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TABLE OF CONTENTS DESCRIPTION
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D C 20549

Form 10-K

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

For the fiscal year ended December 31, 2002
Commission file number 001-31446

CIMAREX ENERGY CO.
(Exact name of registrant as specified in its charter)

707 Seventeenth Street, Suite 3300, Denver, Colorado 80202
(Address of principal executive offices including ZIP code)

(303) 295-3995
(Registrant's telephone number)

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

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

Indicate by check mark 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.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934.

        YES  o    NO  ý

Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 28, 2002 was approximately $0.

Number of shares of Cimarex Energy Co. common stock outstanding as of March 7, 2003 was 41,495,615.

        Documents Incorporated by Reference:    Portions of the Registrant's Proxy Statement for its 2003 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K

TABLE OF CONTENTS

DESCRIPTION

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Glossary

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
MMcfe—Million cubic feet equivalent
Net Acres—Gross acreage multiplied by working interest percentage
Net Production—Gross production multiplied by net revenue interest
NGL—Natural gas liquids

        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:

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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 schedule of any 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 occur, or should underlying assumptions prove 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. Principal areas of operations are located in Oklahoma, Kansas, Texas and Louisiana. We also have activity in Mississippi, California and other western states. Our gas is marketed through a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI).

        At December 31, 2002, proved reserves totaled 408.8 Bcfe consisting of 318.6 Bcf of gas and 15,025 MBbls of oil. Of total proved reserves, 78 percent are gas and more than 99 percent are classified as proved developed. We operate the wells that account for 62 percent of our total proved reserves.

        The estimated present value of the future net cash flow before income taxes from year-end 2002 proved reserves, using a 10 percent discount rate, is $741.2 million. For purposes of this calculation, Cimarex used an average gas price of $4.22 per Mcf and an average oil price of $28.56 per barrel. The standardized measure of discounted future net cash flows was $533.9 million.

        Cimarex was formed in February 2002 as a wholly owned subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and gas exploration and production assets and the common stock of CESI to Cimarex. On September 30, 2002, H&P distributed in the form of a dividend to H&P stockholders approximately 26.6 million shares of Cimarex common stock. As a result, 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. The transaction was treated as a tax-free reorganization and accounted for as a purchase business combination. In the merger, we issued 14.1 million shares of Cimarex common stock on a one-for-one basis for 100 percent of the shares of Key common stock outstanding. Key continues to conduct exploration and development activities as a wholly owned subsidiary of Cimarex.

        Because the merger was accounted for as a purchase business combination, the financial and operating results presented in this report on Form 10-K, unless expressly noted otherwise, include Key only for the period subsequent to the merger on September 30, 2002.

        On September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31. As a consequence, financial statements included in this report show results of operations for the year ended December 31, 2002, the three months ended December 31, 2001 and the two fiscal years ended September 30, 2001 and 2000.

        Cimarex operates in the oil and gas industry, and is comprised of an exploration, development and production segment and natural gas marketing segment. For a discussion of financial information about the two segments of Cimarex, see Note 11 of the Consolidated Financial Statements contained herein.

        Corporate headquarters are located at 707 Seventeenth Street, Suite 3300, Denver, Colorado 80202, telephone (303) 295-3995. Principal operations offices are at 15 East 5th Street, Suite 1000, Tulsa, Oklahoma 74103, telephone (918) 585-1100. Our common stock is listed on the New York Stock Exchange and trades under the symbol "XEC."

Business Strategy

        Our strategy centers on achieving consistent profitable growth in proved reserves and production by conducting a continually expanding moderate-risk drilling program and optimizing production rates

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through recompletions and workovers. We also intend to supplement our growth with acquisitions and mergers. To accomplish these objectives, we will implement the following strategy:

•

Generate prospects and manage the drilling activities associated with our operated properties by applying current technology and leveraging off our operational capabilities;



•

Exploit our existing properties to increase production and enlarge our reserve base;



•

Allocate 90 to 95 percent of our capital budget to exploration and development projects and 5 to 10 percent to production enhancement activities;



•

Evaluate the economic and strategic attractiveness of acquisition and merger opportunities; and



•

Maintain financial flexibility and an appropriate capital structure.

Exploration and Development

        Exploration and development activities are focused in the Mid-Continent and onshore Gulf Coast regions of the United States. The most significant concentration of effort is in the Mid-Continent region, principally the Anadarko and Arkoma basins of Oklahoma, the Hugoton basin of Kansas, and the Hardeman basin of north Texas. Our Gulf Coast projects are in south Louisiana, coastal Texas and Mississippi. We also have operations in the Permian basin of west Texas, the Sacramento basin of California, and other western states including North Dakota, Montana and Wyoming.

        The focus of our exploration and development program is on moderate-risk prospects. In each of our core areas we have assembled integrated teams comprised of landmen, geoscientists and petroleum engineers who base their drilling decisions on economic models that contemplate an evaluation of program and individual well risks. Through our exploration management system, we closely monitor results and provide continuous feedback to allow each region to better plan for expected risks, reserves, drilling costs and overhead.

        Company-wide, we participated in drilling 110 gross wells during 2002, with an overall success rate of 88 percent. In the fourth quarter, following the Key merger, we drilled 36 wells, of which 35 were successful. The bulk of these new wells were in the Anadarko basin of Oklahoma and the Hardeman basin of north Texas. On a net basis, 39.12 of 44.2 total wells drilled during 2002 were successful. Overall, 2002 exploration and development expenditures, excluding leasehold costs, totaled $66.5 million and resulted in 24.9 Bcfe of proved reserve additions.

        We drilled 70 gross wells in our Mid-Continent region and completed 98 percent of them as producers. In the Gulf Coast, we drilled 24 gross wells and 54 percent were productive; in West Texas 11 of our 12 gross wells were productive; and in our Western region, we drilled four gross wells and completed 100 percent.

Acquisitions

        As noted earlier, Cimarex acquired 100 percent of the common stock of Key on September 30, 2002. The acquisition of the proved and unproved oil and gas properties was valued at approximately $297 million and resulted in the addition of 149.4 Bcfe of proved reserves, of which 98 percent were classified as proved developed. The reserves acquired in the Key transaction are located primarily in the Anadarko basin of Oklahoma, the Hardeman basin of north Texas, south Louisiana, south Texas and the Mississippi Salt basin. In 2002, Cimarex also acquired a variety of smaller interests totaling 0.9 Bcfe for approximately $1.0 million.

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Production Activities

        Full-year 2002 production volumes averaged 132 MMcfe per day versus 130 MMcfe per day in the fiscal year ended September 30, 2001. Gas production was 113.2 MMcf per day, compared to 116.1 MMcf per day during fiscal 2001. Oil production was 3,209 barrels per day in 2002 versus 2,242 barrels per day in fiscal 2001.

        Although we benefited from a substantial increase in gas prices during the latter part of 2002, the weighted-average price received for the full year of $2.91 per Mcf was 36 percent lower than the price for fiscal 2001 of $4.55 per Mcf. Oil prices also declined from $27.88 per barrel in fiscal 2001 to $24.91 per barrel in calendar 2002.

        Cimarex employs management systems over our production activities that monitor actual results against plan, evaluate the profitability of investment decisions, and measure controllable costs. The management of our production activities is centralized from our office in Tulsa, Oklahoma.

Gas Marketing

        Our marketing company, CESI, is responsible for selling substantially all of Cimarex's gas production. CESI also markets gas for joint interest partners and purchases third-party gas for resale. CESI has an investment in compression, gathering services and processing facilities, from which it earns a fee. The joint interest partner and third-party business resulted in CESI recording total gross sales of $60.2 million and gross costs of $57.5 million. These purchases and sales are physical contracts that require CESI to take title to the natural gas and deliver physical gas. The physical volumes under these contracts are matched to one another. Neither Cimarex nor CESI has any marketing arrangements that are considered derivative instruments within the scope of Statement of Financial Accounting Standard No. 133.

        CESI sells natural gas to markets in the Midwest and Mid-Continent areas under Index-based terms or spot market contracts having a duration of 30 days or less. CESI also enters into interruptible and non-interruptible agreements with pipeline companies for the transportation of its gas. As of December 31, 2002, CESI had firm transportation commitments to transport 16,000 MMBtu per day through September 30, 2003. These commitments expire in October 2009 and have annual volume elections and price determinations.

        CESI actively monitors the credit worthiness of its customers and may require parental guarantees, letters of credit or prepayments when CESI deems such additional security is necessary.

Employees

        Cimarex employed approximately 250 people in connection with our business at December 31, 2002. None of our employees are subject to collective bargaining agreements.

Competition

        The oil and gas industry is highly competitive. Competition is particularly intense in the acquisition of prospective oil and gas properties and oil and gas reserves. The principal raw materials and resources necessary for the exploration and development of natural gas and crude oil are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. Our competitive position depends on our geological, geophysical and engineering expertise, our financial resources, and our ability to select, acquire and develop proved reserves. We must compete for such raw materials and resources with both major oil companies and independent operators having larger financial, human and technological resources.

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        We also compete with major and independent oil and gas companies in the marketing and sale of oil and gas to transporters, distributors and end users. The oil and gas industry competes with other industries supplying energy and fuel to industrial, commercial and individual consumers. Many of these competitors have financial resources, staffs and facilities 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 properties are acquired or are deemed to be productive. Cimarex believes that title to its oil and gas properties is generally good and defensible in accordance with standards acceptable in the industry. Oil and gas properties in general are subject to customary royalty interests contracted for in connection with the acquisitions of title, liens incident to operating agreements, liens for current taxes and other burdens and minor encumbrances, easements and restrictions.

Governmental Regulation in the Oil and Gas Industry

        We are affected from time to time in varying degrees by political developments and federal and state laws and regulations. In particular, oil and gas production operations and economics are affected by price control, tax and other laws relating to the petroleum industry, by changes in such laws, and by constantly changing administrative regulations. Most states in which Cimarex conducts or may conduct oil and gas activities regulate the production and sale of oil and natural gas, including regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas 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 limit the amounts of oil and natural gas that Cimarex can produce from its wells and to limit the number of wells or locations at which Cimarex can drill. In addition, legislation affecting the natural oil and gas industry is under constant review. Cimarex believes that compliance with existing federal, state and local laws, rules and regulations will not have a material adverse effect upon its capital expenditures, earnings or competitive position.

Regulatory Controls

        The Federal Energy Regulatory Commission (FERC) requires interstate pipelines to provide open access transportation of natural gas. Interstate pipelines have implemented this requirement by modifying their tariffs and implementing new services and rates. These changes have provided Cimarex 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.

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        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. Cimarex believes that its gathering systems meet the test for non-jurisdictional "gathering" systems under the NGPA. Therefore, Cimarex believes that its gathering facilities are not subject to federal regulations. Although exempt from federal regulatory oversight, Cimarex's 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. Cimarex cannot predict when or whether any such proposals may become effective and what effect they will have on operations of Cimarex. Cimarex does not anticipate that compliance with existing federal, state and local laws, rules or regulations will have a material adverse effect upon the capital expenditures, earnings or competitive position of Cimarex.

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

Federal and State Income Taxation

        Cimarex and the petroleum industry in general are affected by certain federal income tax laws. Cimarex has considered the effects of such federal and state income tax laws on its operations and does not anticipate that there will be any material impact on the capital expenditures, earnings or competitive position of Cimarex.

Environmental Laws

        The activities of Cimarex are subject to existing federal and state laws and regulations governing environmental quality and pollution control. Such laws and regulations may substantially increase the costs of exploring, developing or producing oil and gas and may prevent or delay the commencement or continuation of a given operation. In the opinion of Cimarex's management, its operations substantially comply with applicable environmental legislation and regulations. Cimarex believes that compliance with existing federal, state and local laws, rules and regulations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment will not have any material effect upon the capital expenditures, earnings or competitive position of Cimarex.

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 materially adversely affect our business, financial condition or results of operations and could negatively impact the value of our common stock.

        Oil and natural gas prices fluctuate widely, and low prices could harm our business.

        Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Declines in the prices of, or demand for, oil and natural gas may adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand

9

for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including:

•

worldwide and domestic supplies of oil and natural gas;



•

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil prices and production controls;



•

political instability or armed conflict in oil-producing regions;



•

the price and level of foreign imports;



•

the price and availability of alternative fuels;



•

the availability of pipeline capacity;



•

weather conditions;



•

domestic and foreign governmental regulations and taxes; and



•

the overall economic environment.

        Exploration is a high-risk activity. The seismic data and other advanced technologies we use are expensive and cannot eliminate exploration risk.

        Our future success depends in part on the success of our drilling program. Poor results from our exploration activities could affect our future results of operations and harm our financial condition. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, we often are uncertain as to the future cost or timing of drilling, completing and producing wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•

unexpected drilling conditions;



•

title problems;



•

pressure or irregularities in formations;



•

equipment failures or accidents;



•

adverse weather conditions;



•

compliance with environmental and other governmental requirements; and



•

cost of, or shortages or delays in the availability of, drilling rigs and equipment.

        We rely to a significant extent on seismic data and other advanced technologies in conducting our exploration activities. Even when used and properly interpreted, seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or if hydrocarbons can be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies.

        The failure to replace our reserves would adversely affect our operations and financial condition.

        In general, the volume of production from oil and natural gas properties declines as reserves are depleted. If we fail to replace our reserves, our operations and financial condition could be adversely affected. Except to the extent we acquire properties containing proved reserves or conduct successful exploitation and exploration activities, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our success in finding or

10

acquiring additional reserves at attractive rates of return. In order to increase reserves and production, we must continue development drilling and recompletion programs, pursue exploration and drilling projects or undertake other replacement activities. Our current strategy includes increasing our reserve base by continuing to exploit our existing properties, by acquiring producing properties and by pursuing exploration opportunities. Our planned exploitation and exploration projects and acquisition activities may not result in significant additional reserves, and our efforts to drill productive wells at favorable finding costs may not be successful.

        Reserve estimates are inherently uncertain. Any material inaccuracies in our reserve estimates or underlying assumptions, such as the discount rate used, could cause the quantities and net present value of our reserves to be misstated.

        There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be misstated. Proved oil and gas reserve quantities are based on estimates prepared by Cimarex's engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, reviewed reserve estimates for properties that comprised 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2002. Petroleum engineering is not an exact science. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as:

•

historical production from the area compared with production from other producing areas;



•

assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices;



•

future operating costs;



•

severance and excise taxes;



•

capital expenditures; and



•

workover and remedial costs.

        Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The net present values referred to in this report should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. In accordance with requirements of the Securities and Exchange Commission, the estimated discounted net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.

        Competition in our industry is intense, and many of our competitors have greater financial, technological and other resources than we do.

        We operate in the highly competitive areas of oil and natural gas exploitation, exploration and acquisition. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. We face intense competition from independent technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:

•

seeking to acquire desirable producing properties or new leases for future exploration;

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•

marketing our oil and natural gas production;



•

integrating new technologies; and



•

seeking to acquire the equipment and expertise necessary to develop and operate our properties.

        Many of our competitors have financial, technological and other resources substantially greater than ours. These companies may be able to pay more for exploratory prospects and productive oil and natural 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. Further, many of our competitors may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for oil and natural gas prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

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

        Exploration for and exploitation, production and sale of oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax laws and environmental laws and 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. Further, these laws and regulations could change in ways that substantially increase our costs. We cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

•

discharge permits for drilling operations;



•

drilling bonds;



•

spacing of wells;



•

unitization and pooling of properties;



•

environmental protection;



•

reports concerning operations; and



•

taxation.

        Under these laws and regulations, we could be liable for:

•

personal injuries;



•

property damage;



•

oil spills;



•

discharge of hazardous materials;



•

well reclamation costs;



•

remediation and clean-up costs; and



•

other environmental damages.

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        We cannot control the activities on properties we do not operate.

        Other companies operate approximately 35 percent of our net production. As a result, we have limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of drilling and exploitation activities on properties operated by others therefore depend upon a number of factors that are 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; and



•

selection of technology.

        Our business involves many operating risks that may result in substantial losses. Insurance may be unavailable or inadequate to protect us against these risks.

        Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:

•

fires;



•

natural disasters;



•

explosions;



•

formations with abnormal pressures;



•

casing collapses;



•

embedded oilfield drilling and service tools;



•

uncontrollable flows of underground natural gas, oil and formation water;



•

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 and destruction of property, natural resources and equipment;



•

pollution and other environmental damage;



•

regulatory investigations and penalties;



•

suspension of our operations; and



•

repair and remediation costs.

        As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, losses could occur for uninsurable or uninsured risks, or in amounts in excess

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of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

        Our exploitation, acquisition and exploration operations require substantial capital, and we may be unable to obtain needed financing on satisfactory terms.

        We make and will continue to make substantial capital expenditures in exploitation, acquisition and exploration projects. We intend to finance these capital expenditures with cash flow from operations and our existing financing arrangements. Additional financing sources may be required in the future to fund our developmental and exploratory drilling. We cannot be certain that financing will continue to be available under existing or new financing arrangements, or that we will be able to obtain necessary financing on acceptable terms, if at all. If additional capital resources are not available, we may be forced to curtail our drilling, acquisition and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

        The acquisition of oil and natural gas properties imposes substantial risks.

        We constantly evaluate acquisition opportunities and frequently engage in bidding and negotiating for acquisitions, many of which are substantial. We may not be successful in identifying or acquiring any material property interests, which could prevent us from replacing our reserves and adversely affect our operations and financial condition. If successful in this process, we may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, issuance of additional debt or equity securities, the sale of production payments, borrowing of additional funds or otherwise. Our existing credit agreement includes covenants limiting our ability to incur additional indebtedness. If we were to proceed with one or more acquisitions for stock, our stockholders would suffer dilution of their interests. These additional capitalization requirements may significantly affect our risk profile. The acquisition of properties that are substantially different in operating or geologic characteristics or geographic locations from our existing properties could change the nature of our operations and business. While we intend to concentrate on acquiring producing properties with exploitation and exploration potential located in our current areas of operation, we may decide to acquire properties located in other geographic regions.

        Our operations require us to attract and retain experienced technical personnel.

        Our exploratory drilling success depends, in part, on our ability to attract and retain experienced professional personnel. Given our emphasis on exploration and development, personnel with a strong background in geology, geophysics, engineering and operations are important to our success.

        In order to preserve the tax-free treatment of the spin-off, Cimarex will be required to abide by potentially significant restrictions which could limit its ability to undertake certain corporate actions (such as the issuance of its common shares) that otherwise could be advantageous.

        Cimarex and H&P entered into a tax sharing agreement which imposes ongoing restrictions on H&P and Cimarex to ensure that applicable statutory requirements under the Internal Revenue Code and applicable Treasury regulations continue to be met so that the spin-off remains tax-free to H&P and its stockholders. As a result of these restrictions, the ability of Cimarex to engage in certain transactions, such as the redemption of a material number of shares of its common stock, the issuance of equity securities and the utilization of its stock as current in an acquisition, will be limited for a period of two years following the spin-off. These restrictions may reduce the ability of Cimarex to engage in certain business transactions that otherwise might be advantageous to Cimarex and its stockholders and could have a negative impact on its business and stockholder value. If the spin-off became taxable, H&P would be expected to recognize a substantial amount of income, which would

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result in a material amount of taxes. Depending on the circumstances, the tax sharing agreement allocates to Cimarex all, or a portion of, any tax liability resulting from the spin-off being taxable. Any such taxes allocated to Cimarex would be expected to be material to Cimarex.

        If Cimarex undergoes a change of control during the two-year period following the spin-off, or if the actions of Cimarex cause the spin-off to be taxable, Cimarex would be required to indemnify H&P for any resulting tax liabilities, which could negatively impact Cimarex's financial condition and future operations.

        H&P or Cimarex may incur a material liability in respect to U.S. federal income taxes that may become payable as a result of a change of control of Cimarex. In particular, if a change of control of Cimarex occurs as a result of a plan or series of related transactions that includes the spin-off, the distribution of the shares of Cimarex common stock may become taxable to H&P. Under section 355(e) of the Internal Revenue Code, any issuance or acquisition of the stock of Cimarex within two years following the spin-off will be presumed to be part of such a plan unless H&P or Cimarex were able to rebut the presumption that the issuance or acquisition was part of the spin-off plan. A change of control that results in tax under section 355(e) of the Internal Revenue Code generally will occur if, within the four-year period ending two years after the spin-off, a 50 percent or greater interest in Cimarex is acquired. As a result of the merger, an approximate 34.75 percent interest in Cimarex will be treated as already having been acquired.

        If H&P or Cimarex (or their respective stockholders) takes or permits an action to be taken (or omits to take an action) that causes the spin-off to become taxable, the relevant corporation generally will be required to bear the cost of the resulting tax liability to the extent that the liability results from the actions or omissions of that corporation (or its stockholders) had caused the transaction to become taxable, such as in the case of a retroactive change of law, Cimarex generally would be required to indemnify H&P for 34.75 percent of the resulting tax liability and H&P generally would be required to bear 65.25 percent of the liability. Payment of such amounts by Cimarex or both H&P and Cimarex could cause the business, financial condition and operating results of Cimarex to suffer.

        The Cimarex certificate of incorporation, by-laws and stockholders' rights plan have 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, the 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 the Cimarex stockholders.

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ITEM 2. PROPERTIES

Properties

        All of Cimarex's operations and leasehold interests are located within the continental United States. Most of the current exploration and development effort is concentrated in Oklahoma, Texas, and Louisiana. Cimarex has varying levels of ownership interests in its oil and gas properties consisting of working, royalty and overriding royalty interests.

        Our engineers estimate proved natural oil and gas reserve quantities in accordance with guidelines established by the Securities and Exchange Commission. Ryder Scott Company, L.P., independent petroleum engineers, reviewed reserve estimates for properties that comprised 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, 2002. All information in this Form 10-K relating to oil and gas reserves is net to Cimarex's interest unless stated otherwise. See Note 14, Supplemental Oil and Gas Disclosures, to the Consolidated Financial Statements for further information. See Item 1, Business, for a description of the Cimarex business.

Proved Oil and Gas Reserves as of December 31, 2002

Significant Properties of Cimarex

Mid-Continent Properties

        Our Mid-Continent reserves are comprised predominately of properties in the Anadarko and Arkoma basins of Oklahoma, the Hugoton basin of southwestern Kansas and the Hardeman basin of north Texas. The Mid-Continent regional office is headquartered in Tulsa, Oklahoma. The Mid-Continent region is Cimarex's largest source of reserves and production, and is the principal area of focus for our drilling program.

        Proved reserves in the Anadarko basin of western Oklahoma are concentrated in Roger Mills, Washita, Custer and Beckam counties. Our reserves in this area are 97 percent natural gas and represent 23 percent of total proved reserves. We have an average working interest of 31 percent in 530 gross wells. The majority of these wells are operated by other companies.

        The Hugoton field in southwestern Kansas includes reserves from the Chase and Council Grove formations. Reserves in this area are 85 percent natural gas and make up nearly 21 percent of our total proved reserve base. We have an average working interest of approximately 50 percent in 512 gross wells and we operate over 75 percent of these wells.

        Our proved reserves in the Hardeman basin of north central Texas approximate 14 Bcfe or 4 percent of total proved. Our average working interest in the 57 wells in the Hardeman basin is 83 percent and we operate the majority of these wells. The production from the wells in Hardeman County is comprised primarily of oil.

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        Other significant reserves in the Mid-Continent region come from the Ashland field in the Arkoma basin of eastern Oklahoma, the Scholem Alechem field in southern Oklahoma and our Hobart Ranch properties in the Texas panhandle. The reserves from these three areas comprise 8 percent of our total proved reserves. There are a total of 173 wells in which we have working interests varying from 30 to 94 percent.

West Texas

        Proved reserves in West Texas include varying working interests in Dixieland, Gomez and Toro fields and a 1 percent interest in the Denver Unit. Our most significant property is the Dixieland field where we operate five producing wells with an average working interest of nearly 100 percent. At year-end 2002, the area accounted for 14 percent of total proved reserves.

Gulf Coast

        Gulf Coast exploration activities in southern Louisiana and coastal Texas are coordinated out of our Tulsa office. Our New Orleans office manages our Mississippi Salt basin projects. Approximately 9 percent of our total proved reserves are located in the Gulf Coast area where we have an average 15 percent working interest in 444 gross wells.

        Properties located in the Mississippi Salt basin comprise 2 percent of proved reserves, while properties in Liberty County, Texas and the Laredo field of south Texas each account for 1 percent of total reserves.

Western

        The Western region office is headquartered in Denver. Our Western region reserves are concentrated in the Powder River and Wind River basins of Wyoming, the Williston basin in North Dakota and Montana and the Sacramento basin of California. Total proved reserves attributable to the Western region were 38.7 Bcfe at year end, or 9 percent of total proved reserves.

Acreage

        The undeveloped and developed acreage held by Cimarex as of December 31, 2002, is set forth below:

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Gross Wells Drilled

        Cimarex participated in the following number of gross wells drilled during calendar 2002, the three months ended December 31, 2001 and fiscal years ended September 30, 2001 and 2000:

        Cimarex was in the process of drilling 10 gross (4.5 net) wells at December 31, 2002.

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Net Wells Drilled

        The number of net wells Cimarex drilled during calendar year 2002, the three months ended December 31, 2001 and the two fiscal years ended September 30, 2001 and 2000 are shown below:

Reserve Information

        Cimarex's estimated proved oil and gas reserves, as of December 31, 2002 and 2001 and as of September 30, 2001 and 2000 are included in Note 14, Supplemental Oil and Gas Disclosures to Consolidated Financial Statements appearing in this Form 10-K. Supplemental Oil and Gas Disclosures also include Cimarex's net revenues from production (including royalty and working interest production) of oil and gas for the same periods.

        Future reserve values are based on year-end prices except in those instances where the sale of gas is covered by contract terms providing for determinable escalations. Operating costs, production and ad valorem taxes, and future development costs are based on current costs with no escalations.

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Productive Wells

        Cimarex has working interests in the following productive oil and gas wells as of December 31, 2002:

Production and Pricing Information

        The following table describes for each of the last three fiscal years, our oil and gas production and pricing data:

ITEM 3. LEGAL PROCEEDINGS

        H.B. King, et al v. Helmerich & Payne, Inc., filed in the District Court of Tulsa County, Oklahoma on December 22, 1998 (Case No. CS-98-06012).

        Cimarex is a defendant to certain claims relating to drainage of gas from two properties that we operate. The royalty owner plaintiffs have filed suit on behalf of themselves and a class of similarly situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have suffered approximately 12 Bcf of gross gas drainage. Although the plaintiffs have not specified in their pleadings the amount of damages alleged, the plaintiffs have orally stated that the royalty owner class has sustained actual damages of approximately $6.2 million exclusive of interest and costs. Cimarex estimates that the share of such alleged damages attributable to its working interest ownership would total approximately $1.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former operator, Cimarex is liable for all damages attributable to the drainage. We believe that our liability, if any, should not exceed our working interest share of any actual damages attributable to the alleged drainage. In the event that Cimarex is held liable for the full amount of any actual damages, Cimarex will seek contribution, indemnification and/or other appropriate relief from all other working interest owners for their portion of the alleged drainage that is attributable to the interest of those other owners. This case is in the early stages of discovery and Cimarex cannot estimate the outcome, and accordingly, no accrual has been recorded in connection with this action.

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 2002.

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ITEM 4A. EXECUTIVE OFFICERS OF CIMAREX

        The executive officers of Cimarex as of March 7, 2003 were:

        F.H. MERELLI was elected chairman of the board, chief executive officer, president and a director of Cimarex on September 30, 2002. Prior to Cimarex and since September 1992, Mr. Merelli was the chairman and chief executive officer of Key and from March 2002 until September 30, 2002, and prior to September 1999, he also held the office of president. From July 1991 to September 1992, Mr. Merelli was engaged as a private consultant in the oil and gas industry. Mr. Merelli was president and chief operating officer of Apache Corporation and president, chief operating officer and a director of Key from June 1988 to July 1991, at which time he resigned from those positions in both companies. He was president of Terra Resources, Inc. from 1979 to 1988. Mr. Merelli has been a director of Apache Corporation since July 1997.

        STEVEN R. SHAW was elected executive vice president of Cimarex on September 30, 2002. Prior to his election and since 1985, Mr. Shaw was with H&P. In 1996, Mr. Shaw was appointed vice president, exploration and production of H&P. From 1985 to 1996, Mr. Shaw served as its vice president, production.

        PAUL KORUS was elected vice president, chief financial officer and treasurer of Cimarex on September 30, 2002. Mr. Korus joined Key in September 1999, as its vice president and chief financial officer. He was an equity research analyst with Petrie Parkman & Co., an investment banking firm, from June 1995 to September 1999. Prior to that, Mr. Korus was director of investor relations for Apache Corporation.

        THOMAS E. JORDEN was elected vice president, exploration of Cimarex on September 30, 2002. Prior to Cimarex, Mr. Jorden had been with Key since November 1993. In September 1999, he was appointed vice president, exploration. He served as chief geophysicist from November 1993 until September 1999. Prior to joining Key, Mr. Jorden was with Union Pacific Resources in Fort Worth, Texas.

        STEPHEN P. BELL was elected senior vice president business development and land on September 30, 2002. Prior to Cimarex, Mr. Bell had been with Key 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. From March 1991 to February 1994, he was president of Concord Reserve, Inc., a privately held independent oil and gas company. He was employed by Pacific Enterprises Oil Company (formerly Terra Resources, Inc.) as mid-continent regional manager from February 1990 to February 1991 and as land manager from August 1985 to January 1990.

        JOSEPH R. ALBI was elected vice president-engineering of Cimarex on September 30, 2002. Prior to Cimarex, Mr. Albi had been with Key since June 1994. In September 1999, he was appointed vice president-engineering. He served as manager of engineering from June 1994 to September 1999. He was executive vice president of Black Dome Energy Corporation from 1991 to 1994. Prior to that,

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Mr. Albi held various engineering positions with Apache Corporation and Nicor Oil and Gas Corporation.

        DAVID W. HONEYFIELD was elected controller and chief accounting officer and corporate secretary of Cimarex on September 30, 2002. Prior to Cimarex, Mr. Honeyfield was hired by Key as the controller and chief accounting officer on April 2, 2002. Prior to joining Key, Mr. Honeyfield was a senior audit manager with Arthur Andersen LLP in Denver. Mr. Honeyfield had been with Arthur Andersen LLP since January 1991.

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

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

        Cimarex's common stock, par value $0.01 per share, trades on the New York Stock Exchange under the symbol XEC. No dividends were paid in 2002. Cimarex common stock was listed on the New York Stock Exchange on September 26, 2002, for sale on a when-issued basis, and commenced normal trading on September 30, 2002, upon completion of the spin-off from H&P. The high and low sales prices of the Cimarex common stock for the fourth quarter of 2002 were:

        The closing price of Cimarex's common stock as reported on the New York Stock Exchange on March 7, 2003, was $20.25. At December 31, 2002, the Company's 41,410,308 shares of outstanding common stock were held by approximately 4,900 stockholders of record.

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ITEM 6. SELECTED FINANCIAL DATA

        The following table sets forth selected financial data of the Company for the year ended December 31, 2002, each of the years in the four-year period ended September 30, 2001, and the three months ended December 31, 2001. On September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31. Also, on September 30, 2002, Cimarex acquired 100 percent of the common stock of Key in a tax-free exchange of stock accounted for as a purchase business combination. Results of Key are included in the operating results only for the time subsequent to the acquisition on September 30, 2002. This information should be read in connection with and is qualified in its entirety by the more detailed information and Consolidated Financial Statements provided in Item 8 of this Form 10-K:

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

Results of Operations

        On September 30, 2002, we changed our fiscal year-end from September 30 to December 31. As a result, we are comparing the year ended December 31, 2002 to the fiscal year ended September 30, 2001. We are also comparing the year ended September 30, 2001 to the fiscal year ended September 30, 2000. Each annual period discussed includes a full twelve months of operations. The three months ended December 31, 2001 are compared to the three months ended December 31, 2000.

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Year Ended December 31, 2002 Compared to Fiscal Year Ended September 30, 2001 and the Fiscal Year Ended September 30, 2001 Compared to the Fiscal Year Ended September 30, 2000

        On September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key in a tax-free exchange of stock. In the acquisition, we issued approximately 14.1 million shares of our common stock for all the outstanding shares of Key common stock as of that date, on a one-for-one basis. The results of operations for Cimarex include Key beginning with the fourth quarter of 2002. The acquisition of Key increased our proved reserves by 94.7 Bcf of gas and 9.1 MMBbls of oil, or an aggregate of 149.4 Bcfe. The purchase price allocated to these proved oil and gas properties was approximately $285.0 million.

        We generated net income of $39.8 million, or $1.31 per diluted share for the year ended December 31, 2002, compared with net income of $35.3 million, or $1.33 per diluted share for the year ended September 30, 2001. In fiscal 2000, net income was $57.4 million, or $2.16 per diluted share.

        Wide variations in natural gas prices between and during the years presented are the primary factors causing changes in net income from period to period. In 2002, net income grew by 13 percent compared to fiscal 2001 despite a 36 percent drop in gas prices because fiscal 2001 results were negatively affected by a $78.1 million reduction to the carrying value of oil and gas properties stemming from a sharp drop in gas prices on September 30, 2001 compared to average prices for that year. The carrying cost reduction contributed to a 39 percent decrease in 2001 net income compared with fiscal 2000 earnings, even though gas prices were 63 percent higher.

        Information about oil and gas sales, production volumes and prices are presented in the following table:

        In 2002, oil and gas sales declined $66.4 million, or 31 percent to $149.4 million from $215.8 million in fiscal 2001. Compared to the prior year, gas sales decreased $72.8 million and oil sales increased $6.4 million. Gas prices decreased 36 percent to $2.91 per Mcf while oil realizations fell 11 percent to $24.91 per Bbl. Aggregate production volumes increased 2 percent to 132.4 MMcfe per

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day, from 129.6 MMcfe per day produced during fiscal 2001 as a result of the inclusion of 6,049 MMcfe of production per day from Key in the fourth quarter. Lower gas prices were the most significant factor in the decline in gas sales, while an increase in production volumes caused the bulk of the increase in oil sales.

        Gas sales for the year ended December 31, 2002 decreased by $72.8 million, or 38 percent, to $120.2 million from $193.0 million for the year ended September 30, 2001. The average realized gas price for 2002 was $2.91 per Mcf, compared to $4.55 per Mcf during the year ended September 30, 2001. Lower gas prices accounted for $67.8 million of the decrease in sales.

        Daily gas production in 2002 declined 2 percent to 113.2 MMcf versus 116.1 MMcf in fiscal 2001. Lower gas volumes resulted from natural production declines in existing wells, partially offset by output from new wells that were completed since September 30, 2001 and gas wells acquired through the Key acquisition. Reduced production volumes resulted in a $5.0 million decrease in sales.

        Oil sales in 2002 of $29.2 million were 28 percent higher than $22.8 million in the year ended September 30, 2001. Forty-three percent higher oil production generated $9.8 million of incremental sales partially offset by a $3.4 million decrease in revenues from lower oil prices. We produced an average of 3,209 barrels per day in the year ended December 31, 2002 compared to 2,242 barrels per day in fiscal year 2001. Oil prices averaged $24.91 per barrel in 2002, versus $27.88 per barrel in 2001. The Key acquisition contributed $10.1 million in oil sales and 402 MBbls since September 30, 2002.

        Oil and gas sales for the year ended September 30, 2001 were $215.8 million, compared to $155.7 million for the same period in 2000, an increase of $60.1 million or 39 percent. Gas revenues increased to $193.0 million for the year ended September 30, 2001 from $131.1 million for the same period in 2000 as gas prices increased and volumes declined. The $61.9 million increase in gas revenues was caused primarily by higher gas prices. Gas prices averaged $4.55 per Mcf and $2.79 per Mcf for the years ended September 30, 2001 and 2000, respectively. Gas volumes averaged 116.1 MMcf per day and 128.2 MMcf per day for the comparable two periods.

        Oil revenues decreased to $22.8 million from $24.6 million for the years ended September 30, 2001 and 2000, respectively. Crude oil prices were essentially flat, averaging $27.88 and $27.95 per barrel for the years ended September 30, 2001 and 2000, respectively. The decrease in oil revenues is primarily due to lower volumes. Crude oil volumes averaged 2,242 barrels per day in fiscal 2001 and 2,405 barrels per day in fiscal 2000.

        As the prices for oil and gas change, the components of our oil and gas sales fluctuate. In 2002, our revenues came from the following product mix: 80 percent gas and 20 percent oil. This compares to 89 percent gas and 11 percent oil in fiscal 2001. On a volumetric basis, we produced 85 percent gas and 15 percent oil in 2002 and 90 percent gas and 10 percent oil in fiscal year 2001.

        Net gas marketing revenues fell to $2.7 million for the year ended December 31, 2002 compared to $6.4 million for the year ended September 30, 2001. Gross gas marketing revenues and purchases for 2002 were $60.2 million and $57.5 million, respectively. This compares to $100.2 million and $93.8 million, respectively, for the year ended September 30, 2001. The decreases are due to lower average gas prices in 2002 compared to 2001.

        Gas marketing revenues for the years ended September 30, 2001 and 2000 were $100.2 million and $78.9 million, respectively. Gas marketing purchases were $93.8 million and $74.7 million for fiscal 2001 and 2000, respectively. The change in both sales and purchases is due to significantly higher average gas prices in 2001.

        The prices we receive reflect the impact of market forces, which are influenced by many factors, including: geopolitical events, economic growth, Organization of Petroleum Exporting Countries

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policies, weather, electricity demand and others. We have not entered into any derivative contracts or hedges with respect to our production.

Costs and Expenses

        Depreciation, depletion and amortization (DD&A) expense for oil and gas producing assets remained essentially unchanged for the years ended December 31, 2002 and September 30, 2001. On a unit of production basis, DD&A was $1.02 per Mcfe in 2002, compared to $1.05 per Mcfe in 2001. Calendar 2002 was on trend to be much lower than fiscal 2001 following the $78.1 million reduction to carrying value of oil and gas properties recorded at September 30, 2001. However, the purchase of $285.0 million of oil and gas properties in the Key acquisition increased fourth quarter DD&A, thereby making the unit rate in the two fiscal periods relatively comparable. Fixed asset depreciation of $1.0 million was relatively unchanged between years.

        DD&A expense for the years ended September 30, 2001 and 2000 was $49.7 million and $41.7 million respectively, or $1.05 per Mcfe and $0.80 per Mcfe, respectively. The $8.0 million increase and higher rate was due to a decline in proved reserves and an increase in the amount of costs subject to amortization.

        The risk that we will be required to write-down the carrying value of our oil and gas properties increases when oil and gas prices are depressed, or if we have substantial downward revisions to our proved reserves. The risk also becomes greater if our finding costs increase on a per Mcfe basis relative to our total cost per Mcfe basis in the full cost pool. Based on oil and gas prices in effect on December 31, 2002, we were not required to record a full cost ceiling write-down in 2002. However, at the end of fiscal 2001, we recognized a $78.1 million reduction in the carrying value of our oil and gas properties. Because of the volatility of oil and gas prices, we may be required to record a ceiling test write-down in future periods.

        Between the years ended December 31, 2002 and September 30, 2001, production costs increased 48 percent. On a unit of production basis, annual expenses increased to $0.40 per Mcfe in 2002 from $0.28 per Mcfe in 2001. The decrease in natural gas production, combined with higher costs from oil wells associated with the Key acquisition, resulted in higher overall and per unit production expenses.

        Production costs for the year ended September 30, 2001 were $13.1 million, or $0.28 per Mcfe, compared to $10.7 million, or $0.21 per Mcfe, in the same period of 2000. The $2.4 million increase was due to increased well workovers and expenses related to producing properties added during 2001 and natural declines in production from substantially the same number of wells.

        Taxes other than income for 2002 decreased 31 percent to $13.2 million from $19.0 million for the year ended September 30, 2001. Taxes for 2002 equate to 8.8 percent of oil and gas sales, or $0.27 per Mcfe. This compares to 8.8 percent of oil and gas sales, or $0.40 per Mcfe, in fiscal year 2001. Although the percentage was unchanged from year-to-year, we did have certain items that had an impact on the total amount expended. The decline in production-related taxes was a result of receiving a severance tax refund of $0.8 million in 2002 and new wells in Louisiana receiving an exempt status for the year. 2001 was impacted by ad valorem taxes on properties being valued at January 1, 2001 when gas prices were higher than at January 1, 2002. The decrease on a per unit basis is also the result of the 31 percent decrease in oil and gas sales stemming from lower product prices.

        Taxes other than income for the years ended September 30, 2001 and 2000 were $19.0 million and $12.1 million respectively, or 8.8 percent and 7.8 percent respectively, of oil and gas sales. Increases in both production and property taxes in 2001 were the result of the higher gas prices received in 2001.

        General and administrative (G&A) expense decreased 15 percent between the years ended December 31, 2002 and September 30, 2001. On a unit basis, 2002 G&A decreased to $0.18 per Mcfe compared to $0.21 per Mcfe for 2001. The decrease is primarily due to a decrease in the allocation of

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salary and benefits from Helmerich & Payne, Inc. (H&P) in 2001 and slightly higher average daily production.

        G&A expense for the years ended September 30, 2001 and 2000 was $10.1 million and $7.6 million, respectively. The $2.5 million increase is primarily due to legal and other professional services related to the efforts to establish Cimarex as a separate public entity and increases in labor costs.

        Interest expense before capitalization was $0.6 million for the year ended December 31, 2002 and a credit of $1.5 million for the year ended September 30, 2001. Interest expense for 2001 is negative as a result of the settlement of an ad valorem tax contingency settled for less than originally escrowed, resulting in a portion of the interest component of the settlement being reversed. We capitalized $0.2 million in interest expense related to borrowings associated with undeveloped leasehold costs in 2000. At December 31, 2002, our effective interest rate was 5.5 percent, including the commitment fee, on debt of $32.0 million.

        Income tax expense totaled $21.6 million for 2002 versus $19.6 million for 2001. Tax expense was calculated using a combined federal and state effective income tax rate of 38 percent for all periods, adjusted for items that are deductible only for income tax purposes. The adjustments resulted in a 35 percent effective rate in 2002 and 36 percent in both fiscal 2001 and 2000.

Three Months Ended December 31, 2001 Compared to December 31, 2000

        We generated net income of $4.5 million, or $0.17 per diluted share, for the quarter ended December 31, 2001, compared with net income of $27.6 million, or $1.04 per diluted share, for the quarter ended December 31, 2000. The decline in net income for the quarter ended December 31, 2001 as compared to the same period in 2000 is primarily attributable to a decrease in revenues to $39.6 million for the quarter ended December 31, 2001 versus $86.4 million for the same period of 2000. Commodity prices, particularly for natural gas, were substantially higher in the quarter ended December 31, 2000.

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Results of Operations

        Information about oil and gas sales, production volumes and prices are presented in the following table:

        Revenue from oil and gas sales declined $32.7 million or 57 percent, between the fourth quarter of 2000 and 2001 to $25.0 million. Compared to a year earlier, gas sales decreased $29.7 million and oil sales decreased $3.0 million in the fourth quarter of 2001. The declines were due primarily to lower oil and gas prices during the quarter ended December 31, 2001. Combined oil and gas production volumes during the latest three month period were 124.0 MMcfe per day, a decrease from 131.4 MMcfe per day produced during the quarter ended December 31, 2000.

        Driven by lower prices in the quarter ended December 31, 2001, gas sales decreased $29.7 million, or 59 percent, to $20.9 million, as compared to $50.5 million in the same quarter of 2000. Lower gas prices caused $27.2 million of the decrease and slightly lower production volume resulted in the remaining $2.5 million decrease. The average realized gas price for the quarter ended December 31, 2001 was $2.05 per Mcf, compared to $4.72 per Mcf during the same three months of 2000. Daily gas production declined 5 percent to 110.6 MMcf per day in the quarter ended December 31, 2001 versus 116.4 MMcf per day in the comparable 2000 period. The slight fall in daily gas production is due to natural declines in wells in the Mid-Continent and Gulf Coast regions, partially offset by production from wells that were completed during 2001.

        Oil sales decreased $3.0 million, or 43 percent, to $4.1 million in the quarter ended December 31, 2001 as compared to the same period in 2000. Approximately $2.3 million of the decrease is related to lower oil prices. We produced an average of 2,236 barrels per day in the fourth quarter of 2001 compared to 2,502 barrels per day in the fourth quarter of 2000. We realized an average price of $19.97 per barrel in the quarter ended December 31, 2001, compared to $31.04 per barrel in the same quarter of 2000.

        In the quarter ended December 31, 2001, our oil and gas revenues came from the following product mix: 84 percent gas and 16 percent oil. This compares to the following mix for the same quarter of 2000: 88 percent gas and 12 percent oil. On a volumetric basis, we produced 89 percent gas and 11 percent oil in each quarter ended December 31, 2001 and 2000.

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        Net gas marketing income decreased from $4.6 million in the fourth quarter of 2000 to $1.7 million in 2001. Spot market prices were very volatile in November and December 2000 as gas prices were rapidly increasing to relatively high levels. In the three months ended December 31, 2001, gas prices were substantially lower and much more stable. The $2.9 million variance in net revenues reflects the less volatile market conditions that existed during the last three months of 2001 when spot market sales of third-party gas were accomplished at prices only slightly higher than the cost of gas purchases. Gross gas marketing revenues for the three months ended December 31, 2001 and 2000 were $14.6 million and $28.3 million, respectively. Gas marketing purchases for the three months ended December 31, 2001 and 2000 were $12.9 million and $23.7 million, respectively.

Costs and Expenses

        DD&A expense decreased 5 percent between the quarter ended December 31, 2001 and 2000. On a unit of production basis, DD&A was $0.79 per Mcfe in the quarter ended December 31, 2001 and $0.78 per Mcfe for the same period in 2000. Fixed asset depreciation of $0.3 million was relatively unchanged for these comparable periods.

        Our production expenses increased 59 percent between the quarters ended December 31, 2001 and the same period of 2000. The December 31, 2001 quarter production expense increased to $0.37 per Mcfe from $0.22 per Mcfe in 2000. The 2001 production expense increase was a result of approximately $0.3 million of production costs associated with new wells in the Gulf Coast and in Kansas. Also recorded in 2001 was additional compression costs of approximately $0.3 million in our Mid-Continent region. Lastly, we incurred approximately $0.6 million of production costs associated with outside operated properties as a result of general cost increases. The cost per Mcfe increase was attributable primarily to the factors mentioned above together with the decrease in production.

        Taxes other than income for the quarter ended December 31, 2001 decreased 39 percent to $2.6 million from $4.2 million in the prior year's comparable quarter. The tax of 2001 equates to 10.3 percent of oil and gas sales, or $0.22 per Mcfe. This compares to 7.3 percent of oil and gas sales, or $0.35 per Mcfe in 2000. The decline in production related taxes is primarily the result of lower oil and gas prices.

        G&A increased 53 percent between the quarter ended December 31, 2001 and 2000. On a per Mcfe basis, in the fourth quarter of 2001, G&A increased to $0.32 per Mcfe compared to $0.20 per Mcfe for the comparable period in 2000. The increase is primarily due to a $0.9 million impairment of receivables from Enron Corporation and costs associated with legal proceedings. Cimarex has no additional exposure relating to Enron as all sales to Enron were terminated at November 30, 2001.

        Income tax expense totaled $2.8 million for the three months ended December 31, 2001 compared to $16.5 million for the comparable period in 2000 a year earlier. The substantial decrease was a result of lower revenue resulting from lower oil and gas prices. The combined Federal and state effective income tax rate during the quarter ended December 31, 2001 was 38 percent versus 37 percent during the final three months of 2000.

Cash Flow and Liquidity

        We primarily need cash to fund our exploration, development, and acquisition activities and to pay existing obligations and trade commitments related to our oil and gas operations. Our primary source of liquidity is the cash flow generated from operating activities. The prices we receive for future oil and gas sales and the level of production will significantly impact future cash flows from operating activities. No prediction can be made as to the oil and gas prices we will receive in the future. Production volumes will be dependent upon, among other things, the amount of future capital expenditures (which are also dependent on product prices), the outcome of new wells that will be drilled, and potential

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acquisitions of producing properties. Strategically, Cimarex plans to profitably grow its production volumes through a moderate risk-drilling program, supplemented from time-to-time by acquisitions.

        Cash flows provided by operations for the year ended December 31, 2002 were $104.5 million compared to $162.4 million and $110.0 million for the years ended September 30, 2001 and 2000, respectively. The $57.9 million decrease from 2001 was primarily the result of lower natural oil and gas prices in 2002 compared to 2001 and 2000.

        Cash flows used in investing activities for the year ended December 31, 2002 were $73.8 million compared to $101.4 million and $72.7 million for 2001 and 2000, respectively. The $27.6 million decrease in 2002 was due to a reduced capital expenditure budget resulting from lower commodity prices during 2002, as well as H&P reducing the budget for exploration in the first part of the year due to the planned spin-off of Cimarex from H&P.

        Cash flows used by financing activities in 2002 were $17.6 million versus $61.4 million in 2001, a decrease of $43.8 million. Cash flows used by financing activities for the year ended September 30, 2000 were $37.1 million, $24.3 million lower than in 2001. The decrease in cash used by financing activities in 2002 compared to fiscal year 2001 resulted from a reduction in payments to H&P during the year ended December 31, 2002.

        Upon closing of the acquisition of Key, Cimarex acquired $2.1 million of cash and cash equivalents and assumed $36.0 million of debt. In October 2002, Cimarex closed on a three-year $400 million Senior Secured Revolving Credit Facility. This credit facility had an initial borrowing base of $275 million and Cimarex elected a $200 million initial commitment amount. The borrowing base is subject to redetermination each April and October. Borrowings under this facility bear interest at LIBOR rates plus 1.25 - 2.00 percent, depending on the outstanding principal amount. Unused borrowings are subject to a commitment fee of 0.375 - 0.50 percent, also depending on borrowing base usage. The credit facility is secured by mortgages on the Company's oil and gas properties and the stock of its subsidiaries. The Company is also subject to customary financial and non-financial covenants. Borrowings under the facility were $32.0 million at December 31, 2002 with an average interest rate of 5.5 percent.

        Subsequent to the acquisition on Key, we expect the incremental net cash flows generated from the Key oil and gas properties will be used to fund capital expenditures.

        At December 31, 2002, we had contractual obligations and material commitments as follows:

        In addition to the items in the table above, we have issued parental financial guarantees of $7.0 million related to our marketing business for the benefit of companies we purchase gas from.

        CESI also has some firm sales contracts to deliver fixed volumes of natural gas at index-related prices. These contracts vary in length from three months to one year. As of December 31, 2002, Cimarex had an obligation to deliver approximately 4.2 Bcf of natural gas.

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        All of the commitments were routine and were made in the normal course of our business. We believe that cash on hand, net cash generated from operations and amounts available 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.

Critical Accounting Policies

        We rely on management estimates and assumptions to prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

        Significant estimates with regard to our consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows. Each quarter end, proved oil and gas reserve quantities are based on estimates prepared by Cimarex's engineers, in accordance with guidelines established by the SEC. We engaged Ryder Scott Company, L.P., independent petroleum engineers, to review our December 31, 2002 oil and gas reserve estimates associated with the majority of the value of our oil and gas reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. Future oil and gas prices may vary significantly from the prices in effect at the time the estimates are made. The estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows can affect the charge for DD&A and the net carrying value of our oil and gas properties, as discussed below.

        We use the full cost method of accounting for our investment in oil and gas properties. As prescribed by full cost accounting rules, we capitalize all costs directly associated with property acquisition, exploration, and development activities. Our 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 oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized.

        Our rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimates of proved reserves decline, the rate at which we record DD&A increases. Such a decline in reserves may result from lower market prices, which may make it economically unfeasible to drill for and produce higher cost wells. We utilize the units-of-production method to calculate our DD&A expense.

        Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.

        In accordance with full cost accounting rules, we are subject to a limitation on the capitalized costs of our oil and gas properties. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related tax effects and deferred tax revenues (the "full cost ceiling limitation"). These rules generally require pricing future oil and gas production at the

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unescalated oil and gas prices in effect at the end of each fiscal quarter and require a write-down if the "ceiling" is exceeded. A full cost ceiling write-down is a non-cash charge to earnings. Moreover, the expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation. Based on oil and gas prices in effect on December 31, 2002, we were not required to record a full cost ceiling write-down.

        Our results of operations are also highly dependent upon the prices we receive for natural gas and crude oil production, and those prices have been volatile and unpredictable in response to changing 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.

        Accordingly, our natural gas revenue is impacted by these price fluctuations. If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into various derivative or off-balance sheet arrangements, such as non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options, and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments or arrangements to mitigate commodity price changes. If we decide to use derivative arrangements in the future, they could have a significant impact, positive or negative, on our results of operations and cash flows.

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        Cimarex recorded approximately $45.8 million of goodwill in conjunction with the purchase price allocation of the Key acquisition. Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangibles, requires us to assess the carrying value of the goodwill on an annual basis. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of the commodity prices may cause more frequent assessments.

        We use a two-component process to evaluate goodwill, a cash flow model and the equity value of the Company. The relative weight of the two measures and the cash flow assumptions is subjectively evaluated by management based on management's view of the going concern long-term fair value of the exploration and production segment. The weighting of the two measures could create different results, including a possible impairment. No impairment was indicated at December 31, 2002 based on our calculation.

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

        Prior to the spin-off of Cimarex from H&P on September 30, 2002, Cimarex's operating results historically had been included in consolidated federal and state income tax returns filed by H&P. A tax sharing agreement exists between Cimarex and H&P to allocate and settle among themselves the consolidated tax liability on a shared company basis through September 30, 2002 (see Note 6 of the Consolidated Financial Statements).

        Cimarex recognizes revenues from oil and gas sales on the sales method with revenue recognized based on actual volumes of oil and gas sold to purchasers.

Recent Accounting Pronouncements

        In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 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. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. We analyzed the effect of SFAS No. 143 and the effect of adoption on January 1, 2003 and expect to record an increase to the full cost pool of approximately $10.3 million, a decrease to accumulated depreciation, depletion and amortization of approximately $5.9 million, an increase to long-term liabilities for plugging and abandonment costs of approximately $13.7 million and an increase to the deferred taxes of approximately $1.0 million. We will also recognize income related to a cumulative effect of a change in accounting principle of approximately $1.6 million, net of income taxes of approximately $1.0 million.

        In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and amends APB Opinion No. 30, Reporting the Results of Operations—Reporting the Effects of a Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. SFAS No. 144 retains the basic framework of SFAS No. 121, resolves certain implementation issues of SFAS No. 121, extends applicability to discontinued operations, and broadens the presentation of discontinued operations to include a component of an entity. SFAS No. 144 was effective January 1, 2002. The adoption of SFAS No. 144 had no impact on the financial position or results of operations of Cimarex.

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        In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operation, plant closing, or other exit or disposal activity. We do not expect the adoption of SFAS No. 146 to have a material impact on the financial position or results of operations of Cimarex.

        In December 2002, FASB issued SFAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure, which amended SFAS No. 123. SFAS No. 148 provided alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Cimarex adopted SFAS No. 148 for disclosure purposes for the year ended December 31, 2002.

Future Trends

        During 2003, we anticipate exploration and development expenditures of approximately $150 million, including $90 million for the Mid-Continent region and $40 - 45 million in the Gulf Coast area. The amount and allocation of our future capital expenditures depends on a number of factors, including the impact of oil and gas prices on available cash flow and investment opportunities, the availability of rigs, the availability of debt and equity capital, the availability of attractive drilling opportunities, the rate in which we evaluate these opportunities and our drilling success. Although much less predictable, we are actively pursuing the acquisition of proved reserves that we believe have exploration or development potential. We plan to fund these expenditures with cash provided by operating activities, supplemented by borrowings under our bank line of credit to the extent necessary.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

Price Fluctuations

        Our results of operations are highly dependent upon the prices we receive for natural gas and crude oil 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.

        Oil and gas price realizations for 2002 ranged from a monthly low of $2.02 per Mcf and $17.13 per Bbl, and a monthly high of $3.65 per Mcf and $27.44 per Bbl, respectively. It is impossible to predict future oil and gas prices with any degree of certainty.

        If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments to mitigate commodity price changes.

        Any sustained weakness in oil and gas 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 our exploration and development activities and could cause us to record a reduction in the carrying value of our oil and gas properties.

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Interest Rate Risk

        Our reported earnings are impacted by changes in interest rates. Any fluctuation in the rate will directly affect the amount of interest expense we report. At December 31, 2002, we had $32 million of debt outstanding at an average interest rate of 5.5 percent. The due date of these borrowings is October 2005. At our election, our interest charges are based on either the prime rate or the LIBOR rate plus a margin predetermined by our debt agreement. As the interest rate is variable and is reflective of current market conditions, the carrying value of our debt approximates its fair value.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CIMAREX ENERGY CO.

INDEX TO FINANCIAL STATEMENTS

        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.

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Independent Auditors' Report

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, 2002 and 2001 and the related consolidated statements of operations, stockholders' equity, and cash flows for the year ended December 31, 2002 and the three months ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2002 and 2001, and the results of their operations and their cash flows for the year ended December 31, 2002 and the three months ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Denver, Colorado
February 18, 2003

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REPORT OF INDEPENDENT AUDITORS

The Board of Directors
Cimarex Energy Co.

        We have audited the accompanying consolidated statements of operations, stockholder's equity and cash flows of Cimarex Energy Co., (See Note 1) for the years ended September 30, 2001 and 2000. These financial statements are the responsibility of Cimarex Energy Co.'s management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the 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 financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Cimarex Energy Co. (See Note 1) for each of the two years in the period ended September 30, 2001, in conformity with accounting principles generally accepted in the United States.

ERNST & YOUNG LLP

Tulsa, Oklahoma
May 8, 2002, except as to the first paragraph of Note 1
as to which the date is September 30, 2002.

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CIMAREX ENERGY CO.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share information)

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

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CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)