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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PART IV

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D C 20549

Form 10-K

Commission file number 001-31446

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

1700 Lincoln Street, Suite 1800, Denver, Colorado 80203

(Address of principal executive offices including ZIP code)

(303) 295-3995

(Registrant's telephone number)

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

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

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

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

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

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES ý    NO o

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

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

         Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 20092010 was approximately $2,319,938,473.$5,888,486,826.

         Number of shares of Cimarex Energy Co. common stock outstanding as of February 19, 201018, 2011 was 83,839,327.85,520,628.

         Documents Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 20102011 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

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DESCRIPTION

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GLOSSARY

Bbl/d—Barrels (of oil)oil or natural gas liquids) per day

Bbls—Barrels (of oil)
oil or natural gas liquids)

Bcf—Billion cubic feet

Bcfe—Billion cubic feet equivalent

        Btu—British thermal unit

MBbls—Thousand barrels

Mcf—Thousand cubic feet (of natural gas)

Mcfe—Thousand cubic feet equivalent

MMBbls—Million barrels

MMBtu—Million British Thermal Units
thermal units

MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

Net Acres—Gross acreage multiplied by Cimarex's working interest percentage

Net Production—Gross production multiplied by Cimarex's net revenue interest

NGL—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

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

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PART I

Forward-Looking Statements

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

•

amount, nature and timing of capital expenditures;



•

drilling of wells;



•

reserve estimates;



•

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



•

operating costs and other expenses;



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cash flow and anticipated liquidity;



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



•

marketing of oil and natural gas.gas;



•

legislation and regulatory changes;



•

access to capital markets.

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

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

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

        All forward-looking statements, express or implied, included in this Form 10-K and attributable to Cimarex are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to update any

forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and Exchange Commission, except as required by law.

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ITEM 1.    BUSINESS

General

        Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico, Kansas and Wyoming. Proved oil and gas reserves as of year-end 20092010 totaled 1.51.9 Tcfe, consisting of 1.21.3 Tcf of gas and 58.0105 million barrels of oil and natural gas liquids. Of total proved reserves, 77 percent67% are gas and 77 percent77% are classified as proved developed. Our 20092010 production averaged 462.9595.9 MMcfe per day, comprised of 323.2363.9 MMcf of gas per day and 23,28338,674 barrels of oil and natural gas liquids per day. We operate the wells that account for 79 percent79% of our total proved reserves and approximately 82 percent85% of production.

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

        Our Web site address iswww.cimarex.com. There you will find our news releases, annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other Securities and Exchange Commission ("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 telephonetelephonic request to our Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries.

History

        Cimarex was formed in February 2002 as a wholly owned subsidiary of Tulsa-based Helmerich & Payne, Inc. On September 30, 2002, Cimarex was completely spun off to Helmerich and& Payne shareholders and simultaneously merged with Denver-based Key Production Company, Inc. Our common stock began trading on the New York Stock Exchange on October 1, 2002 under the symbol XEC.

        On June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger including assumption of liabilities. That transaction effectively tripled our proved reserves and doubled our production. Since 2005, we have principally focused on exploration and development drilling and have funded these investments with cash flow provided by operating activities.

Market Conditions

        Beginning in the fourth quarter of 2008, severe financial market disruptions and global economic contraction contributed to large decreases in the prices we received for our oil and gas production. Our oil price realizations for 2009 averaged $56 per barrel, 42% less than our 2008 average of $96 per barrel. Our average gas price dropped 51% to $4.12 per Mcf during 2009 from $8.43 per Mcf in 2008. The large decrease in price resulted in a significant decrease in the amount of cash flow available to invest in exploration and development. In response, we sharply reduced our drilling activity. In 2009 we drilled 76% fewer wells as compared to 2008. Our total capital investment in exploration and development during 2009 was just $524 million versus $1.4 billion in 2008.

        In early 2010 oil and gas prices have improved and the cost to drill and complete our wells has decreased. We have begun to increase our drilling activity and our exploration and development capital investment for 2010 is presently expected to range from $700-$900 million.

2009 Summary

        During 20092010 we accomplished the following positive highlights:

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Realized record net income of $575 million, or $6.70 (diluted) per share



•

Grew production 29% to an all-time high of 596 MMcfe per day



•

Increased proved reserves 15%23% to 1.531.9 Tcfe

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Added 312560 Bcfe of proved reserves from extensions, discoveries and improved recovery,revisions replacing 185 percent258% of production.



•

Reduced drilling costs and improved our well performance in our western Oklahoma, Cana-Woodford shale play ending the year with 225 Bcfe of proved reserves.



•

By year-end, had brought on approximately 100 MMcfe/d of new production in southeast Texas.



•

Reduced borrowings outstanding under our revolving credit facility by $195debt $43 million, exiting the year with a debt to total capitalization ratio of 16 percent.

        However, largely as a result of low oil and gas prices we also:

•

Recorded a first-quarter 2009 non-cash full-cost ceiling test write-down of oil and gas properties of $502 million after-tax.



•

Had a net loss for 2009 of $311.9 million.12%

Business Strategy

        Our principal business objective is to profitably grow our proved reserves and production for the long-term benefit of our shareholders. Our strategy centers on maximizing cash flow from our producing

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properties and profitably reinvesting that cash flow in exploration and development.development drilling. During 2009,2010, our cash flow from operating activitiesoperations totaled approximately $675 million.$1.19 billion. Our 2009total 2010 capital investment inwas $1.04 billion, including $999 million on exploration and development was $524 million.development.

        A cornerstone to our approach is a detailed evaluation of each drilling decision based on its risk-adjusted discounted cash flow rate of return on investment. Our analysis includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs, future production profiles and future oil and gas prices.

        Our integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback to the originating exploration team in order to help them improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined capital investment process mitigates risk and positions us to continue to achieve consistent increases in proved reserves and production.

        While our primary focus is drilling, we occasionally consider acquisition and merger opportunities that allow us to either enhance our competitive position in existing core areas or to add new areas. The 2005 Magnum Hunter acquisition significantly increased our presence in the Permian Basin and enhanced our Mid-Continent operations in the Texas Panhandle. In 2008, we acquired 38,000 net acres in our western Oklahoma Cana-Woodford shale play. The cost of that acquisition was $180.9 million.

        Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low prices. At year-end 20092010 we had $393$350 million of long-term debt and our debt to total capitalization ratio was 16 percent.12%.

2011 Outlook

        Our 2011 exploration and development capital investment is presently expected to be in the range of $1.2-$1.4 billion, principally funded from cash flow. We project our 2011 production to grow 3-8% over 2010. We anticipate approximately 55% of the capital investment to be directed toward the Permian Basin, 38% to the Mid-Continent and 7% to the Gulf Coast and other.

        As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions. For 2011, the majority of our oil and gas production is not hedged. We have approximately 5-6% of our gas and 40-45% of our oil production hedged. For a complete discussion of our hedging activities, a listing of open contracts as of December 31, 2010 and the estimated fair value of these contracts as of that date, see Note 4, "Derivative Instruments/Hedging," to our consolidated financial statements.

Business Segments

        Cimarex has one reportable segment (exploration and production).

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Exploration and Development Overview

        Our exploration and development (E&D) activities are conducted within three main areas: the Mid-Continent region, the Permian Basin and the Gulf Coast. The Mid-Continent region consists of Oklahoma, the Texas Panhandle and southwest Kansas. The Permian Basin encompasses west Texas and southeast New Mexico. Our Gulf Coast operations are currently focused in southeast Texas. We also have a gas field development project underway in Wyoming.

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        We drilled and completed 219 gross (129 net) wells during 2010, investing $999 million on E&D. Of total expenditures, 45% were invested in projects located in the Mid-Continent area; 42% in the Permian Basin; and 12% in the Gulf Coast.

        A summary of our 20092010 exploration and development (E&D) activity by region is as follows.

        Company-wide, we participated in drilling 110 gross wells during 2009, with an overall completion rate of 93 percent. On a net basis, 60 of 67 total wells drilled during 2009 were completed as producers.

        Our 2009 E&D investment totaled $524 million and resulted in 312 Bcfe of proved reserve additions. Of total expenditures, 48 percent were invested in projects located in the Mid-Continent area; 30 percent in the Permian Basin; and 20 percent in the Gulf Coast.

Mid-Continent

        Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 51114 gross (22(44 net) Mid-Continent wells during 2009,2010, completing 98 percent97% as producers. The bulk of this drilling activity is directed at gas-bearing geological formationswas in the Anadarko Basin of western Oklahoma. Full-year 20092010 investment in this area was $251$451 million, or 48 percent45% of total E&D capital.

        We drilled 44 gross (17 net)In the Anadarko Basin wells, of which 98 percent were completed as producers. Ourwestern Oklahoma, our largest investment in this area is in the western Oklahoma, Cana-Woodford shale play. We have approximately 94,000 net acres in the play.

The Cana-Woodford formation is a shale interval that varies in thickness from 120-280 feet at depths of 12,000-16,000 feet throughout our acreage. During 2009,2010, we drilled and completed 3586 gross (13.6(32.8 net) horizontal Cana-Woodford wells. At year-end there were 1126 gross (6.3(10.2 net) wells waiting on completion. We have approximately 100,000 net acres in the play.

        Since the Cana play began in late 2007, Cimarex has participated in a total of 75189 gross (32.8(70.8 net) wells. Of which, 58total wells, 143 gross (23.7(55 net) wells have been broughtwere on production and the remainder were either in the process of being drilled or awaiting completion at year-end 2009. For the 58 producing wells,2010. On average gross estimated gross ultimatewell-head recovery exceeds 6.56.7 Bcfe per well. Our acreage positions have multiple years of drilling opportunity.

        In the Texas Panhandle, we drilled 214 gross (2(7.4 net) successful Granite Wash and Morrow wells. Our land position in the Texas Panhandle is primarily in Roberts and Hemphill counties.

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Permian Basin

        Our Permian Basin operations cover both west Texas and southeast New Mexico. Drilling principally occurred in the Delaware Basin portion of New Mexico, mainly targeting the Bone Spring, Abo and Paddock formations. In total, we drilled 4992 gross (36(74 net) wells in this area during 20092010 completing 4488 gross (32(70 net) as producers. Full-year 20092010 investment in this area totaled $155$419 million, or 30 percent42% of total E&D capital. Our 20092010 drilling focused on horizontal oil plays.

        SoutheastWe are also evaluating multiple shale intervals in the Delaware Basin, including the Wolfcamp, Avalon and Cisco/Canyon. In southern Eddy County New Mexico drilling, mainly targeting the Bone Spring, Cherry Canyon, Abo, Paddock and Culberson County Texas, we drilled seven horizontal Wolfcamp formations, totaled 38 gross (30 net)shale wells with 87% being completed as producers.in 2010. Thirty-day average initial production on these wells averaged 6.3 MMcfe/d, comprised of 3.1 MMcf/d of gas, 188 barrels per day of oil and 340 barrels per day of NGLs. The wells had an average lateral length of 3,800'.

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Gulf Coast

        Our current Gulf Coast exploration drilling is primarily in southeast Texas. This effort is generally characterized by reliance on three-dimensional (3-D) seismic information for prospect generation. We alsoCompared to our other core areas, we often experience larger potential reserves per well, greater drilling depths and lower success rates.rates in the Gulf Coast. Full-year 20092010 investment in the Gulf Coast area was $106$116 million, or 20 percent12% of total E&D capital. During 20092010 we drilled 911 gross (8.1(10.2 net) Gulf Coast wells, realizing an 89 percent82% success rate. The majority of the activity occurred near Beaumont in Jefferson County, Texas, where seventen gross (6.9(9.2 net) Yegua/Cook Mountain wells were drilled.

        We also own interests offshore Louisiana on the Gulf of Mexico shelf (water depth less than 300 feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our 20092010 capital investment activity in this area consisted primarily of workovers and recompletions.was less than $1 million.

Other

        We have a large development project in Sublette County, Wyoming where we are developing the deep Madison gas formation and constructing a gas processing plant. During 20092010 we invested a total of $20.1$39.6 million in this project and our cumulative investment in this project is $70.9$110.5 million. We presently expect that we will initiate gas sales from this project in 2011. Our share of the total investment, including planned expansion, will approximate $200 million.

Production, Pricing and PricingCost Information

        The following table sets forth certain information regarding the company's production volumes, and the average oilcommodity prices received and gas prices received:production cost per Mcfe. In 2010, the proved reserves of our Cana-Woodford shale play, located in Watonga-Chickasha field, were 26.7% of our total proved reserves. No other field had reserves in excess of 15% of our total proved reserves.

        Total 2009 oil and gasequivalent 2010 production fell five percentgrew 29% averaging 462.9595.9 MMcfe per day as compared to 485.8462.9 MMcfe per day in 2008.2009. Gas production in 2009 decreased seven percent2010 increased 13% to 323.2363.9 MMcf per day and oil and NGL production grew one percent66% to 23,28338,674 barrels per day. A portion of the NGL increase results from 2010 changes in contractual terms clarifying where title transfer occurs which determines how volumes are recorded.

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        Production changes reflect the early-2009 reduction in company-operated drilling rigs and number of wells drilled. During the fourth quarter of 2008, we were running an average of 31 operated rigs. By the end of March 2009, we were operating only 3 rigs. In the second half of 2009 we began to pick up our drilling activity and had 12 rigs running during the fourth quarter. In total, we drilled and completed 110 gross (67 net) wells during 2009 compared to 450 gross (276.9 net) in 2008. Partially offsetting the impact of the sharp reduction in drilling were four new highly productive wells in southeast Texas that contributed 70 MMcfe/d to our average fourth quarter volumes.

        Reflecting weaker overall U.S. gas markets, we sold our 2009 gas at an average price of $4.12 per Mcf, which was 51 percent lower than the $8.43 per Mcf we received in 2008. Declining global oil prices negatively impacted the oil prices we received. Our annual average realized oil price during 2009 dropped 42 percent to $56.13 per barrel from $96.03 per barrel in 2008.

The following table summarizes Cimarex's daily production by region for 20092010 and 2008.2009.

        Our largest producing area is the Mid-Continent region. During 20092010 our Mid-Continent production averaged 218.5255.4 MMcfe per day, or 47 percent43% of our total 20092010 production. Limited drillingDrilling activity outside of thein our western Oklahoma Cana-Woodford shale play and in the Texas Panhandle Granite Wash resulted in Mid-Continent production decreasing two percentincreasing 17% in 2009.2010.

        The Permian Basin contributed 161.4165.4 MMcfe per day in 2009,2010, which was 35 percent28% of our total production. Oil productionPermian drilling increased seven percentthroughout 2010 as a result of successfulcontinuing improvement in oil prices and return on investment. Our operated rig count went from five in the first-quarter 2010 to 12 by the fourth quarter. Most of the activity was horizontal oil drilling in the Bone Spring, Cherry Canyon, Abo and Paddock formations. Oil production grew 3% in 2010 over 2009 and Wolfcamp formations in southeast New Mexico and West Texas.18% from first-quarter 2010 to fourth-quarter.

        Gulf Coast production averaged 80.2174.1 MMcfe per day during 2009,2010, or 17 percent29% of total production. Full-year 20092010 Gulf Coast volumes decreased 12 percentincreased over 110% as compared to 20082009 as a result of natural production declines and theexploration success in Jefferson County Texas, near Beaumont. Gulf Coast volumes can fluctuate significantly depending on timing of exploration success. Successful exploration drilling in the second-half of 2009 near Beaumont Texas, resulted insuccess relative to natural production volumes increasing to 116.2 MMcfe/d, a 54 percent increase over fourth-quarter 2008 average of 75.7 MMcfe/d.declines.

Acquisitions and Divestitures

        During 2009,2010, we sold oil and gas properties, mostly in Mississippi, for a total of $28.2 million. Associated proved reserves were 8.7 Bcfe. Through several transactions in 2010 totaling $38 million we acquired additional interests in our Cana-Woodford shale play.

        We sold various oil and gas properties in 2009 for a total of $109.4 million. Associatedmillion, to which we attributed 25 Bcfe of proved reserves were 25 Bcfe.reserves. The largest transaction was $79 million for an interest in a West Texas secondary oil field. There were no significant acquisitions during 2009. Subsequent to year end we acquired additional interests in our Western Oklahoma Cana-Woodford shale play for approximately $23 million.

        During 2008 we sold interests in various oil and gas properties primarily located in South Texas for $38.1 million. Also during 2008, we purchased 38,000 undeveloped acres in western Oklahoma for $180.9 million.

        In 2005, Cimarex acquired Magnum Hunter Resources, Inc, an independent oil and gas exploration and production company with operations concentrated in the Permian Basin and the Gulf of Mexico. Magnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves (60 percent gas and 73 percent proved developed).

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Marketing

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

        We sell our oil and gas to a broad portfolio of customers. Our two largest customercustomers accounted for approximately 14 percent22% and 15%, respectively, of 20092010 revenues. Because over 95 percent95% of our gas production is from wells in Kansas,Texas, Oklahoma, New Mexico, TexasKansas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.

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Employees

        We employed 756775 people on December 31, 2009.2010. None of our employees are subject to collective bargaining agreements.

Competition

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

        We compete with integrated, independent and other energy companies for the sale and transportation of oil and gas to marketing companies and end users. The oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial and human resources. The effect of these competitive factors 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. Nevertheless, we are involved in title disputes from time to time which result in litigation. Our oil and gas properties are subject to customary royalty interests, 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 extensive federal, state and local laws and regulations. Compliance with existing laws often is difficult and costly, but has not had a significantly adverse effect upon our operations or financial condition. In recent years, we have been most directly affected by federal and state environmental regulations and energy conservation rules. We are also indirectly affected by federal and state regulation of pipelines and other oil and gas transportation systems.

        The states in which we conduct operations establish requirements for drilling permits, the method of developing new fields, the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production from wells, generally prohibit the venting

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or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill.

        Environmental Regulation.    Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

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

        We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could arise, or our future costs of complying with these governmental requirements. We do maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water or other substances.

        Gas Gathering and Transportation.    The Federal Energy Regulatory Commission (FERC) requires interstate gas pipelines to provide open access transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines have implemented these requirements, providing 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 FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and Federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities.

        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.

        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.

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Federal and State Income and Other Local Taxation

        Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax regulations involving ad valorem, personal property, franchise, severance and other excise taxes. 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. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business operations. If any of the following risks

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and uncertainties actually occurs, our business, financial condition or results of operations could be materially adversely affected, and these events could negatively impact the value of our common stock.

Oil, gas, and gasNGL prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.

        Oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, changes in global supply and demand for oil and gas, the actions of the Organization of Petroleum Exporting Countries, the level of global oil and gas exploration and production activity, weather conditions, technological advances affecting energy consumption, domestic and foreign governmental regulations proximity and capacity of oil and gas pipelines and other transportation facilitiestaxes, and the price and technological advancement of alternative fuels.

        The downward pressure in naturalHistorically, oil and gas prices that began in the last halfhave fluctuated widely. In 2010 we sold our gas at an average price of 2008 continued in 2009.$4.92 per Mcf, which was 19% higher than our 2009 average sales price of $4.12 per Mcf. Our average 2010 oil price of $76.76 per barrel was 36% higher than the price we received in 2009 of $56.63 per barrel. The higher realized naturalprices in 2010 increased sales from 2009 to 2010 by $295.0 million. In contrast, our 2009 average gas price forwas 51% lower than our 2008 average sales price of $8.43 per Mcf, and our 2009 decreased 51% from 2008. Additionally, althoughaverage oil prices have improved since the endprice was 41% lower than our 2008 average oil sales price of 2008, our average$96.76. The lower realized price for oil for 2009 was down 42% from 2008. The decrease in prices significantly decreased the amount available to invest in exploration and development drilling and the present value of our proved reserves. As a result of the drop in commodity prices in the first quarter of 2009 we recorded a $502 million after-tax, full-cost ceiling test write-down of proved properties book-value.compared to 2008 decreased sales from 2008 to 2009 by $845.0 million.

        Our proved oil and gas reserves and production volumes 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. Low prices 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 wouldmay also be impacted.

If oil and natural gas prices decrease, further, we may be required to take additional write-downs of the carrying values of our oil and gas properties and/or our goodwill.

        Accounting rules require that we review the carrying value of our oil and gas properties and goodwill for possible impairment at the end of each reporting period. If prices decrease significantly, we may incur

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additional impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken. For example, low prices contributed to reductions in the carrying value of our oil and gas properties of $2.2 billion and $791 million in 2008 and 2009, respectively.

The globalGlobal financial crisismarkets may have impacts onimpact our business and financial condition that we currently cannot predict.condition.

        The continuedRecurrence of a credit crisis and relatedor other turmoil in the global financial system may have an impact on our business and our financial condition, and we may face challenges if conditions in the financial markets do not improve.condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, which could have an impact on our flexibility to react to changing economic and business conditions. TheDeteriorating economic situationconditions could have an impact on our lenders, purchasers of our oil and gas production and working interest owners in properties we operate, causing them to fail to meet their obligations to us.

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Failure to economically replace commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth.

        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. This can require significant capital expenditures and can impose reinvestment risk for our company, as we may not be able to continue to replace our reserves economically. 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.

        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.

        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.completion services.

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

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

•

timing of development expenditures;



•

amount of required capital expenditures and associated economics;



•

recovery efficiencies, decline rates, drainage areas, reservoir limits;



•

anticipated reservoir and production characteristics, and interpretations of geologic and geophysical data;



•

timing of investments;



•

production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions;



•

future oil, gas, and gasNGL prices;



•

effects of governmental regulation;



•

future operating costs;



•

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



•

capital expenditures;



•

work-over and remedial costs; and

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•

Federal and state income taxes.

        The estimation

Table of the category of proved undeveloped reserves can be subject to an even greater possibility of revision.Contents

        At December 31, 2009, 23 percent2010, 23% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 61 percent50% are related to a project in Wyoming and 33 percent48% are from the western Oklahoma, Cana-Woodford shale play.

        Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent80% of the discounted future net cash flows before income taxes, using a 10 percent10% discount rate, as of December 31, 2009.2010.

        The cash flow amounts 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 the average of the previous twelve months' prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.

Hedging transactions may limit our potential gains and involve other risks.

        To manage our exposure to price risk, we from time to time enter into hedging arrangements, using commodity derivatives with respect to a significant portion of our future production. The goal of these hedges is to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if oil and gas prices rise above the price established by the hedges.

        In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•

the counterparties to our futures contracts fail to perform under the contracts;



•

a sudden unexpected event materially impacts oil and natural gas prices;



•

our production is less than expected; or



•

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement.

        Because all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in derivative gains or losses on our income statement as changes occur in the relevant price indexes.

We have been an early entrant into new or emerging resource development projects; as a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful.

        New or emerging oil and gas resource development projects have limited or no production history. Consequently, we may be unable to use past drilling results in those areas to help predict our future drilling results. Therefore, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage may decline if drilling results are unsuccessful. Furthermore, if drilling results are unsuccessful, we may be required to write down the carrying value of our undeveloped acreage in new or emerging plays.

        Unless production is established during the term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop the related properties.

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Our business depends on oil, gas, and natural gasNGL transportation facilities, most of which are owned by others.

        The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. The lack of availability of these facilities for an extended period of time could

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negatively affect our revenues. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

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.

        Almost all of the wells we drill make extensive use of hydraulic fracturing, a process that creates a fracture extending from the well bore in a rock formation, to enable gas or oil to move through the rock pores to a production well. Fractures are typically created through the injection of water, chemicals and sand into the rock formation. Legislative and regulatory efforts at the Federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have a material adverse effect on our operations and financial results.

In addition, studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases," may be impacting the earth's climate. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil and natural gas, are examples of greenhouse gases. The U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases. In December 2009, the Environmental Protection Agency (EPA) issued findings that methane and carbon dioxide present a health and safety issue such that they should be regulated under the Clean Air Act. Restrictions resulting from legislation by Federal or state legislators, or regulations imposed by the EPA, may have an effect on demand for our products, and may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have an adverse effect on our operations.

        We make extensive use of hydraulic fracturing, a process that creates a fracture extending from the well bore in a rock formation, to enable gas or oil to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water, chemicals and sand into the rock formation. Legislative and regulatory efforts at the Federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have an adverse effect on our operations.

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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 18 percent15% 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

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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.

We may not be able to generate enough cash flow to meet our debt obligations.

        At December 31, 2009, we had total2010, our long-term debt consisted of $392.8 million, consisting of $25.0 million of bank debt, $350 million of unsecured 7.125% Senior Notes and $17.8 million of Convertible Notes ($19.45 million face value).Notes. Subject to the limits contained in the agreements governing our senior revolving credit facility, we have a borrowing base of $1 billion as of December 31, 2009,2010, with current bank commitments of $800 million. We have demands on our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures.

        Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, our financial condition, results of operations and prospects and other factors, many of which are beyond our control. Our ability to meet our debt service obligations may also be affected by changes in prevailing interest rates, as borrowing under our existing senior revolving credit facility and our Convertible Notes bearbears interest at floating rates.

        Our business may not generate sufficient cash flow from operations, nor could there be adequate future sources of capital to enable us to service our indebtedness, or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include:

•

reducing or delaying capital expenditures;



•

seeking additional debt financing or equity capital;

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•

selling assets; or



•

restructuring or refinancing debt.

        We may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.

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The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.

        The indentures governing our senior subordinated notes and credit agreement contain various restrictive covenants that may potentially limit our management's discretion in certain respects. In particular, these agreements will limit our and our subsidiaries' ability to, among other things:

•

pay dividends on, redeem or repurchase our capital stock or redeem or repurchase our subordinated debt;



•

make loans to others;



•

make investments;



•

incur additional indebtedness or issue preferred stock;



•

create certain liens;



•

sell assets;



•

enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;



•

consolidate, merge or transfer all or substantially all of the assets of us and our restricted subsidiaries taken as a whole;



•

engage in transactions with affiliates;



•

enter into hedging contracts;



•

create unrestricted subsidiaries; and



•

enter into sale and leaseback transactions.

        In addition, our revolving credit agreement requires us to maintain a debt to EBITDA ratio (as defined in the credit agreement) of less than 3.5 to 1 and a current ratio (defined to include undrawn borrowings) of greater than 1 to 1. Also, the indentures under which we issued our senior unsecured notes restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.25 to 1. The additional indebtedness limitation does not prohibit us from borrowing under our $1.0 billion revolving credit facility. See Note 7, Long-term Debt, in Notes to Consolidated Financial Statements for further information.

        If we fail to comply with the restrictions in the indentures governing our senior notes or credit facility or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds.

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

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

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acquisition. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such review will not reveal all existing or potential problems. Our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Therefore, the purchase price we pay may exceed the value we realize. When we make entity acquisitions, we may have transferee liability that is not fully indemnified. Acquisitions may have an adverse effect on our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.

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.

Our 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 our stockholders.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        None.

ITEM 2.    PROPERTIES

Oil and Gas Properties and Reserves

        Effective December 31, 2009, the SEC and the Financial Accounting Standards Board ("FASB") adopted amendments to required oil and gas reporting disclosures. The amendments were designed to modernize disclosure requirements and to align them with current practices and changes in technology. The revised rules require reserve calculations to be based on the unweighted average first-day-of-the-month prices for the prior twelve months. In prior years proved reserves were based on

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prices in effect at period end. The current rules permit the use of additional technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about recoverable volumes. Companies may also disclose their probable and possible reserves to investors. We have chosen to not make disclosures of unproved reserves in our SEC filings. The effect of our adoption of the new rules was minimal, apart from the change to using the 12-month average pricing.

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        Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the SEC. Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All reserve estimates of Cimarex are maintained by the Company's internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions of the company. The primary objective of the Corporate Reservoir Engineering Group is to maintain accurate forecasts on all properties of the Company through ongoing monitoring and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.) in accordance with guidelines established by the SEC. This separation of function and responsibility is a key internal control.

        Corporate engineers are responsible for the Company's reserve estimates on all properties within specified geographic areas. For both newly drilled and existing properties, corporate engineers interact with the exploration and production departments to ensure all available engineering and geologic data is taken into account prior to establishing or revising a reserve estimate. After preparing the reserve updates, the corporate engineers review their recommendations with the Vice President—Corporate Engineering. After the Vice President—Corporate Engineering approves the proposed changes, the revisions are entered into the Company's reserve database by the engineering technician.

        During the course of the year, the Vice President—Corporate Engineering presents summary reserve information to Senior Management and Board of Directors for their review. From time to time, the Vice President—Corporate Engineering will also confer with the Vice Presidents of Exploration and Operations, as well as the Chief Executive Officer, regarding specific reserve-related issues. In addition, the Corporate Reservoir Engineering group maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserve database are performed on a regular basis.

        Together, these internal controls are designed to promote a comprehensive, objective and accurate reserve estimation process. As an additional confirmation of the reasonableness of the Company's internal reserve estimates an independent petroleum engineering consulting firm reviews properties representing greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex on an annual basis.

        The technical employee primarily responsible for overseeing the oil and gas reserve estimation process is the company's Vice President—Corporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than fifteensixteen years of practical experience in oil and gas reserve evaluation. This individual has been directly involved in the annual SEC reserve reporting process of Cimarex since 2002 and serving in the current role for the past fivesix years.

        DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than eighty percent80% of the total future net revenue discounted at ten percent10% attributable to the total interests owned by Cimarex as of December 31, 2009.2010. The technical individual primarily responsible for overseeing the reserves review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-fivethirty-six years of experience in oil and gas reservoir studies and evaluations.

        All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise 79 percent79% of our proved reserves. All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 17, Unaudited Supplemental Oil and Gas Disclosures, in Notes to Consolidated Financial Statements for

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further information. The following table sets forth the present value and estimated volume of our oil and gas proved reserves:

        At December 31, 2009, the impact of adopting the new rules requiring the use of a twelve month average price, rather than prices in effect at year end, was significant to our reserve volumes and more so to our reserve values. At year end the reference prices for gas and oil were $5.79 per MMBtu and $79.36 per barrel, respectively, whereas the twelve month average reference prices were $3.87 per MMBtu and $61.18 per barrel. Adjusted for regional differentials, the average prices used were $3.56 per Mcf and $57.58 per barrel. Had prices in effect at year end been used, we believe our December 31, 2009 total equivalent proved reserve volumes would be approximately five to six percent greater than those calculated

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using the average price. We estimate that the Standardized Measure at year end would be approximately 60 percent greater if prices in effect at year end had been used.

Significant Properties

        As of December 31, 2009, 79 percent2010, 85% of our total proved reserves were located in the Mid-Continent and Permian Basin regions. In total we owned an interest in 12,32012,425 gross (4,748(4,798 net) productive oil and gas wells.

        The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2009.2010.

        Our ten largest producing fields hold 35 percent45% of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except Jo-Mill). The table below summarizes certain key statistics about these properties.

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Acreage

        The following table sets forth as of December 31, 2009,2010, the gross and net acres of both developed and undeveloped leases held by Cimarex. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest.

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        The table below summarizes by year and region our undeveloped acreage expirations in the next five years. In most cases the drilling of a commercial well will hold the acreage beyond the expiration.

Gross Wells Drilled

        We participated in drilling the following number of gross wells during calendar years 2010, 2009, 2008, and 2007:2008:

        We were in the process of drilling 1632 gross (9.7(26.6 net) wells at December 31, 20092010 and there were 1143 gross (6.3(23 net) Cana-Woodford wells waiting on completion.

Net Wells Drilled

        The number of net wells we drilled during calendar years 2010, 2009, 2008, and 20072008 are shown below:

Productive Wells

        We have working interests in the following productive wells as of December 31, 2009:2010:

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ITEM 3.    LEGAL PROCEEDINGS

        In January 2009, the Tulsa County District Court issued a judgment in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P") case. This lawsuit was originally filed in 1998 and addressed H&P's conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. DamagesWe had a judgment of $119.6 million, of which $6.9 million plus $119.5 million forpertained to damages, with the remainder being disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted damages, were awarded to plaintiff royalty owners for a total of $126.4 million. This amount was subsequently adjusted by the court to a total of $119.6 million.damages. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P's exploration and production business. In 2008 we had accrued litigation expense of $119.6 million for this lawsuit. During 2009 and 2010, we have accrued an additional interest and fees of $9.4 million.million and $8.9 million, respectively. We have appealed the District Court's judgments.

        In the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. For the year 2009, we had approximately $10.0 million of such expenses. Though some of the related claims may be significant, the resolution of them we believe,

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individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.

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 2009.

ITEM 4A.    EXECUTIVE OFFICERS

        The executive officers of Cimarex as of February 26, 201025, 2011 were:

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

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

        JOSEPH R. ALBI was named executive vice president of operations on March 1, 2005. Since December 8, 2003, Mr. Albi served as senior vice president of corporate engineering. From September 30, 2002 to December 8, 2003, Mr. Albi served as vice president of engineering. Prior to September 30, 2002, Mr. Albi was with Key Production Company, Inc. where he served as vice president of engineering (October 1999 to September 2002) and manager of engineering (June 1994 to October 1999).

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

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2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources.

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

        PAUL KORUS was electednamed senior vice president in December 2010 after having served in a similar role as vice president and chief financial officer and treasurer onof Cimarex since September 30, 2002. From June 1999 to September 2002, Mr. Korus was vice president and chief financial officer of Key Production Company, Inc. from

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September 1999 to September 2002.Company. Prior to September 1999 and since June 1995, Mr. KorusKey, he was an equity research analyst with Petrie Parkman & Co., an energy investment banking firm.firm from 1995 to 1999 and was with Apache Corporation from 1982 to 1995.

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

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

        JAMES H. SHONSEY was named vice president in April 2006. Mr. 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.

        THOMAS A. RICHARDSON joined Cimarex in August 2008 and was elected vice president and general counsel on September 20, 2008. Mr. Richardson retired as a senior partner of Holme Roberts & Owen LLP, a Denver law firm, in December 2007. Mr. Richardson joined Holme Roberts in June 1970 and served as a partner of the firm from 1975 to his retirement. His specialties at the firm included corporate, securities and merger and acquisition law.

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PART II

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

        Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. A cash dividend of $.06 per share was paid to shareholders in each quarter of 2009.2010. Future dividend payments will depend on the Company's level of earnings, financial requirements and other factors considered relevant by the Board of Directors.

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

        The closing price of Cimarex stock as reported on the New York Stock Exchange on February 19, 2010,18, 2011, was $59.98.$114.62. At December 31, 2009,2010, Cimarex's 83,541,99585,234,721 shares of outstanding common stock were held by approximately 4,0922,731 stockholders of record.