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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, 20102011 was approximately $5,888,486,826.$7.5 billion.

         Number of shares of Cimarex Energy Co. common stock outstanding as of February 18, 201115, 2012 was 85,520,628.85,701,346.

         Documents Incorporated by Reference: Portions of the Registrant's Proxy Statement for its 20112012 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 or natural gas liquids) per day

        Bbls—Barrels (of 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

        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;



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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;



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marketing of oil and natural 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 described 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

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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., 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.Kansas.

        Proved oil and gas reserves as of year-end 20102011 totaled 1.92.05 Tcfe, consisting of 1.31.2 Tcf of gas and 105138 million barrels of oil and natural gas liquids. Of total proved reserves, 67%59% are gas and 77%82% are classified as proved developed.

        Our 20102011 production averaged 595.9592.3 MMcfe per day, comprised of 363.9329.1 MMcf of gas per day and 38,67443,875 barrels of oil and natural gas liquids per day. WeThe wells we operate the wells that account for 79%76% of our total proved reserves and approximately 85%81% of our production.

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

        Our Web site address 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 Compensation and Governance Committee Charter. Copies of these documents are available in print upon a written or telephonic 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. ("H&P"). On September 30, 2002, Cimarex was completely spun off to Helmerich & PayneH&P 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. Since 2005, we have principally focused on exploration and development drilling and have funded these investments with cash flow provided by operating activities.

20102011 Summary Highlights

        During 20102011 we accomplished the following highlights:following:

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Realized record netNet income of $575$530 million, or $6.70$6.15 (diluted) per shareshare;



•

Grew production 29% to an all-time highCash flow from operating activities of 596 MMcfe per day$1.3 billion;



•

Increased proved reserves 23%9% to 1.9 Tcfe2.05 Tcfe; adjusted for property sales, proved reserves increased 23%;



•

Added 560587 Bcfe of proved reserves from extensions and discoveries and revisions replacing 258%272% of productionproduction;



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Reduced debt $43Sold $229 million exitingof non-strategic assets and reinvested proceeds in core area exploration and development activities;

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Evaluated, de-risked and expanded our acreage position in several key long-term future drilling projects;



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Grew Permian and Mid-Continent production 16% to an all-time high of 487 MMcfe/d; overall production of 592 MMcfe/d was about flat with 2010 production; and



•

Exited the year with a debt to total capitalization ratio of 11%, down from 12% at year-end 2010.

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 drilling.

        During 2010,2011, our cash flow from operationsoperating activities totaled approximately $1.19$1.3 billion. Our total 20102011 capital investment was $1.04$1.625 billion, including $999 million$1.58 billion on exploration and development. We funded our capital program primarily with cash flow and property sales.

        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.play, and we have continued to increase our acreage positions in this play over the last three years.

        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 20102011 we had $350$405 million of long-term debt and our debt to total capitalization ratio was 12%11%.

20112012 Outlook

        Our 20112012 exploration and development capital investment is presently expected to be in the range of $1.2-$1.4 billion, principally funded from cash flow.$1.4-1.6 billion. We projectexpect nearly all of our 2011 production to grow 3-8% over 2010. We anticipate approximately 55% of the2012 capital investment to be directed towardtowards oil or liquids-rich gas drilling in the Permian Basin, 38% to theand Cana-Woodford shale play.

        Full-year 2012 Mid-Continent and 7%Permian production volumes are projected to thegrow 19-25% above 2011, averaging between 580-610 MMcfe/d. Gulf Coast and other.volumes, assuming no new production contribution from drilling, are projected to average 35-40 MMcfe/d for 2012. Total company 2012 volumes are projected to average 615-650 MMcfe/d, or 4-10% growth over 2011.

        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.

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        For 2011, the majority2012 we have approximately 50% of our oil and gas production is not hedged. We do not have approximately 5-6%any of our gas and 40-45% of our oilor natural gas liquids production hedged. For a complete discussion of our hedging activities, a listing of open contracts as of December 31, 20102011 and the estimated fair value of these contracts as of that date, see Note 4, "DerivativeDerivative Instruments/Hedging," to our consolidated financial statements.

Business Segments

        Cimarex has one reportable segment (exploration and production).

Exploration and Development Overview

        Our exploration and development (E&D) activities arehave been conducted primarily within threetwo main areas: the Mid-Continent region and the Permian Basin and the Gulf Coast.Basin. 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 focusedwere conducted in southeast Texas. We also have a gas field development project underway in Wyoming.

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        We drilled and completed 219331 gross (129(174 net) wells during 2010,2011, investing $999 million$1.6 billion on E&D. Of total expenditures, 45%47% were invested in projects located in the Mid-Continent area; 42%46% in the Permian Basin; and 12%7% in the Gulf Coast.Coast and other.

        A summary of our 20102011 exploration and development activity by region is as follows.

Mid-Continent

        Our Mid-Continent region encompasses operations in Oklahoma, southwest Kansas and the Texas Panhandle. We drilled 114180 gross (44(64 net) Mid-Continent wells during 2010,2011, completing 97%100% as producers. The bulk of this drilling activity was in the Anadarko Basin of western Oklahoma. Full-year 20102011 investment in this area was $451$741 million, or 45%47% of total E&D capital.

        In the Anadarko Basin of western Oklahoma, our largest investment is in the Cana-Woodford shale play. The Cana-Woodford formation is a shale interval that varies in thickness from 120-280 feet at depths of 12,000-16,00011,000-16,000 feet throughout our acreage. During 2010,2011, we drilled and completed 86154 gross (32.8(49 net) horizontal Cana-Woodford wells. At year-end there were 2613 gross (10.2(4.9 net) wells waiting on completion. We have approximately 100,000120,000 net acres in the play.

        Since the Cana play began in late 2007, Cimarex has participated in a total of 189330 gross (70.8(119 net) wells. Of total wells, 143297 gross (55(105 net) were on production and the remainder were either in the process of being drilled or awaiting completion at year-end 2010.2011. On average gross estimated well-head recovery exceeds 6.76.3 Bcfe per well. Our acreage positions have multiple years of drilling opportunity.

        In the Texas Panhandle, we drilled or participated in 14 gross (7.4(7.6 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 west Texas and southeast New Mexico. Drilling principally occurred in the Delaware Basin portion of New Mexico and West Texas, mainly targeting the Bone Spring, Abo and Paddock formations. In total, we drilled 92140 gross (74(100 net) wells in this area during 20102011 completing 88134 gross (70(95 net) as producers. Full-year 20102011 investment in this area totaled $419$731 million, or 42%46% of total E&D capital. Our 20102011 drilling focused on horizontal oil plays.plays and new emerging liquids rich gas.

        Full-year 2011 New Mexico Bone Spring wells drilled and completed totaled 63 gross (40 net). The 30-day gross production from the 2011 Bone Spring wells averaged 530 barrels equivalent (Boe) per day (84% oil). Seventeen of these wells were brought on in the fourth-quarter with an average 30-day gross rate of 597 Boe per day (85% oil). Texas Third Bone Spring drilling totaled 17 gross (14 net) wells, which on average had 30-day gross production rates of 730 Boe/d (73% oil).

        We are also evaluating multiple shale intervals in the Delaware Basin, including the Wolfcamp, Avalon and Cisco/Canyon. The majority of drilling to date has been in the Wolfcamp. In southern Eddy County New Mexico and Culberson County Texas, we drilled seven11 gross (10 net) horizontal Wolfcamp shale wells in 2010.2011. Since commencing the play in 2010, we have drilled a total of 18 gross (16.8 net) Wolfcamp wells. Thirty-day average initial production on these wells averaged 6.36.5 MMcfe/d, comprised of 3.1 MMcf/d of44% gas, 188 barrels per day of24% 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 iswas primarily in southeast Texas. This effort is generally characterized by reliance on three-dimensional (3-D) seismic information for prospect generation. Compared to our other core areas, we often experience larger potential reserves per well, greater drilling depths and lower success rates in the Gulf Coast. Full-year 20102011 investment in the Gulf Coast area was $116$95 million, or 12%6% of total E&D capital. During 20102011 we drilled 11 gross (10.2(9.6 net) Gulf Coast wells, realizing an 82%a 27% success rate. The majority of the activity occurred near Beaumont in Jefferson County, Texas, where ten gross (9.2 net) Yegua/Cook Mountain wells were drilled.Texas.

        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 2010We had no capital investment activity 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 2010 we invested a total of $39.6 million in this project and our cumulative investment in this project is $110.5 million. We presently expect that we will initiate gas sales from this project induring 2011. Our share of the total investment, including planned expansion, will approximate $200 million.

Production, Pricing and Cost Information

        The following table sets forth certain information regarding the company's production volumes, the average commodity prices received and production cost per Mcfe. In 2010,2011, the total proved reserves of our

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Cana-Woodford shale play, located in the Watonga-Chickasha field, were 26.7%42.4% of our total proved reserves. No other field had reserves in excess of 15% of our total proved reserves.

        Total equivalent 20102011 production grew 29% averaging 595.9averaged 592.3 MMcfe per day as compared to 462.9595.9 MMcfe per day in 2009.2010. Gas production in 2010 increased 13%2011 decreased 10% to 363.9329.1 MMcf per day and oil and NGL production grew 66%13% to 38,67443,875 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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        The following table summarizes Cimarex's daily production by region for 20102011 and 2009.2010.

        Our largest producing area is the Mid-Continent region. During 20102011 our Mid-Continent production averaged 255.4292.6 MMcfe per day, or 43%49% of our total 20102011 production. Drilling activity in our western Oklahoma Cana-Woodford shale play and in the Texas Panhandle Granite Wash resulted in Mid-Continent production increasing 17%15% in 2010.2011.

        The Permian Basin contributed 165.4194.4 MMcfe per day in 2010,2011, which was 28%33% of our total production. Permian drilling increased throughout 20102011 as a result of continuing 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 drillingfocused in the Bone Spring, Abo and Paddock formations. Oil production grew 3%20% in 20102011 over 2009 and 18% from first-quarter 2010 to fourth-quarter.2010.

        Gulf Coast production averaged 174.1105.3 MMcfe per day during 2010,2011, or 29%18% of total production. Full-year 20102011 Gulf Coast volumes increased over 110%decreased by 40% as compared to 20092010 as a result of exploration successdeclines in wells drilled in Jefferson County Texas, near Beaumont. Gulf Coast volumes can fluctuate significantly depending on timing of exploration success relative to natural production declines.

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Acquisitions and Divestitures

        In August 2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (including purchase price adjustments). The assets sold principally consisted of a gas processing plant under construction and related assets and 210 Bcf of proved undeveloped gas reserves. The sales contract also provides for up to a $15 million contingent payment to be paid by the buyer at the time the gas processing facility is operational and certain other performance standards are met, which is expected to occur in the second quarter of 2012.

        We also sold interests in certain other non-strategic oil and gas properties with proved reserves of 16.3 Bcfe, most of which were located in south Texas and southeast New Mexico. These transactions totaled $33.3 million. Certain of these properties were included as part of like-kind exchanges for selected purchases in our core plays. We acquired additional oil and gas properties in 2011 for a total of $45.4 million of which $42.2 million was in our Cana-Woodford shale play.

        During 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.

        WeIn 2009, we sold various oil and gas properties in 2009 for a total of $109.4 million, to which we attributed 25 Bcfe of proved reserves. The largest transaction was $79 million for an interest in a West Texas secondary oil field. There were no significant acquisitions during 2009.

        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.

Marketing

        Our oil and gas production is sold under variousseveral 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 customers accounted for approximately 22% and 15%, respectively, of 20102011 revenues. Because over 95% of our gas production is from wells in Texas, Oklahoma, New Mexico, Kansas and Louisiana,Kansas, 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 775824 people on December 31, 2010.2011. 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

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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 significantlysignificant 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 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.

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        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.

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 ITEM 1A.    RISK FACTORS

        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 anyThe occurrence of the followingone or more of these risks

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or uncertainties could materially and uncertainties actually occurs,adversely affect our business, our financial condition, orand the results of our operations, could be materially adversely affected, and these eventswhich in turn could negatively impact the value of our common stock.securities.

Oil, gas, and NGL 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 wevolatile. We cannot predict future prices. The prices we receive for our 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, geopolitical instability, 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, governmental regulations and taxes, and the price and technological advancement of alternative fuels.

        Historically, oil and gas prices have fluctuated widely. In 2010 we sold our gas at an average priceTable of $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 prices in 2010 increased sales from 2009 to 2010 by $295.0 million. In contrast, our 2009 average gas price was 51% lower than our 2008 average sales price of $8.43 per Mcf, and our 2009 average oil price was 41% lower than our 2008 average oil sales price of $96.76. The lower realized prices in 2009 compared to 2008 decreased sales from 2008 to 2009 by $845.0 million.Contents

        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. ForAccordingly, 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 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 may also be impacted.

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

        Accounting rules require that we periodically review the carrying value of our oil and gas properties and goodwill for possible impairment at the end of each reporting period.impairment. If prices decrease significantly, we may incur 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 reductionsthe impairment charge of $791 million that we recorded in the carrying value of our oil and gas properties of $2.2 billion and $791 million in 2008 and 2009, respectively.2009.

Global financial markets may impact our business and financial condition.

        Recurrence of a credit crisis or other turmoil in the global financial system may have an impact on our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing, whichfinancing. This could have an impact on our flexibility to react to changing economic and business conditions. Deteriorating economic conditions 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 new regulations or legislation and 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 also from productive wells that do not produce sufficient reserves to return a profit.profit or from declines in commodity prices.

        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,formations. In addition, 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 and completion services.services may also negatively impact our drilling operations.

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

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assumptions. See Forward-Looking Statements in this report. 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, and reservoir limits;



•

anticipated reservoir and production characteristics,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 NGL prices;



•

effects of governmental regulation;



•

future operating costs;



•

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



•

work-over and remedialremediation costs; and



•

Federal and state income taxes.

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        At December 31, 2010, 23%2011, 18% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 50%98% are related to a project in Wyoming and 48% are from theour 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% of the discounted future net cash flows before income taxes, using a 10% discount rate, as of December 31, 2010.2011.

        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, usingarrangements. We use commodity derivatives with respect to a significant portion of our future production. For 2012, we have hedged approximately 50% of our anticipated oil 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.

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        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; asprojects. As a result, our drilling results in these areas are uncertain, and theuncertain. 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, in those areas we may be unable to usenot have 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 theexpected. 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 primary term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop the relatedthose properties.

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

        The marketability of ourOur oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems and transportation facilities owned by third parties. The lack of available capacity on these systems and facilities (or the lack of such systems and facilities in proximity to our wells) 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, adverse court rulings, 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 andproperties. They may also be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

We may be subject to information technology system failures, network disruptions and breaches in data security.

        Information system failures, network disruptions and breaches in data security could have a material adverse effect on our ability to conduct our business. We could experience system failures due to power or telecommunications failures, human error, natural disasters, fire, sabotage, hardware or software malfunction or defects, computer viruses, intentional acts of vandalism or terrorism and similar acts. Such system failures could result in the unanticipated disruption of our operations, the processing of transactions and the reporting of our financial results. While management has taken steps to address these concerns by implementing sophisticated network security and internal control measures, there can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition and operation results.

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

        Exploration, development, production and the sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex environmental laws. We maylaws and regulations protecting the environment and human health and safety. Federal and state regulatory agencies frequently require permitting and impose conditions on our activities. During the permitting process, these regulatory authorities often exercise considerable discretion in both the timing and ultimate scope of the permits. The requirements or conditions imposed by these authorities can be costly, possibly resulting in delays in the commencement of our operations. Further, if the required to make large expenditurespermits are not issued or if the current requirements become more burdensome, costs could materially increase and our operations could be significantly restricted.

        Failing to comply with environmental and other governmental regulations. Failure to comply with theseany of the applicable laws and regulations maycould 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 both our financial condition and resultsoperations.

Environmental matters and costs can be significant.

        As an owner, lessee or operator of oil and gas properties, we are subject to various complex and constantly evolving environmental laws and regulations that have tended to become more onerous over time. Our operations create the risk of environmental liability to the government and private parties, including for the discharge of oil, gas or other substances into the air, soil or water. Liabilities under environmental law can be joint and several and can in some cases be imposed regardless of fault on our part. Further, we may be liable for remediating facilities that were previously owned or operated by others. Since these environmental risks generally are not fully insurable and can result in substantial costs, these liabilities could have a material adverse effect on both our financial condition and operations.

        AlmostFederal and state legislation and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.

        In order to achieve economic production rates and recoverable reserves, we use hydraulic fracturing for almost all of the wells we drill make extensive use of hydraulicour wells. Hydraulic fracturing is a process that createsinvolves pumping fluid at high pressure into a fracture extending from the well bore in a rockhydrocarbon bearing formation to create fractures. Those fractures enable gas or oil to move through the rockformation's pores to a production well. Fractures arethe well bore. The fluid used in this process is typically created through the injectionmade up primarily of water chemicals and sand, intobut it also contains chemicals or additives designed to optimize production. Certain states are requiring companies to disclose the rock formation. Legislative and regulatory efforts atcomponents of this fluid. Additional states, as well as the Federal government, may follow with similar or conflicting requirements. The efforts to regulate hydraulic fracturing at both the state and Federal level are increasing. Many new regulations are being considered, including limiting water withdrawals and water used, restricting which additives may be used, implementing state-wide hydraulic fracturing moratoriums and temporary or permanent bans in certain environmentally sensitive areas. Public debate over hydraulic fracturing and shale gas production also has been increasing, which has resulted in delays of well permits in some states have been made toareas. The potential result of these efforts could render permitting and compliance requirements to become more stringent for hydraulic fracturing. Such effortsfracturing, which could have a material adverse effect on our operations and financial results.

        In addition, studiesThe adoption of climate change legislation or regulations restricting emission of "greenhouse gases" could result in increased operating costs and reduced demand for the oil and natural gas we produce.

        Studies have suggested that emissionsemission 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, and in some cases implementing, climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases. In December 2009, the Environmental

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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,legislation or regulations imposed by the EPA, may have an effect on our ability to produce oil and gas, as well as the demand for our products, andproducts. Such changes 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.operations and financial results.

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 15%19% of our net production. Our success in properties operated by others depends upon a number of factors outside of our control, includingcontrol. These factors include 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, andfailures. They would also include environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases. Any of these risks can cause substantial losses resulting from from:

•

injury or loss of life, life;



•

damage to or destruction of property, natural resources and equipment, equipment;



•

pollution and other environmental damages, damages;



•

regulatory investigations and penalties, penalties;



•

damage to our reputation;



•

suspension of our operationsoperations; 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, 2010,2011, our long-term debt consisted of $350 million of unsecured 7.125% Senior Notes. Subject to the limits contained in the agreements governing our senior revolving credit facility, we have a borrowing baseNotes and $55 million of $1 billion as of December 31, 2010, with current bank commitments of $800 million. We have demands on our cash resources indebt. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources 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 future performance and our ability to repay or refinance our debt as it becomes due. Our

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future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations 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 bears interest at floating rates.

        Our business may not generate sufficient cash flow from operations, nor couldoperations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness,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;



•

selling non-strategic 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 indenturesindenture governing our senior subordinated notes and our 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 indenturesindenture under which we issued our senior unsecured notes restrictrestricts us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge

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coverage ratio (as defined in the indentures)indenture) 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 indenturesindenture governing our senior notes or the agreement governing our 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.

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 beThe 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 requireproducing properties requires an assessment of a number ofseveral factors, including estimates of including:

•

recoverable reserves, exploration potential, reserves;



•

future oil and natural gas prices and their appropriate differentials;



•

operating costscosts; and



•

potential environmental and other liabilities. Such

        The accuracy of these assessments are inexact.is inherently uncertain. In connection with ourthese assessments, we perform a review of the acquiredsubject properties whichthat we believe isto be generally consistent with industry practices. However, suchOur review will not reveal all existing or potential problems. Our review may notproblems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Therefore,Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the purchase price we payseller may exceedbe unwilling or unable to provide effective contractual protection against all or part of 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.problems.

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 certificateWe are involved in various legal proceedings, the outcome of incorporation, by-lawswhich could have an adverse effect on our liquidity.

        In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the "Krug v. H&P" case. See Note 16, Commitments and stockholders' rights plan include provisionsContingencies in this report for more detailed information.

        Because this case is subject to further appeal, despite the fact that the ultimate outcome currently is unknown, we have accrued for the District Court's original judgment in our financial statements. If the District Court's original judgment is ultimately affirmed in its entirety, the $119.6 million plus the then determined amount of post-judgment interest and costs would become payable. This could discouragehave an unsolicited corporate takeoveradverse effect on our liquidity.

        In the normal course of business, we have other various lawsuits and related disputed claims. Although we currently believe the resolution of these lawsuits and claims, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations, our assessment

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of our current litigation and other legal proceedings could prevent stockholders from realizingchange in light of the discovery of facts with respect to legal actions or other proceedings pending against us not presently known to us or determinations by judges, juries or other finders of fact which are not in accord with our evaluation of the possible liability or outcome of such litigation or proceedings. Therefore, there can be no assurance that outcomes of future legal proceedings would not have an adverse effect on our liquidity and capital resources.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, as a premium on their investment.result of future legislation.

        The certificateFiscal Year 2013 Budget proposed by the President recommends elimination of incorporationcertain key U.S. federal income tax incentives currently available to oil and by-lawsnatural gas exploration and production companies, and legislation has been introduced in Congress which would implement many of Cimarex provide for a classified board of directors with staggered terms, restrictthese proposals. These changes include, but are not limited to, (i) the ability of stockholders to take action by written consent and prevent stockholders from calling a meetingrepeal 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.percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities, including the production of oil and gas; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

        The stockholders' rights plan, the certificatepassage of incorporation and the by-laws may have the effect of delaying, deferringthis legislation or preventing aany other similar change in control of Cimarex, even if theU.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change in control might be beneficial tocould have an adverse effect on our stockholders.financial position.

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 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.SEC's modernized rules for reporting oil and gas reserves. Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates of Cimarex are maintained by the Company'sour 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 theour 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.

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        During the course of the year, the Vice President—Corporate Engineering presents summary reserve information to Senior Management and our Board of Directors for their review. From time to time, the Vice President—Corporate Engineering will also confer with the Vice Presidents of ExplorationChief Operating Officer 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, DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviews properties representingreviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex on an annual basis.as of December 31, 2011. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over thirty-seven years of experience in oil and gas reservoir studies and evaluations.

        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 sixteenseventeen 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 servinghas served in the current role for the past sixseven years.

        DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewed greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, 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-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%76% 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 17,18, 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:

Significant Properties

        As of December 31, 2010, 85%2011, 98% of our total proved reserves were located in the Mid-Continent and Permian Basin regions. In total we owned an interest in 12,42512,701 gross (4,798(4,805 net) productive oil and gas wells.

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        The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2010.2011.

        Our ten largest producing fields hold 45%59% 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, 2010, the gross and net acres of both developed and undeveloped leases held by Cimarex.Cimarex as of December 31, 2011. 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 2011, 2010, 2009, and 2008:2009:

        We were in the process of drilling 3227 gross (26.6(11.9 net) wells at December 31, 20102011 and there were 4323 gross (23(11.2 net) wells waiting on completion.

Net Wells Drilled

        The number of net wells we drilled during calendar years 2011, 2010, 2009, and 20082009 are shown below:

Productive Wells

        We have working interests in the following productive wells as of December 31, 2010:2011:

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ITEM 3.    LEGAL PROCEEDINGS

        In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus Helmerich & Payne, Inc. ("H&P")&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. We had a judgment of $119.6 million, of which $6.9 million pertained to damages, with the remainder being disgorgement of H&P's estimated potential compounded profit since 1989 resulting from the noted 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 accruedrecorded litigation expense of $119.6 million for this lawsuit. During 2009 and 2010, weWe have accrued additional expense for associated post-judgment interest and fees of $9.4 million and $8.9 million, respectively. Wethat have appealedaccrued during the appeal of the District Court's judgments.

        In the normal course of business, we haveAdditional information regarding this and other various litigation related matters. We assess the probability of estimable amounts related to litigation mattersis included in accordance with guidance established by the FASBNote 16, Commitments and adjust our accruals accordingly. Though someContingencies of the related claims may be significant, the resolutionnotes to our consolidated financial statements included in Item 8 of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.this report.

ITEM 4.    MINE SAFETY DISCLOSURES

        Not applicable.

ITEM 4A.    EXECUTIVE OFFICERS

        The executive officers of Cimarex as of February 25, 201122, 2012 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 electedcontinues to serve as executive chairman of the board. From September 30, 2002 to September 30, 2011, Mr. Merelli served as chairman of the board, chief executive officer, and president on September 30, 2002.president. 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.

        THOMAS E. JORDEN was named president and chief executive officer effective September 30, 2011. Since December 8, 2003, Mr. Jorden served as executive vice president of exploration and had served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources.

JOSEPH R. ALBI was named executive vice president of operations onand chief operating officer effective September 30, 2011. Since March 1, 2005.2005, Mr. Albi served as executive vice president of operations. 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,

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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 named senior vice president in December 2010 after having served in a similar role as vice president and chief financial officer of Cimarex since September 2002. From June 1999 to September 2002, Mr. Korus was vice president and chief financial officer of Key Production Company. Prior to Key, he was an equity research analyst with an energy investment banking 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 was paid to shareholders in each quarter of 2010.2011. 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 18, 2011,15, 2012, was $114.62.$81.59. At December 31, 2010,2011, Cimarex's 85,234,72185,774,084 shares of outstanding common stock were held by approximately 2,7312,433 stockholders of record.

        The following graph compares the cumulative 5-year total return attained by shareholders on Cimarex Energy Co.'s common stock relative to the cumulative total returns of the S&P 500 index and the Dow Jones US Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all dividends) from 12/31/2005December 31, 2006 to 12/31/2010.December 31, 2011.

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COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Cimarex Energy Co., the S&P 500 Index
and the Dow Jones US Exploration & Production Index

*$100 invested on 12/31/0506 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.

Copyright© 20102012 S&P, a division of The McGraw-Hill Companies, Inc. All rights reserved.
Copyright© 20102012 Dow Jones & Co. All rights reserved.

        The stock price performance included in this graph is not necessarily indicative of future stock price performance.

ITEM 5C.    STOCK REPURCHASES

        In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expireexpired on December 31, 2011. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were noNo shares have been repurchased in the fourth quarter of 2010, or since the quarter ended September 30, 2007.

Issuer Purchases of Equity Securities for the Quarter Ended December 31, 2010

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ITEM 6.    SELECTED FINANCIAL DATA

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