UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D C 20549

Form 10-K

		(Mark One)

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

			For the fiscal year ended December 31, 2003

			OR

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

			Commission file number 001-31446

CIMAREX ENERGY CO.

(Exact name of registrant as specified in its charter)

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

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:

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

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

Indicate by check mark 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 ý NO o

Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2003 was approximately $971,834,366.

Number of shares of Cimarex Energy Co. common stock outstanding as of February 29, 2004 was 41,317,563.

Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement for its 2004 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K

TABLE OF CONTENTS

DESCRIPTION

Item

Glossary

PART I

1.	Business
2.	Properties
3.	Legal Proceedings
4.	Submission of Matters to a Vote of Security Holders
4A.	Executive Officers of Cimarex

PART II

5.	Market for the Registrant’s Common Equity and Related Stockholders Matters
6.	Selected Financial Data
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
7A.	Quantitative and Qualitative Disclosures About Market Risk
8.	Financial Statements
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9A.	Controls and Procedures

PART III

10.	Directors and Executive Officers of the Registrant
11.	Executive Compensation
12.	Security Ownership of Certain Beneficial Owners and Management
13.	Certain Relationships and Related Transaction
14.	Principal Accountant Fees and Services

PART IV

15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K

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.

PART I

Forward-Looking Statements

Throughout this Form 10-K, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, events, outcomes and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. Forward-looking statements include statements with respect to, among other things:

• amount, nature and timing of capital expenditures;

• drilling of wells;

• reserve estimates;

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

• operating costs and other expenses;

• cash flow and anticipated liquidity;

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

• marketing of oil and natural gas.

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

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

ITEM 1. BUSINESS

General

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our principal areas of operations are located in Oklahoma, Texas, Kansas, and Louisiana.

At December 31, 2003, proved reserves totaled 422.2 Bcfe consisting of 337.3 Bcf of gas and 14.1 million barrels of oil. Of total proved reserves, 80 percent are gas and more than 99 percent are classified as proved developed. We operate the wells that account for 65 percent of our total proved reserves and production.

Approximately 39 percent of our proved reserves are located in Oklahoma. Properties situated in Texas and Kansas comprised 25 percent and 20 percent of total proved reserves, respectively. We have active exploration and development programs underway in each of those states as well as in Mississippi, Louisiana, New Mexico, California, and North Dakota.

The estimated present value using a 10 percent discount rate of the future net cash flow before income taxes from year-end 2003 proved reserves is $1.03 billion. The standardized measure of discounted future net cash flow after tax is $711.6 million. In accordance with standardized measure guidelines established by the Securities and Exchange Commission (SEC), we used an average gas price of $5.54 per Mcf and an average oil price of $30.49 per barrel over the life of the properties to determine these amounts.

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 its gas marketing subsidiary 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, Cimarex acquired Key Production Company, Inc. (Key) in a stock-for-stock transaction whereby each of Key’s 14.1 million outstanding common shares were exchanged for Cimarex common stock on a one-for-one basis. Key continues to conduct exploration and development activities as a wholly owned subsidiary of Cimarex.

Because the merger with Key was a tax-free reorganization that 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 years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the fiscal year ended September 30, 2001.

Cimarex is comprised primarily of an exploration and production segment, but because we market third party gas incidental to the sale of our own production, we also report in our footnotes segment information for natural gas marketing. For a discussion of financial information about the two segments of Cimarex, see Note 13 of Notes to 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 5^th 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 Approach

Our approach to the business is fundamentally driven by seeking to achieve consistent profitable growth in proved reserves and production by conducting a continually expanding drilling program. To supplement our growth, from time to time we also consider acquisitions and mergers but do not view these activities as being our primary growth drivers. To implement these strategies, we seek to:

• Generate our own drilling inventory by maintaining a highly qualified staff of geoscientists;

• Maintain a balanced portfolio of prospects that is underpinned by a predominant mixture (70-90 percent of total capital) of low-to-moderate risk drilling prospects combined with a smaller proportion of higher risk/higher potential projects;

• Mitigate exploration risk by operating in multiple basins, which provides both geologic and geographic diversification to our drilling program;

• Maintain operational control of our drilling and production activities;

• Closely monitor the production performance of our existing properties and constantly evaluate the potential to increase production rates and enhance ultimate recoveries through workovers, recompletions and operational efficiencies;

• 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 primarily focused in western Oklahoma and the upper Gulf Coast areas of Texas and Louisiana. We also have smaller projects underway in Kansas, the Hardeman Basin of north Texas, the Permian Basin of west Texas and southeast New Mexico, the Mississippi Salt Basin, the northern San Joaquin Valley of California, the Williston Basin of North Dakota and Montana, and the Gulf of Mexico.

For each of our core exploration areas we have assembled integrated teams of landmen, geoscientists and petroleum engineers, who base their drilling decisions on detailed analysis of the potential reserves, expected costs, future net cash flow and risks associated with individual wells and programs. Through our centralized exploration management system, we measure actual results and provide continuous feedback about them to the respective exploration teams in order to help them improve and refine future investment decisions.

Company-wide, we participated in drilling 178 gross wells during 2003, with an overall success rate of 81 percent. On a net basis, 73 of 97 total wells drilled during 2003 were successful.

Our 2003 exploration and development expenditures, excluding leasehold costs, totaled $151.3 million and resulted in 78.2 Bcfe of proved reserve additions. Including lease acquisition costs, we invested nearly $161 million. Of total expenditures, 60 percent ($97 million) was invested in projects located in the mid-continent area of the U.S., including Kansas, Oklahoma and north Texas. Approximately 30 percent, or $48 million, was directed toward prospects located along the Texas and Louisiana Gulf Coast and adjacent shallow waters in the Gulf of Mexico.

One of our most notable discoveries during 2003 was the Mauboules #1 well on the West Gueydan prospect in Vermilion Parish, Louisiana. As of year-end 2003, the well was awaiting completion operations. First sales occurred on February 20, 2004 and by month end had risen to daily production of 18.0 MMcf of gas and 280 barrels of oil.

The new well was drilled to a total depth of 18,300 feet and found two gas-bearing intervals in the Miogyp formation. During testing operations, it produced nearly 19 MMcfe per day from the upper interval. A second well, the Mauboules #2, is situated approximately 2,000 feet north of the #1 well and is being drilled to develop the lower zone. We operate both wells with a 64.5 percent working interest and have a 46.4 percent revenue interest. We also plan to drill during 2004 one to three additional exploratory wells on separate geologic features in the immediately surrounding area.

Elsewhere in the upper Gulf Coast area, we drilled six wells in Liberty County, Texas, three of which were productive in the the Yegua and Cook Mountain formations. The two best wells were the Henderson #1 (82 percent working interest) and the Brookhollow #1 (50 percent working interest), that tested at gross rates of 7.8 MMcfe per day and 6.8 MMcfe per day, respectively. We plan to drill another seven to nine wells in this area during 2004.

We continue to have a high level of drilling activity in western Oklahoma, primarily targeting the Red Fork and Granite Wash formations in the Anadarko Basin. During 2003, we completed 78 of 81 gross wells in this area, and we anticipate drilling over 100 wells there during 2004.

In the Mountain Front play of southwestern Oklahoma, each of the six wells drilled were completed as producers. The larger discoveries in this area produced gas at high initial rates when they were brought on line during November 2003, helping boost our aggregate fourth-quarter 2003 volumes to 187 MMcfe per day. Of particular importance were the Gwendolyn #3-29, with net production of 9.4 MMcf per day; the Buddy #3-32, producing a net 6.7 MMcf per day; and the Lisa #4-30, with net production of 4.8 MMcf per day. We plan to drill 13 more wells in this area during 2004.

In the Arkoma basin of eastern Oklahoma, we drilled and completed twelve wells during 2003, and have a similar level of activity planned for 2004. In the Hardeman Basin, we completed nine of 21 wells. We own approximately 400 square miles of 3-D seismic survey data in the Hardeman and plan to drill an additional six to eight wells on our acreage during 2004.

We completed four of seven wells drilled in the Permian Basin during 2003. Primarily targeting Pennsylvanian-age, gas-bearing formations, we have identified as many as 25 potential drilling locations for 2004.

Acquisitions

As noted earlier, on September 30, 2002 in connection with the spin off of Cimarex from H&P, Cimarex acquired 100 percent of the common stock of Key. Key’s oil and gas properties were valued at $297 million and resulted in the addition of 149.4 Bcfe of proved reserves (98 percent proved developed) principally in Oklahoma, Texas, Mississippi and Louisiana.

In 2003, we added to our ownership interest primarily in certain Texas and Louisiana properties by acquiring incremental interests for $2 million. The property interests acquired had associated proved reserves of 1.6 Bcfe.

Production

Production volumes during 2003 averaged 180 MMcfe per day versus 132 MMcfe per day in 2002. Gas production was 138.5 MMcf per day, compared to 113.2 MMcf per day during 2002. Oil production was 6,859 barrels per day in 2003 versus 3,209 barrels per day in 2002. The increase in

volumes primarily stems from the acquisition of Key and favorable drilling results. Because of natural production declines from the wells we own, our production would typically decrease by 20-25 percent year-to-year if we did not conduct successful drilling operations or acquire existing producing properties.

The weighted-average gas price we received during 2003 was $4.96 per Mcf , which was 60 percent higher than the $3.10 per Mcf average price we received during 2002. Our annual average realized oil price during 2003 increased by 17 percent to $29.30 per barrel from $24.97 per barrel in 2002. The increase in the prices we received during 2003 was the result of tighter market conditions for oil and gas.

Our largest producing area was western Oklahoma, providing nearly 64 MMcfe per day, or 36 percent of our total production during 2003. We operated 67 percent of this production, of which 93 percent was gas.

Production from Kansas, primarily from the Hugoton Field, totaled 28 MMcfe per day or 16 percent of our total production, with 84 percent being gas. We operated 93 percent of the related volumes.

The areas along the Gulf Coast of Texas, Louisiana and Mississippi yielded approximately 30 MMcfe per day of output, which was 17 percent of our total production. Of these volumes, 70 percent was gas and 42 percent was operated.

The Permian basin provided another 22 MMcfe per day or 12 percent of total production, with 80 percent of the related volumes being gas and 68 percent from properties that we operate.

We have implemented management systems over our production operations that monitor actual results against plan and measure controllable costs. We have field offices located near our major concentrations of operated properties in Kansas, Oklahoma and Texas and have a centralized production management team in our Tulsa office. Overall, approximately 65 percent of both our production and oil and gas reserves are from properties that we operate.

Marketing

Our oil and gas production is sold under various short-term arrangements at market-responsive prices. We sell our oil at various prices directly or indirectly tied to field postings, posted platts, as well as daily front-month contract prices on the New York Mercantile Exchange (NYMEX). Our gas is generally sold under pricing mechanisms related to either monthly index prices on pipelines where we deliver our gas or the spot market.

We sell our oil and gas to a broad portfolio of customers. Our largest customer, OGE Energy Resources, Inc., accounted for 10.3 percent of 2003 revenues. Because approximately two-thirds of our gas production is from wells in Kansas and Oklahoma, most of our customers are from those states or other Midwest market centers. We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.

We have a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI), through which we conduct a majority of our gas marketing activity. Like Cimarex, CESI enters into sales transactions with various purchasers under a variety of short-term arrangements and supplies these sales with equity gas (gas produced by Cimarex) or gas purchased from third parties. Certain gathering systems and related equipment are held and operated by Cimarex and its subsidiaries. CESI operates most of the gas gathering systems and processing plants incidental to our production. Non-equity gas handled by CESI is predominantly comprised of gas owned by our royalty interest owners and working interest partners who have elected to have us sell their gas for them. Gas purchased from other third parties, such as marketing companies and owners of production from wells that we do not have an interest in, is generally limited to

activity associated with supplying gas sales arrangements under which our equity gas is also being sold. Approximately 56 percent of the gas sold through CESI was Cimarex equity gas.

CESI has no employees and is not considered an autonomous operating unit. Neither Cimarex nor CESI has any long-term sales contracts nor any marketing arrangements that would be considered derivative instruments within the scope of Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities.

Employees

We employed 315 people on December 31, 2003. None of our employees are subject to collective bargaining agreements.

Web Site Access

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

Competition

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

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

Title to Oil and Gas Properties

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

Government Regulation

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

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

Environmental Regulation. Various Federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect our operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations and could cause us to incur remediation or other corrective action costs in connection with a release of regulated substances, including crude oil, into the environment. In addition, we have acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under our control. Under environmental laws and regulations, we could be required to remove or remediate wastes disposed of or released by prior owners or operators. It is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts that are material in relation to our exploration and development expenditure program in order to comply with environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. We also could incur costs related to the clean up of sites to which we sent regulated substances for disposal and for damages to natural resources or other claims related to releases of regulated substances at such sites.

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

Under the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional “gathering” systems under the NGPA and that our facilities are not subject to Federal regulations. Although exempt from Federal regulatory oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state agencies.

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

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

Federal and State Income Taxation

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

Certain Risks

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

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

Our revenues and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Historically, oil and gas prices have fluctuated widely. For example, in 2003 we sold our gas at an average price of $4.96 per Mcf, which was 60 percent higher than our 2002 average sales price of $3.10 per Mcf. Similarly, our average 2003 oil price of $29.30 per barrel was 17 percent higher than the price we received in 2002 of $24.97 per barrel. As a result, our combined 2003 oil and gas sales increased by 106 percent to $324 million from $157 million in 2002, versus a 36 percent increase in our aggregate production volumes.

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

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

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

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

Exploration and development involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. Exploration and development can also be

unprofitable, not only from dry wells, but from productive wells that do not produce sufficient reserves to return a profit.

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

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

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

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

• future oil and gas prices;

• assumed effects of governmental regulation;

• future operating costs;

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

• capital expenditures;

• workover and remedial costs; and

• Federal and state income taxes.

Estimates of proved reserves and future net cash flow prepared by different engineers or by the same engineers at different times may vary substantially. Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, reviewed our 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, 2003.

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

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines.

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

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

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

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

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

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

Other companies operate approximately 35 percent of our net production. Our success in properties operated by others depends upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.

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

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

In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease.

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

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

We regularly evaluate opportunities and frequently engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves

and adversely affect our financial results and rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If we do complete an acquisition, we must anticipate difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses.

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

Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to grow our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations.

The tax agreement with Helmerich & Payne, Inc. imposes significant restrictions until October 1, 2004 on our ability to issue or redeem our common stock or to undergo a change of control.

On September 30, 2002, Cimarex entered into an agreement with H&P that imposes certain restrictions on Cimarex until October 1, 2004 to redeem or issue a material number of shares of its common stock or for Cimarex to undergo a change of control. Such actions by Cimarex could cause the spin off of Cimarex by H&P to be deemed a taxable event, potentially resulting in a substantial amount of taxable income to H&P. Under the terms of the agreement, if Cimarex takes or permits an action to be taken that causes the spin off to be taxable, Cimarex would generally be liable for all or a portion of the resultant tax liability. It is expected that any such taxes allocated to Cimarex would be material.

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

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

ITEM 2. PROPERTIES

Properties

All of our proved reserves and undeveloped acreage is located in the United States, primarily in Oklahoma, Texas, Kansas, Louisiana and Wyoming. We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 65 percent of our proved reserves.

Our engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. Ryder Scott Company, L.P., independent petroleum engineers, reviewed our reserve estimates for those properties that comprised 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, 2003. All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 16, Supplemental Oil and Gas Disclosures, to Notes to Consolidated Financial Statements for further information. See Item 1, Business, for a description of our business.

Proved Oil and Gas Reserves as of December 31, 2003

	Gas (MMcf)	Oil, Condensate and NGL (MBbls)	Equivalent (MMcfe)

Oklahoma	156,895	1,390	165,235
Texas	71,707	5,590	105,245
Kansas	69,354	2,749	85,847
Louisiana	12,380	457	15,122
Wyoming	11,222	2,286	24,935
Other	15,786	1,665	25,783
Total	337,344	14,137	422,167

Proved Developed	336,230	13,876	419,488

Significant Properties

Although no single property accounts for more than three percent of our total production, collectively our properties in western Oklahoma produced at an average daily rate of 64 MMcfe during 2003, which was 36 percent of our company-wide 2003 production. These properties consist of varying working interests in approximately 940 wells, mostly located in Roger Mills, Washita, Custer and Beckham counties. We operate wells that account for 67 percent of our Anadarko Basin output.

Elsewhere in the state, we have concentrations of properties in the Arkoma Basin of eastern Oklahoma. During 2003, net production from the Arkoma Basin, principally the Ashland field, averaged six MMcf of gas per day (45 percent operated).

Altogether, at year-end 2003, our Oklahoma properties accounted for 165.2 Bcfe of proved reserves, or 39 percent of our total proved reserves. Production from these properties during 2003 averaged nearly 70 MMcfe per day and equated to 40 percent of our aggregate output. Including all wells, our average working interest in Oklahoma is 24 percent.

During 2003, oil production from the Hardeman Basin of north-central Texas averaged 2,050 barrels per day, which equated to 30 percent of our total company-wide oil sales. We have an average working interest of 82 percent in 52 wells and operate 94 percent of our 2003 net production in the Basin.

In Liberty County, Texas, we have over 600 square miles of 3-D seismic survey data and are actively exploring for production from the Yegua and Cook Mountain formations. To date, we have six producing wells in the area with working interests ranging from 35 to 85 percent.

Proved reserves in west Texas include varying working interests in the Dixieland, Gomez and Toro fields, and a one percent interest in the Denver Unit. The Dixieland #10-2 well in Reeves County produced gas at an average rate of 5 MMcf per day during 2003 and was the most prolific producing well we owned during the year. The Dixieland #10-1 well produced 1 MMcf per day.

Overall, our proved oil and gas reserves in Texas amounted to 105.2 Bcfe, represent 25 percent of total proved reserves and are 68 percent natural gas. Production volumes during 2003 from our Texas properties averaged 37 MMcfe per day, or 21 percent of total production.

In southwest Kansas, our principal properties produce from the Chase and Council Grove formations of the Hugoton field. During 2003, net production from this area averaged 28 MMcfe per day, or 16 percent of total company output. We have a 55 percent average working interest in over 500 Hugoton wells, and we operate 93 percent of the related 2003 production. Our year-end 2003 proved reserves in Kansas of 85.8 Bcfe were 81 percent gas and 20 percent of our total proved reserves.

In the coastal areas of Louisiana and Mississippi, our proved reserves are largely derived from properties located in the West Gueydan field of Vermilion Parish, Louisiana and the Mississippi Salt Basin. In total, our south Louisiana properties have proved reserves equal to 3.6 percent of our company-wide total proved reserves and our Mississippi assets comprise two percent.

In the western U.S., our principal properties include small (generally less than three percent) royalty and working interests in over 1,100 non-operated wells in the Powder River, Wind River and Big Horn basins of Wyoming. In aggregate, these interests accounted for 6 percent of our total proved reserves.

In the Williston Basin of North Dakota and Montana, we own an average working interest of 17 percent in 94 producing wells. During 2003, oil production from this area averaged 209 barrels per day and our total proved reserves amounted to 4.8 Bcfe, of which 92 percent was oil.

Although currently exploring in California’s San Joaquin Valley, the bulk of our proved reserves and production in this state stem from 36 producing wells situated in the Sacramento Basin. We operate almost all of these wells with an average 70 percent working interest. In total, proved reserves attributable to these interests amount to 7.1 Bcf of gas, which equate to 1.7 percent of our total proved reserves.

Acreage

The undeveloped and developed acreage held by us as of December 31, 2003 is set forth below:

	Undeveloped Acreage		Developed Acreage
	Gross Acres	Net Acres	Gross Acres	Net Acres

Alabama	1,600	1,400	—	—
Arkansas	—	—	4,766	1,638
California	17,962	13,334	8,138	6,481
Colorado	2,944	32	2,333	762
Kansas	17,343	17,079	122,489	89,720
Louisiana	5,108	2,471	26,446	5,073
Michigan	2,135	2,020	—	—
Mississippi	10,606	3,897	10,547	2,747
Montana	15,412	2,329	9,751	5,511
Nebraska	12,821	969	480	168
New Mexico	522	53	2,480	192
North Dakota	20,702	662	7,329	1,262
Oklahoma	28,073	22,716	194,340	86,884
Texas	103,763	56,966	168,946	64,227
Utah	1,094	1,094	280	2
Wyoming	39,805	7,724	17,034	1,472
	279,890	132,746	575,359	266,139

Gross Wells Drilled

We participated in drilling the following number of gross wells during calendar years 2003 and 2002, the three months ended December 31, 2001 and fiscal year ended September 30, 2001:

	Exploratory			Developmental
	Productive	Dry	Total	Productive	Dry	Total

Year ended December 31, 2003	19	27	46	125	7	132
Year ended December 31, 2002	13	12	25	84	1	85
Three months ended December 31, 2001	3	5	8	6	—	6
Year ended September 30, 2001	24	21	45	70	8	78

We were in the process of drilling 15 gross (6.5 net) wells at December 31, 2003.

Net Wells Drilled

The number of net wells we drilled during calendar years 2003 and 2002, the three months ended December 31, 2001 and the fiscal year ended September 30, 2001 are shown below:

	Exploratory			Developmental
	Productive	Dry	Total	Productive	Dry	Total

Year ended December 31, 2003	17.42	20.12	37.54	55.45	4.21	59.66
Year ended December 31, 2002	7.05	4.15	11.20	32.07	0.93	33.00
Three months ended December 31, 2001	0.92	1.63	2.55	3.66	—	3.66
Year ended September 30, 2001	9.04	9.96	19.00	43.46	7.00	50.46

Reserve Information

Our estimated proved oil and gas reserves, as of December 31, 2003, 2002, 2001 and September 30, 2001 are included in Note 16, Supplemental Oil and Gas Disclosures to Notes to Consolidated Financial Statements appearing in this Form 10-K. The Supplemental Oil and Gas Disclosures also include for the same periods estimates of our future revenue and associated costs resulting from projected production of our proved reserves.

	Total Proved Reserves			Proved Developed Reserves
	Gas (MMcf)	Oil (MBbls)	Total (MMcfe)	Gas (MMcf)	Oil (MBbls)	Total (MMcfe)
As of:
December 31, 2003	337,344	14,137	422,167	336,230	13,876	419,488
December 31, 2002	318,627	15,025	408,779	318,452	14,765	407,044
December 31, 2001	212,326	5,304	244,150	211,874	4,607	239,513
September 30, 2001	216,337	5,932	251,927	213,931	5,213	245,207

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 (in thousands, except price data).

	Discounted Future Net Cash Flow Before Income Tax (Discounted at 10 Percent)		Standardized Measure of Discounted Future Net Cash Flow (Discounted at 10 Percent)

					Average Price Used in Year-end Calculation of Future Net Cash Flow
					Gas		Oil
As of:
December 31, 2003	$	1,030,340	$	711,581	$	5.54	$	30.49
December 31, 2002	741,209		533,859		4.22		28.56
December 31, 2001	241,150		182,565		2.23		18.10
September 30, 2001	191,240		144,039		1.90		20.25

Productive Wells

We have working interests in the following productive oil and gas wells as of December 31, 2003:

	Gas		Oil
	Gross	Net	Gross	Net
Kansas	441	271.0	234	101.7
Louisiana	75	19.2	40	3.2
Oklahoma	1,165	308.5	391	57.2
Texas	389	126.0	3,586	127.2
Wyoming	88	7.7	1,135	60.5
Other	146	42.0	164	26.7
	2,304	774.4	5,550	376.5

Production and Pricing Information

The following table describes for the periods indicated our production, pricing and production cost data:

	Gas (MMcf)	Oil (MBbls)					Average Production Cost Per Mcfe

			Average Sales Price
			Per Mcf		Per Bbl

Year ended December 31, 2003	50,522	2,504	$	4.96	$	29.30	$	0.49
Year ended December 31, 2002	41,300	1,171	$	3.10	$	24.97	$	0.40
Three months ended December 31, 2001	10,174	206	$	2.24	$	19.97	$	0.37
Year ended September 30, 2001	42,387	818	$	4.70	$	27.88	$	0.28

ITEM 3. LEGAL PROCEEDINGS

H.B. Krug, 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 it operates. 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 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was in an amount that significant. The plaintiffs have stated that the royalty owner class has sustained actual damages of $20 million exclusive of interest and costs. We estimate that the share of such alleged damages attributable to our working interest ownership would total approximately $3.0 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. We have received confirmation from the court that any claim against Cimarex will be limited to our proportionate interest in the two properties. We cannot predict the outcome of this litigation, 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 2003.

ITEM 4A. EXECUTIVE OFFICERS

The executive officers of Cimarex as of March 7, 2004 were:

Name	Age	Office

F.H. Merelli	67	Chairman of the Board, Chief Executive Officer and President
Thomas E. Jorden	46	Executive Vice President-Exploration
Steven R. Shaw	53	Executive Vice President-Operations
Paul Korus	47	Vice President, Chief Financial Officer, Treasurer and Secretary
Stephen P. Bell	49	Senior Vice President, Business Development and Land
Joseph R. Albi	45	Senior Vice President-Corporate Engineering
Richard S. Dinkins	59	Vice President of Human Resources
James H. Shonsey	52	Chief Accounting Officer and Controller

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

F.H. MERELLI was elected chairman of the board, chief executive officer, president and a director of Cimarex on September 30, 2002. Prior to its merger with Cimarex, Mr. Merelli had been the chairman and chief executive officer of Key since 1992.

THOMAS E. JORDEN was named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since September 30, 2002. Prior to its merger with Cimarex, Mr. Jorden was with Key. He served as chief geophysicist from November 1993 until September 1999, before being appointed vice president of exploration. Prior to joining Key, Mr. Jorden was with Union Pacific Resources in Fort Worth, Texas.

STEVEN R. SHAW was elected executive vice president of operations on September 30, 2002. From 1985 through September 30, 2002, Mr. Shaw was with H&P, serving as vice president of exploration and production since 1996 and as its vice president of production from 1985 to 1996.

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

STEPHEN P. BELL was elected senior vice president of business development and land on September 30, 2002. Prior to its merger with Cimarex, Mr. Bell had been with Key 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.

JOSEPH R. ALBI was named senior vice president of corporate engineering on December 8, 2003. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. From 1994 until September 30, 2002, Mr. Albi was with Key where he served as vice president of engineering.

RICHARD S. DINKINS was named vice president of human resources on December 8, 2003. Mr. Dinkins joined Key Production in March 2002 as its director of human resources. Prior to joining Key and since February 1999, Mr. Dinkins was with Sprint in Overland Park, Kansas.

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

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

Cimarex’s $0.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. Cimarex does not pay dividends and does not anticipate declaring dividends in the foreseeable future. We intend to retain earnings for the operation and expansion of our business, including exploration and development activities.

Cimarex common stock was listed on the New York Stock Exchange on September 26, 2002, on a “when-issued” basis, and commenced normal trading on October 1, 2002. The high and low sales prices of Cimarex common stock for the fourth quarter of 2002 and for each quarter during 2003 were:

	2003				2002
	High		Low		High		Low

First Quarter	$	20.42	$	17.07
Second Quarter	$	24.40	$	18.80
Third Quarter	$	23.70	$	19.24
Fourth Quarter	$	28.14	$	19.50	$	18.00	$	13.49

The closing price of Cimarex stock as reported on the New York Stock Exchange on March 4, 2004, was $28.90. At December 31, 2003, Cimarex’s 41,063,653 shares of outstanding common stock were held by approximately 2,208 stockholders of record.

ITEM 6. SELECTED FINANCIAL DATA

The following table shows selected financial data for the years ended December 31, 2003 and 2002, together with similar information for each of the three preceding fiscal years ended September 30, and the three months ended December 31, 2001.

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 business purchase combination. Also on September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31. Results of Key are included in the operating results only for the period 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:

	As of and For the Years Ended										Three Months Ended December 31, 2001
	December 31,				September 30,
	2003		2002		2001		2000		1999
	(In thousands, except per share and proved reserve amounts)

Operating results:
Revenues	$	454,212	$	209,644	$	316,778	$	237,021	$	146,902	$	39,596
Net income	94,633		39,819		35,253		57,386		23,559		4,479
Net income per share:
Basic	2.28		1.32		1.33		2.16		0.89		0.17
Diluted	2.22		1.31		1.33		2.16		0.89		0.17
Cash dividends declared per share	—		—		—		—		—		—
Balance sheet data:
Total assets	805,508		674,286		246,212		286,090		234,929		251,966
Total debt	—		32,000		—		—		—		—
Stockholders’ equity	534,740		444,880		166,795		192,972		172,664		175,082
Other financial data:
Oil and gas sales	324,119		157,299		222,136		158,502		93,808		26,857
Oil and gas capital expenditures	162,627		368,503		104,975		73,821		55,933		14,425
Proved Reserves:
Gas (MMcf)	337,344		318,627		216,337		262,498		239,620		212,326
Oil (MBbls)	14,137		15,025		5,932		6,305		4,834		5,304
Total equivalent (MMcfe)	422,167		408,779		251,927		300,329		268,623		244,150

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

INTRODUCTION

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our primary focus is to explore for and discover new reserves. To supplement our growth, from time to time we also consider acquisitions and mergers. Our operations are presently focused in Oklahoma, Texas, Kansas and Louisiana.

Industry and Economic Factors

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

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

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

Extensive Federal, state and local regulation of the industry significantly affects our operations. In particular, our activities are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.

Approach to the Business

Profitable growth of our assets will largely depend upon our ability to successfully find and develop new proved reserves. To accommodate an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate and higher risk exploration and development projects. We believe that this approach allows for consistent increases in our oil and gas reserves, while minimizing the chance of failure. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We may consider the use of transaction specific hedging of oil and gas prices, if warranted, to reduce price risk. However, to date the use of hedging has not been implemented.

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities and external sources of capital.

We project that 2004 exploration and development expenditures will approximate $200-220 million, up from $160 million in 2003. We are expanding our 2004 program as a result of successful exploration wells drilled in 2003, growth in our western Oklahoma development projects and entry into new basins. Similar to 2003, a large portion of our 2004 expenditures will be directed to our projects in Oklahoma, Texas and Louisiana. A total of $100 million is anticipated to be spent in the mid-continent area of Oklahoma and north Texas. In the coastal regions of Texas, Louisiana and Mississippi, we plan to

spend $75 million during 2004. The remainder of our projected expenditures will be focused in the Permian basin, California and other western states.

With shareholder equity of $534.7 million, a cash balance of $40.4 million, no debt, and proved reserves of 422.2 Bcfe, we believe we are well positioned to fund the projects identified for 2004 and beyond.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 3 to our consolidated financial statements included in this report. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production.

Oil and Gas Reserves

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Revisions of reserve estimates as of December 31, 2003 equaled an increase of 41 MBbls of oil and an increase of 6.7 Bcf of gas, representing 0.3 percent and 2.0 percent of total proved oil and gas reserves, respectively, as of the end of the year. Corresponding percentages of revisions of previous oil and gas reserve estimates, respectively, for 2002 equal an increase of 7.3 percent and 9.8 percent. See Note 16, Supplemental Oil and Gas Disclosures for reserve data.

As described in Note 3 of Notes to Consolidated Financial Statements, we use the unit-of-production method to amortize our oil and gas properties. Changes in reserve quantities will cause corresponding changes in depletion expense in periods subsequent to the quantity revision or, in some cases, a full cost ceiling limitation charge in the period of the revision. To date, changes in expense resulting from changes in previous estimates of reserves have not been material. A reduction in the carrying value of oil and gas properties of $78.1 million was incurred during the year ended September

30, 2001. This reduction was the result of a reduction of the present value of estimated future net cash flows due to a drop in oil and gas prices and not to changes in estimates of proved reserves.

Carrying Value of Long-Lived Assets

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

We perform an impairment analysis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. Cash flows used in the full cost ceiling limitation are determined based upon estimates of proved oil and gas reserves, future prices, and the costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil and gas prices could cause us to reduce the carrying amounts of our properties. In accordance with the full cost accounting rules, capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization 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. This is referred to as the “full cost ceiling limitation.” At the end of each quarter, a full cost ceiling limitation calculation is made. To date, the only reduction in the carrying value of oil and gas properties was incurred during the year ended September 30, 2001, which amounted to $78.1 million. See Note 3 of Notes to Consolidated Financial Statements.

Goodwill

As described in Note 3 of Notes to Consolidated Financial Statements, we account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of the reporting unit. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. These factors are each individually weighted to estimate the total fair value of the reporting unit. If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill of the unit is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. We recorded $45.0 million of goodwill in the purchase of Key on September 30, 2002. To date, no related impairment has been recorded, nor is any currently anticipated.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us. As of December 31, 2003, no liabilities have been accrued for known contingencies. See Note 15 of Notes to Consolidated Financial Statements.

Recent Accounting Developments

The FASB is currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, to companies in the extractive industries, including oil and gas companies. The FASB is considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.

Cimarex has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, approximately $32.4 million, less $18.2 million in accumulated depreciation, depletion and amortization, of our proved oil and gas property costs would be separately classified as intangible assets. In addition, approximately $19.5 million of unproved properties would be classified as intangible assets. Income and other results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. The classification of oil and gas lease acquisition costs as intangible assets would not have any impact on our compliance with covenants under our debt agreements.

Overview

Our results of operations are impacted by oil and gas prices, which are volatile. Realized oil and gas prices increased from $24.97 per Bbl and $3.10 per Mcf in 2002 to $29.30 per Bbl and $4.96 per Mcf in 2003. The majority of our revenues are from oil and gas sales, so price fluctuations can significantly affect our financial results.

Marketing sales and related purchases pertain to activities with third parties conducted by our marketing group. Natural gas sales transactions are conducted with various purchasers under a variety of terms and conditions and supplied by purchasing gas from other producers and marketing companies. For the sales transactions in which the gas is supplied by our own production, related sales and costs are reflected in Cimarex’s gas sales and transportation expense.

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

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

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

Depreciation, depletion and amortization of our producing properties is computed using the unit-of-production method. Because the economic life of each producing well depends upon the assumed price for production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion.

General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices. While we

expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth.

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees.

Basis of Presentation

Also on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key). 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 it fiscal year from September 30 to December 31. As a consequence, financial statements included in this report show results of operations for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the fiscal year ended September 30, 2001.

RESULTS OF OPERATIONS

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

SUMMARY DATA:

	For the Years Ended December 31,
(in thousands or as indicated)	2003		2002

Net income	$	94,633	$	39,819
Per share-basic	2.28		1.32
Per share-diluted	2.22		1.31

Gas sales	$	250,764	$	128,060
Oil sales	73,355		29,239
Total oil and gas sales	$	324,119	$	157,299

Total gas volume-MMcf	50,552		41,300
Gas volume-MMcf per day	138.5		113.2
Average gas price-per Mcf	$	4.96	$	3.10

Total oil volume-thousand barrels	2,504		1,171
Oil volume-barrels per day	6,859		3,209
Average oil price-per barrel	$	29.30	$	24.97

Marketing sales	$	130,156	$	52,350
Marketing purchases	129,503		49,671
Marketing margin	$	653	$	2,679

Depreciation, depletion and amortization	$	88,774	$	49,231
Production	31,801		19,427
Transportation	7,472		7,918
Taxes other than income	27,485		13,154
General and administrative	17,526		8,568
Stock compensation	1,824		125
Asset retirement obligation accretion	1,009		—

We reported net income of $94.6 million, or $2.22 per diluted share in 2003 compared to net income of $39.8 million, or $1.31 per diluted share in 2002. The primary reason for this increase in net income is the increase in revenues from oil and gas sales. These sales for 2003 equaled $324.1 million, compared to $157.3 million in 2002. The $166.8 million increase in sales between the two years consists of $104.8 million related to higher oil and gas prices, and $62.0 million associated with increased production volumes.

Realized gas prices averaged $4.96 per Mcf for 2003, compared to $3.10 per Mcf for 2002. This 60 percent increase had an incremental effect on sales of $94.0 million between the two years. Realized oil prices averaged $29.30 per barrel for 2003, compared to $24.97 per barrel for 2002. The effect on sales between years resulting from this 17 percent improvement in oil prices totaled $10.8 million. Higher prices were the direct result of overall market conditions. We have not entered into any derivative contracts or hedges with respect to our production.

Oil and gas sales also benefited from higher production volumes. Average gas volumes rose 25.3 MMcf per day in 2003 to 138.5 MMcf per day from 113.2 MMcf per day in 2002, resulting in $28.7 million of incremental revenues. Oil volumes averaged 6,859 barrels per day in 2003, compared to 3,209

barrels per day in 2002, resulting in increased revenues of $33.3 million. The increase in overall sales volumes between the two years is due to the Key acquisition and positive drilling results during 2003. Prior to the acquisition, sales volumes for the first three quarters of 2002 averaged 116.4 MMcfe per day. With the inclusion of Key’s volumes in the fourth quarter of 2002, production increased to 179.7 MMcfe per day. Average daily production contributed from wells drilled during 2003 totaled 17.2 MMcfe, which largely offset natural declines.

Marketing sales net of related purchases equaled $0.7 million in 2003 compared to $2.7 million in 2002. These sales relate to marketing activities with outside parties conducted by our marketing group. The financial impact from these activities is small relative to our overall results of operations. The marketing margin in 2002 was favorably impacted by wide fluctuations in gas prices. Revenues and costs related to marketing of our own production are eliminated in consolidation.

Costs and Expenses (Other than Income tax expense)

Overall costs and expenses (not including income taxes) were $176.5 million in 2003 compared to $98.6 million in 2002. The largest component of this $77.9 million increase between years is a $39.5 million increase in total depreciation, depletion and amortization expense (DD&A) from $49.2 million in 2002 to $88.8 million in 2003, resulting from a larger asset base following the acquisition of Key and higher costs for reserves added during 2003. On a unit of production basis, DD&A was $1.35 per Mcfe in 2003 compared to $1.02 per Mcfe for 2002.

Taxes other than income were $14.3 million greater, rising from $13.2 million in 2002 to $27.5 million in 2003. This increase resulted from a 106 percent jump in oil and gas sales stemming from higher product prices and volumes.

Production costs rose $12.4 million from $19.4 million in 2002 to $31.8 million in 2003 due to the acquisition of Key’s properties and higher workover costs incurred during 2003 for the maintenance of our wells. The mix of Key’s wells included proportionately more oil wells, which generally cost more to operate because of additional pumping and electricity charges.

General and administrative (G&A) expenses increased $8.9 million from $8.6 million in 2002 to $17.5 million in 2003, due to the larger organization resulting from the Key acquisition as well as the expanded drilling program that has been implemented.

Stock compensation related to amortization of restricted stock costs increased by $1.7 million between years, because the majority of the restricted stock and stock units were issued in December 2002.

Accretion expense associated with asset retirement obligations was $1.0 million in 2003. Asset retirement obligations were recorded with the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003.

Income tax expense

Income tax expense totaled $55.1 million for 2003 versus $21.6 million for 2002. Tax expense equaled a combined Federal and state effective income tax rate of 37.2 percent and 35.1 percent in 2003 and 2002, respectively. The increase in effective rates results from greater utilization of tax credits in 2002. We estimate that $24.6 million of our 2003 income tax expense is current.

Year Ended December 31, 2002 Compared with Fiscal Year Ended September 30, 2001

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. 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.

SUMMARY DATA:

	For the Years Ended
(in thousands or as indicated)	December 31, 2002		September 30, 2001

Net income	$	39,819	$	35,253
Per share-basic	1.32		1.33
Per share-diluted	1.31		1.33

Gas sales	$	128,060	$	199,321
Oil sales	29,239		22,815
Total oil and gas sales	$	157,299	$	222,136

Total gas volume-MMcf	41,300		42,387
Gas volume-MMcf per day	113.2		116.1
Average gas price-per Mcf	$	3.10	$	4.70

Total oil volume-thousand barrels	1,171		818
Oil volume-barrels per day	3,209		2,242
Average oil price-per barrel	$	24.97	$	27.88

Marketing sales	$	52,350	$	93,877
Marketing purchases	49,671		87,460
Marketing margin	$	2,679	$	6,417

Reduction to carrying value of oil and gas properties	$	—	$	78,082
Depreciation, depletion and amortization	49,231		49,699
Production	19,427		13,091
Transportation	7,918		6,359
Taxes other than income	13,154		18,965
General and administrative	8,568		10,068
Financing costs, net	171		(1,784		)

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 on 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 reported net income of $39.8 million, or $1.31 per diluted share for the year ended December 31, 2002 compared to net income of $35.3 million, or $1.33 per diluted share for the year ended

September 30, 2001. Wide variations in gas prices between and during the years contributed both directly and indirectly to the changes in net income. In 2002, net income grew by 13 percent compared to fiscal 2001, despite a 34 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.

Oil and gas sales dropped $64.8 million from $222.1 million in fiscal 2001 to $157.3 million in 2002. Gas sales decreased $71.3 million between the two periods. Realized gas prices averaged $3.10 per Mcf for 2002, compared to $4.70 per Mcf for fiscal 2001. This decrease in price had a negative effect on sales of $66.1 million between the two years. Average daily gas volumes decreased 2.9 MMcf in 2002 to 113.2 MMcf from 116.1 MMcf in 2001, reducing revenues by $5.1 million during 2002. Lower gas volumes resulted from natural production declines in existing wells, though partially offset by output from new wells that were completed since September 30, 2001, and gas wells acquired through the Key acquisition.

Oil sales increased from $22.8 million in fiscal 2001 to $29.2 million in 2002. Realized oil prices averaged $24.97 per barrel for 2002, compared to $27.88 per barrel for 2001. The effect on sales between years resulting from this drop in oil prices totaled $3.4 million. The volatility in prices was the result of overall market conditions. Daily oil volumes averaged 3,209 barrels in 2002, compared to 2,242 barrels in 2001, resulting in increased revenues of $9.8 million during 2002. Increase in oil volumes between the two years is due to the acquisition of Key, with Key properties contributing 402 MBbls in the fourth quarter of 2002.

Marketing sales net of related purchases equaled $2.7 million in 2002 compared to $6.4 million in fiscal 2001. The net decrease in 2002 is due to lower average gas prices in 2002 compared to 2001.

Costs and Expenses (Other than Income tax expense)

Overall costs and expenses (not including income taxes) were $98.6 million in 2002 compared to $174.5 million in fiscal 2001. The largest component of this $75.9 million decrease between years is the previously mentioned $78.1 million reduction in carrying value of oil and gas properties in 2001.

DD&A expense dropped slightly to $49.2 million in 2002 from $49.7 million in fiscal 2001.

Taxes other than income decreased to $13.2 million in 2002 from $19.0 million in 2001. These taxes equate to 8.4 percent and 8.5 percent of oil and gas sales for 2002 and 2001, respectively. The expense decreased in 2002 due to lower oil and gas prices realized during the year.

Production costs rose from $13.1 million in fiscal 2001 to $19.4 million in 2002. The biggest contributing factor to the increase was the September 30, 2002 Key acquisition.

Financing costs increased $2.0 million due to 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 in fiscal 2001.

Smaller variances that effectively offset each other were general and administrative expenses between the two years decreasing $1.5 million and transportation expense increasing $1.5 million.

Income tax expense

Income tax expense totaled $21.6 million for 2002 versus $19.6 million for 2001. Tax expense equaled combined Federal and state effective income tax rates of 35.1 percent in 2002 and 35.7 percent in fiscal 2001.

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

SUMMARY DATA:

	For Three Months Ended December 31,
(in thousands or as indicated)	2001		2000
			(unaudited)
Net income	$	4,479	$	27,582
Per share-basic	0.17		1.04
Per share-diluted	0.17		1.04

Gas sales	$	22,750	$	52,004
Oil sales	4,107		7,147
Total oil and gas sales	$	26,857	$	59,151

Total gas volume-MMcf	10,174		10,710
Gas volume-MMcf per day	110.6		116.4
Average gas price-per Mcf	$	2.24	$	4.86

Total oil volume-thousand barrels	206		230
Oil volume-barrels per day	2,236		2,502
Average oil price-per barrel	$	19.97	$	31.04

Marketing sales	$	12,655	$	26,795
Marketing purchases	10,994		22,233
Marketing margin	$	1,661	$	4,562

Depreciation, depletion and amortization	$	8,972	$	9,477
Production	4,197		2,638
Transportation	1,886		1,469
Taxes other than income	2,559		4,194
General and administrative	3,637		2,378

We reported net income of $4.5 million, or $0.17 per diluted share for the fourth quarter ended December 31, 2001 compared to net income of $27.6 million, or $1.04 per diluted share for the three months ended December 31, 2000. The decline in net income is primarily attributable to a decrease in oil and gas sales of $32.3 million. Commodity prices were substantially higher in the quarter ended December 31, 2000.

Realized gas prices averaged $2.24 per Mcf for the fourth quarter of 2001, compared to $4.86 per Mcf for the fourth quarter of 2000. This decrease in price had a negative effect on sales of $26.7 million between the two periods. Realized oil prices averaged $19.97 per barrel for the fourth quarter in 2001, compared to $31.04 per barrel for the same period in 2000, resulting in a decrease in sales between periods of $2.3 million.

Oil and gas sales also decreased due to lower production volumes. Average daily gas volumes decreased 5.8 MMcf in the fourth quarter of 2001 to 110.6 MMcf from 116.4 MMcf for the same period in 2000, resulting in lower revenues of $2.6 million during 2001. Daily oil volumes averaged 2,236 barrels in 2001, compared to 2,502 barrels in 2000, resulting in decreased revenues of $0.7 million during 2001. Lower gas volumes resulted from natural production declines in wells, partially offset by output from new wells that were completed during 2001. Oil volumes between the two periods decreased due to natural production declines.

Marketing sales net of related purchases equaled $1.7 million for the fourth quarter in 2001 compared to $4.6 million for the same period in 2000. 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 more stable. The $2.9 million variance in net revenues reflects less volatile market conditions that existed during the fourth quarter of 2001 when spot market sales were accomplished at prices only slightly higher than the cost of gas purchases.

Costs and Expenses (Other than Income tax expense)

Overall costs and expenses (not including income taxes) were $21.3 million in fourth quarter of 2001 compared to $20.1 million for the same period in 2000.

DD&A on oil and gas properties decreased slightly to $9.0 million for the fourth quarter in 2001 from $9.5 million for the same period in 2000.

Transportation expenses increased to $1.9 million from $1.5 million for the fourth quarters of 2001 and 2000, respectively.

Taxes other than income decreased to $2.6 million in the fourth quarter of 2001 from $4.2 million in the same period of 2000, due to lower oil and gas prices realized in 2001.

Production costs increased from $2.6 million in the fourth quarter of 2000 to $4.2 million in the same three months of 2001, due primarily to general cost increases on outside operated wells and additional compression costs.

G&A expenses increased from $2.4 million in the fourth quarter of 2000 to $3.6 million in the fourth quarter of 2001. 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

Income tax expense totaled $2.8 million for the fourth quarter of 2001 versus $16.5 million for the same period in 2000. Tax expense was calculated using a combined Federal and state effective income tax rate of 38.2 percent in 2001 versus 37.4 percent in 2000. The decrease in the expense between periods was a result of lower revenue resulting from lower oil and gas prices.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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

Cash flow provided by operating activities for the year ended December 31, 2003 was $206.3 million, compared to $104.5 million and $162.4 million for the years ended December 31, 2002 and September 30, 2001, respectively. The increase in 2003 from the earlier periods results primarily from higher prices and production.

Higher revenues from oil and gas sales facilitated the payment of our long-term debt, funded our exploration and development expenditure program for the year, and built a larger balance of cash at year end than we held in 2002.

Cash flow used in investing activities for the year ended December 31, 2003 was $159.6 million, compared to $71.7 million and $101.4 million for the years ended December 31, 2002 and September 30, 2001, respectively. The increase in 2003 stems from a larger exploration and development program.

Cash flow used by financing activities in 2003 was $28.6 million versus $17.6 million in 2002, an increase of $11 million. The most significant item that occurred during 2003 was the repayment of $32.0 million of our long-term credit facility afforded by higher oil and gas prices in 2003. Cash flows used by financing activities for the year ended September 30, 2001 were $61.4 million, $43.8 million higher than in 2002. The decrease in cash used by financing activities in 2002 compared to fiscal year 2001 resulted from a reduction in payments to the previous parent company, H&P.

Financial Condition

As of December 31, 2003, stockholders’ equity totaled $534.7 million, up from $444.9 million at December 31, 2002. The increase resulted primarily from 2003 net income of $94.6 million. During 2003 we repaid all of the $32 million of long-term debt that was outstanding at year end 2002 and increased our cash balance by $18.1 million from $22.3 million at December 31, 2002 to $40.4 million at December 31, 2003.

Working Capital

Working capital at December 31, 2003 totaled $37.7 million, compared to $21.4 million at December 31, 2002. The largest component of this increase was the higher cash balance that resulted from cash flow provided by operating activities. Receivables comprise another significant portion of our working capital, totaling $68.3 million at December 31, 2003. Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. The collection of receivables has been timely, with associated losses historically not being significant.

Financing

In October 2002, we closed on a three-year $400 million Senior Secured Revolving Credit Facility. The Facility has a borrowing base of $275 million and we have elected a $200 million commitment amount. The borrowing base is subject to redetermination each April and October. Borrowings under this Facility bear interest at a LIBOR rate plus 1.25 percent to 2.00 percent, based on borrowing base usage. Unused borrowings are subject to a commitment fee of 0.375 percent to 0.50 percent, also depending on borrowing base usage. The Credit Facility is secured by mortgages on our oil and gas properties and the stock of our subsidiaries. We are also subject to customary financial and non-financial covenants. We are in compliance with all such covenants. There were no borrowings under the Facility at December 31, 2003. We have not sought a corporate credit rating since we have no outstanding long-term debt.

Contractual Obligations and Material Commitments

At December 31, 2003, we had contractual obligations and material commitments as follows:

	Payments Due by Period
Contractual obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Operating leases	$	18,172	$	1,715	$	3,898	$	4,236	$	8,323
Drilling commitments	23,682		23,682		—		—		—
Deferred income taxes(1)	155,293		—		—		—		155,293
Asset retirement obligation	16,463		2,804		1,786		1,655		10,218
Deferred compensation(2)	11,724		2,444		4,732		2,364		2,184
Other liabilities	1,779		158		120		115		1,386

Total obligations	$	227,113	$	30,803	$	10,536	$	8,370	$	177,404

(1) Deferred income taxes are projected not to be paid within the next five years, due to the anticipated drilling expenditures to be incurred during the periods.

(2) The deferred compensation will be paid via the issuance of shares of common stock.

In addition to the items in the table above, we have issued parental guarantees of $9.8 million related to our marketing business for the benefit of companies we purchase gas from.

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004. We have a right to extend this contract annually. Maximum amount that would be payable, if deliveries are not made, would be $0.3 million.

Additionally, we have guaranteed to deliver 2.3 Bcf of natural gas from five wells over a three-year period as reimbursement for connection costs to the pipeline. If the minimum delivery is not met, the maximum exposure is $0.2 million. We have also agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well or a prorated payment based on the total reserves on 17 wells. The maximum amount that would be payable, if we deliver no natural gas, would be $0.6 million.

We also have firm sales contracts to deliver fixed volumes of gas based on an index price. These contracts vary in length from two months to one year. As of December 31, 2003, we had an obligation to deliver approximately 3.8 Bcf of natural gas. If this gas is not delivered, our financial commitment would be approximately $20.7 million based on index prices as of December 31, 2003. This commitment will fluctuate due to price volatility and actual volumes delivered. We believe no financial commitment will be due based on our reserves and current production levels.

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

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

Our projected 2004 exploration and development expenditure program of $200 million will require a great deal of coordination and effort. Though there are a variety of factors that could curtail,

delay or even cancel some of our drilling operations, we believe our projected program has a high degree of occurrence. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts in these areas warrant pursuit of the projects.

Costs of operations on a per Mcfe basis for 2004 are estimated to approximate levels realized in 2003. Should factors beyond our control fluctuate, our program and realized costs will vary from current projections. These factors could include volatility in commodity prices, changes in the supply of and demand for oil and gas, weather conditions, governmental regulations and more.

Estimated production levels for 2004 will range between 195 to 210 MMcfe per day. The revenues to be realized from the sale of this production will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized from the sales. During 2003, the average price realized from our gas sales was $4.96 per Mcf and $29.30 per barrel from our oil sales. Current indications are that anticipated prices for 2004 should approximate 2003 levels. Prices can be highly volatile, however, and the possibility of realized prices for 2004 to vary from current estimates is high.

ITEM 7A. Qualitative and Quantitative Disclosures about Market Risk

Price Fluctuations

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

Oil and gas price realizations for 2003 ranged from a monthly low of $4.13 per Mcf and $26.34 per barrel, to a monthly high of $7.24 per Mcf and $31.31 per barrel, 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. To date, we have not used any of these financial instruments to mitigate commodity price changes.

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

Interest Rate Risk

Cimarex may be exposed to risk resulting from changes in interest rates as a result of our variable-rate bank credit facility. However, because we presently have no debt outstanding, the potential effect that changes in interest rates would have no affect on our results of operations.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CIMAREX ENERGY CO.

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES

Independent Auditors’ Report for the years ended December 31, 2003 and 2002 and the three months ended December 31, 2001
Report of Independent Auditors for the year ended September 30, 2001
Consolidated balance sheets as of December 31, 2003 and 2002
Consolidated statements of operations for the years ended December 31, 2003 and 2002, and September 30, 2001 and for the three months ended December 31, 2001 and 2000
Consolidated statements of cash flows for the years ended December 31, 2003 and 2002, and September 30, 2001 and for the three months ended December 31, 2001
Consolidated statements of stockholders’ equity for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001
Notes to consolidated 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.

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, 2003 and 2002 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2003 and 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, 2003 and 2002, and the results of their operations and their cash flows for the years ended December 31, 2003 and 2002 and the three months ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 5 to the Consolidated Financial Statements, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

KPMG LLP

Denver, Colorado

February 9, 2004

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 year ended September 30, 2001. 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 audit.

We conducted our audit 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 audit provides 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 the year 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.

CIMAREX ENERGY CO.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share information)

	December 31,
	2003			2002
Assets
Current assets:
Cash and cash equivalents	$	40,420		$	22,327
Accounts receivable:
Trade, net of allowance	15,847			7,524
Oil and gas sales, net of allowance	21,350			28,222
Marketing, net of allowance	31,096			22,530
Inventories	6,700			3,986
Deferred income taxes	1,631			2,073
Other current assets	6,160			2,949
Total current assets	123,204			89,611
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	1,331,095			1,172,488
Unproved properties and properties under development, not being amortized	39,370			23,941
	1,370,465			1,196,429
Less – accumulated depreciation, depletion and amortization	(746,161		)	(665,711		)
Net oil and gas properties	624,304			530,718
Fixed assets, less accumulated depreciation of $6,422 and $5,163	12,092			6,849
Goodwill	44,967			45,836
Other assets, net	941			1,272
	$	805,508		$	674,286
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable:
Trade	$	11,146		$	9,500
Marketing	7,248			12,839
Accrued liabilities:
Exploration and development	16,964			7,415
Taxes other than income	6,362			3,743
Other	25,013			10,734
Revenue payable	18,776			24,022
Total current liabilities	85,509			68,253
Long-term debt	—			32,000
Deferred income taxes	155,293			127,023
Asset retirement obligation	16,463			—
Deferred compensation	11,724			—
Other liabilities	1,779			2,130
Total liabilities	270,768			229,406
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued	—			—
Common stock, $0.01 par value, 100,000,000 shares authorized, 41,063,653 and 41,410,308 shares issued and outstanding, respectively	411			414
Paid-in capital	237,430			243,420
Unearned compensation	(9,540		)	(10,814		)
Retained earnings	306,439			211,860
	534,740			444,880
	$	805,508		$	674,286

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

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	For the Years Ended									For the Three Months Ended December 31,
	December 31,						September 30, 2001
	2003			2002						2001			2000
													(Unaudited)

Revenues:
Gas sales	$	250,764		$	128,060		$	199,321		$	22,750		$	52,004
Oil sales	73,355			29,239			22,815			4,107			7,147
Marketing sales	130,156			52,350			93,877			12,655			26,795
Other	(63		)	(5		)	765			84			461
	454,212			209,644			316,778			39,596			86,407
Costs and expenses:
Depreciation, depletion and amortization	88,774			49,231			49,699			8,972			9,477
Reduction to carrying value of oil and gas properties	—			—			78,082			—			—
Accretion expense	1,009			—			—			—			—
Production	31,801			19,427			13,091			4,197			2,638
Transportation	7,472			7,918			6,359			1,886			1,469
Taxes other than income	27,485			13,154			18,965			2,559			4,194
Marketing purchases	129,503			49,671			87,460			10,994			22,233
General and administrative	17,526			8,568			10,068			3,637			2,378
Stock compensation	1,824			125			—			—			—
Financing costs:
Interest expense	1,285			620			(1,509		)	141			107
Capitalized interest	(304		)	(206		)	—			—			—
Interest income	(332		)	(243		)	(275		)	(43		)	(133		)
	306,043			148,265			261,940			32,343			42,363
Income before income tax expense and cumulative effect of a change in accounting principle	148,169			61,379			54,838			7,253			44,044
Income tax expense	55,141			21,560			19,585			2,774			16,462
Income before cumulative effect of a change in accounting principle	93,028			39,819			35,253			4,479			27,582
Cumulative effect of a change in accounting principle, net of tax	1,605			—			—			—			—
Net income	$	94,633		$	39,819		$	35,253		$	4,479		$	27,582
Earnings per share:
Basic:
Income before cumulative effect of a change in accounting principle	$	2.24		$	1.32		$	1.33		$	0.17		$	1.04
Cumulative effect of a change in accounting principle, net of tax	0.04			—			—			—			—
Net income	$	2.28		$	1.32		$	1.33		$	0.17		$	1.04
Diluted:
Income before cumulative effect of a change in accounting principle	$	2.18		$	1.31		$	1.33		$	0.17		$	1.04
Cumulative effect of a change in accounting principle, net of tax	0.04			—			—			—			—
Net income	$	2.22		$	1.31		$	1.33		$	0.17		$	1.04

Weighted average shares outstanding:
Basic	41,521			30,239			26,591			26,591			26,591
Diluted	42,640			30,317			26,591			26,591			26,591

Pro forma amounts assuming new method of accounting for asset retirement obligations is applied retroactively
Net income				$	39,236		$	34,659		$	4,300		$	27,451
Earnings per share:
Basic				$	1.30		$	1.30		$	0.16		$	1.03
Diluted				$	1.29		$	1.30		$	0.16		$	1.03

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

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended									Three Months Ended December 31, 2001
	December 31,						September 30, 2001
	2003			2002

Cash flows from operating activities:
Net income	$	94,633		$	39,819		$	35,253		$	4,479
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	88,774			49,231			49,699			8,972
Amortization of restricted stock compensation	1,914			125			—			—
Reduction to carrying value of oil and gas properties	—			—			78,082			—
Cumulative effect of a change in accounting principle, net of taxes	(1,605		)	—			—			—
Deferred income taxes	30,590			21,428			(11,138		)	2,805
Asset retirement obligation accretion	1,009			—			—			—
Income tax benefit related to stock options exercised	1,203			—			—			—
Other	433			58			(167		)	(241		)
Change in operating assets and liabilities:
(Increase) decrease in accounts receivable	(10,123		)	(15,996		)	9,658			7,387
(Increase) decrease in inventories	(2,714		)	1,770			(1,994		)	541
(Increase) decrease in other current assets	(3,242		)	(934		)	6,373			(396		)
Decrease in other assets	—			—			164			—
Increase (decrease) in accounts payable	(9,310		)	17,010			5,550			(16,656		)
Increase (decrease) in accrued liabilities	15,626			(8,321		)	(9,370		)	(3,319		)
Increase (decrease) in other noncurrent liabilities	(875		)	265			248			32
Net cash provided by operating activities	206,313			104,455			162,358			3,604
Cash flows from investing activities:
Capital expenditures	(150,501		)	(66,458		)	(100,201		)	(14,667		)
Acquisition of proved oil and gas properties	(2,032		)	—			—			—
Merger costs	—			(5,079		)	—			—
Cash received in connection with acquisition	—			2,135			—			—
Proceeds from sale of assets	1,041			313			205			681
Other capital expenditures	(8,149		)	(2,596		)	(1,387		)	(345		)
Net cash used by investing activities	(159,641		)	(71,685		)	(101,383		)	(14,331		)
Cash flows from financing activities:
Long-term borrowings	—			41,016			—			—
Payments on long-term debt	(32,000		)	(45,016		)	—			—
Financing costs incurred	—			(927		)	—			—
Common stock reacquired and retired	(8		)	—			—			—
Net (distributions to) contributions from Helmerich & Payne, Inc.	—			—			(61,430		)	4,808
Change in amount due (to) from Helmerich & Payne, Inc.	—			(13,089		)	—			13,089
Proceeds from issuance of common stock	3,429			403			—			—
Net cash provided by (used in) financing activities	(28,579		)	(17,613		)	(61,430		)	17,897
Net increase (decrease) in cash and cash equivalents	18,093			15,157			(455		)	7,170
Cash and cash equivalents at beginning of period	22,327			7,170			455			—
Cash and cash equivalents at end of period	$	40,420		$	22,327		$	—		$	7,170

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

CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

	Common Stock					Paid-in Capital			Unearned Compensation			Retained Earnings			Total Stockholders’ Equity
	Shares		Amount

Balance, September 30, 2000	26,591		$	266		$	—		$	—		$	192,706		$	192,972

Net income	—		—			—			—			35,253			35,253
Net distributions to Helmerich & Payne, Inc.	—		—			—			—			(61,430		)	(61,430		)
Balance, September 30, 2001	26,591		266			—			—			166,529			166,795

Net income	—		—			—			—			4,479			4,479
Net contributions from Helmerich & Payne, Inc.	—		—			—			—			3,808			3,808
Balance, December 31, 2001	26,591		266			—			—			174,816			175,082

Net income	—		—			—			—			39,819			39,819
Issuance of restricted stock awards in conjuction with the Cimarex spinoff	38		—			—			(156		)	156			—
Common stock issued for the acquisition of Key Production Company, Inc.	14,079		141			232,212			(159		)	—			232,194
Net distributions to Helmerich & Payne, Inc.	—		—			—			—			(2,931		)	(2,931		)
Issuance of restricted stock awards	644		6			10,721			(10,727		)	—			—
Common stock reacquired and retired	(13	)	—			(197		)	—			—			(197		)
Amortization of unearned compensation	—		—			—			228			—			228
Exercise of stock options, net of tax benefit of $282 recorded in paid-in capital	71		1			684			—			—			685
Balance, December 31, 2002	41,410		414			243,420			(10,814		)	211,860			444,880

Net income	—		—			—			—			94,633			94,633
Issuance of restricted stock awards	65		1			1,348			(1,349		)	—			—
Common stock reacquired and retired	—		—			(8		)	—			—			(8		)
Amortization of unearned compensation	—		—			—			2,394			—			2,394
Exercise of stock options, net of tax benefit of $1,203 recorded in paid-in capital	295		3			4,695			—			—			4,698
Net distribution to Helmerich & Payne, Inc.	—		—			—			—			(54		)	(54		)
Restricted stock forfeited and retired	(17	)	—			(308		)	229			—			(79		)
Shares of restricted stock exchanged for restricted stock units	(689	)	(7		)	(11,717		)	—			—			(11,724		)
Balance, December 31, 2003	41,064		$	411		$	237,430		$	(9,540	)	$	306,439		$	534,740

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

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Cimarex Energy Co. (Cimarex or the Company) 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 operations and the common stock of Cimarex Energy Services, Inc. (CESI), which is involved in natural gas marketing, to Cimarex. As a result of a dividend declared and paid by H&P on September 30, 2002, in the form of 26,591,321 shares of Cimarex common stock, Cimarex was spun off and became a stand-alone Company. All par value, common stock and per share amounts have been retroactively restated in the accompanying consolidated financial statements to reflect the spin off.

Also on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. Cimarex issued one share of its common stock for each of the 14,079,243 shares of Key common stock outstanding as of that date. The acquisition of Key has been accounted for using the purchase method of accounting. The acquisition of Key is reflected in the accompanying balance sheets and in the results of operations and cash flows for the periods subsequent to the acquisition on September 30, 2002.

On September 30, 2002, Cimarex changed its fiscal year from September 30 to December 31.

The accounts of Cimarex and its subsidiaries are presented in the accompanying consolidated financial statements. All intercompany accounts and transactions were eliminated in consolidation.

We make certain 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 and in disclosures of commitments and contingencies. Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates.

The more significant areas requiring the use of management’s estimates and judgments relate to preparation of estimated oil and gas reserves, the use of these oil and gas reserves in calculating depletion, depreciation and amortization, the use of the estimates of future net revenues in computing the ceiling test limitations and estimates of abandonment obligations used in such calculations and in recording asset retirement obligations. Estimates and judgments are also required in determining the reserves for bad debts, the impairments of undeveloped properties, the assessment of goodwill and the valuation of deferred tax assets.

Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to the current year presentation.

2. DESCRIPTION OF BUSINESS

Cimarex is an independent oil and gas exploration and production company. Our principal areas of operations are located in Oklahoma, Kansas, Texas and Louisiana.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

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

Inventories

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

Oil and Gas Properties

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities 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 directly identified with acquisition, exploration and development activities are also capitalized. Capitalized costs including estimated future development and abandonment costs are amortized using the unit-of-production method.

In accordance with the full cost accounting rules, capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization 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 (the “full cost ceiling limitation”). If capitalized costs exceed this limit, the excess must be charged to expense. The expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation. The Company recorded a reduction in the carrying value of oil and gas properties of $78.1 million during the year ended September 30, 2001.

The costs of certain unevaluated properties are not being amortized. On a quarterly basis, such costs are evaluated for transfer to the full cost pool resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as adjustments of capitalized costs to the proved oil and gas properties with no losses recognized.

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

Goodwill

Cimarex recorded goodwill in the purchase of Key on September 30, 2002. Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets, states that goodwill and other intangibles determined to have an infinite life are no longer amortized. However, these assets are reviewed for impairment once a year and when circumstances indicate that an impairment may have occurred. The evaluation of the estimated fair value of the goodwill is performed on individual

reporting units. The exploration and production segment is considered the only reporting unit to which goodwill has been assigned.

Cimarex uses the estimated fair value approach to value its goodwill. This approach involves evaluating the estimated fair value of the reporting unit, compared to its carrying amount, including goodwill. The estimated fair value of the exploration and production segment of our business is based on numerous factors, each individually weighted, to estimate total reporting unit estimated fair value. If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. If the carrying amount of a reporting unit exceeds its estimated fair value, then a measurement of any impairment loss must be performed. Measuring any indicated impairment is done by comparing the implied fair value of the reporting unit goodwill with the carrying amount of that goodwill. Any deficiency of the implied goodwill amount compared to the carrying value of goodwill is recorded as an impairment up to the carrying amount. As no deferred taxes have been established for goodwill, any impairment would not be subject to a deferred tax benefit in the income tax provision. Subsequent reversal of a previous goodwill impairment loss is prohibited.

Revenue Recognition

Cimarex recognizes revenues from oil and gas sales based on actual volumes of oil and gas sold to purchasers.

Gas Imbalances

We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. As of December 31, 2003 and 2002, Cimarex had reduced reserves by 465 MMcf and 420 MMcf, respectively. In situations where there are insufficient reserves available to make-up an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2003 and 2002 was $1.4 million and $0.9 million, respectively.

Transportation Costs

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

Income Taxes

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

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. The allocation was finalized and settled in 2003 with a non-cash distribution to H&P of $0.1 million.

Stock Options

We apply Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations to account for all stock option grants and grants of restricted stock. No compensation cost has been recognized for stock options granted as the option prices were the same as the market price of the underlying common stock on the date of grant.

SFAS No. 123, Accounting for Stock Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, requires us to provide pro forma information regarding net income as if the compensation cost for our stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123. 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. To provide the required pro forma information, we estimate the theoretical fair value of each stock option at the grant date by using the Black-Scholes option-pricing model.

Had compensation cost for the plan been determined based on the fair value at the grant dates for awards to employees under the plan, consistent with the methodology of SFAS No. 123, pro forma net income would have been as indicated below for calendar 2003 and 2002. For periods prior to the spin off and the issuance of stock options in exchange for H&P options held by employees, pro forma compensation expense was based on the estimated fair value of the H&P options (in thousands except per share amounts).

	Years Ended						Three Months Ended December 31, 2001
	December 31,				September 30, 2001
	2003		2002		September 30, 2001

Net income, as reported	$	94,633	$	39,819	$	35,253	$	4,479

Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	2,352		1,328		1,270		318

Pro forma net income	$	92,281	$	38,491	$	33,983	$	4,161

Earnings per share:
Basic – as reported	$	2.28	$	1.32	$	1.33	$	0.17
Basic – pro forma	$	2.22	$	1.27	$	1.28	$	0.16

Diluted – as reported	$	2.22	$	1.31	$	1.33	$	0.17
Diluted – pro forma	$	2.16	$	1.27	$	1.28	$	0.16

As required by SFAS No. 123 and amended by SFAS No. 148, the above pro forma data reflects the effect of stock option grants to employees of Cimarex beginning with H&P options issued in 1997. These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years.

The weighted-average fair values of the Cimarex and H&P stock options granted to employees of Cimarex (adjusted for the spin off conversion ratio) at their grant date during calendar 2003 and 2002, and fiscal 2001 were $7.64, $8.16 and $6.56, respectively, and was $6.21 for grants made in the quarter ended December 31, 2001. The estimated theoretical fair value of each option granted is calculated using the Black-Scholes option-pricing model. The following summarizes the weighted-average assumptions used in the model:

	Years Ended						Three Months Ended December 31, 2001
	December 31,				September 30, 2001
	2003		2002		September 30, 2001

Expected years until exercise	7.5		7.5		4.5		4.5
Expected stock volatility	26.7	%	38.9	%	43.1	%	47.7	%
Dividend yield	0.0	%	0.0	%	0.0	%	0.0	%
Risk-free interest rate	3.2	%	3.8	%	5.2	%	4.0	%

Earnings per Share

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

Fair Value of Financial Instruments

The carrying amounts of our cash, accounts receivable, accounts payable and accrued liabilities approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2003, the allowance for doubtful accounts for trade, oil and gas sales, and marketing receivables was $0.2 million, $0.4 million and $0.7 million, respectively. At December 31, 2002, the allowance for doubtful trade accounts was $0.3 million and the allowance for marketing receivables was $0.7 million.

Comprehensive Income

Cimarex applies the provisions of SFAS No. 130, Reporting Comprehensive Income. Cimarex had no comprehensive income for the periods presented.

4. ACQUISITION OF KEY PRODUCTION COMPANY, INC.

On September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key in a tax-free exchange pursuant to which Key became a wholly owned subsidiary of Cimarex. The acquisition of Key was accounted for using the purchase method of accounting.

Our consolidated balance sheets include the assets and liabilities of Key as well as the adjustments required to record the acquisition in accordance with the purchase method of accounting. The final purchase price and the final allocation of the purchase price were finalized at September 30, 2003 based on the actual fair value of current assets and liabilities, and long-term liabilities. The results of operations of Key are included in our consolidated statements of operations for the period since the acquisition on September 30, 2002.

The following unaudited pro forma financial information presents the combined results of Cimarex and Key, and was prepared as if the acquisition had occurred at the beginning of the periods presented. The unaudited pro forma data presented is based on numerous assumptions and is not necessarily indicative of actual results of operations, had the companies been operating as one. The unaudited pro forma results of operations for the year ended September 30, 2001 includes Key’s results of operations for the year ended December 31, 2001. Included in the pro forma results for the year ended December 31, 2002 is $11.0 million of merger related and severance expenses incurred by Key.

	Years Ended					Three Months Ended December 31, 2001
	December 31, 2002		September 30, 2001			Three Months Ended December 31, 2001
	(In thousands, except per share amounts)

Total revenues	$	267,935	$	425,663		$	57,493

Net income (loss)	34,474		(6,595		)	3,395

Diluted earnings (loss) per share	0.84		(0.16		)	0.08

5. ASSET RETIREMENT OBLIGATIONS

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

The adoption of the Statement resulted in recording an increase to the full cost pool of approximately $10.4 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 $13.8 million, an increase to the deferred tax liability of approximately $0.9 million and income reported as a cumulative effect of a change in accounting principle of approximately $1.6 million, net of income taxes of $1.0 million. On a pro forma basis, the asset retirement obligation would have been approximately $12.6 million as of January 1, 2002.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the year ended December 31, 2003 (in thousands):

Initial adoption amount as of January 1, 2003	$	13,784

Liabilities incurred in the current period	1,929
Liabilities settled in the current period	(259		)
Accretion expense	1,009

Balance as of December 31, 2003	$	16,463

6. LONG-TERM DEBT

At December 31, 2003, we had no debt outstanding. We have the capability to borrow on our $400 million Senior Secured Revolving Credit Facility led by Bank One, N.A. This facility presently has a borrowing base of $275 million and we have commitments from our lenders totaling $200 million. The borrowing base is subject to redetermination each April and October.

Borrowings under this facility bear interest at a LIBOR rate plus 1.25 to 2.00 percent, based on borrowing base usage. Unused borrowings are subject to a commitment fee of 0.375 to 0.50 percent, also depending on the borrowing base usage.

The credit facility is secured by mortgages on certain of our oil and gas properties and the stock of our operating subsidiaries. We are also subject to customary financial and non-financial covenants and are in compliance with those covenants. The term of the credit facility expires in October 2005.

7. INCOME TAXES

Federal income tax expense for the years ended December 31, 2003 and 2002, September 30, 2001 and the three months ended December 31, 2001 differ from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state income taxes, percentage depletion and deductible merger costs.

Key’s final tax basis has been determined resulting in an increase of $3.9 million from the original estimate made at the time of the merger with Cimarex. The increase was accounted for at the statutory tax rate of 38 percent and resulted in an adjustment to reduce goodwill by $1.5 million.

The components of the provision for income taxes are as follows (in thousands):

	Years Ended							Three Months Ended December 31, 2001
	December 31,				September 30, 2001
	2003		2002
Current taxes:
Federal	$	21,136	$	—	$	27,219		$	103
State	3,415		132		3,504			(134		)
	24,551		132		30,723			(31		)
Deferred taxes	30,590		21,428		(11,138		)	2,805
	$	55,141	$	21,560	$	19,585		$	2,774

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

	Years Ended								Three Months Ended December 31, 2001
	December 31,					September 30, 2001
	2003		2002

Provision at statutory rate	$	51,859	$	21,482		$	19,193		$	2,539
Effect of state taxes	3,254		1,841			1,024			218
Non-conventional fuel source credits utilized	—		(313		)	(367		)	(92		)
Excess statutory depletion	—		(271		)	(323		)	(81		)
Deductible merger related costs	—		(1,178		)	—			—
Other	28		(1		)	58			190
Income tax expense	$	55,141	$	21,560		$	19,585		$	2,774

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

	December 31,
	2003			2002
Long-term:
Assets -
Net operating loss carryforwards	$	3,921		$	323
Credit carryforwards	1,207			3,256
Long-term assets and liabilities	4,374			1,756
	9,502			5,335
Liabilities:
Property, plant and equipment	(164,795		)	(132,358		)
Net, long-term deferred tax liability	(155,293		)	(127,023		)

Current:
Net current deferred tax assets	1,631			2,073
Net deferred tax liabilities	$	(153,662	)	$	(124,950	)

A net tax operating loss carryforward of approximately $10.3 million exists at December 31, 2003, which expires in the years 2010 through 2022. These net operating losses (NOLs) were acquired as part of an acquisition, and therefore, are subject to annual limitations. We believe all NOLs will be utilized before they expire. An alternative minimum tax credit carryfoward of approximately $1.2 million exists at December 31, 2003.

We have recorded a deferred tax asset of $11.1 million of which $3.9 million is attributable to the NOL carryforward. Realization is dependent on generating sufficient taxable income in the future. Although realization is not assured, we believe it is more likely than not all of the deferred tax asset will be realized.

8. STOCK PLANS

Stock Options

Cimarex’s 2002 Stock Incentive Plan reserves seven million shares of common stock for issuance to directors and employees, including officers. Options granted under the plan after December 5, 2002, expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. All grants are made at the closing price of our common stock as reported on the New York Stock Exchange on the date of grant. Upon the exercise of the options for shares of common stock, the employee is required to hold at least 50 percent of the profit shares, as defined in the plan, until the eighth anniversary of the grant date.

At the date of distribution on September 30, 2002, H&P stock options held by former H&P employees who became Cimarex employees were converted into Cimarex stock options exercisable for 1,630,269 shares of Cimarex common stock based on the intrinsic value at the date of the distribution. The weighted average exercise price for the new options was $13.24 per share. The tables below show the former H&P stock option activity through September 30, 2002, at which time these options were converted to Cimarex stock options. No accounting charge resulted from this exchange because the

economic interest of option holders before and after the spin off was unchanged and the spin off from H&P was for a fixed number of shares of Cimarex common stock. No activity associated with option exercises prior to September 30, 2002, is shown in the statements of stockholders’ equity.

On September 30, 2002, stock options for 785,501 shares of Key common stock held by former employees of Key were converted to Cimarex stock options on a one-for-one basis. These options vested upon closing of the merger. The weighted average exercise price for these options was $11.06 per share.

The following summary reflects the status of stock options granted to employees and directors as of December 31, 2003, and changes during the year:

	Options Outstanding		Weighted Average Exercise Price		Options Exercisable

H&P Activity:
Outstanding as of September 30, 2000	643,778		$	23.81
Granted	216,000		32.31
Exercised	(190,830	)	22.76
Forfeited/Expired	(6,250	)	27.11
Outstanding as of September 30, 2001	662,698		26.82		160,064
Granted	205,000		29.78
Exercised	(4,050	)	16.15
Forfeited/Expired	(5,250	)	27.94
Outstanding as of December 31, 2001	858,398		27.56		355,897
Exercised	(68,073	)	20.70
Forfeited/Expired	(23,500	)	29.48
Outstanding on September 30, 2002, pre spin off	766,825		28.15
Cimarex Activity:
Incremental options issued for conversion to Cimarex stock options	863,444		—
Outstanding on September 30, 2002, post spin off	1,630,269		13.24
Acquired in Key acquisition	785,501		11.06
Granted	1,290,800		16.69
Exercised	(71,294	)	5.65
Forfeited/Expired	(3,189	)	14.01
Outstanding as of December 31, 2002	3,632,087		14.14		1,720,486
Granted	24,000		20.36
Exercised	(294,921	)	11.59
Forfeited/Expired	(39,867	)	16.02
Outstanding as of December 31, 2003	3,321,299		$	14.39	1,992,360

The following table summarizes information about Cimarex stock options held by employees and directors at December 31, 2003:

	Outstanding Stock Options				Exercisable Stock Options
Range of Exercise Prices	Options	Weighted- Average Remaining Contractual Life	Weighted- Average Exercise Price		Options	Weighted- Average Exercise Price
$6.11 to $8.14	182,298	4.7 Years	$	7.81	182,298	$	7.81
$8.15 to $10.17	177,500	5.7 Years	9.69		177,500	9.69
$10.18 to $12.21	534,472	4.4 Years	11.52		534,472	11.52
$12.22 to $14.25	579,585	6.9 Years	13.61		379,741	13.40
$14.26 to $16.28	352,923	6.9 Years	15.20		248,745	15.20
$16.29 to $18.32	1,425,521	8.4 Years	16.77		424,604	16.96
$18.33 to $20.36	69,000	8.1 Years	19.32		45,000	18.77

Restricted Stock and Units

We have a long-term incentive program whereby grants of restricted stock and/or units are awarded to certain employees. The restrictions related to these awards are associated with the continued employment of the grantee for one to five years from the date of the original grant, at which time these shares will vest and there is a three year required holding period subsequent to vesting. The restricted stock and stock unit agreements provide that the grantees will be entitled to receive dividends. We do not currently intend to pay dividends on our common stock.

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

There were 29,087 shares of restricted stock and 688,600 restricted stock units outstanding as of December 31, 2003. There were 674,973 shares of restricted stock outstanding as of December 31, 2002.

Compensation expense for restricted shares or units is based upon the market price of the restricted stock multiplied by the number of shares of restricted stock granted. Compensation cost is being recognized over the associated vesting period. For the year ended December 31, 2003 and 2002, we recorded compensation expense of $1.8 million, net of $0.6 million capitalized to oil and gas properties, and $0.2 million, respectively.

Stockholder Rights Plan

Cimarex has a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an unsolicited takeover attempt.

For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock of the Company. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15 percent or more of our common stock. The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases to prevent dilution.

Cimarex generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time prior to the close of business on the tenth business day after there has been a public announcement of the acquisition of the beneficial ownership by any person or group of 15 percent or more of our common stock. The Rights may not be exercised until our board’s right to redeem the stock has expired. Unless redeemed earlier, the Rights expire on February 23, 2012.

9. EARNINGS PER SHARE

The calculations of basic and diluted net earnings per common share for the years ended December 31, 2003 and 2002, and September 30, 2001 and the three months ended December 31, 2001 are presented in the table below (in thousands, except per share data):

	Years Ended						Three Months Ended December 31, 2001
	December 31,				September 30, 2001
	2003		2002		September 30, 2001
Basic earnings per share:
Income available to common stockholders	$	94,633	$	39,819	$	35,253	$	4,479
Weighted average basic share outstanding	41,521		30,239		26,591		26,591
Basic earnings per share	$	2.28	$	1.32	$	1.33	$	0.17
Diluted earnings per share:
Income available to common stockholders	$	94,633	$	39,819	$	35,253	$	4,479
Weighted average basic shares outstanding	41,521		30,239		26,591		26,591
Incremental shares assuming the exercise of stock options and vesting of restricted stock units	1,119		78		—		—
Weighted average diluted shares outstanding	42,640		30,317		26,591		26,591
Diluted earnings per share	$	2.22	$	1.31	$	1.33	$	0.17

There were stock options outstanding for 3,321,299 and 3,632,087 shares of Cimarex common stock at December 31, 2003 and 2002, respectively. The weighted average common shares for the diluted earnings per share calculation for the year ended December 31, 2002 excludes the incremental effect related to outstanding stock options exercisable for 1,516,401 shares of Cimarex common stock whose exercise price was in excess of the average price of Cimarex’s stock of $15.66 for the period the options were outstanding in 2002 and therefore were antidilutive.

10. EMPLOYEE BENEFIT PLANS

Cimarex maintains and sponsors contributory health care plans and a contributory 401(k) plan. Cimarex employees participate in these plans and costs related to these plans were $3.8 million and $1.9 million, $1.1 million, and $0.3 million in the years ended December 31, 2003 and 2002, and September 30, 2001 and the three months ended December 31, 2001, respectively.

11. RELATED PARTY TRANSACTIONS

H&P provides contract drilling services to Cimarex through its wholly owned subsidiary, Helmerich & Payne International Drilling Company. Drilling costs of approximately $4.6 million and $1.4 million were incurred by Cimarex related to such services for the years ended December 31, 2003 and 2002, respectively. During the fiscal year ended September 30, 2001 and the three months ended December 31, 2001, related drilling costs were $4.5 million and $0.3 million, respectively. Cimarex also reimbursed H&P an additional $0.6 million related to costs incurred by H&P on behalf of Cimarex for the Cimarex stand-alone Oklahoma tax return for the year ended September 30, 2002 and other miscellaneous payments. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of H&P.

Additionally, in the years ended December 31, 2003 and 2002 and the three months ended December 31, 2001, non-cash distributions of $0.1 million, $2.9 million and $1.0 million, respectively, were made to H&P pursuant to the tax sharing agreement.

12. MAJOR CUSTOMERS

During 2003, we sold oil and gas production representing 10.3 percent of revenues to OGE Energy Resources, Inc. For the years ended December 31, 2002 and September 30, 2001 and the three months ended December 31, 2001, no purchasers represented more than 10 percent of our revenues. Alternative purchasers are readily available; therefore, we believe the loss of OGE Energy as a purchaser would not have a material adverse effect on our revenues.

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

13. SEGMENT INFORMATION

Cimarex operates in the oil and gas industry, and is comprised of an exploration and production segment and a natural gas marketing segment. Exploration and production activities are located primarily in Oklahoma, Kansas, Texas, Louisiana and Wyoming. Information presented for our natural gas marketing segment represents business conducted with third parties, usually incidental to sales of our own production.

Summarized financial information of Cimarex’s reportable segments for the years ended December 31, 2003 and 2002, and September 30, 2001 and the three months ended December 31, 2001 is shown in the following table (in thousands):

	External Sales				Operating Profit Before Income Taxes		DD&A and Reduction in Carrying Value of Oil and Gas Properties		Total Assets		Additions to Long- Lived Assets

Year Ended December 31, 2003:
Exploration and Production	$	324,119			$	148,474	$	88,560	$	773,041	$	169,844
Natural Gas Marketing	130,156				407		214		32,467		241

Total	$	454,275			$	148,881	$	88,774	$	805,508	$	170,085

Year Ended December 31, 2002:
Exploration and Production	$		157,299		$	59,922	$	49,040	$	650,243	$	419,026
Natural Gas Marketing	52,350				1,633		191		24,043		409

Total	$			209,649	$	61,555	$	49,231	$	674,286	$	419,435

Year Ended September 30, 2001:
Exploration and Production	$			222,901	$	51,638	$	127,611	$	231,606	$	101,319
Natural Gas Marketing	93,877				5,254		170		14,606		269

Total	$			316,778	$	56,892	$	127,781	$	246,212	$	101,588
Three Months Ended December 31, 2001:
Exploration and Production	$			26,941	$	6,694	$	8,927	$	239,882	$	14,834
Natural Gas Marketing	12,655				459		45		12,084		178

Total	$			39,596	$	7,153	$	8,972	$	251,966	$	15,012

The following table reconciles segment operating profit per the above table to income before taxes as reported on the consolidated statements of operations (in thousands).

	Years Ended									Three Months Ended December 31, 2001
	December 31,						September 30, 2001
	2003			2002

Segment operating profit including depreciation, depletion and amortization	$	148,881		$	61,555		$	56,892		$	7,153

Unallocated amounts:
Other revenue (loss)	(63		)	(5		)	—			198
General and administrative expense allocated from H&P	—			—			(3,839		)	—
Interest expense, net	(649		)	(171		)	1,785			(98		)
	$	148,169		$	61,379		$	54,838		$	7,253

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

	For the Years Ended						Three Months Ended December 31, 2001
	December 31,				September 30, 2001
	2003		2002		September 30, 2001

Cash paid during the period for:
Interest (net of amounts capitalized)	$	830	$	69	$	3,358	$	55
Income taxes (net of refunds received)	$	21,382	$	14	$	30,670	$	—

In connection with the acquisition of Key in 2002 for $237.3 million, we acquired assets with a fair value of $367.5 million and assumed liabilities of $130.2 million. This acquisition was a non-cash transaction except for the cash and cash equivalents of $2.1 million received from Key as more fully described in Note 4.

15. COMMITMENTS AND CONTINGENCIES

Litigation

Cimarex is a defendant to certain claims relating to drainage of gas from two properties that it operates. 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 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was in an amount that significant. The plaintiffs have stated that the royalty owner class has sustained actual damages of approximately $20 million exclusive of interest and costs. We estimate that the share of such alleged damages attributable to its working interest ownership would total approximately $3.0 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. We have received confirmation from the court that any claim against Cimarex will be limited to our proportionate interest in the two properties. We cannot predict the outcome of this litigation, and accordingly, no accrual has been recorded in connection with this action.

Cimarex has other various litigation matters in the normal course of business, none of which are material, individually or in aggregate. We are also party to certain litigation items as plaintiffs that could result in potential gains of between $2.5 million to $3.0 million, net to our interest.

Leases

Cimarex has noncancelable operating leases for office and parking space in Denver and Tulsa and for small district and field offices. Rental expense for the operating leases totaled $2.1 million and $0.6 million for the years ended December 31, 2003 and 2002, respectively, and $0.3 million for the year ended September 30, 2001 and $0.1 million for the three months ended December 31, 2001.

The following table summarizes the future minimum lease payments under all noncancelable operating lease obligations.

Year Ending December 31,	Future Minimum Lease Payments
	(In thousands)

2004	$	1,715
2005	1,826
2006	2,072
2007	2,106
2008	2,130
2009 and thereafter	8,323
	$	18,172

Transportation and Gas Deliveries

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004. We have a right to extend this contract annually. The maximum amount that would be payable, if deliveries are not made, would be $0.3 million.

Additionally, we have guaranteed to deliver 2.3 Bcf of natural gas from five wells over a three-year period as reimbursement for connection costs to the pipeline. If the minimum delivery is not met, our maximum exposure is less than $0.2 million. We have also agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well or a prorated payment based on the total reserves on 17 wells. The maximum amount that would be payable, if no gas is delivered, would be $0.6 million.

We also have firm sales contracts to deliver fixed volumes of gas based on an index price. These contracts vary in length from two months to one year. As of December 31, 2003, we had an obligation to

deliver approximately 3.8 Bcf of natural gas. If this gas is not delivered, our financial commitment would be approximately $20.7 million based on index prices as of February 1, 2004. This commitment will fluctuate due to price volatility and actual volumes delivered. We believe no financial commitment will be due based on our reserves and current production levels.

Tax Sharing Agreement

On September 30, 2002, Cimarex entered into an agreement with H&P that imposes certain restrictions on Cimarex’s ability to redeem or issue a material number of shares of its common stock or to undergo a change of control. These restrictions expire on October 1, 2004. Such actions by Cimarex could cause the spin off of Cimarex by H&P to be deemed a taxable event, potentially resulting in a substantial amount of taxable income to H&P. Under the terms of the agreement, if Cimarex takes or permits an action to be taken that causes the spin off to be taxable, Cimarex would generally be liable for all or a portion of the resultant tax liability. It is expected that any such taxes allocated to Cimarex would be material.

Cimarex has also provided indemnification of H&P in connection with any future tax claims that may be made relating to the oil and gas exploration and production assets contributed to Cimarex by H&P.

Other

The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2003 of approximately $23.7 million.

Parental Guarantees

Cimarex has approximately $9.8 million of parental guarantees outstanding. These guarantee the credit of various CESI agreements and are for the benefit of counterparties from which CESI purchases gas.

16. SUPPLEMENTAL OIL AND GAS DISCLOSURES

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

	Years Ended						Three Months Ended December 31, 2001
	December 31,				September 30, 2001
	2003		2002
	(In thousands, except per Mcfe data)

Oil and gas revenues from production	$	324,119	$	157,299	$	223,026	$	26,857
Less operating costs and income taxes:
Depletion	86,390		48,272		48,931		8,792
Asset retirement obligation accretion	1,009		—		—		—
Reduction to carrying value of oil and gas properties	—		—		78,082		—
Production	31,801		19,427		13,091		4,197
Transportation	7,472		7,918		6,359		1,886
Taxes other than income	27,485		13,154		18,965		2,559
Income taxes	63,226		25,356		20,574		3,357
	217,383		114,127		186,002		20,791
Results of operations from oil and gas producing activities	$	106,736	$	43,172	$	37,024	$	6,066
Amortization rate per Mcfe	$	1.32	$	1.00	$	1.03	$	0.77

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

	Year Ended									Three Months Ended December 31, 2001
	December 31,						September 30, 2001
	2003			2002
Costs incurred during the year:
Acquisition of properties
Proved	$	2,032		$	286,041		$	738		$	—
Unproved	9,330			16,008			18,612			850
Exploration	50,350			29,181			44,166			7,296
Development	100,915			37,273			41,459			6,279
Oil and gas expenditures	162,627			368,503			104,975			14,425
Property sales	(694		)	(151		)	(977		)	—
Asset retirement obligation (Adoption)	10,428			—			—			—
Asset retirement obligation (Additions)	1,675			—			—			—
	$	174,036		$	368,352		$	103,998		$	14,425

Costs Not Being Amortized – The following table summarizes oil and gas property costs not being amortized at December 31, 2003, by year that the costs were incurred (in thousands):

2003	$	29,743
2002	4,838
2001	3,393
2000 and prior	1,396
	$	39,370

We expect the majority of these costs to be evaluated, and to become subject to amortization within the next five years.

Oil and Gas Reserve Information (Unaudited) – Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). Ryder Scott Company, L.P., independent petroleum engineers, has reviewed the proved reserve estimates associated with approximately 80 percent of the discounted future net cash flows before income taxes for the years ended December 31, 2003 and 2002. Netherland, Sewell & Associates, Inc., independent petroleum engineers, prepared the proved reserve estimates as of September 30, 2001. The estimates of proved reserves as of December 31, 2001 were prepared by H&P.

Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following reserve data at December 31, 2003, 2002 and 2001 and at September 30, 2001 represents estimates only and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of Mexico.

	December 31, 2003				December 31, 2002				December 31, 2001				September 30, 2001
	Gas		Oil		Gas		Oil		Gas		Oil		Gas		Oil
	(MMcf)		(MBbl)		(MMcf)		(MBbl)		(MMcf)		(MBbl)		(MMcf)		(MBbl)

Total proved reserves - Developed and undeveloped
Beginning of year	318,627		15,025		212,326		5,304		216,337		5,932		262,498		6,305
Revisions of previous estimates	6,699		41		31,153		1,094		1,260		(432	)	(17,018	)	(700	)
Extensions and discoveries	1,625		1,625		21,064		643		4,903		10		12,748		1,145
Purchases of reserves	1,320		43		95,388		9,155		—		—		496		—
Production	(50,552	)	(2,504	)	(41,300	)	(1,171	)	(10,174	)	(206	)	(42,387	)	(818	)
Sales of properties	(295	)	(93	)	(4	)	—		—		—		—		—
End of year	337,344		14,137		318,627		15,025		212,326		5,304		216,337		5,932

Proved developed reserves	336,230		13,876		318,452		14,765		211,874		4,607		213,931		5,213

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

Under the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax

basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10 percent annual discount rate to arrive at the Standardized Measure.

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

	December 31,									September 30, 2001
	2003			2002			2001			September 30, 2001
Cash inflows	$	2,258,337		$	1,742,435		$	560,439		$	467,886
Production costs	(562,124		)	(511,168		)	(189,216		)	(167,914		)
Development costs	(16,014		)	(6,909		)	(3,961		)	(6,789		)
Income tax expense	(554,746		)	(361,423		)	(89,562		)	(81,253		)
Net cash flow	1,125,453			862,935			277,700			211,930
10% annual discount rate	(413,872		)	(329,076		)	(95,135		)	(67,891		)
Standardized measure of discounted future net cash flow	$	711,581		$	533,859		$	182,565		$	144,039

Discounted future net cash flow before income taxes	$	1,030,340		$	741,209		$	241,150		$	191,240

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

	December 31,									September 30, 2001
	2003			2002			2001
Standardized measure, beginning of period	$	533,859		$	182,565		$	144,039		$	488,071
Sales, net of production costs	(257,362		)	(116,801		)	(18,215		)	(179,776		)
Net change in sales prices, net of production costs	202,135			200,935			52,126			(400,679		)
Extensions, discoveries, and improved recovery, net of future production and development costs	266,128			62,648			9,669			29,387
Net change in future development costs	2,120			4,039			3,691			27,978
Revision of quantity estimates	16,038			70,532			(1,305		)	(15,298		)
Accretion of discount	74,121			24,115			19,124			68,021
Change in income taxes	(111,409		)	(148,765		)	(11,385		)	160,776
Purchases of reserves in place	4,174			297,394			—			619
Sales of properties	(837		)	(1		)	—			—
Settlement of asset retirement obligation	(259		)	—			—			—
Change in production rates and other	(17,127		)	(42,802		)	(15,179		)	(35,060		)

Standardized measure end of period	$	711,581		$	533,859		$	182,565		$	144,039

Impact of Pricing (Unaudited) – The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations are largely due to the seasonal pricing nature of natural gas, supply perceptions for natural gas and significant worldwide volatility in oil prices.

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

	December 31,						September 30, 2001
	2003		2002		2001		September 30, 2001
Price per Mcf	$	5.54	$	4.22	$	2.23	$	1.90
Price per Bbl	$	30.49	$	28.56	$	18.10	$	20.25

Under SEC rules, companies that follow full cost accounting methods are required to make quarterly “ceiling test” calculations. Under this test, capitalized costs of oil and gas properties, net of accumulated DD&A, and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10 percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the “year-by-year” method for purposes of the supplemental oil and gas disclosures and use the “short-cut” method for the ceiling test calculation. Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs.

17. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA

	First		Second		Third		Fourth
	(In thousands, except for per share data)
2003
Revenues	$	136,559	$	99,270	$	112,762	$	105,621
Expenses, net	105,416		78,230		90,221		87,317
Income before cumulative effect of change in accounting principle	31,143		21,040		22,541		18,304
Cumulative effect of change in accounting principle, net	1,605		—		—		—
Net income	$	32,748	$	21,040	$	22,541	$	18,304
Earnings per common share:
Basic:
Income before cumulative effect of change in accounting principle	$	0.75	$	0.51	$	0.54	$	0.44
Cumulative effect of change in accounting principle, net	0.04		—		—		—
Net income	$	0.79	$	0.51	$	0.54	$	0.44
Diluted:
Income before cumulative effect of change in accounting principle	$	0.74	$	0.50	$	0.53	$	0.43
Cumulative effect of change in accounting principle, net	0.04		—		—		—
Net income	$	0.78	$	0.50	$	0.53	$	0.43

	First		Second		Third		Fourth
	(In thousands, except for per share data)
2002
Revenues	$	34,575	$	46,134	$	51,809	$	77,126
Expenses, net	30,317		36,290		41,879		61,339
Net income	$	4,258	9,844		9,930		15,787
Earnings per common share:
Basic	$	0.16	$	0.37	$	0.37	$	0.39
Diluted	$	0.16	$	0.37	$	0.37	$	0.38

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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, with the participation of management, Cimarex’s Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of Cimarex’s disclosure controls and procedures (as defined in Securities Exchange Act Rules 13a-14(c) and 15(d)-14(c)) to ensure that information required to be disclosed by Cimarex under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Cimarex’s disclosure controls and procedures are effective.

There were no significant changes in Cimarex’s internal controls or in other factors that could significantly affect these controls subsequent to the Evaluation Date.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX

Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2004. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report.

ITEM 11. EXECUTIVE COMPENSATION

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 19, 2004 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 29, 2004.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PART IV

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

(a)	(1)	The following financial statements are included in Item 8 to this 10-K:
		Consolidated balance sheets as of December 31, 2003 and 2002
		Consolidated statements of operations for the years ended December 31, 2003 and 2002, September 30, 2001 and for the three months ended December 31, 2001 and 2000
		Consolidated statements of cash flows for the years ended December 31, 2003 and 2002, September 30, 2001 and for the three months ended December 31, 2001
		Consolidated statements of stockholders’ equity for the year ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001

		Notes to consolidated financial statements

	(2)	Financial statement schedules – None

	(3)	Exhibits:

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.

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

2.1		Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co. and Key Production Company, Inc. (filed as Exhibit 2.1 to the Registrant’s Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

3.1		Amended and Restated Certificate of Incorporation of Cimarex Energy Co. filed as Exhibit 3.1 to the Registrant’s Registration Statement on Form S-4, dated May 9, 2002 (Registration No. 333-87948), and incorporated herein by reference.

3.2		By-laws of Cimarex Energy Co. filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form S-4, dated May 9, 2002 (Registration No. 333-387948) and incorporated herein by reference.

4.1		Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-4 dated July 2, 2002 (Registration No. 333-87948) and incorporated herein by reference).

4.2		Rights Agreement, dated as of February 23, 2002, by and between Cimarex Energy Co. and UMB Bank, N.A. (filed as Exhibit 4.2 to dated May 9, 2002 the Registration Statement on Form S-4 (Registration No. 333-87948) and incorporated herein by reference).

10.1		Credit Agreement, dated October 2, 2002, among Cimarex Energy Co., the lenders party thereto, Bank One, NA, as Administrative Agent, Royal Bank of Canada, as Co-Documentation Agent, Wachovia Bank, National Association, as Co-Documentation Agent, and Banc One Capital Markets, Inc., as Lead Arranger and Sole Book Runner. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002, file no. 001-31446).

10.2		First Amendment to Credit Agreement, dated as of April 21, 2003, among Cimarex Energy Co., BankOne, NA, as Administrative Agent, and the Lenders under the Credit Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 2003, file no. 001-31446).

10.3		Distribution Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.1 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

10.4		Tax Sharing Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.2 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

10.5		Employee Benefits Agreement, dated as of February 23, 2002, by and between Helmerich & Payne, Inc. and Cimarex Energy Co. (filed as Exhibit 10.3 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

10.6		First Amendment to Employee Benefits Agreement, dated August 2, 2002, by and among Helmerich & Payne, Inc., Cimarex Energy Co. and Key Production Company, Inc. (filed as Exhibit 10.3.1 to Amendment No. 2 to the Registration Statement on Form S-4 dated August 2, 2002 (Registration No. 333-87948) and incorporated herein by reference).

10.7		Employment Agreement dated September 1, 1992 between Key Production Company, Inc. and F.H. Merelli (filed as Exhibit 10.5 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+

10.8		Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+

10.9		Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+

10.10		Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+

10.11		Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+

10.12		Change of Control Agreement, dated April 11, 2002, by and between Steven R. Shaw and Helmerich & Payne, Inc. (filed as Exhibit 10.10 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).+

10.13		Key Production Company, Inc. Income Continuance Plan, dated effective June 1, 1994 (incorporated by reference to Exhibit 10.18 to Key Production Company, Inc.’s Form 10-K for the fiscal year ended December 31, 1992, file no. 0-17162).+

10.14		Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. (incorporated by reference to Exhibit 10.14 to the Registrant’s From 10-K for the fiscal year ended December 31, 2002, file no. 001-31446).+

10.15		Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective March 3, 2003). (incorporated by reference to Exhibit 10.15 to the Registrant’s Form 10-K for the fiscal year ended December 31, 2002, file no. 001-31446). +

14.1		Code of Ethics for Chief Executive Officer and Senior Financial Officers*

21.1		Subsidiaries of the Registrant*

23.1		Consent of KPMG LLP.*

23.2		Consent of Ernst & Young LLP.*

23.3		Consent of Ryder Scott Company, LP.*

23.4		Consent of Netherland, Sewell & Associates, Inc.*

24.1		Power of Attorney of directors of the Registrant.*

31.1		Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2		Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

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

32.2		Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

(b)		Form 8-K filed October 8, 2003, provided an update of operations.

		Form 8-K filed November 5, 2003, announcing financial and operating results for the third quarter and first nine months of 2003.

SIGNATURE

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

Date: March 10, 2004

	CIMAREX ENERGY CO.


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

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

Signature	Title	Date

/s/ F.H. Merelli	Director, Chairman, President and Chief	March 10, 2004
F.H. Merelli	Executive Officer
	(Principal Executive Officer)

/s/ Paul Korus	Vice President, Chief Financial Officer	March 10, 2004
Paul Korus	Corporate Secretary and Treasurer
	(Principal Financial Officer)

/s/ James H. Shonsey	Controller, Chief Accounting Officer	March 10, 2004
James H. Shonsey	(Principal Accounting Officer)

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
Glenn A. Cox

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
Cortlandt S. Dietler

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
Hans Helmerich

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
David A. Hentschel

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
Paul D. Holleman

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
L.F. Rooney, III

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
Michael J. Sullivan

/s/ F.H. Merelli	Director	March 10, 2004
Attorney-in-Fact
L. Paul Teague