf for 2004. This 40 percent change increased sales by $230.0 million between the two periods. Realized oil prices averaged $55.25 per barrel for 2005, compared to $40.19 per barrel for 2004. The increase in sales between periods resulting from this 37 percent improvement in oil prices totaled $72.0 million. Changes in realized prices were the direct result of overall market conditions.

Sales also benefited from higher production volumes. Average gas volumes rose 100.9 MMcf per day in 2005 to 274.7 MMcf per day from 173.8 MMcf per day in 2004, resulting in $211.1 million of incremental revenues. Oil volumes averaged 13,162 barrels per day for 2005, compared to 7,215 barrels per day in 2004, resulting in increased revenues of $86.9 million. The increase in sales volumes between the periods of 2005 and 2004 is due to positive drilling results during 2004 and 2005, and the inclusion of production from Magnum Hunter operations from June 7, 2005. Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted during the third and fourth quarters of 2005 as a result of hurricanes. It is estimated to have negatively impacted fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day and full-year volumes by 17 to 20 MMcf equivalent per day. At year-end 2005, approximately 20 MMcf equivalent was still shut-in. It is anticipated that most of the remaining shut-in volumes will be restored by the end of the first quarter of 2006. The timetable to restore full production largely depends on the startup of refineries, gas processing plants, platforms, facilities and pipelines owned and operated by others. No oil and gas reserves have been lost as a result of the storms and essentially all associated repair costs will be covered by insurance.

Gas gathering and processing revenues, net of related costs, equaled $12.4 million in 2005, compared to a loss of $0.2 million in 2004. The increase is due to the inclusion of related activities from Magnum Hunter operations from June 7, 2005. We own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.

Gas marketing net revenues decreased to $2 million from $2.7 million, net of related costs of $213.7 million and $193.0 million for 2005 and 2004, respectively. Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that is incidental to sales of our own production.

Costs and Expenses

Costs and expenses (not including gas gathering, marketing and processing costs) were $570.3 million in 2005 compared to $228.6 million in 2004. Depreciation, depletion and amortization (DD&A) was the largest component of the increase between periods. DD&A equaled $258.3 million in 2005 compared to $124.3 million in 2004. On a unit of production basis, DD&A was $2.00 per Mcfe in 2005 compared to $1.56 per Mcfe for 2004. The increase largely stems from costs associated with Magnum Hunter operations and higher costs for reserves added during 2004 and 2005.

Another large component of the increase in costs and expenses between periods was the loss on derivative instruments. Prior to the acquisition of Magnum Hunter, Cimarex did not use financial instruments to mitigate commodity price changes. In connection with the merger, we recognized a $39.3 million net liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments have not been designated for hedge accounting treatment. As a result, Cimarex recognized in earnings during 2005 a net loss of $67.8 million. The charge includes both non-cash mark-to-market derivative losses as well as cash settlements. Cash payments related to these contracts that settled in 2005 totaled $64.3 million. The net derivative liability at December 31, 2005 equals $41.9 million. Cimarex will continue to recognize mark-to-market gains and losses as well as amortization of these contracts in future earnings until the derivative instruments mature.

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Production costs rose $66.6 million from $37.5 million ($.47 per Mcfe) in 2004 to $104.1 million ($.81 per Mcfe) in 2005  The higher costs in 2005 resulted primarily from the inclusion of costs associated with Magnum Hunter operations, higher field operating expenses from an expanded number of properties and higher maintenance costs.

Transportation costs increased from $10.0 million in 2004 to $15.3 million in 2005. The increase is the result of expiring contracts being renewed with increased current market rates and the inclusion of transportation costs associated with Magnum Hunter operations.

Taxes other than income were $35.6 million greater, rising from $37.8 million in 2004 to $73.4 million in 2005. The increase between periods resulted from increases in oil and gas sales stemming from inclusion of Magnum Hunter operations, higher production volumes and commodity prices.

General and administrative (G&A) expenses increased $11.0 million from $22.5 million in 2004 to $33.5 million in 2005. The increase between periods is due to an expansion of staff and higher employee-benefit costs.

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards. Stock compensation increased from $2.0 million in 2004 to $5.0 million in 2005 due primarily to the $3.4 million expensing of stock options resulting from the adoption of SFAS No. 123R as of January 1, 2005. As of December 31, 2005, there was approximately $4.1 million of total unrecognized compensation cost related to non-vested share-option compensation awards granted under our stock incentive plan. That cost is expected to be recognized pro rata over a weighted-average period of five years.

As of December 31, 2005, expenses associated with the Magnum Hunter merger totaled $9.4 million. Of the $9.4 million, $3.6 million is due to the acceleration of vesting of stock options and restricted stock units resulting from change of control provisions under our stock incentive plan becoming effective due to the Magnum Hunter merger. The remaining $5.8 million consists of $4.3 million of general integration costs, $1.0 million for retention bonuses, and $0.5 million of related financing costs.

Net interest expense in 2005 of $5.8 million is comprised of $19.6 million of interest expense, offset by $11.7 million of capitalized interest resulting from interest recognized on borrowings associated with costs incurred to bring properties under development, not being amortized, to their intended use and $2.1 million of amortization of fair value of debt. This has increased from $1.1 million of interest expense in 2004. The additional components of the 2005 net interest amount and the increase from 2004 results from amounts associated with the debt assumed in the Magnum Hunter merger. Prior to the Magnum Hunter merger, Cimarex had no outstanding debt.

Income tax expense

Income tax expense totaled $188.1 million for 2005 versus $92.7 million for 2004. Tax expense equaled a combined federal and state effective income tax rate of 36.4 percent and 37.6 percent in 2005 and 2004, respectively. Approximately $75.2 million of our 2005 income tax expense is current.

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Year Ended December 31, 2004 Compared with Year Ended December 31, 2003:

SUMMARY DATA: