Cimarex Energy (CIMXP) 10-K 2005 FY Annual report

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)

Delaware	45-0466694
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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:

Title of Each Class	Name of each exchange on which registered
Common Stock ($.01 par value)	New York Stock Exchange

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):

Large accelerated filer   ý Accelerated filer   o Non-accelerated filer   o

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

Item
Glossary
PART I
1.	Business
2.	Properties
3.	Legal Proceedings
4.	Submission of Matters to a Vote of Security Holders
4A.	Executive Officers
PART II
5.	Market for the Registrant’s Common Equity and Related Stockholders Matters
6.	Selected Financial Data
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
7A.	Quantitative and Qualitative Disclosures About Market Risk
8.	Financial Statements
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9A.	Controls and Procedures
9B.	Other information
PART III
10.	Directors and Executive Officers of the Registrant
11.	Executive Compensation
12.	Security Ownership of Certain Beneficial Owners and Management
13.	Certain Relationships and Related Transaction
14.	Principal Accountant Fees and Services
PART IV
15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K

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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.

	Exploration and Development Capital		Gross Wells Drilled	Net Wells Drilled	Success Rate		12/31/05 Proved Reserves (Bcfe)
	(in millions)
Permian Basin	$	150	117	75.0	87	%	611.8
Mid-Continent	238		185	93.4	96	%	539.4
Gulf Coast	167		44	27.7	66	%	117.9
Gulf of Mexico	65		24	8.7	83	%	55.5
Other	22		12	5.6	75	%	68.1
	$	642	382	210.4	88	%	1,392.7

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:

	Years Ending December 31,
	2005		2004		2003
Production Volumes
Gas (MMcf)	100,272		63,611		50,552
Oil (MBbls)	4,804		2,641		2,504
Equivalent (MMcfe)	129,096		79,457		65,576
Net Average Daily Volumes:
Gas (MMcf)	274.7		173.8		138.5
Oil (MBbl)	13.2		7.2		6.9
Equivalent (MMcfe)	353.7		217.1		179.9
Average Sales Price
Gas ($/MMcf)	$	8.05	$	5.76	$	4.96
Oil ($/Bbl)	$	55.25	$	40.19	$	29.30

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.

	Second-Half 2005 Average Daily Production
	Oil (Bbl/d)	Gas (MMcf/d)	Total (MMcfe/d)	2005 Avg. (MMcfe/d)
Mid-Continent	4,810	146.4	175.3	156.5
Permian Basin	7,950	82.4	130.1	82.7
Gulf Coast	2,790	67.7	84.4	80.3
Gulf of Mexico	1,240	30.5	37.9	23.6
Other	560	7.1	10.5	10.6
	17,350	334.1	438.2	353.7

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:

	Years Ending December 31,
	2005		2004			2003
Total Proved Reserves -
Gas (MMcf)	1,004,482		364,641			337,344
Oil, condensate and NGLs (MBbls)	64,710		14,063			14,137
Equivalent (MMcfe)	1,392,742		449,020			422,167
Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands)	$	3,028,100	$	798,033		$	711,581
Average price used in calculation of future net cash flow -
Gas ($/MMcf)	$	7.89	$		5.58	$	5.54
Oil ($/Bbl)	$	57.65	$	40.76		$	30.49

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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.

	Oil (MBbl)	Gas (MMcf)	Equivalent (MMcfe)	Percent of Proved Reserves
Permian Basin	43,960	348,012	611,772	44	%
Mid-Continent	14,074	454,986	539,430	39	%
Gulf Coast	3,872	94,628	117,860	8	%
Gulf of Mexico	1,566	46,126	55,522	4	%
Other	1,238	60,730	68,158	5	%
	64,710	1,004,482	1,392,742	100	%

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.

Field	Region	% of Total Proved Reserves		Avg. Working Interest		Avg. Depth (feet)	Primary Formation
Hugoton	Mid-Continent	4	%	60	%	2,600	Chase
Eola-Robberson	Mid-Continent	4	%	97	%	5,500-11,000	Bromide/McLish/Oil Creek
Panhandle East	Mid-Continent	4	%	98	%	2,400	Brown Dolomite
Carlsbad South	Permian	4	%	53	%	11,500	Morrow/Atoka
Spraberry	Permian	3	%	84	%	7,500	Spraberry
Quail Ridge	Permian	3	%	61	%	13,000	Morrow
Jo-Mill	Permian	3	%	13	%	7,500	Spraberry
Hemphill	Mid-Continent	2	%	96	%	11,000	Granite Wash
Canute, North	Mid-Continent	1	%	52	%	13,000-15,000	Red Fork/Atoka
Keystone	Permian	1	%	99	%	4,300-5,000	Holt/San Andres
		29	%

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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	Undeveloped Acreage		Developed Acreage		Total Acreage
	Gross	Net	Gross	Net	Gross	Net
Mid-Continent	186,371	98,139	876,445	414,706	1,062,816	512,845
Permian	208,712	97,869	582,715	319,025	791,427	416,894
Gulf Coast	148,713	53,421	407,178	111,831	555,891	165,252
Gulf of Mexico	832,057	513,540	317,610	109,906	1,149,667	623,446
Other	2,381,451	1,872,380	372,311	144,664	2,753,762	2,017,044
	3,757,304	2,635,349	2,556,259	1,100,132	6,313,563	3,735,481

Gross Wells Drilled

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

	Exploratory			Developmental
	Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2005	55	20	75	283	24	307
Year ended December 31, 2004	12	11	23	177	21	198
Year ended December 31, 2003	19	27	46	125	7	132

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:

	Exploratory			Developmental
	Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2005	33.21	15.59	48.80	144.77	16.78	161.55
Year ended December 31, 2004	6.78	6.55	13.33	78.78	12.16	90.94
Year ended December 31, 2003	17.42	20.12	37.54	55.45	4.21	59.66

Productive Wells

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

	Gas		Oil
	Gross	Net	Gross	Net
Mid-Continent	3,411	1,869.0	729	273.3
Permian	1,027	537.6	6,270	1,291.8
Gulf Coast	498	152.2	162	68.6
Gulf of Mexico	114	35.9	43	7.5
Other	138	29.0	486	32.8
	5,188	2623.7	7,690	1674.0

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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:

Name	Age	Office
F.H. Merelli	69	Chairman of the Board, Chief Executive Officer and President
Thomas E. Jorden	48	Executive Vice President-Exploration
Joseph R. Albi	47	Executive Vice President-Operations
Paul Korus	49	Vice President, Chief Financial Officer, and Treasurer
Stephen P. Bell	51	Senior Vice President, Business Development and Land
Gary R. Abbott	33	Vice President-Corporate Engineering
Richard S. Dinkins	61	Vice President of Human Resources
James H. Shonsey	54	Chief Accounting Officer and Controller

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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.

2005	High		Low		Dividends Per Share
First Quarter	$	42.56	$	34.48	$	.00
Second Quarter	$	40.55	$	33.82	$	.00
Third Quarter	$	45.98	$	38.30	$	.00
Fourth Quarter	$	46.31	$	35.85	$	.00

2004	High		Low		Dividends Per Share
First Quarter	$	29.75	$	24.05	$	.00
Second Quarter	$	30.25	$	26.24	$	.00
Third Quarter	$	35.25	$	29.20	$	.00
Fourth Quarter	$	41.45	$	33.60	$	.00

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.

Period	Total Number of Shares Purchased	Average Price Paid per Share
December 1, 2005 to December 31, 2005	68,000	$	43.00

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.

	For the Years Ended December 31,								For the Fiscal Year Ended September 30,		Three Months Ended December 31,
	2005		2004		2003		2002		2001 (1)		2001 (1)
	(In thousands, except per share and proved reserve amounts)
Operating results:
Revenues	$	1,118,622	$	475,164	$	325,621	$	160,620	$	228,995	$	28,647
Net income	328,325		153,592		94,633		39,819		35,253		4,479
Basic earnings per share	5.07		3.70		2.28		1.32		1.33		0.17
Diluted earnings per share	4.90		3.59		2.22		1.31		1.33		0.17
Cash dividends declared per share	—		—		—		—		—		—
Balance sheet data:
Total assets	4,180,335		1,105,446		805,508		674,286		246,212		251,966
Total debt	352,451		—		—		32,000		—		—
Stockholders’ equity	2,595,453		700,712		534,740		444,880		166,795		175,082
Other financial data:
Oil and gas sales	1,072,422		472,389		324,119		157,299		222,136		26,857
Oil and gas capital expenditures	2,462,826		296,429		162,627		368,503		104,975		14,425
Proved Reserves:
Gas (MMcf)	1,004,482		364,641		337,344		318,627		216,337		212,326
Oil (MBbls)	64,710		14,063		14,137		15,025		5,932		5,304
Total equivalent (MMcfe)	1,392,742		449,020		422,167		408,779		251,927		244,150

(1)    On September 30, 2002, Cimarex changed its fiscal year from the twelve months ended September 30 to the twelve months ended December 31.

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:

	For the Years Ended December 31,
(in thousands or as indicated)	2005			2004
Net income	$	328,325		$	153,592
Per share-basic	5.07			3.70
Per share-diluted	4.90			3.59
Gas sales	$	807,007		$	366,260
Oil sales	265,415			106,129
Total oil and gas sales	$	1,072,422		$	472,389
Total gas volume-Mcf	100,272			63,611
Gas volume-MMcf per day	274.7			173.8
Average gas price-per Mcf	$	8.05		$	5.76
Total oil volume-thousand barrels	4,804			2,641
Oil volume-barrels per day	13,162			7,215
Average oil price-per barrel	$	55.25		$	40.19
Gas gathering and processing revenues	$	44,238		$	101
Gas gathering and processing costs	(31,890		)	(284			)
Gas gathering and processing margin	$	12,348		$	(183		)
Gas marketing revenues, net of related costs	$	1,962		$		2,674
Costs and expenses:
Depreciation, depletion and amortization	$	258,287		$	124,251
Production	104,067			37,476
Transportation	15,338			10,003
Taxes other than income	73,360			37,761
General and administrative	33,497			22,483
Stock compensation	4,959			1,957
Expenses related to merger	9,422			—
Loss on derivative instruments	67,800			—
Int. exp., net of cap. int. & amort. of F.V. of debt	5,789			1,075
Asset retirement obligation accretion	3,819			1,241
Other income, net	(6,061		)	(7,685			)

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:

	For the Years Ended December 31,
(in thousands or as indicated)	2004			2003
Net income	$	153,592		$	94,633
Per share-basic	3.70			2.28
Per share-diluted	3.59			2.22
Gas sales	$	366,260		$	250,764
Oil sales	106,129			73,355
Total oil and gas sales	$	472,389		$	324,119
Total gas volume-MMcf	63,611			50,552
Gas volume-MMcf per day	173.8			138.5
Average gas price-per Mcf	$	5.76		$	4.96
Total oil volume-thousand barrels	2,641			2,504
Oil volume-barrels per day	7,215			6,859
Average oil price-per barrel	$	40.19		$	29.30
Gas gathering and processing revenues	$	101		$	679
Gas gathering and processing costs	(284		)	(849		)
Gas gathering and processing margin	$	(183	)	$	(170	)
Gas marketing revenues, net of related costs	$	2,674		$	823
Costs and expenses:
Depreciation, depletion and amortization	$	124,251		$	88,774
Production	37,476			31,801
Transportation	10,003			7,472
Taxes other than income	37,761			27,485
General and administrative	22,483			17,526
Stock compensation	1,957			1,824
Interest expense	1,075			1,285
Asset retirement obligation accretion	1,241			1,009
Other income, net	(7,685		)	(269		)

We reported net income of $153.6 million, or $3.59 per diluted share, in 2004 compared to net income of $94.6 million, or $2.22 per diluted share, in 2003. The primary reason for this increase in net income is the increase in revenues from oil and gas sales. These sales for 2004 equaled $472.4 million, compared to $324.1 million in 2003. The $148.3 million increase in sales between the two years consists of $79.6 million related to higher oil and gas prices, and $68.7 million associated with increased production volumes.

Realized gas prices averaged $5.76 per Mcf for 2004, compared to $4.96 per Mcf for 2003. This 16 percent increase had an incremental effect on sales of $50.9 million between the two years. Realized oil prices averaged $40.19 per barrel for 2004, compared to $29.30 per barrel for 2003. The effect on sales between years resulting from this 37 percent improvement in oil prices totaled $28.7 million. Higher prices were the direct result of overall market conditions.

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Oil and gas sales also benefited from higher production volumes. Average gas volumes rose 35.3 MMcf per day in 2004 to 173.8 MMcf per day from 138.5 MMcf per day in 2003, resulting in $64.8 million of incremental revenues. Oil volumes averaged 7,215 barrels per day in 2004, compared to 6,859 barrels per day in 2003, resulting in increased revenues of $3.9 million. The increase in overall sales volumes between the two years is due to positive drilling results during 2004. Average daily production contributed from wells drilled during 2004 totaled 27.8 MMcfe, which largely offset natural declines.

Gas gathering and processing revenues, net of related costs, equaled a loss of $0.2 million in both 2004 and 2003, respectively. 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. The financial impact from these activities is small relative to our overall results of operations.

Gas marketing net revenues increased to $2.7 million from $0.8 million, net of related costs of $193.0 million and $128.7 million for 2004 and 2003, 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. The marketing margin in 2004 was favorably impacted by wide fluctuations in gas prices.

Costs and Expenses

Overall costs and expenses (not including gas gathering, processing and marketing activities) were $228.6 million in 2004 compared to $176.9 million in 2003. The largest component of this $51.7 million increase between years is a $35.5 million increase in total depreciation, depletion and amortization expense (DD&A) from $88.8 million in 2003 to $124.3 million in 2004, resulting from higher costs for reserves added during 2004. On a unit of production basis, DD&A was $1.56 per Mcfe in 2004 compared to $1.35 per Mcfe for 2003.

Production costs rose $5.7 million from $31.8 million in 2003 to $37.5 million in 2004 due primarily to the installation and operation of additional compressors (primarily in Kansas) to enhance production, higher field operating expenses from an expanded number of properties, and higher maintenance costs.

Taxes other than income were $10.3 million greater, rising from $27.5 million in 2003 to $37.8 million in 2004. This increase resulted from a 46 percent jump in oil and gas sales stemming from higher product prices and volumes.

General and administrative (G&A) expenses increased $5.0 million from $17.5 million in 2003 to $22.5 million in 2004, due to an expansion of staff as a result of a larger drilling program, higher employee-benefit costs, and higher consulting fees.

Other income and expense, net equaled $7.7 million in 2004, consisting of $3.2 million of net gains from the sale of inventory, $3.5 million of net gains from the settlement of various litigation, and $1.0 million of interest income, versus $0.3 million of interest income in 2003.

Smaller variances of costs between years include stock compensation related to amortization of costs of restricted stock, increasing by $0.1 million from $1.8 million in 2003 to $1.9 million in 2004; and accretion expense associated with asset retirement obligations, increasing by $0.2 million from $1.0 million in 2003 to $1.2 million in 2004. Asset retirement obligations were recorded with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003.

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Income tax expense

Income tax expense totaled $92.7 million for 2004 versus $55.1 million for 2003. Tax expense equaled a combined federal and state effective income tax rate of 37.6 percent and 37.2 percent in 2004 and 2003, respectively. The increase in effective rates results from greater utilization of tax credits in 2003. We estimate that $25.9 million of our 2004 income tax expense is current.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our primary source of capital is cash flow generated from operating activities. Prices we receive for oil and gas sales and our level of production will impact these future cash flows. No prediction can be made as to the prices we will receive. Production volumes will in large part be dependent upon the amount and results of future capital expenditures. In turn, actual levels of capital expenditures may vary due to many factors, including drilling results, oil and gas prices, industry conditions, prices and availability of goods and services, and the extent to which proved properties are acquired.

Cash flow provided by operating activities for 2005 was $704.7 million, compared to $355.9 million for 2004. The increase in 2005 from the earlier period resulted primarily from higher oil and gas production and prices and the acquisition of Magnum Hunter.

Higher revenues from oil and gas sales facilitated the funding of our exploration and development expenditure program for 2005.

Cash flow used in investing activities for 2005 was $497.5 million, compared to $293.1 million for 2004. The increase in 2005 stemmed from a larger exploration and development program.

Cash flow used in financing activities in 2005 was $261.4 million versus $12.6 million provided in 2004. The cash used in financing activities in 2005 resulted primarily from the payment of $273.5 million on debt (including $3.5 million of capital lease debt) assumed in the Magnum Hunter acquisition, offset by proceeds from issuance of common stock from stock option exercises.

Financial Condition

As of December 31, 2005, stockholders’ equity totaled $2.6 billion, up from $700.7 million at December 31, 2004. The increase resulted primarily from $1.5 billion of common stock issued in connection with the Magnum Hunter acquisition, 2005 net income of $328.3 million and $49.6 million of fair value of common stock associated with the convertible debt assumed in the Magnum Hunter merger. At December 31, 2005 our cash balance equaled $61.6 million.

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. Also 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 at an average price of $43.00. 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.

Working Capital

Working capital at December 31, 2005 totaled $31.6 million, compared to $93.4 million at December 31, 2004. The decrease is primarily the result of a decrease in cash and an increase in current derivative liability. Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various

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industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been significant.

Financing

Prior to the Magnum Hunter merger, Cimarex had no outstanding debt. In connection with the merger on June 7, 2005, Cimarex assumed the following debt (in thousands):

Bank debt	$	270,000
Capital lease obligations	3,501		(1)
9.6% Notes due 2012 (face value $195,000)	215,475		(2)
Floating rate convertible notes due 2023 (face value $125,000)	144,750		(3)
	633,726
Less: Current portion of capital lease obligations	(758		)(1)
Total long-term debt	$	632,968

Debt at December 31, 2005 consisted of the following (in thousands).

Bank debt	$	—
9.6% Notes due 2012 (face value of $195,000)	213,770		(4)
Floating rate convertible notes due 2023, 4.49% at December 31, 2005 (face value of $125,000)	138,681		(4)
Total long-term debt	$	352,451

(1)Paid in its entirety in August 2005.

(2)Fair market value at June 7, 2005.

(3)Fair market value at June 7, 2005. Reflected in Paid-in-Capital is $49.6 million related to the fair value of common stock associated with the convertible debt.

(4)Fair market value at date of acquisition less amortization of the premium of fair market value over face value.

We have the capability to borrow on a Senior Secured Revolving Credit Facility. On June 13, 2005, Cimarex entered into a new Revolving Credit Facility that provides for $500 million of long-term committed credit, with a borrowing base of $825 million. Effective November 1, 2005, Cimarex’s borrowing base, as determined by its lenders in accordance with certain provisions under the credit agreement, was increased to $1 billion. The new facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries.

The Credit Facility agreement contains both financial and non-financial covenants, including limitations on share repurchases, dividends and other restricted payments. The financial covenants require Cimarex to maintain a minimum ratio of funded indebtedness to trailing twelve-month EBITDA (earnings before interest, taxes and DD&A adjusted for non-cash items associated with mark-to-market accounting, stock-based compensation and impairment of goodwill) of less than three times and a ratio of current assets plus unused commitments to current liabilities of greater than one. Cimarex continues to comply with these covenants and does not view them as materially restrictive.

At the Company’s option, advances under the Credit Facility bear interest based upon a Base rate or a Eurodollar rate. The Base rate means the greater of (a) the JP Morgan Chase Bank prime rate or (b) the federal funds rate plus one-half of one percent. The Eurodollar rate means the applicable

37

British Bankers’ Association London Interbank Offered Rate (LIBOR) plus a margin ranging from 1.00-1.75 percent depending on the borrowing base usage. There were no borrowings outstanding under this facility at December 31, 2005. Unused commitments under the agreement are subject to a commitment fee ranging from 0.225-0.375 percent, also depending on the borrowing base usage.

Cimarex currently has a letter of credit posted against its borrowing base of $2.5 million that reduces funds available under the Credit Facility. The letter of credit is un-drawn and was posted to cover future plugging and abandonment costs and potential environmental remediation costs associated with a certain producing property located in New Mexico.

The 9.6% notes assumed in the Magnum Hunter merger have a face value of $195 million and are due March 15, 2012. The notes are unsecured and are redeemable, as a whole or in part, at Cimarex’s option, on and after March 15, 2007 at the following redemption prices (expressed as percentages of the principal amount), plus accrued interest, if any, thereon to the date of redemption.

Year	Percentage
2007	104.8	%
2008	103.2	%
2009	101.6	%
2010 and thereafter	100.0	%

The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. On December 15, 2005, the interest rate was reset to 4.49%.

Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On December 31, 2005, the closing price of our common stock traded on the New York Stock Exchange was $43.01.

If any holders of the notes elect to tender their notes for conversion, they are entitled to receive a conversion value approximately equal to the ten-day average closing value of our common stock times 34.5. We would then deliver the conversion value as follows:   (1) an amount of cash equal to the lesser of (a) the conversion value or (b) the principal amount of the notes and (2) an amount of common shares equal in value to the conversion value less the principal amount of the notes (net shares). At December 31, 2005, the maximum total net shares that the holders would be entitled to if they all elected to tender their notes was 1.5 million. At December 31, 2005, utilizing an average common stock price of $43.01, the conversion value equaled $185.5 million (or $1,484 per bond). There is not an observable market for the notes. Management estimates the fair value of the notes at December 31, 2005 was $190.8 million (or $1,526 per bond). As discussed in Note 3 to the Consolidated Financial Statements, the common stock component of the convertible debt has been included in stockholders’ equity.

In addition to the holders’ right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require Cimarex to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013 and 2018. The indenture agreement also provides Cimarex with an option to redeem

38

some or all of the notes at a redemption price equal to 100% of the principal amount (plus accrued interest) anytime after December 22, 2008.

All long-term debt is guaranteed by Cimarex and its subsidiaries, except Canvasback. Assets held by Canvasback consist primarily of 790 thousand shares of Cimarex stock, which is included in Cimarex’s Treasury stock.

On February 18, 2005, Magnum Hunter’s 40% owned affiliate, Apple Tree Holdings, LLC (“Apple Tree”), entered into a $20.6 million construction loan agreement (“Construction Loan”). The Construction Loan provides financing for the construction of a processing plant, natural gas lateral, carbon dioxide line and related infrastructure in Huerfano County, Colorado. The Construction Loan bears interest at either LIBOR plus 2.25% or a base rate plus 1.25% and will mature no later than July 31, 2006. Total borrowings under this loan at December 31, 2005 were $19.8 million, of which our share was $7.9 million. We have provided a guarantee to the lender for this Construction Loan. In return for our guarantee, we received an up-front fee as well as the right to receive 55% of distributable cash flows from Apple Tree until certain financial tests are met. In the event that the Construction Loan goes into default and we have to perform under the guarantee, we will have recourse against the project and related subsidiaries. We have included $162 thousand in other liabilities on our condensed consolidated balance sheet to represent the fair value of our guarantee issued for the Construction Loan.

Contractual Obligations and Material Commitments

At December 31, 2005, we had contractual obligations and material commitments as follows:

	Payments Due by Period
	(In thousands)
Contractual obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-term debt (1)	$	320,000	$	—	$	—	$	—	$	320,000
Fixed-Rate interest payments(1)	121,680		18,720		37,440		37,440		28,080
Commodity derivatives	41,926		41,926		—		—		—
Operating leases	31,645		4,079		8,891		7,932		10,743
Drilling commitments	106,036		106,036		—				—
Asset retirement obligation(2)	101,128		3,570		—		—		—
Other liabilities	3,645		21		222		144		3,258

(1) See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt.

(2) We have excluded the long term asset retirement obligations because we are not able to precisely predict the timing of these amounts.

At December 31, 2005, we had a firm sales contract to deliver approximately 1.4 Bcf of natural gas over the next five months. If this gas is not delivered, our financial commitment would be approximately $9.4 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our reserves and current production levels.

Cimarex has other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $4.8 million.

All of the commitments were routine and were made in the normal course of our business.

Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts available

39

under our existing line of credit will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities.

2006 Outlook

Our projected 2006 exploration and development expenditure program of approximately $1 billion will require a great deal of coordination and effort. Though there are a variety of factors that could curtail, delay or even cancel some of our drilling operations, we believe our projected program has a high degree of occurrence. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts in these areas warrant pursuit of the projects.

Costs of operations on a per Mcfe basis for 2006 are estimated to approximate levels realized in late 2005. Should factors beyond our control change, our program and realized costs will vary from current projections. These factors could include volatility in commodity prices, changes in the supply of and demand for oil and gas, weather conditions, governmental regulations and more.

Production estimates for 2006 range from 480 to 505 MMcfe per day. Revenues will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2005, our realized prices averaged $8.05 per Mcf of gas and $55.25 per barrel of oil. Prices can be very volatile and the possibility of 2006 realized prices being less than they were in 2005 is high.

ITEM 7A.QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

Price Fluctuations

Our results of operations are highly dependent upon the prices we receive for oil and gas production, and those prices are constantly changing in response to market forces. Nearly all of our revenue is from the sale of oil and gas, so these fluctuations, positive and negative, can have a significant impact on our results of operations and cash flows.

Monthly gas price realizations during 2005 ranged from $5.95 per Mcf to $11.35 per Mcf. Oil prices ranged from $45.24 per barrel to $61.81 per barrel. It is impossible to predict future oil and gas prices with any degree of certainty.

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. 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. Actual gains and losses to be recognized in the future may differ materially, arising from movements in the prices of oil and natural gas. Cimarex will continue to recognize gains and losses in future earnings until the derivative instruments mature. Actual gains and losses to be recognized may differ materially from current fair value estimates.

40

The following is a summary of the company’s open derivative contracts as of December 31, 2005:

Commodity	Type	Volume/Day	Duration	Weighted Average Price	Fair Value (000’s)
Natural Gas	Collar	20,000 MMBTU	Jan 06 – Dec 06	$5.25 - $6.30	$	32,169
Crude Oil	Collar	1,000 BBL	Jan 06 – Dec 06	$30.00 - $35.85	9,757
					$	41,926

Weighted average NYMEX prices at December 31 for 2006 approximate $10.77 per Mcf of gas and $62.59 per barrel of oil.

Any sustained weakness in prices may affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for exploration and development and could cause us to record a reduction in the carrying value of our oil and gas properties.

Interest Rate Risk

Fixed and Variable Rate Debt. Cimarex assumed fixed and variable rate debt as part of the acquisition of Magnum Hunter. These agreements expose the company to market risk related to changes in interest rates. The company has a credit facility that bears interest at either a Base rate or a Eurodollar rate at the Company’s option. There were no borrowings outstanding under this facility at December 31, 2005.

The following table presents the carrying and fair value of the company’s debt along with average interest rates as of December 31, 2005. Fair values for the fixed rate Senior Notes and the Convertible Notes are valued at their last traded value before December 31, 2005.

Expected Maturity Dates	2012		2023		Total		Book Value		Fair Value
(in thousands of dollars)
Variable Rate Debt:
Convertible Notes (a)	$	—	$	125,000	$	125,000	$	138,681	$	190,775
Fixed Rate Debt:
Senior Notes (b)	$	195,000	$	—	$	195,000	$	213,770	$	214,988

(a)

The interest rate on the convertible notes is 4.49%. The rate on these notes is equal to the three month LIBOR, adjusted quarterly. A holder of these notes has the right to require us to repurchase all or a portion of these notes on December 15, 2008, 2013, and 2018. The repurchase will be equal to the face value of the notes plus accrued and unpaid interest up to the date of repurchase. Included in Paid in Capital is $49.6 million related to the fair value of common stock associated with the convertible debt.

(b)

The interest rate on the senior notes due 2012 is a fixed 9.6%.

41

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CIMAREX ENERGY CO.

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES

All other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or related notes thereto.

42

Report of Independent Registered Public Accounting Firm

The Board of Directors
Cimarex Energy Co.:

We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the three year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2005 in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission, and our report dated March 8, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

As discussed in Note 6 to the Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

As discussed in Note 2 to the Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of Financial Accounting Standards No. 123 (R), Share Based Payments as of January 1, 2005.

/s/ KPMG LLP

Denver, Colorado
March 8, 2006

43

CIMAREX ENERGY CO.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share information)

	December 31,
	2005			2004
Assets
Current assets:
Cash and cash equivalents	$	61,647		$	115,746
Accounts receivable:
Trade, net of allowance	66,965			22,465
Oil and gas sales, net of allowance	191,748			29,127
Gas gathering, processing, and marketing, net of allowance	30,471			52,397
Inventories	34,784			9,742
Deferred income taxes	17,959			2,149
Other current assets	25,454			4,821
Total current assets	429,028			236,447
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	3,602,797			1,596,704
Unproved properties and properties under development, not being amortized	388,839			72,249
	3,991,636			1,668,953
Less – accumulated depreciation, depletion and amortization	(1,114,677		)	(866,660		)
Net oil and gas properties	2,876,959			802,293
Fixed assets, less accumulated depreciation of $17,171 and $8,795	86,916			16,109
Goodwill	717,391			44,967
Other assets, net	70,041			5,630
	$	4,180,335		$	1,105,446
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	50,529		$	12,430
Gas gathering, processing, and marketing	31,418			14,081
Accrued liabilities:
Exploration and development	76,725			31,604
Taxes other than income	15,978			12,702
Other	86,373			33,056
Derivative fair value	41,926
Revenue payable	94,469			39,129
Total current liabilities	397,418			143,002
Long-term debt	352,451			—
Deferred income taxes	717,790			225,285
Asset retirement obligation	97,558			17,202
Deferred compensation	13,881			14,683
Other liabilities	5,784			4,562
Total liabilities	1,584,882			404,734
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued	—			—
Common stock, $0.01 par value, 200,000,000 shares authorized, 83,524,285 and 41,729,280 shares issued, respectively	835			417
Treasury stock, at cost, 1,146,822 shares held	(43,554		)
Paid-in capital	1,865,597			250,248
Unearned compensation	(15,862		)	(10,072		)
Retained earnings	788,356			460,031
Accumulated other comprehensive income	81			88
	2,595,453			700,712
	$	4,180,335		$	1,105,446

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

44

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	For the Years Ended December 31,
	2005			2004			2003
Revenues:
Gas sales	$	807,007		$	366,260		$	250,764
Oil sales	265,415			106,129			73,355
Gas gathering and processing	44,238			101			679
Gas marketing, net of related costs of $213,749, $193,041 and $128,654 respectively	1,962			2,674			823
	1,118,622			475,164			325,621
Costs and expenses:
Depreciation, depletion and amortization	258,287			124,251			88,774
Asset retirement obligation accretion	3,819			1,241			1,009
Production	104,067			37,476			31,801
Transportation	15,338			10,003			7,472
Gas gathering and processing	31,890			284			849
Taxes other than income	73,360			37,761			27,485
General and administrative	33,497			22,483			17,526
Stock compensation	4,959			1,957			1,824
Expenses related to merger	9,422			—			—
Loss on derivative instruments	67,800			—			—
	602,439			235,456			176,740
Operating income	516,183			239,708			148,881
Other income and expense:
Interest expense	19,607			1,075			1,285
Amortization of fair value of debt	(2,132		)	—			—
Capitalized interest	(11,686		)	—			(304		)
Other, net	(6,061		)	(7,685		)	(269		)
Income before income tax expense and cumulative effect of a change in accounting principle	516,455			246,318			148,169
Income tax expense	188,130			92,726			55,141
Income before cumulative effect of a change in accounting principle	328,325			153,592			93,028
Cumulative effect of a change in accounting principle, net of tax	—			—			1,605
Net income	$	328,325		$	153,592		$	94,633
Earnings per share:
Basic:
Income before cumulative effect of a change in accounting principle	$	5.07		$	3.70		$	2.24
Cumulative effect of a change in accounting principle, net of tax	—			—			0.04
Net income	$	5.07		$	3.70		$	2.28
Diluted:
Income before cumulative effect of a change in accounting principle	$	4.90		$	3.59		$	2.18
Cumulative effect of a change in accounting principle, net of tax	—			—			0.04
Net income	$	4.90		$	3.59		$	2.22
Weighted average shares outstanding:
Basic	64,761			41,466			41,521
Diluted	67,000			42,763			42,640

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

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CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2005			2004			2003
Cash flows from operating activities:
Net income	$	328,325		$	153,592		$	94,633
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	258,287			124,251			88,774
Asset retirement obligation accretion	3,819			1,241			1,009
Cumulative effect of a change in accounting principle, net of taxes	—			—			(1,605		)
Deferred income taxes	112,890			66,849			30,590
Amortization of restricted stock compensation	4,959			1,957			1,914
Derivative instruments	3,483			—			—
Other	12,844			798			433
Changes in operating assets and liabilities, net of effects of the acquisition of Magnum Hunter:
(Increase) in receivables, net	(45,787		)	(35,696		)	(10,123		)
(Increase) in inventory and other current assets	(27,293		)	(1,703		)	(5,956		)
Increase in accounts payable and accrued liabilities	52,488			42,918			6,316
Increase (decrease) in other noncurrent liabilities	719			1,646			(875		)
Net cash provided by operating activities	704,734			355,853			205,110
Cash flows from investing activities:
Oil and gas expenditures	(631,549		)	(281,407		)	(150,501		)
Acquisition of oil and gas properties	(1,973		)	(324		)	(2,032		)
Merger costs	(13,740		)	—			—
Cash received in connection with acquisition	33,407			—			—
Proceeds from sale of assets	141,842			926			1,041
Other expenditures	(25,440		)	(12,296		)	(8,149		)
Net cash used by investing activities	(497,453		)	(293,101		)	(159,641		)
Cash flows from financing activities:
Borrowing (payments) on long-term debt, net	(273,501		)	—			(32,000		)
Financing costs incurred	(1,516		)	—			—
Common stock reacquired and retired	(2,130		)	(1,254		)	(8		)
Proceeds from issuance of common stock	15,767			13,828			4,632
Net cash provided by (used in) financing activities	(261,380		)	12,574			(27,376		)
Net increase in cash and cash equivalents	(54,099		)	75,326			18,093
Cash and cash equivalents at beginning of period	115,746			40,420			22,327
Cash and cash equivalents at end of period	$	61,647		$	115,746		$	40,420

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

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CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

															Accumulated
															Other						Total
	Common Stock					Paid-in			Unearned			Retained			Comprehensive			Treasury			Stockholders’
	Shares		Amount			Capital			Compensation			Earnings			Income			Stock			Equity
Balance, December 31, 2002	41,410		$	414		$	243,420		$	(10,814	)	$	211,860		$	—		$	—		$	444,880
Net income	—		—			—			—			94,633			—			—			94,633
Issuance of restricted stock awards	65		1			1,348			(1,349		)	—			—			—			—
Common stock reacquired and retired	—		—			(8		)	—			—			—			—			(8		)
Amortization of unearned compensation	—		—			—			2,394			—			—			—			2,394
Exercise of stock options, net of tax benefit of $1,203 recorded in paid-in capital	295		3			4,695			—			—			—			—			4,698
Net distribution to Helmerich & Payne, Inc.	—		—			—			—			(54		)	—			—			(54		)
Restricted stock forfeited and retired	(17	)	—			(308		)	229			—			—			—			(79		)
Shares of restricted stock exchanged for restricted stock units	(689	)	(7		)	(11,717		)	—			—			—			—			(11,724		)
Balance, December 31, 2003	41,064		411			237,430			(9,540		)	306,439			—			—			534,740
Net income	—		—			—			—			153,592			—			—			153,592
Issuance of restricted stock awards	15		—			400			(400		)	—			—			—			—
Issuance of restricted stock unit awards	—		—			—			(2,809		)	—			—			—			(2,809		)
Common stock reacquired and retired	(35	)	—			(1,254		)	—			—			—			—			(1,254		)
Amortization of unearned compensation	—		—			—			2,677			—			—			—			2,677
Exercise of stock options, net of tax benefit of $4,805 recorded in paid-in capital	691		6			13,822			—			—			—			—			13,828
Shares of restricted stock exchanged for restricted stock units	(6	)	—			(150		)	—			—			—			—			(150		)
Net unrealized gains on marketable sercurities of investments															88			—			88
Balance, December 31, 2004	41,729		417			250,248			(10,072		)	460,031			88			—			700,712
Net income	—		—			—			—			328,325			—			—			328,325
Issuance of common stock, net of offering costs	42,185		422			1,587,775			—			—			—			—			1,588,197
Issuance of restricted stock awards	249		2			9,913			(9,915		)	—			—			—			—
Issuance of restricted stock unit awards	—		—			—			(2,856		)	—			—			—			(2,856		)
Treasury Stock	—		—			—			—			—			—			(96,161		)	(96,161		)
Common stock reacquired and retired	(1,450	)	(14		)	(54,723		)	—			—			—			52,607			(2,130		)
Restricted stock forfeited and retired	(2	)	—			(80		)	78			—			—			—			(2		)
Amortization of unearned compensation	—		—			—			4,259			—			—			—			4,259
Exercise of stock options, net of tax benefit of $6,442 recorded in paid-in capital	659		7			15,761			—			—			—			—			15,768
Stock Option Compensation Expense	—		—			2,348			—			—			—			—			2,348
Accelerated vesting of stock options, restricted stock and restricted stock units	154		1			4,713			2,644			—			—			—			7,358
Equity attributable to Floating rate convertible notes	—		—			49,642			—			—			—			—			49,642
Net unrealized gain (loss) on marketable securities of investments	—		—			—			—			—			(7		)	—			(7		)
Balance, December 31, 2005	83,524		$	835		$	1,865,597		$	(15,862	)	$	788,356		$	81		$	(43,554	)	$	2,595,453

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

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CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.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 in the form of Cimarex common stock declared and paid by H&P on September 30, 2002, Cimarex was spun-off and became a stand-alone company. Also on 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. 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). 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 accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation.

Our Consolidated Financial Statements 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. 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.

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.

2.DESCRIPTION OF BUSINESS

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.

3.BUSINESS COMBINATION

On June 7, 2005, Cimarex completed the acquisition of Magnum Hunter Resources, Inc, an 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).

The consolidated balance sheet at December 31, 2005, includes the estimated fair value of assets and liabilities of Magnum Hunter on June 7, 2005, as well as the adjustments required to record the acquisition in accordance with the purchase method of accounting. The results of operations of Magnum Hunter are included in our consolidated statements of operations for the period since the acquisition on June 7, 2005.

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The purchase price of Magnum Hunter’s assets was based on the value of Cimarex common stock issued to the Magnum Hunter stockholders and the fair value of assumed liabilities. The value of the common stock issued is based on the weighted average price of Cimarex’s common stock for the period beginning two days before and ending two days after the announcement of the merger, or $37.66 per share. The purchase price also includes merger costs incurred, which include investment banking expenses, legal and accounting fees, printing expenses and other related costs.

Purchase Price (in millions):
Shares of Cimarex common stock issued to Magnum Hunter stockholders	39.7
Average Cimarex stock price	$	37.66
Fair value of common stock issued	$	1,495.4
Plus: Merger costs incurred	7.4
Cash issued for fractional shares	0.1
Total purchase price	1,502.9
Plus: Liabilities assumed by Cimarex:
Current liabilities	179.3
Fair value of long-term debt	627.3
Other non-current liabilities	78.5
Deferred income taxes	425.8
Value of common stock associated with convertible debt	49.6
Total purchase price plus liabilities assumed	$	2,863.4
Allocation of Purchase Price:
Current assets	$	198.4
Proved oil and gas properties	1,521.4
Unproved oil and gas properties	297.7
Investments	61.2
Other property and equipment	52.8
Other non-current assets	46.5
Goodwill	685.4
	$	2,863.4

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The allocation of the 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 purchase as of December 31, 2005 has been adjusted to $672.4 million, as the valuation process continues. It is not expected that changes in the allocation will have a significant impact on results of operations.

Included in current assets on the acquisition date of June 7, 2005 were assets available for sale of approximately $8.5 million acquired in the Magnum Hunter merger. These assets were sold during the third quarter of 2005 for approximately $8.1 million.

The following unaudited pro forma information has been prepared to give effect to the Magnum Hunter acquisition as if it had occurred at the beginning of the periods presented. The unaudited pro forma data is presented for illustrative purposes only, based on estimates and assumptions deemed appropriate by management, including the preliminary purchase allocation and interest on Magnum Hunter debt assumed, and should not be relied upon as an indication of the operating results that Cimarex would have achieved if the transaction had occurred on January 1, 2004. The pro forma information also should not be used as an indication of future results or trends.

	Years Ended December 31,
(Thousands of dollars, except per share data)	2005		2004
Pro Forma Statement of Operations Data
Revenues	$	1,393,715	$	969,177
Net income	403,925		212,207
Net income per share:
Basic	$	6.24	$	2.61
Diluted	6.03		2.57

4.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value.

Inventories

Inventories, primarily materials and supplies, are valued at the lower of cost or market.

Oil and Gas Properties

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, the fair value of estimated future costs of site restoration,

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dismantlement and abandonment 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.

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a monthly and quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

Proceeds from the sale of oil and gas properties are credited against capitalized costs, unless such proceeds would significantly alter the amortization base. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

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.

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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.

Gas Imbalances

We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. As of December 31, 2005 and 2004, Cimarex had reduced reserves by 327 MMcf and 504 MMcf, respectively for gas imbalances. In situations where there are insufficient reserves available to make-up an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2005 and 2004 was $2.7 million and $1.5 million, respectively.

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.

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 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.

Transportation Costs

Cimarex accounts for transportation costs under Emerging Issues Task Force (“EITF”) 00-10 Accounting for Shipping and Handling Fees and Costs. Amounts paid for transportation are classified as an operating expense and not netted against gas sales.

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. 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

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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.

Income Taxes

Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized.

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.

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.

Stock Options

Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share Based Payment on a modified prospective basis. SFAS No. 123R requires companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation to employees.

Earnings per Share

Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares.

Fair Value of Financial Instruments

The carrying amounts of our cash, accounts receivable, accounts payable and accrued liabilities approximate fair value because of the short-term maturities of these assets and liabilities. At December

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31, 2005, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing and marketing receivables was $3.9 million, $1.2 million and $0.7 million, respectively. At December 31, 2004, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing and marketing receivables was $0.4 million, $0.2 million and $0.7 million, respectively.

Comprehensive Income

Cimarex applies the provisions of SFAS No. 130, Reporting Comprehensive Income. Cimarex reported other comprehensive income of $81 thousand in 2005 and of $88 thousand in 2004 related to the change in fair value of Marketable securities available for sale. We had no comprehensive income in 2003.

Segment Information

In prior years, Cimarex’s wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI) marketed and sold a majority of our gas production. We also sold gas produced by some of our working interest partners for a fee under short-term sales arrangements. In 2005, CESI was merged into Cimarex because we no longer deemed it necessary to manage our gas marketing activities separate from our exploration and production operations. Because our gathering, marketing and processing activities are no longer managed separately, nor is the performance of such activities evaluated separately, we now have only one reportable segment (exploration and production). As such, segment information for 2004 and 2003 has also 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.

5.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 commodity futures and swap contracts based on the difference between the fixed contract price and the underlying market price at the determination date. 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 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 a net loss during 2005 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 derivative liability at December 31, 2005 equals $41.9 million. Cimarex will continue to recognize gains and losses in future earnings as the remaining derivative instruments expire through December 31, 2006. Actual gains and losses to be recognized may differ materially from current fair value estimates. The following is a summary of the company’s open derivative contracts as of December 31, 2005:

Commodity	Type	Volume/Day	Duration	Weighted Average Price	Fair Value (000’s)
Natural Gas	Collar	20,000 MMBTU	Jan 06 – Dec 06	$5.25 - $6.30	$	32,169
Crude Oil	Collar	1,000 BBL	Jan 06 – Dec 06	$30.00 - $35.85	9,757
					$	41,926

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All of the $41.9 million of derivative liabilities is classified as current on our consolidated balance sheet at December 31, 2005. Weighted average NYMEX prices at December 31, 2005 for the 12 months of 2006 approximate $10.77 per Mcf of gas and $62.59 per barrel of oil.

6.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.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2005 and 2004 (in thousands):

	2005			2004
Asset retirement obligation at January 1	$	19,762		$	16,463
Liabilities incurred	5,735			2,427
Liabilities assumed in the Magnum Hunter merger	68,908			—
Liabilities settled	(2,810		)	(348		)
Accretion expense	3,699			1,220
Revisions of estimated liabilities	5,834			—
Asset retirement obligation at December 31	101,128			19,762
Less: Current asset retirement obligation	3,570			2,560
Long-term asset retirement obligation	$	97,558		$	17,202

7.LONG-TERM DEBT

Prior to the Magnum Hunter merger, Cimarex had no debt. In connection with the Magnum Hunter merger on June 7, 2005, Cimarex assumed the following debt (in thousands):

Bank debt	$	270,000
Capital lease obligations	3,501		(1)
9.6% Notes due 2012 (face value $195,000)	215,475		(2)
Floating rate convertible notes due 2023 (face value $125,000)	144,750		(3)
	633,726
Less: Current portion of capital lease obligations	(758		)(1)
Total long-term debt	$	632,968

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Debt at December 31, 2005 consisted of the following (in thousands):

Bank debt	$	—
9.6% Notes due 2012 (face value of $195,000)	213,770		(4)
Floating rate convertible notes due 2023, 4.49% at December 31, 2005 (face value of $125,000)	138,681		(4)
Total long-term debt	$	352,451

(1)Paid in its entirety in August 2005.

(2) Fair market value at June 7, 2005.

(3) Fair market value at June 7, 2005. Reflected in Paid-in-Capital is $49.6 million related to the fair value of common stock associated with the convertible debt.

(4) Fair market value at date of acquisition less amortization of the premium of fair market value over face value.

We have the capability to borrow on a Senior Secured Revolving Credit Facility. On June 13, 2005, Cimarex entered into a new Revolving Credit Facility that provides for $500 million of long-term committed credit, with a borrowing base of $825 million. Effective November 1, 2005 Cimarex’s borrowing base, as determined by its lenders in accordance with certain provisions under the credit agreement, was increased to $1 billion. The new facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries.

The Credit Facility agreement contains both financial and non-financial covenants, including limitations on share repurchases, dividends and other restricted payments. The financial covenants require Cimarex to maintain a minimum ratio of funded indebtedness to trailing twelve-month EBITDA (earnings before interest, taxes and DD&A adjusted for non-cash items associated with mark-to-market accounting, stock-based compensation and impairment of goodwill) of less than three times and a ratio of current assets plus unused commitments to current liabilities of greater than one. Cimarex continues to comply with these covenants and does not view them as materially restrictive.

At the Company’s option, advances under the Credit Facility bear interest based upon a Base rate or a Eurodollar rate. The Base rate means the greater of (a) the JP Morgan Chase Bank prime rate or (b) the federal funds rate plus one-half of one percent. The Eurodollar rate means the applicable British Bankers’ Association London Interbank Offered Rate (LIBOR) plus a margin ranging from 1.00-1.75 percent depending on the borrowing base usage. There were no borrowings outstanding under this facility at December 31, 2005. Unused commitments under the agreement are subject to a commitment fee ranging from 0.225-0.375 percent, also depending on the borrowing base usage.

Cimarex currently has a letter of credit posted against its borrowing base of $2.5 million that reduces funds available under the Credit Facility. The letter of credit is un-drawn and was posted to cover future plugging and abandonment costs and potential environmental remediation costs associated with a certain producing property located in New Mexico.

The 9.6% notes assumed in the Magnum Hunter merger have a face value of $195 million and are due March 15, 2012. The notes are unsecured and are redeemable, as a whole or in part, at Cimarex’s option, on and after March 15, 2007 at the following redemption prices (expressed as percentages of the principal amount), plus accrued interest, if any, thereon to the date of redemption.

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Year	Percentage
2007	104.8	%
2008	103.2	%
2009	101.6	%
2010 and thereafter	100.0	%

The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. On December 15, 2005, the interest rate was reset to 4.49%.

Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On December 31, 2005, the closing price of our common stock traded on the New York Stock Exchange was $43.01.

If any holders of the notes elect to tender their notes for conversion, they are entitled to receive a conversion value approximately equal to the ten-day average closing value of our common stock times 34.5. We would then deliver the conversion value as follows: (1) an amount of cash equal to the lesser of (a) the conversion value or (b) the principal amount of the notes and (2) an amount of common shares equal in value to the conversion value less the principal amount of the notes (net shares). At December 31, 2005, the maximum total net shares that the holders would be entitled to if they all elected to tender their notes was 1.5 million. At December 31, 2005, utilizing an average common stock price of $43.01, the conversion value equaled $185.5 million (or $1,484 per bond). There is not an observable market for the notes. Management estimates the fair value of the notes at December 31, 2005 was $190.8 million (or $1,526 per bond). As discussed in Note 3, the common stock component of the convertible debt has been included in stockholders’ equity.

In addition to the holders’ right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require Cimarex to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013 and 2018. The indenture agreement also provides Cimarex with an option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount (plus accrued interest) anytime after December 22, 2008.

All long-term debt is guaranteed by Cimarex and all of its subsidiaries, except Canvasback. Assets held by Canvasback consist primarily of 790 thousand shares of Cimarex stock, which is included in Cimarex’s Treasury stock.

On February 18, 2005, Magnum Hunter’s 40% owned affiliate, Apple Tree Holdings, LLC (“Apple Tree”), entered into a $20.6 million construction loan agreement (“Construction Loan”). The Construction Loan provides financing for the construction of a processing plant, natural gas lateral, carbon dioxide line and related infrastructure in Huerfano County, Colorado. The Construction Loan bears interest at either LIBOR plus 2.25% or a base rate plus 1.25% and will mature no later than July 31,

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2006. Total borrowings under this loan at December 31, 2005 were $19.8 million, of which our share was $7.9 million. We have provided a guarantee to the lender for this Construction Loan. In return for our guarantee, we received an up-front fee as well as the right to receive 55% of distributable cash flows from Apple Tree until certain financial tests are met. In the event that the Construction Loan goes into default and we have to perform under the guarantee, we will have recourse against the project and related subsidiaries. We have included $162 thousand in other liabilities on our condensed consolidated balance sheet to represent the fair value of our guarantee issued for the Construction Loan.

8.INCOME TAXES

Federal income tax expense for the years ended December 31, 2005, 2004 and 2003 differ from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state income taxes, and the Domestic Production Activities deduction. The components of the provision for income taxes are as follows (in thousands):

	Years Ended December 31,
	2005		2004		2003
Current taxes:
Federal	$	66,994	$	23,255	$	21,136
State	8,246		2,622		3,415
	75,240		25,877		24,551
Deferred taxes:
Federal	108,487		61,571		28,175
State	4,403		5,278		2,415
	112,890		66,849		30,590
	$	188,130	$	92,726	$	55,141

Reconciliations of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense are as follows (in thousands):

	Years Ended December 31,
	2005			2004		2003
Provision at statutory rate	$	180,759		$	86,212	$	51,859
Effect of state taxes	9,301			6,472		3,254
Domestic Production Activities deduction	(2,095		)	—		—
Other	165			42		28
Income tax expense	$	188,130		$	92,726	$	55,141

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The components of Cimarex’s net deferred tax liabilities are as follows (in thousands):

	December 31,
	2005			2004
Long-term:
Assets:
Net operating loss carryforwards	$	38,836		$	1,743
Credit carryforwards	1,207			1,207
Merger related accruals	40,124			—
Other	3,996			2,606
	84,163			5,556
Liabilities:
Property, plant and equipment	(801,953		)	(230,841		)
Net, long-term deferred tax liability	(717,790		)	(225,285		)
Current:
Assets:
Derivative instruments	15,273			—
Other	2,686			2,149
	17,959			2,149
Net deferred tax liabilities	$	(699,831	)	$	(223,136	)

The company has a net tax operating loss (NOL) carryforward of approximately $106.6 million at December 31, 2005. The NOL carryforward expires from 2021 through 2024. The NOL carryforward was acquired as part of an acquisition, and therefore, is subject to annual limitations on its use. We believe that the carryforward will be utilized before it expires. The Company has an alternative minimum tax credit carryfoward of approximately $1.2 million at December 31, 2005.

We have recorded deferred tax assets of $102.1 million of which $38.8 million is attributable to the NOL carryforward. Realization is dependent on generating sufficient taxable income in the future. Although realization is not assured, we believe it is more likely than not all of the deferred tax assets will be realized.

9.STOCK PLANS

Stock Options

Cimarex’s 2002 Stock Incentive Plan reserves 12.7million shares of common stock for issuance to directors and employees, including officers. Options granted under the plan after December 5, 2002, expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. All grants are made at the average of the high and low prices of our common stock as reported on the New York Stock Exchange on the date of grant.

Upon the exercise of the options for shares of common stock, the employee is required to hold at least 50 percent of the profit shares, as defined in the plan, until the eighth anniversary of the grant date. The incentive plan provides for accelerated vesting if there is a change in control (as defined in the plan).

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For periods prior to January 1, 2005, we applied Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations to account for all stock option grants. No compensation cost had been recognized for stock options granted, as the option prices were equal to the market price of the underlying common stock on the date of grant.

Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares. During 2005, amortization of compensation expense related to stock options was approximately $2.3 million or $1.5 million after tax ($.02 per basic and diluted share).

Had compensation cost for stock options been determined based on the fair value at the grant dates for awards to employees under the plan, consistent with the methodology of SFAS No. 123R for 2004 and 2003, such compensation expense would have been approximately $2.1 million and $2.4 million, respectively. Pro forma net income for 2004 and 2003 would have been as indicated below (in thousands except per share amounts).

	2004		2003
Net income, as reported	$	153,592	$	94,633
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	2,121		2,352
Pro forma net income	$	151,471	$	92,281
Earnings per share:
Basic – as reported	$	3.70	$	2.28
Basic – pro forma	$	3.65	$	2.22
Diluted – as reported	$	3.59	$	2.22
Diluted – pro forma	$	3.54	$	2.16

The above pro forma data reflects the effect of stock option grants dating back to 1997. These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years.

The fair value of each option award was estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. Historical data is also used to estimate the probability of option exercise, expected years until exercise and employee termination within the valuation model. The risk free interest rate is based on U.S. Treasury Securities at a constant five year fixed maturity in effect at the date of the grant.

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The following summarizes the weighted-average assumptions used in the model:

	Years Ended December 31,
	2005		2004		2003
Expected years until exercise	7.5		7.5		7.5
Expected stock volatility	25.5	%	25.4	%	26.7	%
Dividend yield	0.0	%	0.0	%	0.0	%
Risk-free interest rate	4.1	%	3.4	%	3.2	%

The merger with Magnum Hunter constituted a “change of control event” under the stock incentive plan. As a result, all participants became entitled to acceleration of vesting of their options. Cimarex obtained waivers of the accelerated vesting from certain option holders including the company’s CEO and other senior officers. Option holders who were not requested to or did not choose to execute a waiver became fully vested in their options on June 7, 2005. Compensation expense related to the accelerated vesting of options was approximately $1.1 million or $.7 million after tax.

The following summary reflects the status of stock options granted to employees and directors as of December 31, 2005, and changes during the year:

			Weighted		Weighted
			Average		Average	Aggregate
			Exercise		Remaining	Intrinsic
	Shares		Price		Term	Value
						(000)
Outstanding as of January 1, 2005	2,657,082		$	14.95
Exercised	(658,679	)	14.16
Granted	30,300		44.14
Canceled	(5,315	)	14.01
Outstanding as of December 31, 2005	2,023,388		$	15.64	5.6 Years	$	55,081
Exercisable as of December 31, 2005	1,567,128		$	14.78	5.1 Years	$	44,007

The weighted-average grant-date fair value of stock options granted to employees of Cimarex during the years ended December 31, 2005, 2004 and 2003 was $17.20, $12.24 and $7.64, respectively. The estimated theoretical fair value of each option granted was calculated using the Black-Scholes option-pricing model.

The total intrinsic value of stock options exercised during the years ended December 31, 2005, 2004 and 2003 was $17.7 million, $12.6 million and $3.2 million, respectively.

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The following summary reflects the status of non-vested stock options granted to employees and directors as of December 31, 2005 and changes during the period:

			Weighted
			Average
			Grant Date
	Shares		Fair Value
Non-vested as of January 1, 2005	883,327		$	8.07
Vested	(455,241	)	8.01
Granted	30,300		17.20
Forfeited	(2,126	)	6.21
Non-vested as of December 31, 2005	456,260		$	8.75

As of December 31, 2005 there was $4.1 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under our incentive plan. That cost is expected to be recognized pro rata over a weighted-average period of five years. Generally, options vest on the anniversary of the grant date. However, as noted above, the merger with Magnum Hunter resulted in certain option holders becoming fully vested in their options as of June 7, 2005. The fair value attributable to such vested shares was approximately $1.1 million. The total fair value of shares vested during the years ended December 31, 2005, 2004 and 2003 was $3.6 million, $3.5 million and $4.0 million, respectively.

Cash received from option exercises during the years ended December 31, 2005, 2004 and 2003 was approximately $9.3 million, $9.0 million and $3.4 million, respectively. The tax benefit realized for the tax deductions from option exercises totaled approximately $6.4 million, $4.8 million and $1.2 million, respectively.

Restricted Stock and Units

We have a long-term incentive program whereby grants of restricted stock and/or units are awarded to certain employees. The restrictions related to these awards are associated with the continued employment of the grantee for one to five years from the date of the original grant, at which time these shares will vest. In addition there is a three year required holding period subsequent to vesting. The restricted stock and stock unit agreements provide that the grantees will be entitled to receive dividends, when, as and if declared.

Cimarex awarded 65,000 restricted shares during 2003. On December 1, 2003, certain employees elected to exchange their restricted stock for restricted stock units (“Units”), in accordance with the provisions of the Stock Incentive Plan. As such, 688,600 restricted shares were cancelled and a like number of Units were issued. The Units issued have been recorded as long-term deferred compensation in an amount equal to the original value attributed to the restricted shares exchanged, with a corresponding adjustment to common stock and paid-in capital. Upon vesting, the Units are exchanged for a like number of shares of common stock and are issued to the employee.

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There were 249,905 shares of restricted stock and 697,937 restricted stock units outstanding as of December 31, 2005. As of December 31, 2004 there were 14,145 shares of restricted stock and 780,787 restricted stock units outstanding.

The following summary reflects the status of restricted stock and units granted to employees and directors as of December 31, 2005, and changes during the year:

	Stock		Units
Outstanding as of January 1, 2005	14,145		780,787
Vested	(11,248	)	(154,600	)
Granted	249,008		71,750
Canceled	(2,000	)	—
Outstanding as of December 31, 2005	249,905		697,937

Compensation expense for restricted shares or units is based upon the market price of the restricted grant multiplied by the number of shares of restricted stock or units granted. Compensation cost is being recognized over the associated vesting period. For the years ended December 31, 2005, 2004 and 2003, we recorded compensation expense of $5.2 million, $2.7 million and $1.8 million, respectively. We also capitalized to oil and gas properties associated costs of $1.7 million, $0.7 million and $0.6 million, respectively.

Merger between Cimarex and Magnum Hunter

The merger constituted a “change of control event” under the Cimarex 2002 Stock Incentive Plan. As a result, all participants in the plan, including executive officers and directors, were entitled to the accelerated vesting of options, restricted stock and restricted stock units. Cimarex obtained agreements from six executive officers to waive their rights to acceleration of vesting. As consideration for the waivers, Cimarex agreed to amend the unit and option agreements to provide for accelerated vesting upon death or disability. Cimarex elected not to seek waivers from the directors holding stock options because the unexercisable options fully vested by their terms on October 1, 2005. In consideration for the waivers obtained from all other holders of restricted stock, restricted stock units and stock options, Cimarex agreed to an additional grant of restricted stock units equal to 25% of the original grant, which will vest and become payable on the third anniversary of the closing of the merger.

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With respect to the acceleration of vesting of options, holders who were not requested to or did not execute a waiver had the right to exercise their options at and after closing until the option terminated in accordance with its terms. All restricted stock and restricted stock units held by those individuals became vested at closing.

For those holders who did not execute waivers, related unearned compensation reflected in Cimarex’s stockholders’ equity did become fully amortized at closing. For those holders who did execute waivers, the waiver agreements were accounted for as a modification of the original awards and Cimarex recorded additional deferred compensation equal to the difference between the fair value of the original award and the fair value of the modified award. The incremental deferred compensation will be amortized over the remaining term of the awards. The additional 25% grant of units was recorded at fair market value on the date of grant, as unearned compensation to be amortized over the vesting period of the award.

Stockholder Rights Plan

Cimarex has a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock of the Company. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15 percent or more of our common stock. The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases to prevent dilution. The merger between Cimarex and Magnum Hunter did not activate the provisions of the plan.

Cimarex generally will be entitled to redeem the Rights under certain circumstances at $.01 per Right at any time prior to the close of business on the tenth business day after there has been a public announcement of the acquisition of the beneficial ownership by any person or group of 15 percent or more of our common stock. The Rights may not be exercised until our Board’s right to redeem the stock has expired. Unless redeemed earlier, the Rights expire on February 23, 2012.

Declared Dividend and Stock Repurchases

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. Also 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 at an average price of $43.00. 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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10.EARNINGS PER SHARE

The calculations of basic and diluted net earnings per common share for the years ended December 31, 2005, 2004 and 2003 are presented in the table below (in thousands, except per share data):

	December 31,
	2005		2004		2003
Basic earnings per share:
Income available to common stockholders	$	328,325	$	153,592	$	94,633
Weighted average basic share outstanding	64,761		41,466		41,521
Basic earnings per share	$	5.07	$	3.70	$	2.28
Diluted earnings per share:
Income available to common stockholders	$	328,325	$	153,592	$	94,633
Weighted average basic shares outstanding	64,761		41,466		41,521
Incremental shares assuming the exercise of stock options, vesting of restricted stock units and conversion of the floating rate convertible notes	2,239		1,297		1,119
Weighted average diluted shares outstanding	67,000		42,763		42,640
Diluted earnings per share	$	4.90	$	3.59	$	2.22

There were stock options outstanding for 2,023,388, 2,657,082 and 3,321,299 shares of Cimarex common stock at December 31, 2005, 2004 and 2003, respectively.

11.EMPLOYEE BENEFIT PLANS

Cimarex maintains and sponsors contributory health care plans and a contributory 401(k) plan. Cimarex employees participate in these plans and costs related to these plans were $6.8 million, $4.7 million and $3.8 million in the years ended December 31, 2005, 2004 and 2003, respectively.

12.RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $15.4 million, $10.4 million and $4.6 million were incurred by Cimarex related to such services for the years ended December 31, 2005, 2004 and 2003, respectively. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc.

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13.MAJOR CUSTOMERS

No individual purchasers represented more than 10 percent of our revenues for the years ended December 31, 2005 and 2004. During 2003, sales to one purchaser represented approximately 10.3 percent of our revenues.

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.

14.SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands)

	For the Years Ended December 31,
	2005		2004		2003
Cash paid during the period for:
Interest (net of amounts capitalized)	$	2,367	$	972	$	830
Income taxes (net of refunds received)	$	49,824	$	20,932	$	21,382

15.COMMITMENTS AND CONTINGENCIES

Litigation

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. Cimarex has other various litigation related matters in the normal course of business, none of which are material, individually or in aggregate. We are also party to certain litigation as plaintiffs that could result in potential gains. Net settlements of $3.4 million were received during 2004 related to litigation in which we were plaintiffs. Such amounts were recorded as other income. Any future potential gains are not deemed material at this time.

Shown below are the five year debt maturities and five year lease commitments as of December 31, 2005:

	Payments Due by Period
	(In thousands)
			Less than		1-3		3-5		More than
	Total		1 Year		Years		Years		5 Years
Long term debt (face value)	$	320,000	$	—	$	—	$	—	$	320,000
Operating leases	$	31,645	$	4,079	$	8,891	$	7,932	$	10,743

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At December 31, 2005, we had a firm sales contract to deliver approximately 1.4 Bcf of natural gas over the next five months. If this gas is not delivered, our financial commitment would be approximately $9.4 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our reserves and current production levels.

Cimarex has other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $4.8 million.

Cimarex has noncancelable operating leases for office and parking space in Denver, Tulsa, Dallas and for small district and field offices. Rental expense for the operating leases totaled $3.5 million, $2.5 million and $2.1 million for the years ended December 31, 2005, 2004 and 2003, respectively.

The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2005 of approximately $106 million.

All of the noted commitments were routine and were made in the normal course of our business.

Tax Sharing Agreement

On September 30, 2002, Cimarex entered into an agreement with Helmerich & Payne, Inc. that provides for indemnification for future tax claims that may be made relating to the oil and gas assets contributed to Cimarex by Helmerich & Payne, Inc.

16.PROPERTY SALES

Various interests in oil and gas properties were sold during 2005, with net consideration equaling $149.3 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 BCF equivalent, and related production was 13.0 MMcf equivalent per day.

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17.SUPPLEMENTAL OIL AND GAS DISCLOSURES

Oil and Gas Operations – The following tables contain direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income taxes related to our oil and gas operations are computed using the effective tax rate for the period (in thousands):

	Years Ended December 31
	2005		2004		2003
Oil and gas revenues from production	$	1,072,422	$	472,389	$	324,119
Less operating costs and income taxes:
Depletion	248,017		120,499		86,390
Asset retirement obligation accretion	3,819		1,241		1,009
Production	104,067		37,476		31,801
Transportation	15,338		10,003		7,472
Taxes other than income	73,360		37,761		27,485
Income taxes	228,527		99,794		63,226
	673,128		306,774		217,383
Results of operations from oil and gas producing activities	$	399,294	$	165,615	$	106,736
Amortization rate per Mcfe	$	1.92	$	1.52	$	1.32

Costs Incurred – The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities (in thousands):

	Years Ended December 31,
	2005			2004			2003
Costs incurred during the year:
Acquisition of properties
Proved	$	1,523,356		$	324		$	2,032
Unproved	338,557			17,177			9,330
Exploration	225,297			57,485			50,350
Development	375,616			222,105			100,915
Oil and gas expenditures	2,462,826			297,091			162,627
Property sales	(149,262		)	(662		)	(694		)
Asset retirement obligation, net	9,118			2,059			12,103
	$	2,322,682		$	298,488		$	174,036

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Aggregate Capitalized Costs–The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at December 31, 2005 (in thousands):

Proved properties	$	3,602,797
Unproved properties and properties under development, not being amortized	388,839
	3,991,636
Less-accumulated depreciation, depletion and amortization	(1,114,677		)
Net oil and gas properties	$	2,876,959

Costs Not Being Amortized – The following table summarizes oil and gas property costs not being amortized at December 31, 2005, by year that the costs were incurred (in thousands):

2005	$	377,019
2004	10,008
2003	424
2002 and prior	1,388
	$	388,839

Costs not being amortized include the costs of wells in progress and certain unevaluated properties. On a monthly and quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.

Oil and Gas Reserve Information (Unaudited) – Proved oil and gas reserve quantities are based on estimates prepared by Cimarex 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 the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2005. Ryder Scott Company, L.P has reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the years ended December 31, 2004 and 2003.

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following reserve data at December 31, 2005, 2004 and 2003 represents estimates only and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of Mexico.

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	December 31, 2005				December 31, 2004				December 31, 2003
	Gas		Oil		Gas		Oil		Gas		Oil
	(MMcf)		(MBbl)		(MMcf)		(MBbl)		(MMcf)		(MBbl)
Total proved reserves - Developed and undeveloped
Beginning of year	364,641		14,063		337,344		14,137		318,627		15,025
Revisions of previous estimates	9,534		270		20,068		1,154		6,699		41
Extensions, discoveries & improved recovery	209,758		4,477		70,748		1,443		61,545		1,625
Purchases of reserves	531,862		59,288		134		2		1,320		43
Production	(100,272	)	(4,804	)	(63,611	)	(2,641	)	(50,552	)	(2,504	)
Sales of properties	(11,041	)	(8,584	)	(42	)	(32	)	(295	)	(93	)
End of year	1,004,482		64,710		364,641		14,063		337,344		14,137
Proved developed reserves	820,244		51,521		364,566		13,372		336,230		13,876

Standardized Measure of Future Net Cash Flows (Unaudited) – The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves” (Standardized Measure) is a disclosure requirement under FASB Statement No. 69, Disclosures About Oil and Gas Producing Activities. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure.

The following summary sets forth the Company’s Standardized Measure (in thousands):

	December 31,
	2005			2004			2003
Cash inflows	$	11,502,690		$	2,570,347		$	2,258,337
Production costs	(2,957,911		)	(658,658		)	(562,124		)
Development costs	(504,686		)	(9,246		)	(16,014		)
Income tax expense	(2,682,075		)	(641,485		)	(554,746		)
Net cash flow	5,358,018			1,260,958			1,125,453
10% annual discount rate	(2,329,918		)	(462,925		)	(413,872		)
Standardized measure of discounted future net cash flow	$	3,028,100		$	798,033		$	711,581

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The following are the principal sources of change in the Standardized Measure (in thousands):

	December 31,
	2005			2004			2003
Standardized measure, beginning of period	$	798,033		$	711,581		$	533,859
Sales, net of production costs	(879,657		)	(387,150		)	(257,362		)
Net change in sales prices, net of production costs	629,462			45,614			202,135
Extensions, discoveries and improved recovery, net of future production and development costs	988,001			313,417			266,128
Net change in future development costs	17,777			16,380			2,120
Revision of quantity estimates	45,895			71,374			16,038
Accretion of discount	117,223			103,034			74,121
Change in income taxes	(956,585		)	(55,438		)	(111,409		)
Purchases of reserves in place	2,379,099			221			4,174
Sales of properties	(136,102		)	(289		)	(837		)
Change in production rates and other	24,954			(20,711		)	(17,386		)
Standardized measure, end of period	$	3,028,100		$	798,033		$	711,581

Impact of Pricing (Unaudited) – The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations in prices are due to supply and demand and are beyond our control.

The following average prices were used in determining the Standardized Measure as of:

	December 31,
	2005		2004		2003
Price per Mcf	$	7.89	$	5.58	$	5.54
Price per Bbl	$	57.65	$	40.76	$	30.49

Under SEC rules, companies that follow full cost accounting methods are required to make quarterly “ceiling test” calculations. Under this test, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at ten percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the “year-by-year” method for purposes of the supplemental oil and gas disclosures and use the “short-cut” method for the ceiling test calculation. Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs.

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18.UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

	First		Second		Third		Fourth
	(In thousands, except for per share data)
2005
Revenues	$	137,944	$	188,058	$	363,094	$	429,526
Expenses, net	94,579		135,581		299,019		261,118
Net income	$	43,365	$	52,477	$	64,075	$	168,408
Earnings per common share:
Basic	$	1.04	$	1.01	$	0.78	$	2.04
Diluted	$	1.00	$	0.98	$	0.76	$	1.98

	First		Second		Third		Fourth
	(In thousands, except for per share data)
2004
Revenues	$	96,185	$	115,816	$	120,523	$	142,640
Expenses, net	66,320		79,346		81,341		94,565
Net income	$	29,865	$	36,470	$	39,182	$	48,075
Earnings per common share:
Basic	$	0.72	$	0.88	$	0.94	$	1.15
Diluted	$	0.70	$	0.85	$	0.91	$	1.12

The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period’s computation is based on the weighted average number of shares outstanding during that period.

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ITEM 9. CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Cimarex’s management, with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 2005 and concluded that the disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on 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, 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. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is also based upon certain assumptions about the likelihood of future events. Therefore, 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. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of December 31, 2005, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Other than the events discussed under “Internal Controls Over Financial Reporting and the Magnum Hunter Resources, Inc. Acquisition” below, there have been no changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended December 31, 2005, that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

INTERNAL CONTROLS OVER FINANCIAL REPORTING AND THE MAGNUM HUNTER RESOURCES, INC. ACQUISITION

The June 7, 2005, acquisition of Magnum Hunter Resources Inc., met the criteria of being a significant acquisition. As of December 31, 2005, Magnum Hunter accounted for approximately $1.8 billion of total assets and total revenues of approximately $400 million. For additional information regarding the Magnum Hunter acquisition, please read Item 1 and Footnote 3 “Business Combination” of the notes to the consolidated financial statements of this report.

On June 22, 2004, the Office of the Chief Accountant of the SEC issued guidance regarding the reporting of internal controls over financial reporting in connection with a major acquisition. On October 6, 2004, the SEC revised its guidance to include expectations of quarterly reporting updates of new internal controls and the status of the controls regarding any exempted businesses.

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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. A summary of the reasons for exclusion follow:

•Given the time required to test the operating effectiveness of such controls and the due date for the Section 404 attestation, it was not practical from a timing or resource standpoint for Cimarex to conduct a thorough assessment prior to year end 2005.

•Magnum Hunter utilized a financial accounting (i.e. a general ledger ) computer system that is different from that used by Cimarex. For practicality reasons, Magnum Hunter assets remained on these systems through December 31, 2005. We converted this financial accounting computer system to Cimarex’s in February 2006, effective January 1, 2006. As a result, we believe that reporting on the controls of the computer system used by Magnum Hunter during 2005 would not be useful to our investors since these systems were discontinued on December 31, 2005. In addition, we believe that obtaining an independent review of such computer systems and controls at Magnum Hunter would not have been feasible.

•Cimarex is in the process of implementing its internal control structure over the operations of Magnum Hunter. Due to the magnitude of the business, we expect that this effort will be completed in early 2006. The assessment and documentation of internal controls requires a complete implementation of controls operating in a stable and effective environment.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Cimarex Energy Co. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company’s internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles.

As of December 31, 2005, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria established in “Internal Control - Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, but excluding the acquired company of Magnum Hunter Inc., management determined that the Company maintained effective internal control over financial reporting as of December 31, 2005. Magnum Hunter was acquired on June 7, 2005 and as of December 31, 2005, Magnum Hunter accounted for approximately $1.8 billion of total assets and total revenues of approximately $400 million. An explanation of this exclusion is provided above.

KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of Cimarex included in this Annual Report on Form 10-K, has issued an attestation report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. The report, which expresses unqualified opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm”.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Cimarex Energy Co.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Cimarex Energy Co. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cimarex Energy Co.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Cimarex Energy Co. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Cimarex Energy Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Cimarex Energy Co. acquired Magnum Hunter Resources, Inc. during 2005, and management excluded from its assessment of the effectiveness of Cimarex Energy Co.’s internal control over financial reporting as of December 31, 2005, Magnum Hunter Resources, Inc.’s internal control over financial reporting associated with total assets of $1.8 billion and total revenues of $400 million included in the consolidated financial statements of Cimarex Energy Co. and subsidiaries as of and for the year ended December 31, 2005. Our audit of internal control over financial reporting of Cimarex Energy Co. also excluded an evaluation of the internal control over financial reporting of Magnum Hunter Resources, Inc.

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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidatedbalance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005, and our report dated March 8, 2006expressed an unqualified opinion on those consolidated financial statements.

As discussed in Note 6 to the Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

As discussed in Note 2 to the Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of Financial Accounting Standards No. 123 (R), Share Based Payment, as of January 1, 2005.

/s/ KPMG LLP

Denver, Colorado

March 8, 2006

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ITEM 9B.OTHER INFORMATION

None.

PART III

ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX

Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2006. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report.

ITEM 11.EXECUTIVE COMPENSATION

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2006.

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2006.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2006.

ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 17, 2006 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2006.

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PART IV

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)	(1)	The following financial statements are included in Item 8 to this 10-K:
		Consolidated balance sheets as of December 31, 2005 and 2004.
		Consolidated statements of operations for the years ended December 31, 2005, 2004 and 2003.
		Consolidated statements of cash flows for the years ended December 31, 2005, 2004 and 2003.
		Consolidated statements of stockholders’ equity for the year ended December 31, 2005, 2004 and 2003.
		Notes to consolidated financial statements.
	(2)	Financial statement schedules – None
	(3)	Exhibits:

Exhibits not incorporated by reference to a prior filing are designated by a † and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.

Exhibits designated by a plus sign (+) are management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15.

2.1	Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as Exhibit 2.1 to the Registrant’s Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).
2.2	Agreement and Plan of Merger, dated as of January 25, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Co. and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference).
2.3	Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy statement/prospectus which forms a part of the Registration Statement on Form S-4 dated February 25, 2005 (Registration No. 333-123019) and incorporated herein by reference).
2.4	Amendment No. 2 to Agreement and Plan of Merger, dated as of April 20, 2005, among Cimarex Energy Co., Cimarex Nevada Acquisition Sub and Magnum Hunter Resources, Inc. (attached as Annex A to the joint proxy statement/prospectus which forms a part of this registration statement and incorporated herein by reference).
3.1	Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant’s Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by reference).

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3.2	By-laws of Cimarex Energy Co. (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form S-4, dated May 9, 2002 (Registration No. 333-387948) and incorporated herein by reference).
4.1	Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and incorporated herein by reference).
4.2	Rights Agreement, dated as of February 23, 2002, between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to the Registration Statement on Form S-4 (Registration No. 333-87948) and incorporated herein by reference).
4.3	Indenture, dated March 15, 2002, among Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Bankers Trust Company, as Trustee (incorporated by reference to Magnum Hunter’s Form 10-K for the year ended December 31, 2001).
4.4	Form of 9.6% Senior Notes due 2012 (included in Exhibit 4.3).
4.5	Indenture dated December 15, 2003 between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Magnum Hunter’s Form 10-K for the year ended December 31, 2003).
4.6	Form of Floating rate Convertible Senior Notes due 2023 (included in Exhibit 4.5).
4.7	First Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas, (filed as Exhibit 4.1 to Registrant’s Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference).
4.8	Second Supplemental Indenture dated as of June 7, 2005, among Cimarex Energy Co., Magnum Hunter Resources, Inc., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to Registrant’s Form 8-K (file no. 001-31446) dated June 7, 2005 and incorporated herein by reference).
4.9	Third Supplemental Indenture dated as of June 13, 2005, among Cimarex Energy Co., the Subsidiary Guarantors party thereto and Deutsche Bank Trust Company Americas (filed as Exhibit 4.1 to Registrant’s Form 8-K (file no. 001-31446) dated June 17, 2005, and incorporated herein by reference).
4.10	Registration Rights Agreement dated as of December 17, 2003, among Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Deutsche Bank Securities Inc. and Banc of America Securities LLC, as representatives of the initial purchasers (filed as Exhibit 4.10 to Registrant’s Form S-3 Registration Statement (file no. 333-125235) dated May 25, 2005 and incorporated herein by reference).
4.11	Joinder to Registration Rights Agreement dated as of June 13, 2005, among Cimarex Texas LLC, Cimarex Texas L.P., Cimarex California Pipeline LLC, Cimarex Energy Services, Inc., Key Production Company, Inc., Key Texas LLC, Key Production Texas L.P., Brock Gas Systems & Equipment, Inc., Columbus Energy Corp., Columbus Texas, Inc., Columbus Energy L.P. and Columbus Gas Services, Inc. (filed as Exhibit 4.3 to Registrant’s Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference).

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10.1	Amended and Restated Credit Agreement dated as of June 13, 2005, among Cimarex Energy Co., the Lenders listed on the signature pages thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, U.S. Bank National Association, as Co-Syndication Agent, Bank of America, N.A., as Co-Syndication Agent, Wells Fargo Bank, N.A., as Documentation Agent and J.P. Morgan Securities Inc., as Lead Arranger and SoleBook Runner (filed as Exhibit 10.1 to Registrant’s Form 8-K (file no. 001-31446) dated June 17, 2005 and incorporated herein by reference).
10.2	First Amendment to Amended and Restated Credit Agreement effective December 15, 2005, among Cimarex Energy Co., the Lenders and JPMorgan Chas Bank, N.A., as Administrative Agent. †
10.3	Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).
10.4	Tax Sharing Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.2 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).
10.5	Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).
10.6	First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference).
10.7	Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +
10.8	Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +
10.9	Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +
10.10	Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +

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10.11	Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference). +
10.12	Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. (filed as Exhibit 10.14 to the Registrant’s From 10-K for the fiscal year ended December 31, 2002, file no. 001-31446, and incorporated herein by reference).
10.13	Amendment No. 2 to 2002 Stock Incentive Plan of Cimarex Energy Co., dated March 10, 2005. †
10.14	Amendment No. 3 to 2002 Stock Incentive Plan of Cimarex Energy Co., effective June 6, 2005. †
10.15	Form of Performance Award Agreement dated January 4, 2006 (filed as Exhibit 10.1 to Registration’s Form 8-K dated January 4, 2006 (File no. 001-31446) and incorporated herein by reference). †
10.16	Deferred Compensation Plan for Non-Employee Directors effective May 19, 2004. †
10.17	Amendment to Deferred Compensation Plan for Nonemployee Directors effective June 6, 2005. †
10.18	Amendment to Deferred Compensation Plan for Nonemployee Directors, effective January 1, 2005. †
10.19	Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective March 3, 2003). (filed as Exhibit 10.15 to the Registrant’s Form 10-K for the fiscal year ended December 31, 2002, file no. 001-31446, and incorporated herein by reference).
10.20	Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005 (filed as Exhibit 10.13 to Amendment No. 1 to Registration Statement on Form S-4 dated April 8, 2005 (Registration No. 333-123019) and incorporated herein by reference).
14.1	Code of Ethics for Chief Executive Officer and Senior Financial Officers (filed as Exhibit 14.1 to the Annual Report on Form 10-K for the year ended December 31, 2003, file no. 001-31446, and incorporated herein by reference).
21.1	Subsidiaries of the Registrant. †
23.1	Consent of KPMG LLP. †
23.2	Consent of Ryder Scott Company, LP. †
23.3	Consent of DeGolyer and MacNaughton †
24.1	Power of Attorney of directors of the Registrant. †
31.1	Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. †
31.2	Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. †

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32.1	Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †
32.2	Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: March  9, 2006

CIMAREX ENERGY CO.
By:	/s/ F.H. Merelli
	F.H. Merelli
	Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ F.H. Merelli	Director, Chairman, President and Chief		March 9, 2006
F.H. Merelli	Executive Officer (Principal Executive Officer)
/s/ Paul Korus	Vice President, Chief Financial Officer,		March 9, 2006
Paul Korus	and Treasurer (Principal Financial Officer)
/s/ James H. Shonsey	Controller, Chief Accounting Officer		March 9, 2006
James H. Shonsey	(Principal Accounting Officer)
/s/ F.H. Merelli	Director		March 9, 2006
Attorney-in-Fact
Jerry Box
/s/ F.H. Merelli	Director		March 9, 2006
Attorney-in-Fact
Glenn A. Cox
/s/ F.H. Merelli	Director		March 9, 2006
Attorney-in-Fact
Cortlandt S. Dietler
/s/ F.H. Merelli	Director		March 9, 2006
Attorney-in-Fact
Hans Helmerich
/s/ F.H. Merelli	Director		March 9, 2006
Attorney-in-Fact
David A. Hentschel
/s/ F.H. Merelli	Director		March 9, 2006
Attorney-in-Fact
Paul D. Holleman

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/s/ F.H. Merelli	Director	March 9, 2006
Attorney-in-Fact
Monroe W. Robertson
/s/ F.H. Merelli	Director	March 9 2006
Attorney-in-Fact
Michael J. Sullivan
/s/ F.H. Merelli	Director	March 9, 2006
Attorney-in-Fact
L. Paul Teague

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