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united states
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
securities and exchange commission
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D C 20549
Form 10-K
| (Mark One) | |
ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2007 | |
OR | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
(Mark One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
OR
oTransition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Commission file number 001-31446
CIMAREX ENERGY CO.
(Exact name of registrant as specified in its charter)
Delaware |
| |
| 45-0466694 |
1700 Lincoln Street, Suite 1800, Denver, Colorado 80203
(Address of principal executive offices including ZIP code)
(303) 295-3995
(Registrant’sRegistrant's telephone number)
Securities Registered Pursuant to Section 12(b) of the Act:
| Title of Each Class | Name of each exchange on which registered | ||||
|---|---|---|---|---|---|
Common Stock ($.01 par value) | New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES ýxNO 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 xý
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 ýxNO 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’sregistrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities ExchangeExchage Act of 1934). (Check One):
| Large accelerated filer ý | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Large accelerated filerx Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act. YES o NO xý
Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 20062007 was approximately $3,403,194,051.$3,227,233,825.
Number of shares of Cimarex Energy Co. common stock outstanding as of February 15, 20072008 was 83,245,444.82,779,666.
Documents Incorporated by Reference: Portions of the Registrant’sRegistrant's Proxy Statement for its 20072008 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS DESCRIPTION GLOSSARY Bbl/d—Barrels Bbls—Barrels (of oil) Bcf—Billioncubic feet Bcfe—Billion cubic feet equivalent MBbls—Thousand barrels Mcf—Thousand cubic feet (of natural gas) Mcfe—Thousand cubic feet equivalent MMBbls—Million barrels MMBtu—Million British Thermal Units MMcf—Million cubic feet MMcf/d—Million cubic feet per day MMcfe—Million cubic feet equivalent MMcfe/d—Million cubic feet equivalent per day Net Net Production—Gross production multiplied by net revenue interest NGL—Natural gas liquids Tcf—Trillion cubic feet Tcfe—Trillion cubic feet equivalent One barrel of oil is the energy equivalent of six Mcf of natural gas. Forward-Looking Statements Throughout this Form 10-K, we make statements that may be deemed 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. General Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana and Our corporate headquarters are located at 1700 Lincoln Street, Suite 1800, Denver, Colorado 80203 and our main telephone number at that location is (303) 295-3995. Our Web site address is During 2007 we accomplished the following highlights: Cimarex, a Delaware corporation, 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 On June 7, 2005, we acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger plus assumption of Business Strategy Our principal business objective is to A cornerstone to our approach is detailed evaluation of each drilling decision based on its risk-adjusted discounted During While our primary focus is drilling, we We also periodically divest selected assets that we no longer deem important to our ongoing operations. During 2007, we sold properties with estimated proved reserves of 123 Bcfe, or about eight percent of our beginning of the year reserves. Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet enables us to carry on a consistent drilling program and pursue acquisition and other opportunities, when conditions warrant. Our year-end 2007 debt to total capitalization ratio was 13 percent. Business Segments Cimarex has one reportable segment (exploration and production). Exploration and Development Activity Overview Our operations are currently focused in the Mid-Continent region which consists of Oklahoma, the Texas Panhandle and southwest Kansas; the Permian Basin region of west Texas and southeast New Mexico; and the A summary of our Exploration Gross Net Wells Completion 12/31/06 (in millions) Mid-Continent $ 350 302 186 97 % 595 Permian Basin 331 167 119 96 % 563 Gulf Coast 211 49 28 65 % 105 Gulf of Mexico 128 16 6 44 % 44 Western/Other 29 24 7 71 % 142 $ 1,049 558 346 91 % 1,449 Company-wide, we participated in drilling Our Mid-Continent Our Mid-Continent operations We drilled We drilled We also have a large inventory of recompletion, workover and in-fill drilling locations in Permian Basin Southeast New Mexico drilling totaled In West Texas, a total of Gulf Coast Our onshore Gulf Coast focus area generally encompasses coastal Texas, south Louisiana and Mississippi. During Production and Pricing Information The following table sets forth certain information regarding the Years Ending December 31, 2006 2005 2004 Production Volumes Gas (MMcf) 124,733 100,272 63,611 Oil (MBbls) 6,529 4,804 2,641 Equivalent (MMcfe) 163,907 129,096 79,457 Net Average Daily Volumes: Gas (MMcf) 341.7 274.7 173.8 Oil (MBbl) 17.9 13.2 7.2 Equivalent (MMcfe) 449.1 353.7 217.1 Average Sales Price Gas ($/Mcf) $ 6.50 $ 8.05 $ 5.76 Oil ($/Bbl) $ 61.96 $ 55.25 $ 40.19 per MMBtu. For a discussion of derivatives, see Note 5 of Notes to Consolidated Financial Statements contained herein. The following table summarizes 2006 Average Daily Production Second-half Oil Gas Total 2005 Avg. Mid-Continent 4.7 152.5 180.7 175.3 Permian Basin 8.1 83.8 132.4 130.1 Gulf Coast 3.2 61.8 80.7 84.4 Gulf of Mexico 1.6 36.2 45.9 37.9 Other 0.3 7.4 9.4 10.5 17.9 341.7 449.1 438.2 Our largest producing area is the Mid-Continent region which averaged Cimarex in the Permian Basin 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 largest customer accounted for We employed 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 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, Oil and gas production and transportation is subject to Environmental Regulation.Various 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 aniticipate 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 Under the Natural Gas Policy Act (NGPA), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes 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 The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current and future investors in our securities. If any of the following risks and uncertainties develop into actual events, this could have a material adverse affect on our business, financial condition or results of operations and could negatively impact the value of our common stock. Our revenues and results of operations are highly dependent on oil and gas prices. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Historically, oil and gas prices have fluctuated widely. For example, in The volatility in oil and gas prices limits the predictability of the prices, which directly impacts future development plans and operations. If prices decline, future earnings would be reduced and growth could be adversely affected. In recent years, oil prices have responded to changes in supply and demand stemming from actions taken by the Organization of Petroleum Exporting Countries, worldwide economic conditions, growing transportation and power generation needs, and other events. Factors affecting gas prices have included domestic supplies; the level and price of natural gas imports into the U.S.; weather conditions; the economy and the price and level of alternative sources of energy such as renewable energy assets, nuclear power, hydroelectric power, coal, and other petroleum products. Our proved oil and gas reserves and production volumes will decrease in quantity unless we successfully replace the reserves we produce with new discoveries or acquisitions. For the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves to replace the reserves we produce and to increase our total proved reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations. Our use of hedging arrangements could result in financial losses or reduce our income. To reduce our exposure to fluctuations in natural gas prices, from time to time we In July 2006, using zero-cost collars with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 80,000 MMBtu per day for 2007 and 40,000 MMBtu per day for 2008. Though associated volumes for the existing contracts are significantly less than our overall production, hedging arrangements could limit the benefit we would otherwise receive from increases in natural gas prices. Failure of our exploration and development program to find commercial quantities of new oil and gas reserves could negatively affect our financial results and future rate of growth. Most of our wells produce from reservoirs characterized by high 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. The high-rate production characteristics of our properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves. Unless we conduct successful development activities or acquire properties containing proved reserves, our proved reserves will decline as they are produced. Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Because of the high-rate production profiles of our properties, replacing produced reserves is more difficult for us than for companies whose reserves have longer-life production profiles. This imposes greater reinvestment risk for our company as we may not be able to continue to economically replace our reserves. Our proved reserve estimates may be inaccurate and future net cash flows are uncertain. Estimates of total proved oil and gas reserves (consisting of proved developed and The estimation of the category of proved undeveloped reserves can be subject to an even greater possibility of revision. At December 31, 2007, 21.4 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 62 percent are related to a project in Wyoming. Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent petroleum engineers, reviewed our reserve estimates for properties that comprised at least 80 percent of the discounted future net cash flows before income taxes, using a 10 percent discount rate, as of December 31, The values referred to in this report should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash flow from proved reserves is based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different. The marketability of our oil and natural gas production depends in large part Competition in our industry is intense and many of our competitors have greater financial and technological resources. We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business. Exploration, development, production and sale of oil and gas are subject to extensive Federal, state and local laws and regulations, including complex environmental laws. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection, and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable. Such liabilities and costs could have a material adverse effect on our financial condition and results of operations. Our limited ability to influence operations and associated costs on properties not operated by us could result in economic losses that are partially beyond our control. Other companies operate approximately of capital expenditures, the 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, 2007, we had total long-term debt of $487.2 million, consisting of $350 million of unsecured 7.125% Senior Notes and $137.2 million of Convertible Notes ($125 million face value). Subject to the limits contained in the agreements governing our senior revolving credit facility, we would have been able to incur up to $1 billion of debt as of December 31, 2007, only $500 million of which is currently committed. We have 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 We have outstanding $125 million of Convertible Notes (face value) that mature on December 15, 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: 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. Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations. We evaluate opportunities and engage in bidding and negotiating for acquisitions, some of which are substantial. Under certain circumstances, we may pursue acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be successful in identifying or acquiring any material property interests, which could hinder us in replacing our reserves and adversely affect our financial results and rate of growth. Even if we do identify attractive opportunities, there is no assurance that we will be able to complete the acquisition of the business or prospect on commercially acceptable terms. If we do complete an acquisition, we must anticipate difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses. Competition for experienced, technical personnel may negatively impact our operations. Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. In particular, our Chairman and Chief Executive Officer, F.H. Merelli, has over 45 years of oil and gas experience and is well known in the industry. The loss of his services for any reason could adversely affect our business, revenues and results of operations. As we continue to grow our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering and operations. There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected. While limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a control system, misstatements due to error or fraud may occur and not be detected. The Cimarex certificate of incorporation, by-laws and 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 None. Oil and Gas Properties and Reserves All of our proved reserves and undeveloped acreage are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests. We operate the wells that comprise Our engineers estimate our proved oil and gas reserve quantities in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewed our reserve estimates for those properties that comprised at least 80 percent of the discounted value of the projected future net cash flow before income taxes as of December 31, information. The following table sets forth the present value and estimated volume of our oil and gas proved reserves: Years Ending December 31, 2006 2005 2004 Total Proved Reserves— Gas (MMcf) 1,090,362 1,004,482 364,641 Oil, condensate and NGLs (MBbls) 59,797 64,710 14,063 Equivalent (MMcfe) 1,449,146 1,392,742 449,020 Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands) $ 2,200,889 $ 3,028,100 $ 798,033 Average price used in calculation of future net cash flow— Gas ($/Mcf) $ 5.54 $ 7.89 $ 5.58 Oil ($/Bbl) $ 56.91 $ 57.65 $ 40.76 As of December 31, The following table summarizes our estimated proved oil and gas reserves by region as of December 31, Oil Gas Equivalent Percent of Mid-Continent 8,709 542,447 594,701 41 % Permian Basin 44,351 296,969 563,076 39 % Gulf Coast 4,671 76,640 104,663 7 % Gulf of Mexico 964 38,111 43,895 3 % Western/Other 1,102 136,195 142,811 10 % 59,797 1,090,362 1,449,146 100 % Our ten largest producing fields hold Field Region % of Total Avg. Avg. Depth Primary Formation Hugoton Mid-Continent 4.3 % 59 % 2,600 Chase Hemphill Mid-Continent 4.1 % 95 % 11,000 Granite Wash Panhandle East Mid-Continent 3.5 % 98 % 2,400 Brown Dolomite Eola-Robberson Mid-Continent 3.2 % 95 % 5,500-11,000 Bromide/McLish/Oil Creek Carlsbad South Permian 2.8 % 58 % 11,500 Morrow/Atoka Red Deer Creek Mid-Continent 2.8 % 47 % 11,000 Granite Wash Quail Ridge Permian 2.6 % 59 % 13,000 Morrow Jo-Mill Permian 2.5 % 13 % 7,500 Spraberry Mendota NW Mid-Continent 2.3 % 71 % 11,000 Granite Wash Westbrook Permian 2.1 % 90 % 3,500 Clearfork 30.2 % Acreage The following table sets forth as of December 31, Undeveloped Acreage Developed Acreage Total Acreage Gross Net Gross Net Gross Net Mid-Continent Kansas 3,480 2,415 158,391 105,601 161,871 108,016 Oklahoma 103,772 85,182 395,645 168,255 499,417 253,437 Texas 144,826 106,218 232,402 110,785 377,228 217,003 252,078 193,815 786,438 384,641 1,038,516 578,456 Permian Basin New Mexico 86,178 64,943 144,645 94,115 230,823 159,058 Texas 53,794 37,850 232,664 156,045 286,458 193,895 139,972 102,793 377,309 250,160 517,281 352,953 Gulf Coast Louisiana 22,063 17,114 21,521 6,356 43,584 23,470 Texas 81,473 33,938 164,734 61,674 246,207 95,612 Mississippi 6,027 3,779 25,583 6,539 31,610 10,318 109,563 54,831 211,838 74,569 321,401 129,400 Gulf of Mexico 711,140 438,125 324,614 110,709 1,035,754 548,834 Western/Other Arkansas — — 6,719 2,115 6,719 2,115 Arizona 914,695 914,695 — — 914,695 914,695 California 35,715 30,678 8,770 6,752 44,485 37,430 Colorado 96,690 6,759 26,497 6,498 123,187 13,257 Illinois 1,782 1,191 554 183 2,336 1,374 Indiana 175 175 344 310 519 485 Michigan 31,803 31,686 549 549 32,352 32,235 Montana 49,449 16,298 18,858 7,735 68,307 24,033 Nebraska 4,560 116 2,118 168 6,678 284 Nevada 160 1 560 1 720 2 New Mexico 1,649,340 1,621,646 13,574 2,281 1,662,914 1,623,927 North Dakota 64,741 18,152 25,818 2,706 90,559 20,858 South Dakota 10,583 9,329 2,420 379 13,003 9,708 Utah 120,625 63,621 20,159 2,223 140,784 65,844 Wyoming 252,551 31,542 118,416 24,239 370,967 55,781 3,232,869 2,745,889 245,356 56,139 3,478,225 2,802,028 4,445,622 3,535,453 1,945,555 876,218 6,391,177 4,411,671 We participated in drilling the following number of gross wells during calendar years 2007, 2006, Exploratory Developmental Productive Dry Total Productive Dry Total Year ended December 31, 2006 20 32 52 490 16 506 Year ended December 31, 2005 55 20 75 283 24 307 Year ended December 31, 2004 12 11 23 177 21 198 We were in the process of drilling 30 gross The number of net wells we drilled during calendar years 2007, 2006, Exploratory Developmental Productive Dry Total Productive Dry Total Year ended December 31, 2006 12.4 23.9 36.3 303.7 6.2 309.9 Year ended December 31, 2005 33.2 15.6 48.8 144.8 16.8 161.6 Year ended December 31, 2004 6.8 6.5 13.3 78.8 12.1 90.9 We have working interests in the following productive wells as of December 31, Gas Oil Gross Net Gross Net Mid-Continent 3,396 1,721 1,017 529 Permian 1,023 557 6,109 1,629 Gulf Coast 525 138 186 91 Gulf of Mexico 124 27 38 6 Western/Other 144 24 632 35 5,212 2,467 7,982 2,290 As of December 31, 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 The executive officers of Cimarex as of February F.H. Merelli Chairman of the Board, Chief Executive Officer, and President Joseph R. Albi Executive Vice President, Operations Thomas E. Jorden Executive Vice President, Exploration Stephen P. Bell Senior Vice President, Business Development and Land Paul Korus Vice President, Chief Financial Officer, and Treasurer Gary R. Abbott Vice President, Corporate Engineering Richard S. Dinkins Vice President, Human Resources James H. Shonsey Vice President, Chief Accounting Officer, and Controller There are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he was selected as an executive officer. F.H. MERELLIwas 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. ALBIwas 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. JORDENwas named executive vice president of exploration on December 8, 2003 and has served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as vice president of exploration (October 1999 to September 2002) and chief geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources. STEPHEN P. BELLwas 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 KORUSwas elected vice president, chief financial officer and treasurer on September 30, 2002. Mr. Korus was vice president and chief financial officer of Key Production Company, Inc. from September 1999 to September 2002. Prior to September 1999 and since June 1995, Mr. Korus was an equity research analyst with Petrie Parkman & Co., an investment banking firm. GARY R. ABBOTTwas 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. DINKINSwas 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. SHONSEYwas 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. ITEM 5. MARKET FOR THE 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. 2006 High Low Dividends First Quarter First Quarter $ 47.80 $ 39.21 $ .04 Second Quarter Second Quarter $ 47.40 $ 35.84 $ .04 Third Quarter Third Quarter $ 43.03 $ 33.57 $ .04 Fourth Quarter Fourth Quarter $ 38.46 $ 32.56 $ .04 2005 High Low Dividends First Quarter $ 42.56 $ 34.48 $ .00 Second Quarter $ 40.55 $ 33.82 $ .00 Third Quarter $ 45.98 $ 38.30 $ .00 Fourth Quarter $ 46.31 $ 35.85 $ .00 The closing price of Cimarex stock as reported on the New York Stock Exchange on February 15, In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. Through December 31, Period Total Number of Average December 1, 2005 to December 31, 2006 250,100 $ 44.05 ITEM 6. SELECTED FINANCIAL DATA The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto provided in Item 8 of this Form 10-K. For the Years Ended December 31, 2006 2005 2004 2003 2002 Operating results: Revenues $ 1,267,144 $ 1,118,622 $ 475,164 $ 325,621 $ 160,620 Net income 345,719 328,325 153,592 94,633 39,819 Basic earnings per share 4.21 5.07 3.70 2.28 1.32 Diluted earnings per share 4.11 4.90 3.59 2.22 1.31 Cash dividends declared per share .16 — — — — Balance sheet data: Total assets 4,829,750 4,180,335 1,105,446 805,508 674,286 Total debt 443,667 352,451 — — 32,000 Stockholders’ equity 2,976,143 2,595,453 700,712 534,740 444,880 Other financial data: Oil and gas sales 1,215,411 1,072,422 472,389 324,119 157,299 Oil and gas capital expenditures 1,074,673 2,462,826 296,429 162,627 368,503 Proved Reserves: Gas (MMcf) 1,090,362 1,004,482 364,641 337,344 318,627 Oil (MBbls) 59,797 64,710 14,063 14,137 15,025 Total equivalent (MMcfe) 1,449,146 1,392,742 449,020 422,167 408,779 ITEM 7. We are an independent oil and gas exploration and production company with operations In 2007, we achieved the following financial and operating results: We seek to achieve profitable growth in proved reserves and production primarily through exploration and development. We generally fund our growth with cash flow provided by our operating activities. To achieve a consistent rate of growth and mitigate risk, we maintain a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. Our oil and gas reserves and operations are mainly located in Texas, Oklahoma, From time to time we also consider selling certain assets. During 2007, we sold $177.0 million of non-core properties. The While our revenues are a function of both production and prices, wide swings in prices On an energy equivalent basis, 73% of our 2007 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a $12 million change in our gas revenues. Similarly 27% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in approximately a $7.4 million change in our oil revenues. To mitigate a portion of our exposure to potentially adverse gas market changes, in July 2006 we entered into certain derivative contracts covering approximately 24% of our overall 2007 gas production and about 12% of our estimated 2008 gas volumes. We executed cash flow effective hedges by purchasing $7.00/MMbtu put options on a portion of our 2007 and 2008 Mid-Continent gas production. We used the proceeds from selling call options on the same volume of gas to pay for the puts, thus establishing what is commonly known as a "zero-cost collar." We hedged 29.2 million MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. See Note 5 to the Consolidated Financial Statements and Item 7A of this report for additional information regarding our derivative instruments. Reserve replacement and Growth Because oil and gas are non-renewable forms of energy resources, exploration and production companies face the challenge of resource depletion and natural production decline. Our operations also entail significant In 2007 our total proved The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, In most years our primary source for reserve replacement and growth is exploration and development (E&D). We Cash flow from operating activities for 2007 totaled $994.7 million, which more than funded our drilling program. Based on expected cash flow provided by operating activities, cash on hand and monies available under our bank credit facility, we are well positioned to fund the capital program we have planned for 2008. Production and other operating expenses The costs associated with finding and producing oil and gas wells we own. At the end of Production expense generally consists of the Transportation expense is and in other instances we separately pay for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and expenses, respectively. Depreciation, depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method. Because the economic life of each producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense. General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad valorem and excise taxes. Significant expenses that generally do not trend with production Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees and the expensing of stock options resulting from the adoption of SFAS No. The derivative fair value (gain) loss is the net realized and unrealized gain or loss on derivative financial instruments that do not qualify for hedge accounting treatment and fluctuates based on changes in the fair value of underlying commodities. As of December 31, 2006 all contracts associated with derivative instruments that did not qualify for hedge accounting treatment had settled. The net derivative fair value gain was $23.0 million in 2006 compared to a loss of $67.8 million in 2005. RESULTS OF OPERATIONS 2007 compared to 2006 Net income for 2007 was $346.5 million, or $4.09 per diluted share. This compares to net income of $345.7 million, or $4.11 per diluted share in 2006. The small change in year-over-year net income is generally the result of higher oil and gas sales being offset by higher costs and expenses. Oil and gas sales during 2007 totaled $1.4 billion, compared to $1.2 billion in 2006. Of the $149.2 million increase in sales between the two periods, $25.6 million related to higher production volumes and $123.7 million resulted from higher prices. Compared to 2006, our 2007 oil production increased by 14% to an average of 20,399 barrels per day in 2007. This increase resulted in $56.8 million of incremental revenues. Gas volumes averaged 328.6 MMcf per day in 2007 compared to 341.7 MMcf per day in 2006, resulting in a decrease in revenues of $31.2 million. Total 2007 oil and gas production volumes were 451 MMcfe per day, up 2 MMcfe per day from 2006. Both our gas and oil volumes increased as 2007 unfolded. During the fourth quarter of 2007 our gas production averaged 341.1 MMcf per day up from 329.4 MMcf per day (a 4% increase) in the fourth quarter of 2006. Fourth quarter oil production increased by 17% to 21,680 barrels per day, up from 18,587 barrels per day in 2006. Average realized gas prices increased by 8% to $7.05 per Mcf in 2007, compared to $6.50 per Mcf for 2006. This price increased boosted gas sales by $65.9 million between the two periods. Included in our 2007 realized gas price is $27.8 million of cash receipts (a positive $0.23 per Mcf effect) from settlement of cash flow hedges on 80,000 MMBtu per day of Mid-Continent gas production. We currently have 40,000 MMBtu per day of our Mid-Continent gas production hedged for 2008 at a floor price of $7.00/MMBtu. Realized oil prices averaged $69.71 per barrel during 2007, compared to $61.96 per barrel in 2006. The increase in oil sales resulting from this 13% improvement in oil prices totaled $57.7 million. Changes in realized gas and oil prices were mostly the result of overall market conditions and our modest gas hedging program. We did not have any cash flow effective hedges in place for 2006 volumes. We sometimes transport, process and market third-party gas that is associated with our gas. In 2007, third-party gas gathering and processing contributed $31 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $20.5 million in 2006. Our gas marketing margin (revenues less purchases) increased to $5.1 million in 2007 from $3.9 million in 2006. Increases in net margins from gas gathering, processing and marketing activities are the direct result of increased volumes and overall market conditions. Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $858.9 million in 2007 compared to $722.1 million in 2006. DD&A was the largest component of the increase between periods. DD&A equaled $461.8 million in 2007 compared to $396.4 million in 2006. On a unit of production basis, DD&A was $2.81 per Mcfe in 2007 compared to $2.42 per Mcfe for 2006. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been increasing and we are drilling deeper and more complex wells. Production costs rose $24.7 million from $176.8 million ($1.08 per Mcfe) in 2006 to $201.5 million ($1.22 per Mcfe) in 2007. We have experienced higher direct labor cost, higher third-party field service costs, increased electricity rates and greater water disposal costs. Transportation costs increased from $21.2 million in 2006 to $26.4 million in 2007. The increase is the result of higher sales volumes and that expiring contracts are being renewed with increased current market rates. In 2007, the increase in Other operating, net to $6.6 million from $2.1 million was primarily related to resolution of and accruals related to title and royalty issues. Another component of change in total operating costs and expenses between 2007 and 2006 stems from the $23 million derivative fair value gain we recognized in 2006. This gain was associated with price risk management contracts that were not designated for hedge accounting. These contracts all expired on December 31, 2006. Other income and expense Interest expense increased by $8 million, or 27%, primarily because of a 10% increase in our total debt outstanding at an average interest rate of 7.1%. Capitalized interest decreased by $4.6 million mainly because we are carrying less value associated with unproved properties than we were in 2006. We also had a gain in 2007 on the early extinguishment of debt arising from redemption of our $195 million face value of old 9.6% senior unsecured notes. We replaced the old notes with new ten-year, 7.125% senior unsecured notes. Other, net decreased from $28.6 million of income in 2006 to $14.2 million of income in 2007. Components consist of miscellaneous income and expense items that will vary from period to period, including income and loss in equity investees, gain or loss on sale of inventory and interest income. The decrease from 2006 to 2007 is due primarily to the 2006 liquidation of the Company's investment in the Company's limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. Excess distributions of $19.8 million from this liquidation were recorded during 2006. In 2007 we received an additional distribution from this liquidation in the amount of $3.0 million. Income tax expense Income tax expense totaled $198.2 million for 2007 versus $198.6 million for 2006. Tax expense equaled a combined federal and state effective income tax rate of 36.4% and 36.5% in 2007 and 2006, respectively. Included in the 2007 income tax expense of $198.2 million was a current tax expense of $30.6 million. RESULTS OF 2006 compared to 2005: For the Years Ended December 31, 2006 2005 Net income $ 345,719 $ 328,325 Per share—basic 4.21 5.07 Per share—diluted 4.11 4.90 Gas sales $ 810,894 $ 807,007 Oil sales 404,517 265,415 Total oil and gas sales $ 1,215,411 $ 1,072,422 Total gas volume—Mcf 124,733 100,272 Gas volume—MMcf per day 341.7 274.7 Average gas price—per Mcf $ 6.50 $ 8.05 Total oil volume—thousand barrels 6,529 4,804 Oil volume—barrels per day 17,887 13,162 Average oil price—per barrel $ 61.96 $ 55.25 Gas gathering and processing revenues $ 47,879 $ 44,238 Gas gathering and processing costs (27,410 ) (31,890 ) Gas gathering and processing margin $ 20,469 $ 12,348 Gas marketing revenues, net of related costs $ 3,854 $ 1,962 Expenses and other income: Depreciation, depletion and amortization $ 396,394 $ 258,287 Production 176,833 104,067 Transportation 21,157 15,338 Taxes other than income 91,066 73,360 General and administrative 42,288 33,497 Stock compensation 8,243 4,959 Other operating, net 2,064 15,897 (Gain) Loss on derivative instruments (22,970 ) 67,800 Int. exp., net of cap. int. & amort. of F.V. of debt 1,908 5,789 Asset retirement obligation accretion 7,018 3,819 Other, net (28,591 ) (12,536 ) Net income for the year Oil and gas sales for the year Sales benefited from higher production volumes. Average daily gas production rose 67.0 MMcf in 2006 to 341.7 MMcf from 274.7 MMcf in 2005, resulting in $197.0 million of incremental revenues. Oil volumes averaged 17,887 barrels per day for 2006, compared to 13,162 barrels per day in 2005, resulting in increased revenues of $95.0 million. The increase in sales volumes between the periods of 2006 and 2005 is due to the inclusion of Magnum Hunter operations beginning June 7, 2005 (date of acquisition) and positive drilling results during 2005 and 2006. Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted during the fourth quarter of 2005 as a result of hurricanes. It is estimated to have negatively impacted fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day. These volumes were brought back online throughout 2006, and by the fourth quarter of 2006 less than one MMcf equivalent per day was shut-in from the 2005 hurricane activity. No oil and gas reserves have been lost as a result of the storms and the majority of associated repair costs will be covered by insurance. Realized gas prices averaged $6.50 per Mcf for 2006, compared to $8.05 per Mcf for 2005. This Depreciation, depletion and amortization (DD&A) was the largest component of the increase between periods. DD&A equaled $396.4 million in 2006 compared to $258.3 million in 2005. On a unit of production basis, DD&A was $2.42 per Mcfe in 2006 compared to $2.00 per Mcfe for 2005. The increase stems from higher costs for reserves added during 2005 and 2006. Service costs to drill and complete wells have been increasing. That along with certain high cost dry holes in our Gulf Coast and Gulf of Mexico regions have influenced our per unit rates, even though overall drilling success rates have remained high. Asset retirement obligation increased $3.2 million from $3.8 million in 2005 to $7.0 million in 2006. The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Since 2005 the liability has increased $28.0 million from $101.1 million in 2005 to $129.1 million in 2006. Production costs rose $72.7 million from $104.1 million ($.81 per Mcfe) in 2005 to $176.8 million ($1.08 per Mcfe) in 2006. The higher costs in 2006 resulted from higher field operating expenses from an expanded number and type of properties, higher maintenance costs and increased insurance costs due to past hurricanes. Additional workover/maintenance projects were implemented in 2006, totaling $28.9 million ($0.18 per Mcfe) compared to $11.6 million ($0.09 per Mcfe) in 2005. Transportation costs increased from $15.3 million in 2005 to $21.2 million in 2006. The increase is the result of higher sales volumes and that expiring contracts are being renewed with increased current market rates. Taxes other than income were $17.7 million greater, rising from $73.4 million in 2005 to $91.1 million in 2006. The increase between periods resulted from increases in oil and gas sales stemming from higher production volumes and oil prices. General and administrative (G&A) expenses increased $8.8 million from $33.5 million in 2005 to $42.3 million in 2006. The increase between periods is due to an expansion of staff and higher employee-benefit costs. Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards. Stock compensation increased from $5.0 million in 2005 to $8.2 million in 2006. Other operating, net decreased from $15.9 million in 2005 to $2.1 million in 2006. These expenses in 2005 consisted primarily of $9.4 million of costs associated with the Magnum Hunter merger. Of this $9.4 million, $3.6 million is due to the acceleration of vesting of stock options and restricted stock units resulting from change of control provisions under our stock incentive plan becoming effective due to the Magnum Hunter merger. The remaining $5.8 million consists of $4.3 million of general integration costs, $1.0 million for retention bonuses, and $0.5 million of related financing costs. In addition to merger costs, 2005 expenses also included a mediated $6.5 million litigation settlement pertaining to post-production deductions on properties operated by Cimarex. Other expense for 2006 included $2.1 million of litigation settlements pertaining primarily to resolution of oil and gas property title issues. Another component of Net interest expense in 2006 totaled $1.9 million, comprised of $29.9 million of interest expense, offset by $24.2 million of capitalized interest and $3.8 million of amortization of fair value of debt. We capitalize interest related to borrowings associated with costs incurred to bring properties under development, not being amortized, to their intended use. This has decreased from $5.8 million of net interest expense in 2005, which was comprised of $19.6 million of interest expense, offset by $11.7 million of capitalized interest and $2.1 million of amortization of fair value of debt. The increases in the components of the 2006 net interest amount results from amounts associated with the debt assumed in the Magnum Hunter merger and an increase in costs incurred to bring properties under development, not being amortized, to their intended use. Prior to the Magnum Hunter merger, Cimarex had no outstanding debt. Other, net increased from $12.5 million of income in 2005 to $28.6 million of income in 2006. The components of this other income net of other expenses consist of miscellaneous items that will vary from period to period, including income and loss in equity investees. The large increase from 2005 to 2006 is due primarily to distribution received in excess of our investment in the Income tax expense Income tax expense totaled $198.6 million for 2006 versus $188.1 million for 2005. Tax expense equaled a combined federal and state effective income tax rate of For the Years Ended December 31, 2005 2004 Net income $ 328,325 $ 153,592 Per share—basic 5.07 3.70 Per share—diluted 4.90 3.59 Gas sales $ 807,007 $ 366,260 Oil sales 265,415 106,129 Total oil and gas sales $ 1,072,422 $ 472,389 Total gas volume—MMcf 100,272 63,611 Gas volume—MMcf per day 274.7 173.8 Average gas price—per Mcf $ 8.05 $ 5.76 Total oil volume—thousand barrels 4,804 2,641 Oil volume—barrels per day 13,162 7,215 Average oil price—per barrel $ 55.25 $ 40.19 Gas gathering and processing revenues $ 44,238 $ 101 Gas gathering and processing costs (31,890 ) (284 ) Gas gathering and processing margin $ 12,348 $ (183 ) Gas marketing revenues, net of related costs $ 1,962 $ 2,674 Costs and expenses: Depreciation, depletion and amortization $ 258,287 $ 124,251 Production 104,067 37,476 Transportation 15,338 10,003 Taxes other than income 73,360 37,761 General and administrative 33,497 22,483 Stock compensation 4,959 1,957 Other operating, net 15,897 (3,394 ) Loss on derivative instruments 67,800 — Int. exp., net of cap. int. & amort. of F.V. of debt 5,789 1,075 Asset retirement obligation accretion 3,819 1,241 Other, net (12,536 ) (4,291 ) LIQUIDITY AND CAPITAL RESOURCES Our primary Exploration and development expenditures and dividend payments have generally been funded by cash flow provided by operating activities. Analysis of Cash flow provided by operating activities for Cash flow used in investing activities for Net cash flow used in financing activities in 2007 was $1.3 million versus $74.8 million provided in 2006. Two significant uses were for share repurchases of $42.3 million and $13.4 million for dividends. Proceeds from our May 2007 issuance of $350 million of ten-year, 7.125% senior unsecured notes were used to redeem our old 9.6% notes and reduce outstanding borrowings under our credit facility. Cash flow provided by financing activities in 2006 was $74.8 million versus $261.4 million used in 2005. The cash provided by financing activities in 2006 resulted primarily from the borrowing of $95.0 million on our credit facility. The cash used in financing activities in 2005 resulted primarily from the payment of debt (including $3.5 million of capital lease debt) assumed in the Magnum Hunter acquisition, offset by proceeds from issuance of common stock from stock option exercises. Capital Expenditures The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, exploration, and development activities (in thousands): Property acquisitions in 2007 and 2006 primarily relate to various producing properties and exploratory nonproducing leases. The acquisitions in 2005 relate primarily to the purchase of Magnum Hunter. We have experienced significant service and material cost inflation over the past three years. We are starting to see a flattening of drilling and services costs and expect to see this remain dependent upon commodity prices. Our exploration and development expenditures decreased six percent in 2007 compared to 2006. The decrease in 2007 resulted primarily from a decrease in exploration activity in the Gulf of Mexico. Exploration and development expenditures increased 63% in 2006 compared to 2005. The increase in 2006 resulted from a larger exploration and development program. We drilled 558 gross wells in 2006 compared to 382 gross wells in 2005. We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact. Our 2007 exploration and development drilling program is discussed inExploration and Development Activity Overview under Item 1 of this Form 10-K. Financial Condition Total assets increased by $0.5 billion in 2007 from $4.8 billion at the beginning of the year to reach $5.3 billion by year end. Our net oil and gas assets increased by $0.4 billion, primarily because of our drilling program, and our cash position increased by $118 million as a result of property sales that closed during December. As of December 31, Dividends In December 2005, the Board of Directors declared the Common Stock Repurchase Program In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. Working Capital Working capital increased $77.8 million from year-end 2006 to $140.0 million at year-end 2007. Working capital increased primarily because of the following. These working capital increases were partially offset by an increase Our receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been significant. Financing Debt at December 31, Bank debt $ — 9.6% Notes due 2012 (face value $195,000) 213,770 (1) Floating rate convertible notes due 2023 (face value $125,000) 138,681 (2) Total long-term debt $ 352,451 Bank debt $ 95,000 9.6% Notes due 2012 (face value $195,000) 210,746 (1) Floating rate convertible notes due 2023, 5.36% at December 31, 2006 (face value $125,000) 137,921 (2) Total long-term debt $ 443,667 The The 9.6% notes assumed in the Magnum Hunter merger Also in May 2007 we sold $350 million of new 7.125% senior unsecured notes that will mature May 1, 2017. The notes were sold to the public at par. Net proceeds from the sale were used to redeem the 9.6% notes and reduce borrowings under our credit facility. Interest on the new notes is payable May 1 and November 1 of each year. The first interest payment was made on November 1, 2007. The notes are Year Percentage 2007 104.8 % 2008 103.2 % 2009 101.6 % 2010 and thereafter 100.0 % At any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price equal to 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium. If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase. The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. On December 31, Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On December In addition to the Contractual Obligations and Material Commitments At December 31, Payments Due by Period Contractual obligations Total Less than 1-3 3-5 More than (In thousands) Long-term debt(1) Long-term debt(1) $ 415,000 $ — $ — $ 95,000 $ 320,000 Fixed-Rate interest payments(1) Fixed-Rate interest payments(1) 102,960 18,720 37,440 37,440 9,360 Operating leases Operating leases 31,278 5,158 10,074 7,868 8,178 Drilling commitments Drilling commitments 55,322 55,322 — — — Asset retirement obligation(2) 129,141 4,320 — — — Other liabilities Other liabilities 5,932 202 67 51 5,612 (of (of oil) per day(of oil)barrelsbarrelsAcres���Acres—Gross acreage multiplied by working interest percentage“forward-looking”"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’smanagement'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;·······the Gulf of Mexico.Wyoming. Proved oil and gas reserves as of year-end 20062007 totaled nearly 1.451.5 Tcfe, consisting of 1.1 Tcf of gas and 59.858.3 million barrels of oil and natural gas liquids. Of total proved reserves, 7576 percent are gas and 8079 percent are classified as proved developed. We operate the wells that account for 7382 percent of our total proved reserves and approximately 7079 percent of production.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, Cimarex acquired Dallas-based Magnum Hunter Resources, Inc. in a $1.5 billion stock-for-stock merger plus assumption of liabilities. Proved reserves acquired totaled 886.7 billion cubic feet equivalent (Bcfe), of which 60 percent were gas and 73 percent proved developed. The transaction effectively tripled our proved reserves and doubled our production. www.cimarex.com.www.cimarex.com. There you will find our news releases, annual reports, proxy statements, 10-Ks, 10-Qs, 8-Ks, insider (Section 16) filings and all other SEC filings. We have also posted our Code of Ethics, Code of Business Conduct, Corporate Governance Guidelines, Audit Committee Charter and Governance Committee Charter. Copies of these documents are also available in print upon a written or telephone request to our Corporate Secretary. Throughout this Form 10-K we use the terms "Cimarex," "Company," "we," "our," and "us" to refer to Cimarex Energy Co. and its subsidiaries.Business StrategyHistorybasic business approach is centeredcommon stock began trading on profitable reinvestmentthe New York Stock Exchange on October 1, 2002 under the symbol XEC.the cash flow generated byliabilities. That transaction effectively tripled our producing properties in drilling new wells that have the potential to grow our production and proved reserves and doubled our production.add valueprofitably grow our proved reserves and production for the long-term benefit of our investors. Our strategy centers on continually expanding our drilling program and maximizing cash flow from our production. after-tax cash flow rate of return on investment. Our analysis includes estimates and assessments of potential reserve size, geologic and mechanical risks, expected costs and future production profiles.2006,2007, we drilled 558452 gross wells and invested $1,049$983 million on exploration and development. Our integrated teams of geoscientists, landmen and petroleum engineers continually generate new prospects to maintain a rolling portfolio of drilling opportunities in different basins with varying geologic characteristics. We have a centralized exploration management system that measures actual results and provides feedback about drilling results to the originating exploration teamsteam in order to help them improve and refine future investment decisions. We believe that our detailed technical analysis and disciplined risk assessment is a competitive advantage and best positions us to continue to achieve attractive economic rates of return and consistent increases in proved reserves and production.dooccasionally 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. upper Gulf Coast areas of Texas, south Louisiana, and Mississippi;offshore Louisiana. We also have operations in Michigan and the Gulf of Mexico.Wyoming.20062007 exploration and development activity by region is as follows.
and
Development
Capital
Wells
Drilled
Drilled
Rate
Proved
Reserves
(Bcfe) Exploration
and
Development
Capital Gross
Wells
Drilled Net Wells
Drilled Completion
Rate 12/31/07
Proved
Reserves
(Bcfe) (in millions) $ 385 237 134 95 % 617 368 172 118 91 % 528 225 42 29 71 % 125 Other 5 1 — 100 % 202 $ 983 452 281 91 % 1,472 558452 gross wells during 2006,2007, with an overall completion rate of 91 percent. On a net basis, 316256 of 346281 total wells drilled during 20062007 were completed as producers.20062007 exploration and development expenditures (E&D) totaled $1,049$983 million and resulted in 201242 Bcfe of proved reserve additions from drilling.additions. Of total expenditures, 3339 percent were invested in projects located in the Mid-Continent area; 3237 percent in the Permian Basin; 20and 23 percent in the Gulf Coast; and 12 percent in the Gulf of Mexico.Coast.cover the Anadarko and Arkoma basins of central and southeasternencompass broad areas in Oklahoma, the Hugoton Basin of southwest Kansas and the Texas Panhandle. We drilled 302237 gross (186(134 net) Mid-Continent wells during 2006,2007, completing 9795 percent as producers. The bulk of this activity occurred in the Texas Panhandle and the Anadarko Basin.Basin of western Oklahoma. Full-year 2006 drilling2007 investment in this area totaled $350was $385 million, or 33%39 percent of total E&D capital.86106 gross (59(75 net) Texas Panhandle wells with 9899 percent being completed as producers. Most of these wells targeted the Granite Wash formation in Roberts and Hemphill counties at depths ranging from 11,000-14,000 feet. Drilling activity in the Granite Wash remains active with 75-100125-150 wells planned for 2007.2008.92 (1870 gross (14 net) Anadarko Basin wells, of which 9889 percent were completed as producers. TheOur drilling activity mainly targets the Red Fork and Clinton Lake/Atoka formations at depths ranging from 12,000-15,000 feet. Gross proved reserves for these wells averaged 1.3 Bcfe. We expect to continue an activebegan in the fourth quarter of 2007 evaluating a potential horizontal drilling program in this area, drilling a similar number of wells in 2007 as in 2006.targeting the Woodford Shale formation at 13,000 feet.several exploitation projects, including the Cumberland, Madill and Caddo fields in southern Oklahoma and the Panoma field in the Texas Panhandle.Panhandle Panoma field. The Panoma field area targetsproduces from the Brown Dolomite formation at depths of approximately 2,200 feet. In 20062007 we drilled 8027 gross (79(26 net) wells at Panoma with a 100%100 percent success rate, increasing field production by 3.22.7 MMcfe/d.In the Our Permian Basin our operations cover both west Texas and southeast New Mexico. In total, we drilled 167172 gross (119(118 net) wells in this area during 2007 completing 161157 gross (115(106 net) as producers in the Permian Basin during 2006.producers. Full-year 2006 drilling2007 investment in this area totaled $331$368 million, or 32%37 percent of total E&D capital.6967 gross (47(48 net) wells with 94%84 percent being completed as producers. The primary formations we target in this area are comprised of Pennsylvanian-agedthe Wolfcamp, Morrow, Atoka and Strawn sandstones and conglomerate gas reservoirs at depths ranging from 11,500-14,0009,000-14,000 feet.9871 gross (72(58 net) wells were drilled, of which 98%94 percent were successful. Included in the West Texas program is exploitation of the Westbrook Unit (90% working interest) where 44 infill wells have been drilled and completed in the Clearfork formation at 3,200 feet.Other geologicGeologic targets in West Texas include the Devonian, Ellenburger and Bone Spring formations. In Ward and Spraberry. We drilled or participated in 21 (sevenReeves Counties drilling totaled 16 gross (9.5 net) Devonianhorizontal wells in the Arbol de Nada field in Winkler and Ector Counties, Texas; five gross (five net) Ellenburger wells in the Will-O field in Val Verde County, Texas; and six gross (2.7 net)Third Bone Spring wells in the War-Wink field in Ward County, Texas.formation. /Gulf of MexicoOurWe also own interest offshore Louisiana on the Gulf of Mexico operations are primarily located in offshore Louisiana in water depthsshelf (water depth less than 300 feet and covering approximately one million gross acres.feet). We obtained all of our offshore position through the Magnum Hunter acquisition. Our Gulf Coast and Gulf of Mexico effort is generally characterized by a greater reliance on 3-Dthree-dimensional (3-D) seismic information for prospect generation, larger potential reserves per well, greater drilling depths and lower success rates. Full-year 2007 investment in this area was $225 million, or 23 percent of total E&D capital.20062007 we drilled 4942 gross (28(29 net) Gulf Coast wells, realizing a 6571 percent success rate. A significant portion of the drilling occurred in Liberty County,and Hardin Counties, Texas. Targeting the Yegua and Cook Mountain formations at approximately 10,500 feet, we drilled 1419 gross (nine(16 net) Liberty County wells with a success rate of 6479 percent. Gulf of Mexico 2006 drilling consisted of 16 gross (6.7 net) wells, of which 44% were successful.Western/OtherOur Western/Other region principally includes operations We are currently conducting exploration activity in California, Michigan North Dakota and Wyoming. We drilled 24 gross (7.2 net) wells in the Western/Other region completing only 17 gross (0.2 net) as producers. Included in this area is the Riley Ridge Unithave a large gas development project in Sublette County, Wyoming.company’scompany's production volumes and the average oil and gas prices received: Years Ending December 31, 2007 2006 2005 Production Volumes Gas (MMcf) 119,937 124,733 100,272 Oil (MBbls) 7,445 6,529 4,804 Equivalent (MMcfe) 164,607 163,907 129,096 Net Average Daily Volumes: Gas (MMcf) 328.6 341.7 274.7 Oil (MBbl) 20.4 17.9 13.2 Equivalent (MMcfe) 451.0 449.1 353.7 Average Sales Price Gas ($/Mcf) $ 7.05 $ 6.50 $ 8.05 Oil ($/Bbl) $ 69.71 $ 61.96 $ 55.25 7CombinedTotal 2007 oil and gas production volumes increased 27 percent to 449.1averaged 451 MMcfe per day.day versus 449 MMcfe per day in 2006. Gas production in 2006 rose 242007 decreased four percent to 341.7328.6 MMcf per day and oil production increased 3614 percent to 17,88720,399 barrels per day. The decline in gas volumes resulted primarily from decreased investment in the Gulf of Mexico and property divestitures. The increase in oil volumes primarily stems from the inclusionwas principally a result of production from Magnum Hunter operations beginning June 7, 2005 andsuccessful exploration and development drilling.drilling in the Permian Basin.The weighted-average We sold our 2007 gas at an average price we received during 2006 was $6.50of $7.05 per Mcf, which was 19eight percent lowerhigher than the $8.05$6.50 per Mcf average price we received during 2005.in 2006. Our annual average realized oil price during 20062007 increased by 1213 percent to $69.71 per barrel from $61.96 per barrel from $55.25 per barrel in 2005. Gas prices fell2006. Improved overall market conditions for oil, natural gas and natural gas liquids were the primary reason for the higher realized price in 2006 as2007 compared to 2005 as a result of a number of factors including lower demand because of warm winter weather, no significant hurricane activity causing supply disruptions in the Gulf of Mexico and rising storage levels relative to historic averages.2006.Cimarex assumed Magnum Hunter’s oil and gas commodity swap and collar contracts as part of the merger. These instruments did not qualify for hedge accounting treatment and as such they are not included in the above average sales prices. In third quarter of 2006, we entered into We had natural gas collars for calendar year 2007 andcovering 80,000 MMBtu per day. The collars increased our 2007 average realized gas price by $0.23 per Mcf. For 2008, for 80,000 andwe have collars that cover 40,000 MMBtu per day respectively. The collars have been executed to settle against regional delivery points that correspondof Mid-Continent production with our Mid-Continent production. Beginning in January 2007, these instruments will affect average sales prices to the extent that the benchmark prices fall outside the collar range.a floor price of $7.00 per MMBtu and a ceiling of $9.90Cimarex’sCimarex's daily production by region for the full-year 20062007 and the second-half of 2005. The second-half 2005 volumes reflect the production increases as a result of the Magnum Hunter acquisition.2006. 2007 Average Daily Production 2006 Average Daily Production
(MBbl/d)
(MMcf/d)
(MMcfe/d)
(MMcfe/d) Oil
(MBbl/d) Gas
(MMcf/d) Total
(MMcfe/d) Oil
(MBbl/d) Gas
(MMcf/d) Total
(MMcfe/d) 5.4 160.2 192.3 4.7 152.5 180.7 9.5 87.2 144.3 8.1 83.8 132.4 5.3 75.0 106.9 4.8 98.0 126.6 0.2 6.2 7.5 0.3 7.4 9.4 20.4 328.6 451.0 17.9 341.7 449.1 180.7192.3 MMcfe per day, making-up 40or 43 percent of our total 20062007 production. We grew our 2006 production in this region as a result of successfulSuccessful drilling programs in the Texas Panhandle and the Anadarko Basin.Basin helped boost our Mid-Continent production by six percent in 2007. The Permian Basin contributed 132.4144.3 MMcfe per day in 2006,2007, which was 2932 percent of our total production for this period. The current year productionProduction increased nine percent as a result of successful Morrow and Wolfcamp drilling programs in southeast New Mexico and new horizontal oil wells in the West Texas secondary oil projects and development drilling.Bone Spring formation. Gulf Coast production was 80.7averaged 106.9 MMcfe per day during 2006,2007, or 1824 percent of total production. Gulf Coast volumes decreased in 20062007 as a result of natural declineproduction declines and no new drilling in our wells which were only partially offset by exploration success. Production from the Gulf of Mexico totaled 45.9 MMcfe per day, or 10 percent of our total 2006 production. Our second-half 2005 Gulf of Mexico production rate of 37.9 MMcfe per day was negatively impacted by hurricanes.Mexico.We have field offices located near our major concentrations of operated properties and have a centralized production management team in our Tulsa office.completed its acquisition ofacquired Magnum Hunter Resources, Inc, on June 7, 2005. Magnum Hunter was an independent oil and gas exploration and production company with operations concentratedof West Texas and southeast New Mexico and in the Gulf of Mexico. Magnum’sMagnum's oil and gas properties were valued at $1.8 billion and resulted in the addition of 886.7 Bcfe of proved reserves (73(60 percent gas and 73 percent proved developed).Various During 2007 we sold various interests in oil and gas properties werelocated in West Texas, California and Gulf of Mexico. In total we sold during 2006, with proceeds totaling $4.5 million. Proceeds from the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method123 Bcfe of accounting. Provedproved reserves associated with the sold properties approximated 2.5 billion cubic feet equivalent. We also recognized a $19.8 million gain on sale of certain limited partnership interests in oil and gas properties. Net sales consideration received via distributions from these affiliated partnerships totaled $59.3for $177 million. Revenues are recognized as gas is delivered and are reflected net of gas purchases in the Consolidated Statement of Operations included in this report.11eight percent of 20062007 revenues. Because over two-thirds of our gas production is from wells in Kansas, Oklahoma, Texas and Louisiana, most of our customers are either from those states or nearby end-user market centers. We regularly monitor the credit worthiness of all our customers and may require parental guarantees, letters of credit or prepayments when we deem such security is necessary.734760 people on December 31, 2006.2007. None of our employees are subject to collective bargaining agreements.resources substantially larger than those of Cimarex.resources. The effect of these competitive factors on Cimarex cannot be predicted. contracted for in connection with the acquisition oftitle, liens incidental to operating agreements, tax liens and other burdens and minor encumbrances, easements and restrictions.many varyingextensive Federal, state and complex federallocal laws and state 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 federalFederal and state environmental regulations and energy conservation rules. We are also indirectly affected by federalFederal and state regulation of pipelines and other oil and gas transportation systems. Compliance with such laws and regulations increases our overall cost of business, but has not had a material adverse effect on our operations or financial condition.Most of the The states in which we conduct operations regulateestablish 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 often limit the amounts of oil and natural gas that we can produce from our wells and to limit the number of wells or locations at which we can drill.federal,Federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas. To date, we have not expended any material amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position or results of operations.this requirement by modifying their tariffs and implementing new services and rates. These changes have providedthese 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.“gathering”"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”"gathering" systems under the NGPA and that our facilities are not subject to federal regulations. Although exempt from federal regulatoryFERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state agencies.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.laws.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.Low oilOil and gas prices fluctuate due to a number of uncontrollable factors, creating a component of uncertainty in our development plans and overall operations. Any decline in prices could adversely affect our financial results and future rate of growth in proved reserves and production.20062007 we sold our gas at an average price of $6.50$7.05 per Mcf, which was eight percent higher than our 2006 average sales price of $6.50 per Mcf. The 2006 average gas sales price was 19 percent lower than our 2005 average sales price of $8.05 per Mcf. Conversely, ourOur average 20062007 oil price of $69.71 per barrel was 13 percent higher than the price we received in 2006 of $61.96 per barrel, while the 2006 price was 12 percent higher than the price we received in 2005 of $55.25 per barrel.Because lowTo the extent we have not hedged our production, any decline in oil and gas prices would negatively affect the amount of cash flow available to fund these capital investments, they could also affect our future rate of growth.investments. Low prices may also reduce the amount of oil and gas that we can economically produce and may cause us to curtail, delay or defer certain exploration and development projects. We may be required under accounting rules to write down the carrying value of our properties or impair goodwill when gas and oil prices are low. Moreover, our ability to borrow under our bank credit facility and to raise additional debt or equity capital to fund acquisitions would also be impacted.11have enteredenter into hedging arrangements for a portion of our natural gas production. These hedging arrangements could expose us to risk of financial loss in some circumstances, including when:···levels of initial production rates which decline rapidly and declines which stabilize within three to five years. In order to replace the reserves depleted by production and to maintain or grow our total proved reserves and overall production levels, we must locate and develop new oil and gas reserves or acquire producing properties from others. While we may from time to time seek to acquire proved reserves, our main business strategy is to grow through drilling. Without successful exploration and development, our reserves, production and revenues could decline rapidly, which would negatively impact our results of operations and reduce our ability to raise capital.operations.We often are uncertain as to the future cost or timing of drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or canceled as a result of several factors, including unforeseen poor drilling conditions, title problems, unexpected pressure or irregularities in formations, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, and the cost of, or shortages or delays in the availability of, drilling rigs and related equipment.theirproved undeveloped reserves) and associated future net cash flow necessarily depend on a number of variables and assumptions. Among others, changes in any of the following factors may cause estimates to vary considerably from actual results:········2006.2007.We deliverOur business depends on oil and natural gas through pipelines that we do not own.transportation facilities, most of which are owned by others.uponon the availability, proximity and capacity of pipeline systems owned by third parties. The lack of available capacity on these pipelines. Thesesystems and facilities may not always be available to uscould result in the future.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 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.3021 percent of our net production. Our success in properties operated by others depends upon a number of factors outside of our control, including timing and amountoperator’soperator's expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.outstandingdemands on our cash resources in addition to interest expense and principal on our long-term debt, including, among others, operating expenses and capital expenditures.which are convertible into our common stock.bear interest at floating rates.2023. The Convertible Notes will be2023, and that are currently convertible into a combination of cash and our common stockstock. If the holders of Cimarex uponour convertible notes choose to convert them, we might be required to borrow additional funds under our senior revolving credit facility in order to repay the happening of certain events. In general,required cash amount. Also, upon conversion of a Convertible Note, the holder would receive not only cash equal to the principal amount of the Convertible Note, andbut also Cimarex common stock for the Convertible Note’sNote's conversion value in excess of such principal amount. The number of Cimarex common shares into which the Convertible Notes are convertible is dependent upon the conversion value in excess of the principal amount of the Convertible Notes and our future common stock price. Any such conversion will be dilutive to our existing shareholders.Cimarex haswe have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in its ability to control all circumstances. See Item 9A of this report for a complete discussion of controls and procedures. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherentstockholders’stockholders' rights plan include provisions that could discourage an unsolicited corporate takeover and could prevent stockholders from realizing a premium on their investment.stockholders’stockholders' rights plan. The stockholders’stockholders' rights plan, the certificate of incorporation and the by-laws may have the effect of delaying, deferring or preventing a change in control of Cimarex, even if the change in control might be beneficial to Cimarex stockholders.7382 percent of our proved reserves.2006.2007. All information in this Form 10-K relating to oil and gas reserves is net to our interest unless stated otherwise. See Note 17, Supplemental Oil and Gas Disclosures, in Notes to Consolidated Financial Statements for further Years Ending December 31, 2007 2006 2005 Total Proved Reserves— Gas (MMcf) 1,122,694 1,090,362 1,004,482 Oil, condensate and NGLs (MBbls) 58,250 59,797 64,710 Equivalent (MMcfe) 1,472,195 1,449,146 1,392,742 Standardized measure of discounted future net cash flow after-tax, discounted at 10 percent (in thousands) $ 2,897,631 $ 2,200,889 $ 3,028,100 Average price used in calculation of future net cash flow— Gas ($/Mcf) $ 6.51 $ 5.54 $ 7.89 Oil ($/Bbl) $ 93.66 $ 56.91 $ 57.65 2006, 902007, 78 percent of proved reserves were located in the Mid-Continent and Permian Basin Gulf Coast and Gulf of Mexico regions. In total we owned an interest in 13,19412,841 gross (4,757(4,845 net) productive oil and gas wells.2006.2007.
(MBbl)
(MMcf)
(MMcfe)
Proved
Reserves Oil
(MBbl) Gas
(MMcf) Equivalent
(MMcfe) Percent of
Proved
Reserves 9,166 561,998 616,992 42 % 43,122 269,040 527,777 36 % 5,435 93,058 125,668 8 % Other 527 198,598 201,758 14 % 58,250 1,122,694 1,472,195 100 % 3028 percent of our total equivalent proved reserves. We are the principal operator of our production in each of these fields (except Jo-Mill). The table below summarizes certain key statistics about these properties.
Proved
Reserves
Working
Interest
(feet)Field Region % of Total
Proved
Reserves Avg.
Working
Interest Avg. Depth
(feet) Primary Formation Hemphill Mid-Continent 4.4 % 96 % 11,000' Granite Wash Hugoton Mid-Continent 3.9 % 60 % 2,600' Chase Eola-Robberson Mid-Continent 3.8 % 94 % 5,500' - 11,000' Bromide/McLish/Oil Creek Red Deer Creek Mid-Continent 3.3 % 63 % 11,000' Granite Wash Jo-Mill Permian 2.7 % 13 % 7,500' Spraberry Mendota Mid-Continent 2.4 % 64 % 11,000' Granite Wash Quail Ridge Permian 2.3 % 68 % 13,000' Morrow Westbrook Permian 1.9 % 90 % 3,500' Clearfork Howard Glasscock Permian 1.7 % 59 % 2,000' - 2,600' San Andres/Clearfork War-Wink West Mid-Continent 1.2 % 58 % 11,500' Wolfcamp/Bone Spring 27.6 % 2006,2007, 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. Undeveloped Acreage Developed Acreage Total Acreage Gross Net Gross Net Gross Net Mid-Continent Kansas 3,454 2,388 158,391 105,601 161,845 107,989 Oklahoma 98,806 79,284 401,370 175,246 500,176 254,530 Texas 138,539 106,389 175,063 106,394 313,602 212,783 240,799 188,061 734,824 387,241 975,623 575,302
Permian Basin
New Mexico 86,652 65,262 150,942 99,596 237,594 164,858 Texas 49,551 35,890 183,679 113,150 233,230 149,040 136,203 101,152 334,621 212,746 470,824 313,898
Gulf Coast
Louisiana 16,361 11,792 21,535 6,371 37,896 18,163 Mississippi 6,209 3,265 26,090 7,046 32,299 10,311 Texas 80,322 37,501 141,880 57,930 222,202 95,431 Offshore 476,601 294,041 264,146 84,988 740,747 379,029 579,493 346,599 453,651 156,335 1,033,144 502,934
Other
Arkansas — — 6,719 2,115 6,719 2,115 Arizona 914,695 914,695 — — 914,695 914,695 California 6,536 5,046 1,523 1,342 8,059 6,388 Colorado 95,255 6,759 27,971 6,498 123,226 13,257 Illinois 1,782 1,191 554 183 2,336 1,374 Michigan 35,200 35,083 598 598 35,798 35,681 Montana 47,893 15,283 10,785 2,882 58,678 18,165 Nebraska 4,560 116 2,118 168 6,678 284 Nevada 160 1 440 1 600 2 New Mexico 1,626,253 1,614,523 13,604 2,289 1,639,857 1,616,812 North Dakota 77,441 39,483 15,361 1,899 92,802 41,382 South Dakota 10,482 9,329 2,414 373 12,896 9,702 Utah 105,724 59,591 32,990 2,303 138,714 61,894 Wyoming 247,652 30,702 72,874 13,525 320,526 44,227 3,173,633 2,731,802 187,951 34,176 3,361,584 2,765,978
4,130,128
3,367,614
1,711,047
790,498
5,841,175
4,158,112 2005, and 2004:2005: Exploratory Developmental Productive Dry Total Productive Dry Total Year ended December 31, 2007 55 18 73 361 18 379 20 32 52 490 16 506 55 20 75 283 24 307 (16(23 net) wells at December 31, 2006.2007.2005, and 20042005 are shown below: Exploratory Developmental Productive Dry Total Productive Dry Total Year ended December 31, 2007 36.7 13.1 49.8 221.9 9.6 231.5 12.4 23.9 36.3 303.7 6.2 309.9 33.2 15.6 48.8 144.8 16.8 161.6 2006:2007: Gas Oil Gross Net Gross Net 3,660 1,892 1,061 580 1,057 593 5,811 1,471 514 180 221 104 Other 110 8 407 17 5,341 2,673 7,500 2,172 2006, we have accrued $7.1 million for a mediated litigation settlement pertaining to post-production deductions on properties operated by Cimarex. We have also accrued an additional $1.5 million for a mediated litigation settlement pertaining to oil and gas property title issues. We anticipate payment of both settlements during 2007. Cimarex has other various litigation related matters2007, in the normal course of business, nonewe have various litigation related matters and associated accruals. Though some of which are material,the related claims may be significant, the resolution of them we believe, individually or in aggregate.aggregate, would not have a material adverse effect on our company.192006.2007.27, 200728, 2008 were:Name Age Office 7048495250346255REGISTRANT’SREGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.Cimarex’s Our $.01 par value common stock trades on the New York Stock Exchange under the symbol XEC. In December 2005, the Board of Directors declared the Company’s first quarterly cash dividend of $.04 per share. A $.04 per share cash dividend was also declaredpaid to shareholders in every quarter through fourth quarter of 2006.2007. In December 2007, the Board of Directors declared a $.06 per share dividend payable in the first quarter of 2008. Future dividend payments will depend on the Company’sCompany's level of earnings, financial requirements and other factors considered relevant by the Board of Directors.
Per Share2007 High Low Dividends
Per Share $ 38.07 $ 34.06 $ .04 $ 42.87 $ 36.99 $ .04 $ 42.01 $ 33.83 $ .04 $ 42.86 $ 36.88 $ .04 2006 High Low Dividends
Per ShareFirst Quarter $ 47.80 $ 39.21 $ .04 Second Quarter $ 47.40 $ 35.84 $ .04 Third Quarter $ 43.03 $ 33.57 $ .04 Fourth Quarter $ 38.46 $ 32.56 $ .04
Per Share2007,2008, was $36.10.$44.73. At December 31, 2006, Cimarex’s 82,883,3102007, Cimarex's 82,541,658 shares of outstanding common stock were held by approximately 5,4294,595 stockholders of record.2005, 68,0002007, we have repurchased and cancelled a total of 1,364,300 shares had been repurchased at an overall average price of $43.03. Since December 31, 2005 and through December 31, 2006, an additional 182,100$39.05. The shares have been repurchased for an average price of $44.43 per share.were acquired as follows:
Shares Purchased
Price Paid
per Share Total Number of Shares Purchased Average Price Paid per Share Year ended December 31, 2005 68,000 $ 43.03 Year ended December 31, 2006 182,100 $ 44.43 Year ended December 31, 2007 1,114,200 $ 37.93 1,364,300 $ 39.05 For the Years Ended December 31, 2007 2006 2005 2004 2003 Operating results: Revenues $ 1,431,166 $ 1,267,144 $ 1,118,622 $ 475,164 $ 325,621 Net income 346,469 345,719 328,325 153,592 94,633 Basic earnings per share 4.23 4.21 5.07 3.70 2.28 Diluted earnings per share 4.09 4.11 4.90 3.59 2.22 Cash dividends declared per share .18 .16 — — — Balance sheet data: Total assets 5,362,794 4,829,750 4,180,335 1,105,446 805,508 Total debt 487,159 443,667 352,451 — — Stockholders' equity 3,259,287 2,976,143 2,595,453 700,712 534,740 Other financial data: Oil and gas sales 1,364,622 1,215,411 1,072,422 472,389 324,119 Oil and gas capital expenditures 1,023,434 1,074,673 2,462,826 296,429 162,627 Proved Reserves: Gas (MMcf) 1,122,694 1,090,362 1,004,482 364,641 337,344 Oil (MBbls) 58,250 59,797 64,710 14,063 14,137 Total equivalent (MMcfe) 1,472,195 1,449,146 1,392,742 449,020 422,167 MANAGEMENT’SMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND FINANCIAL CONDITIONINTRODUCTION The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in Item 8 of this report. Certain amounts in prior years' financial statements have been reclassified to conform to the 2007 financial statement presentation. This discussion also includes forward-looking statements. Please refer to "Cautionary Information about Forward-Looking Statements" in Part I of this Form 10-K for important information about these types of statements.Cimarex Energy Co. isOVERVIEWfocusedentirely located in the United States. We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed. Texas, New Mexico, Kansas, Louisiana and the Gulf of Mexico.Wyoming.Our primary focus is exploration and development drilling for new reserves. To supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. On June 7,In 2005 Cimarexwe acquired Magnum Hunter Resources, Inc, in a stock-for-stock merger with a total transaction value of approximately $2.1 billion. Magnum Hunter was a Dallas-based independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Hunter’s common stockholders and assumed $633During 2007 we purchased $40.9 million of debt.assets, with the largest acquisition being in the Texas Panhandle area for $35.8 million. This transaction added over 50 locations to our already active Texas Panhandle drilling program and eight Bcfe of proved reserves.merger was accounted for as a purchase of Magnum Hunter by Cimarex. Results of operations from Magnum Hunter’s properties are included in our consolidated statements of operations beginning June 7, 2005.Our E&D expenditures totaled $1,049two largest sales were $87.5 million for 2006, up from $642our West Texas Spraberry oil properties and $53.5 million in 2005. Operationally, we now have a large base of properties in the Permian Basin with operational characteristics similar tofor our Mid-Continent assets. The merger also extended our onshore Gulf Coast activities into the Gulf of Mexico. Overall, about 39 percent of our proved reserves are in the Permian Basin and 41 percent are in our Mid-Continent region. Our onshore Gulf Coast and Gulf of Mexico operations collectively make up 10 percentMain Pass area operated properties. We continue to evaluate alternatives for the rest of our proved reserves.Industry and Economic FactorsGulf of Mexico assets.In managing our business we must deal with many factors inherent in our industry. First and foremost is wide fluctuation of oil and gas prices. Oil and gas markets are cyclical and volatile, with future price movements difficult to predict.Gas Pricesoften have had the greatest impact on our results of operations. Our annual average realized gas price increased from $6.50 per Mcf in 2006 to $7.05 per Mcf in 2007; and oil prices increased from $61.96 per barrel in 2006 to $69.71 per barrel in 2007. In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. However, we have made limited use of hedging transactions to somewhat reduce price risk as discussed further below. Years Ended December 31, 2007 2006 2005 Gas Prices: Average Henry Hub price ($/Mcf) $ 6.86 $ 7.23 $ 8.60 Average realized sales price ($/Mcf) $ 7.05 $ 6.50 $ 8.05 Effect of hedges ($/Mcf) $ 0.23 $ — $ —
Oil Prices:
Average WTI Cushing price ($/Bbl) $ 72.31 $ 66.22 $ 56.44 Average realized sales price ($/Bbl) $ 69.71 $ 61.96 $ 55.25 complexities. Advancedcomplexities that required the use of advanced technologies requiringand highly trained personnel are utilized in both exploration and production.personnel. Even when themodern exploration technology is properly used, the interpreter still may not know conclusively if hydrocarbons will be present, or the rate at which they will be produced. Exploration is a high-risk activity, often times resulting in no commercially productive reservoirs being discovered. Moreover, costs associated with operating within the industry are substantialproduced, or economic viability. Historically, we have been able to grow our proved reserves and usually move upproduction each year through drilling and down together with prices.The oil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and gas companies, and individual operators. In addition, the industry as a whole competes with other businesses that supply energyacquisitions. Future growth will continue to industrial, commercial, and residential end users.Extensive federal, state, and local regulation of the industry significantly affects our operations. In particular, our activities are subject to comprehensive environmental regulations. Compliance with these regulations increases the cost of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.Approach to the BusinessProfitable growth largely dependsdepend upon our ability to successfully find and develop neweconomically add reserves in excess of production. reserves. To achieve an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate, and higher risk exploration and development projects. We believe that this approach allows for consistent increases in our oil and gas reserves while minimizing the chanceincreased by 1.5% from 1.449 Tcfe to 1.472 Tcfe. This was despite production of failure. To further mitigate risk, we have chosen165 Bcfe and property sales of 123.4 Bcfe. Proved natural gas reserves at year-end 2007 were 1.12 Tcf compared to seek geologic1.09 Tcf at year-end 2006. Natural gas comprised 76% and geographic diversification by operating in multiple basins. We may also consider the use of transaction-specific hedging of oil and gas prices to reduce price risk. In connection with the acquisition of Magnum Hunter, we acquired existing commodity derivatives, as well as in the third quarter of 2006 we entered into additional derivative contracts as discussed more fully below.Implementation75% of our business approach relies ontotal proved reserves at year-end 2007 and 2006, respectively. Our proved oil reserves at year-end 2007 were 58.3 MMBbls compared to 59.8 MMBbls at the end of 2006. Overall, about 42% of our ability to fund ongoing explorationproved reserves are in our Mid-Continent region and development projects with cash flow provided by operating activities, periodic sales of non-core properties, and external sources of capital.We project that 2007 exploration and development expenditures will range from $800 million to $1 billion. Approximately 37 percent of the expenditures will be in the Mid-Continent area, 28 percent36% are in the Permian Basin, 24 percent in theBasin. Our onshore Gulf Coast area, and 8 percentother onshore operations collectively make another 20% of total proved reserves. Only 2% of our total proved reserves are in the Gulf of Mexico.Cash flow from operating activities for 2006 totaled $878.4 million, which helped to fund our drilling program. Based on expected cash provided by operating activities and monies available under our Senior Secured Revolving Credit Facility, we believe we are well positioned to fund the projects identified for 2007 and beyond.23CRITICAL ACCOUNTING POLICIES AND ESTIMATESOur discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 4 to our Consolidated Financial Statements included in this report. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure about Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our Consolidated Financial Statements.Oil and Gas SalesRevenue from the sale of oil and gas is recognized when title passes, net of royalties. This is known as the sales method (versus the entitlement method). Under the sales method, revenue is recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production.Marketing SalesCimarex markets and sells natural gas for working interest partners under short term sales and supply agreements and earns a fee for such services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the accompanying consolidated statement of operations.Gas ImbalancesWe use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2006 and 2005 was $3.2 million and $2.7 million, respectively. At December 31, 2006 we are also in an under-produced position relative to certain other third parties.the subjective decisions and variances in available data for our various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. For 2006,2007, revisions of reserveprevious estimates equaled a decreaseboosted proved reserves by 57.5 Bcfe or 4% of 3.7 MBblstotal proved reserves on December 31, 2007. Most of oil and 14.5 Bcf of gas (due to lowerour positive revisions resulted from higher oil and gas prices), representing twoprices and new data for one halfpercent of proved oil and gas reserves as of December 31, 2006.our large fields in Wyoming. See Note 17, Supplemental Oil and Gas Disclosures for more reserve data.information.useinvested $982.5 million on E&D during 2007 and $1,048.2 million in 2006. Approximately 39% of 2007 expenditures were in the units-of-production methodMid-Continent area, 37% in the Permian Basin, 17% in the Gulf Coast area, and 5% in the Gulf of Mexico. We project that 2008 exploration and development expenditures will range from $1.1 billion to amortize$1.3 billion.properties. Changes in reserve quantities will cause corresponding changes in depletion expense in periods subsequent to the quantity revision or, in some cases, a full cost ceiling limitation charge in the periodare substantial. Some of the revision. To date, changes in expense resulting from changes in previous estimates of reserves have not been material.We use the full cost method of accounting for ourthese costs vary with oil and gas operations. All costs associatedprices, some trend with property acquisition, exploration,production volume and development activitiessome are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred fora function of the purposenumber of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized.each quarter, a full cost ceiling limitation calculation is made whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used2007, we owned interests in the calculationover 12,841 wells.full cost ceiling limitation are determined based on currentof power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to produce oil and gas prices andfrom existing wells. adjusted for designated cash flow hedges if it is determined that net capitalized costs exceed the full cost ceiling limit. If net capitalized costs subject to amortization were to exceed this limit, the excess would be charged to expense. However, if commodity prices increase subsequent to period end and prior to issuance of the financial statements, these higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period.We account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. If the estimated fair value exceeds its carrying amount, goodwill is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. To date, no related impairment has been recorded.SFAS No.133, Accounting for Derivative Instruments and Hedging activities, requires that all derivatives be recorded on the balance sheet at fair value. We determine the fair value of derivative contracts based on the stated contract prices and current and projected market prices at the determination date discounted to reflect the time value of money until settlement. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to theextent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled.In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million net liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments were not designated for hedge accounting treatment. As a result, Cimarex recognized a net gain for the year ended December 31, 2006 of $23 million. Activity included both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in the year ended December 31, 2006 was $19 million. As of December 31, 2006, all derivative contracts assumed with the Magnum Hunter merger had matured.In the third quarter of 2006, we entered into additional derivative contracts to mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas prices. Using zero-cost collars with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million MMbtu and 14.6 million MMbtu of our anticipated Mid-Continent gas production for 2007 and 2008, respectively. At December 31, 2006, this represented approximately 51% and 31% of our current anticipated Mid-Continent gas production for 2007 and 2008, respectively.Under the collar agreements, we will receive the difference between an agreed upon Mid-Continent index price and floor price if the index price is below the floor price. We will pay the difference between the agreed upon contracted ceiling price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. These hedges have been designated for hedge accounting treatment as cash flow hedges.For the year ended December 31, 2006, we recorded an unrealized loss of $13 thousand related to the ineffective portion of the hedges. At December 31, 2006, $41.9 million and $7.1 million of the hedges were recorded as current and long-term assets, respectively, and an unrealized gain (net of deferred income taxes) of $31 million was recorded in other comprehensive income. See Note 5 to the Consolidated Financial Statements and Item 7A of this report for additional information regarding our derivative instruments.Depending on changes in oil and gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions.A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. As of December 31, 2006, we have accrued $7.1 million for a mediated litigation settlement pertaining to post-production deductions on properties operated by Cimarex. We have also accrued an additional $1.5 million for a mediated litigation settlement pertaining to oil and gas property title issues. We anticipate payment of both settlements during 2007. Cimarex has other various litigation related matters in the normal course of business, none of which that can be estimated are deemed to be material, individually or in aggregate. See Note 15 of Notes to Consolidated Financial Statements.The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool.Recent Accounting DevelopmentsIn July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes, which clarifies the accounting for uncertainty in income taxes recognized in the Company’s financial statements in accordance with SFAS 109 “Accounting for Income Taxes.” The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Along with these disclosures, a tabular presentation of significant changes during each period will be required. The Interpretation is effective as of the beginning of the first fiscal year beginning after December 15, 2006 (January 1, 2007 for calendar-year companies). We are currently evaluating the effects of implementing this interpretation and do not believe the adoption of this interpretation will have a material impact on our financial statements.In September 2006 the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 regarding the process of quantifying misstatements within a financial statement, addressing in particular materiality analysis related to the correction of errors. The impact on the current year financial statements of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, must be quantified. Adjustment would be required if the misstatement is deemed material, after considering all relevant quantitative and qualitative factors. The periods in which the correction would be recorded would be dependent on the materiality considerations for each affected period. This did not have a material impact on our financial statements.Also in September 2006 the Financial Accounting Standards Board issued Statement No. 157, Fair Value Measurements, which establishes a single authoritative definition of fair value, sets out a framework for measuring fair value, and requires additional disclosures about fair-value measurements. The Statement applies only to fair-value measurements that are already required or permitted by other accounting standards and is expected to increase the consistency of those measurements. The Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We do not expect the adoption of Statement No. 157 to have a material impact on our financial statements.Our results of operations are primarily impacted by changes in oil and gas prices and changes in our production volumes. Realized gas prices decreased from $8.05 per Mcf in 2005 to $6.50 per Mcf in 2006, and oil prices increased from $55.25 per barrel in 2005 to $61.96 per barrel in 2006. Cimarex also sells gas on behalf of third parties that are incidental to sales of our own production. Sales and costs associated with our production are reflected in gas sales and transportation expense.We also own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.Transportation expenses are comprised of costs paid to carry and delivermove oil and gas from the wellhead to a specified deliverysales point. In some cases we receive a payment from purchasers which is net of transportation costs,Production costs are composed of lease operating expenses, which generally consist of pumpers’ salaries, utilities, water disposal, maintenance and other costs necessary to operate our producing properties.Taxes, other than income, are taxes assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad valorem and excise taxes.offices.offices and not directly associated with exploration, development or production activities. While we expect suchthese costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth.123R.123R,Share Based Payment. Net stock compensation expense in 2007 was $10.8 million compared to $8.2 million in 2006. For the Years Ended
December 31, Percent
Change
Between
2007/2006 Price/Volume Analysis Oil and Gas Sales 2007 2006 Price Volume Variance (In thousands or as indicated) Gas sales $ 845,631 $ 810,894 4 % $ 65,965 $ (31,228 ) $ 34,737 Oil sales 518,991 404,517 28 % 57,699 56,775 114,474 Total oil and gas sales $ 1,364,622 $ 1,215,411 12 % $ 123,664 $ 25,547 $ 149,211
Total gas volume—Mcf
119,937
124,733
(4
)%
Gas volume—MMcf per day 328.6 341.7 Average gas price—per Mcf $ 7.05 $ 6.50 8 % Effect of hedges—per Mcf $ 0.23 $ —
Total oil volume—thousand barrels
7,445
6,529
14
%
Oil volume—barrels per day 20,399 17,887 Average oil price—per barrel $ 69.71 $ 61.96 13 % For the Years Ended
December 31, 2007 2006 Gas Gathering, Processing and Marketing (in thousands): Gas gathering and processing revenues $ 61,471 $ 47,879 Gas gathering and processing costs (30,513 ) (27,410 ) Gas gathering and processing margin $ 30,958 $ 20,469 Gas marketing revenues, net of related costs $ 5,073 $ 3,854 For the Years Ended
December 31, Variance
Between
2007/2006 2007 2006 Operating costs and expenses (in thousands): Depreciation, depletion and amortization $ 461,791 $ 396,394 $ 65,397 Asset retirement obligation 8,937 7,018 1,919 Production 201,512 176,833 24,679 Transportation 26,361 21,157 5,204 Taxes other than income 93,630 91,066 2,564 General and administrative 49,260 42,288 6,972 Stock compensation 10,772 8,243 2,529 Other operating, net 6,637 2,064 4,573 Gain on derivative instruments — (22,970 ) 22,970 $ 858,900 $ 722,093 $ 136,807 BASIS General and administrative (G&A) expenses increased $7.0 million from $42.3 million in 2006 to $49.3 million in 2007. The increase between periods is due to an expansion of staff, higher average salaries, higher employee-benefit costs, and increased legal representation costs.PRESENTATIONOPERATIONSIn June Our financial and operating results for 2005 Cimarexinclude the operating results of properties acquired in the Magnum Hunter Resources, Inc, by issuing 0.415 shares of Cimarex common stock for each share of outstanding Magnum Hunter common stock, resulting in the issuance of 39.7 million Cimarex common shares. At December 31, 2005, Cimarex had 82.4 million shares outstanding. The merger was accounted for as a purchase of Magnum Hunter by Cimarex. The results of operations of Magnum Hunter were included in our consolidated statements of operations beginning June 7, 2005.Certain amounts in prior years’ financial statements have been reclassified to conform to the 2006 financial statement presentation.28RESULTS OF OPERATIONSYear Ended December 31, 2006 Compared with Year Ended December 31, 2005:SUMMARY DATA:(in thousands or as indicated) of 2006 was $345.7 million, or $4.11 per diluted share, compared to net income of $328.3 million, or $4.90 per diluted share in 2005. The change in net income results from the effect of changes in revenues and costs, as discussed further. The results of operations of Magnum Hunter are included in our consolidated statements of operations only for the period since the acquisition on June 7, 2005. For the Years Ended
December 31, Percent
Change
Between
2006/2005 Price/Volume Analysis Oil and Gas Sales 2006 2005 Price Volume Variance (In thousands or as indicated) Gas sales $ 810,894 $ 807,007 1 % $ (192,982 ) $ 196,869 $ 3,887 Oil sales 404,517 265,415 52 % 43,821 95,281 139,102 Total oil and gas sales $ 1,215,411 $ 1,072,422 13 % $ (149,161 ) $ 292,150 $ 142,989
Total gas volume—Mcf
124,733
100,272
24
%
Gas volume—MMcf per day 341.7 274.7 Average gas price—per Mcf $ 6.50 $ 8.05 (19 )%
Total oil volume—thousand barrels
6,529
4,804
36
%
Oil volume—barrels per day 17,887 13,162 Average oil price—per barrel $ 61.96 $ 55.25 12 % of 2006 totaled $1.2 billion, compared to $1.1 billion for 2005. The $143.0 million increase in sales between the two periods results from $292.0 million related to higher production volumes, offset by a decrease of $149.0 million resulting from lower commodity prices.19 percent19% change decreased sales by $193.0 million between the two periods. Realized oil prices, however, averaged $61.96 per barrel for 2006, compared to $55.25 per barrel for 2005. The increase in sales between periods resulting from this 12 percent12% improvement in oil prices totaled $44.0 million. Changes in realized prices were the direct result of overall market conditions. For the Years Ended
December 31, 2006 2005 Gas Gathering, Processing and Marketing (in thousands): Gas gathering and processing revenues $ 47,879 $ 44,238 Gas gathering and processing costs (27,410 ) (31,890 ) Gas gathering and processing margin $ 20,469 $ 12,348 Gas marketing revenues, net of related costs $ 3,854 $ 1,962 Gas gathering We sometimes transport, process and processing revenues, net of related costs, equaled $20.5 million in 2006, compared to $12.4 million in 2005. The increase is due to the inclusion of related activities from Magnum Hunter operations from June 7, 2005. We own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third partymarket third-party gas that is associated with our gas.Gas In 2006, third-party gas gathering and processing contributed $20.5 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $12.4 million in 2005. Our gas marketing net revenuesmargin (revenues less purchases) increased to $3.9 million in 2006 from $2$2.0 million in 2005. Increases in net margins from gas gathering, processing and marketing activities are the direct result of related costs of $144.7 millionincreased volumes and $213.7 million for 2006 and 2005, respectively. Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that is incidental to sales of our own production.overall market conditions. For the Years Ended
December 31, Variance
Between
2006/2005 2006 2005 Operating costs and expenses (in thousands): Depreciation, depletion and amortization $ 396,394 $ 258,287 $ 138,107 Asset retirement obligation 7,018 3,819 3,199 Production 176,833 104,067 72,766 Transportation 21,157 15,338 5,819 Taxes other than income 91,066 73,360 17,706 General and administrative 42,288 33,497 8,791 Stock compensation 8,243 4,959 3,284 Other operating, net 2,064 15,897 (13,833 ) (Gain) Loss on derivative instruments (22,970 ) 67,800 (90,770 ) $ 722,093 $ 577,024 $ 145,069 Costs and ExpensesNet Total operating costs and expenses (not including gas gathering, marketing and processing costs, as well asor income tax expense) were $695.4$722.1 million in 2006 compared to $570.3$577.0 million in 2005.netchange in total operating costs and expenses for 2006 and 2005 was the gain and loss on derivative instruments. In connection with the Magnum Hunter merger, Cimarex recognized a $39.3 million liability associated with Magnum Hunter’sHunter's existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments were not designated for hedge accounting treatment. As a result, Cimarex recognized net gains for the year 2006 of $23.0 million and net losses for 2005 of $67.8 million, respectively. Activity includes both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in 2006 and 2005 totaled $19.0 million and $64.3 million, respectively. ThesesThese contracts expired December 31, 2006.To mitigate a portion of the potential exposure to adverse market changes in an environment of volatile gas prices, we entered into additional derivative contracts in third quarter of 2006. These derivatives have been designated for hedge accounting treatment as cash flow hedges. Changes in the fair value of the hedges, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in otherOther income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled. During 2006, we recognized an unrealized loss of $13 thousand related to the ineffective portion of the derivative contracts.Asset retirement obligation accretion increased $3.2 million from $3.8 million in 2005 to $7.0 million in 2006. The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removalof facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Since 2005 the liability has increased $28.0 million from $101.1 million in 2005 to $129.1 million in 2006.Company’sCompany's limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P. These partnerships sold all of their interest in oil and gas properties during 2006. Cimarex’sCimarex's investments in these partnerships had been reflected in other assets, net. Net sales consideration received via distributions from the partnerships equaled $59.3 million, which are in excess of the Company’sCompany's investment balance in the partnerships. The excess distributions of $19.8 million have been recorded in other income for 2006.36.5 percent36.5% and 36.4 percent36.4% in 2006 and 2005, respectively. Included in the 2006 income tax expense of $198.6 million is a current benefit of $21.9 million.32Year Ended December 31, 2005 Compared with Year Ended December 31, 2004:SUMMARY DATA:(in thousands or as indicated)Net income for the year of 2005 was $328.3 million, or $4.90 per diluted share, compared to net income of $153.6 million, or $3.59 per diluted share in 2004. The change in net income results from the effect of changes in revenues and costs, as discussed further. The results of operations of Magnum Hunter are included in our consolidated statements of operations only for the period since the acquisition on June 7, 2005.Oil and gas sales for the year of 2005 totaled $1.1 billion, compared to $472.4 million for 2004. The $600.0 million increase in sales between the two periods results from $302.0 million related to higher commodity prices and $298.0 million due to higher production volumes (due primarily to increased production resulting from the acquisition of Magnum Hunter).Realized gas prices averaged $8.05 per Mcf for 2005, compared to $5.76 per Mcf for 2004. This 40 percent change increased sales by $230.0 million between the two periods. Realized oil prices averaged$55.25 per barrel for 2005, compared to $40.19 per barrel for 2004. The increase in sales between periods resulting from this 37 percent improvement in oil prices totaled $72.0 million. Changes in realized prices were the direct result of overall market conditions.Sales also benefited from higher production volumes. Average gas volumes rose 100.9 MMcf per day in 2005 to 274.7 MMcf per day from 173.8 MMcf per day in 2004, resulting in $211.1 million of incremental revenues. Oil volumes averaged 13,162 barrels per day for 2005, compared to 7,215 barrels per day in 2004, resulting in increased revenues of $86.9 million. The increase in sales volumes between the periods of 2005 and 2004 is due to positive drilling results during 2004 and 2005, and the inclusion of production from Magnum Hunter operations from June 7, 2005. Production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted during the third and fourth quarters of 2005 as a result of hurricanes. It is estimated to have negatively impacted fourth-quarter 2005 production by 41 to 45 MMcf equivalent per day and full-year volumes by 17 to 20 MMcf equivalent per day. At year-end 2005, approximately 20 MMcf equivalent was still shut-in. It is anticipated that most of the remaining shut-in volumes will be restored by the end of the first quarter of 2006. The timetable to restore full production largely depends on the startup of refineries, gas processing plants, platforms, facilities and pipelines owned and operated by others. No oil and gas reserves have been lost as a result of the storms and essentially all associated repair costs will be covered by insurance.Gas gathering and processing revenues, net of related costs, equaled $12.4 million in 2005, compared to a loss of $0.2 million in 2004. The increase is due to the inclusion of related activities from Magnum Hunter operations from June 7, 2005. We own interests in gas gathering systems and gas processing plants that are connected to our production operations. We transport and process third party gas that is associated with our gas.Gas marketing net revenues decreased to $2 million from $2.7 million, net of related costs of $213.7 million and $193.0 million for 2005 and 2004, respectively. Gas marketing revenues, net of related costs, pertain to sales of gas on behalf of third parties that is incidental to sales of our own production.Costs and ExpensesCosts and expenses (not including gas gathering, marketing and processing costs as well as income tax expense) were $570.3 million in 2005 compared to $228.6 million in 2004. Depreciation, depletion and amortization (DD&A) was the largest component of the increase between periods. DD&A equaled $258.3 million in 2005 compared to $124.3 million in 2004. On a unit of production basis, DD&A was $2.00 per Mcfe in 2005 compared to $1.56 per Mcfe for 2004. The increase largely stems from costs associated with Magnum Hunter operations and higher costs for reserves added during 2004 and 2005.Production costs rose $66.6 million from $37.5 million ($.47 per Mcfe) in 2004 to $104.1 million ($.81 per Mcfe) in 2005 The higher costs in 2005 resulted primarily from the inclusion of costs associated with Magnum Hunter operations, higher field operating expenses from an expanded number of properties and higher maintenance costs.Transportation costs increased from $10.0 million in 2004 to $15.3 million in 2005. The increase is the result of expiring contracts being renewed with increased current market rates and the inclusion of transportation costs associated with Magnum Hunter operations.Taxes other than income were $35.6 million greater, rising from $37.8 million in 2004 to $73.4 million in 2005. The increase between periods resulted from increases in oil and gas sales stemming from inclusion of Magnum Hunter operations, higher production volumes and commodity prices.General and administrative (G&A) expenses increased $11.0 million from $22.5 million in 2004 to $33.5 million in 2005. The increase between periods is due to an expansion of staff and higher employee-benefit costs.Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards. Stock compensation increased from $2.0 million in 2004 to $5.0 million in 2005 due primarily to the $3.4 million expensing of stock options resulting from the adoption of SFAS No. 123R as of January 1, 2005.Other operating, net totaled an expense of $15.9 million in 2005 and income of $3.4 million in 2004. The 2005 expenses consisted primarily of $9.4 million of costs associated with the Magnum Hunter merger. Of this $9.4 million, $3.6 million is due to the acceleration of vesting of stock options and restricted stock units resulting from change of control provisions under our stock incentive plan becoming effective due to the Magnum Hunter merger. The remaining $5.8 million consisted of $4.3 million of general integration costs, $1.0 million for retention bonuses, and $0.5 million of related financing costs. In addition to merger costs, 2005 expenses also included a mediated $6.5 million litigation settlement pertaining to post-production deductions on properties operated by Cimarex. The income reflected in 2004 consisted of miscellaneous litigation settlements in favor of the Company.Another large component of the increase in costs and expenses between periods was the loss on derivative instruments. Prior to the acquisition of Magnum Hunter, Cimarex did not use financial instruments to mitigate commodity price changes. In connection with the merger, we recognized a $39.3 million liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments have not been designated for hedge accounting treatment. As a result, Cimarex recognized in earnings during 2005 a net loss of $67.8 million. The charge includes both non-cash mark-to-market derivative losses as well as cash settlements. Cash payments related to these contracts that settled in 2005 totaled $64.3 million. The net derivative liability at December 31, 2005 equals $41.9 million. Cimarex will continue to recognize mark-to-market gains and losses as well as amortization of these contracts in future earnings until the derivative instruments mature.Net interest expense in 2005 of $5.8 million is comprised of $19.6 million of interest expense, offset by $11.7 million of capitalized interest resulting from interest recognized on borrowings associated with costs incurred to bring properties under development, not being amortized, to their intended use and $2.1 million of amortization of fair value of debt. This has increased from $1.1 million of interest expense in 2004. The additional components of the 2005 net interest amount and the increase from 2004 results from amounts associated with the debt assumed in the Magnum Hunter merger. Prior to the Magnum Hunter merger, Cimarex had no outstanding debt.Asset retirement obligation accretion increased $2.6 million from $1.2 million in 2004 to $3.8 million in 2005. The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Since 2004 the liability has increased $81.3 million from $19.8 million in 2004 to 101.1 million in 2005.Other, net increased from $4.3 million of income in 2004 to $12.5 million of income in 2005. The components of this other income net of other expenses consist of miscellaneous items that will vary from period to period. The increase from 2004 to 2005 is due primarily to additional gains on the sale of miscellaneous equipment inventory.Income tax expenseIncome tax expense totaled $188.1 million for 2005 versus $92.7 million for 2004. Tax expense equaled a combined federal and state effective income tax rate of 36.4 percent and 37.6 percent in 2005 and 2004, respectively.Cash FlowsOverviewsourcesources of liquidity and capital isresources are cash flow generated from operating activities, occasional property sales, borrowings under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share repurchases.Prices we receive for oilWe believe that our cash flow from operating activities and gas sales andother capital resources will be adequate to fund our level of production will impact these future cash flows. No prediction can be made as to the prices we will receive. Production volumes will in large part be dependent upon the amount and results of futureplanned 2008 capital expenditures. In turn, actual levelscapital expenditures may vary due to many factors, including drilling results, oil and gas prices, industry conditions, prices and availability of goods and services, and the extent to which proved properties are acquired.Cash Flow Changes20062007 was $994.7 million, compared to $878.4 million compared tofor 2006 and $704.7 million for 2005. The increase infrom 2006 from the earlier periodto 2007 resulted primarily from higher gas prices, higher oil prices and gasincreased oil production. The increase from 2005 to 2006 resulted primarily from higher production and from higher oil prices. Our production volumes were higher in 2006 versus 2005 because we owned the Magnum Hunter properties for a full year versus seven months in 2005.20062007 was $875.4 million, compared to $1.0 billion compared tofor 2006 and $497.5 million for 2005. The increaseChanges in 2006 stemmed from a largerthe cash flow used in investing activities are generally the result of changes in our exploration and development program.programs, acquisitions and property sales. The decrease from 2006 to 2007 was mostly caused by increased proceeds from property sales. We sold $177 million of properties in 2007 versus $4.5 million in 2006. The increase from 2005 to 2006 resulted primarily from an increase in exploration and development expenditures. For Years Ended
December 31, 2007 2006 2005 Acquisitions: Proved $ 17,334 $ 25,970 $ 1,523,356 Unproved 23,580 513 297,692 40,914 26,483 1,821,048 Exploration and development: Land & Seismic 98,162 104,527 68,703 Exploration 217,696 251,717 197,459 Development 666,662 691,946 375,616 982,520 1,048,190 641,778
Property sales
(176,659
)
(4,459
)
(149,262
) $ 846,775 $ 1,070,214 $ 2,313,564 2006, stockholders’2007, stockholders' equity totaled $3.0$3.3 billion, up from $2.6$3.0 billion at December 31, 2005.2006. The increase resulted primarily from 20062007 net income of $345.7$346.5 million. At December 31, 2006 our cash balance equaled $5.0 million.Company’sCompany's first quarterly cash dividend of $.04 per share payable to shareholders. A $.04 per share dividend has been authorized in every quarter since then. On December 12, 2007 the Board of 2006. Also inDirectors increased the regular cash dividend on our common stock from $0.04 to $0.06 per common share.ThroughDuring 2007 we repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2005, 68,0002007 total 1,364,300 shares had been repurchased at an average price of $43.03. Since December 31, 2005 and through December 31, 2006, an additional 182,100 shares have been repurchased for an average price of $44.43 per share.$39.05.31, 2006 totaled $62.2which allowed us to pay off our remaining bank debt and increase our cash position by $118 million compared to $31.6year-end 2006.at December 31, 2005. Theprimarily due to cash advances paid for construction of a gas processing facility adjacent to our Riley Ridge field development project in Wyoming.is primarily the resultin revenue payable of settlement$35.3 million due to increased production and prices and an increase in other accrued expenses of the liability associated with derivative contracts outstanding at December 31, 2005 and entering into new derivative contracts$39.3 million due to having taxable income in the third quarter for which a current asset was recorded at December 31, 2006.year and an increase in cash advances from partners.362005 consisted of the following (in thousands):Debt at December 31,2007 and 2006 consisted of the following (in thousands): December 31, 2007 2006 $ — $ 95,000 — 210,746 (1) 7.125% Notes due 2017 350,000 — Floating rate convertible notes due 2023 (face value $125,000) 137,159 (2) 137,921 (2) $ 487,159 $ 443,667 Cimarex’s Revolving Credit Facility Our revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At December 31, 2006,2007, there were no outstanding borrowings of $95 million under the Revolving Credit Facility at a weighted average interest rate of approximately 6.75%.revolving credit facility. We also had outstanding letters of credit offor approximately $5$2.7 million posted against the borrowing base, leaving an unused borrowing capacityamount of approximately $400 million at December 31, 2006.$497.3 million.Credit Facilitycredit facility agreement contains both financial and non-financial covenants, including restricting our cash investments to "Cash Equivalent Investments" as defined under the agreement. We noted in early December 2007 that an investment of $16 million in a money market fund was not in compliance with our covenants. Cimarex continues to complyWe then obtained waivers from our lenders for the related investments and amended the definition of "Cash Equivalent Investments". We are in compliance with thesethe amended covenants and doesdo not view them as materially restrictive.havewere redeemed on May 18, 2007 at a faceredemption price of 104.8% of the principal amount plus $3.3 million of accrued interest for a total redemption value of $195$207.6 million. We recognized a gain on the early extinguishment of this debt of $5.1 million which is reflected on the income statement under Other income and are due March 15, 2012.expense.unsecured and are redeemable as aat our option, in whole or in part, at Cimarex’s option,any time on and after March 15, 2007May 1, 2012 at the following redemption prices (expressed as percentages of the principal amount), plus accrued interest, if any, thereon to the date of redemption.Year Percentage 2012 103.6 % 2013 102.4 % 2014 101.2 % 2015 and thereafter 100.0 % 2006,2007, the interest rate equaled 5.36%was 4.99%.29, 2006,31, 2007, the closing price of our common stock traded on the New York Stock Exchange was $36.50.$42.53. There is not an observable market for the notes. Based on an average common stock price of $36.50,$42.53, management estimates the fair value of the notes at December 31, 20062007 was approximately $157.4$183.4 million (or $1,259$1,467 per bond).holders’holders' right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require Cimarexus to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013, and 2018. The indenture agreement also provides Cimarexus with an option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount and shares for the value of the convertible feature (plus accrued interest) anytime after December 22, 2008.2006,2007, we had contractual obligations and material commitments as follows: Payments Due by Period
1 Year
Years
Years
5 Years Total Less than
1 Year 1-3
Years 4-5
Years More than
5 Years (In thousands) $ 475,000 $ — $ — $ — $ 475,000 236,906 24,938 49,875 49,875 112,218 32,491 5,855 10,778 9,585 6,273 98,153 98,153 — — — Gas processing facility(2) 57,871 — 57,871 — — Asset retirement obligation 113,054 7,270 — (3) — (3) — (3) 6,828 37 65 56 6,670 (1) These amounts do not include interest on the $95 million of bank debt outstanding at December 31, 2006. The weighted average interest rate at December 31, 2006 on the bank debt was approximately 6.75%. See item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt.
At December 31, 2006,2007, we had a firm sales contract to deliver approximately fourone Bcf of natural gas over the next eightthree months. If this gas is not delivered, our financial commitment would be approximately $22.3$2.9 million. This commitment willmay fluctuate due to either price volatility and actualor volumes delivered. However, we believe nodo not anticipate that a financial commitment will be due based on our reserves and current production levels.due.
Cimarex has We have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $2.8$3.1 million.
All of the noted commitments were routine and were made in the normal course of our business.
Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts available under our
existing line ofbank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities.
20072008 Outlook
Our projected 2007 exploration and development expenditureexpenditures program rangingfor 2008 are projected to range from $800 million$1.1 billion to $1 billion will require a great deal of coordination and effort.$1.3 billion. Though there are a variety of factors that could curtail, delay or even cancel some of our drillingplanned operations, we believe our projected program has a high degree of occurrence.is likely to occur. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts in these areas warrant pursuit of the projects.
Costs Approximately 43% of operations on a per Mcfe basis for 2007 are estimated to approximate levels realized in late 2006. Should factors beyond our control change, our program and realized coststhe expenditures will vary from current projections. These factors could include volatility in commodity prices, changesbe in the supply ofMid-Continent area, 38% in the Permian Basin, 16% in the Gulf Coast area, and demand for oil and gas, weather conditions, governmental regulations and more.3% in our other areas.
Production estimates for 20072008 range from 450465 to 470485 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2006,2007, our realized prices averaged $6.50$7.05 per Mcf of gas and $61.96$69.71 per barrel of oil. Prices can be very volatile and the possibility of 20072008 realized prices being different than they were in 20062007 is high.
Costs of operations on a per Mcfe basis for 2008 are currently estimated as follows:
| | 2008 | 2007 | ||||
|---|---|---|---|---|---|---|
| Production expense | $1.20 - $1.30 | $ | 1.22 | |||
| Transportation expense | 0.16 - 0.18 | 0.16 | ||||
| DD&A and Asset retirement obligation | 2.85 - 3.00 | 2.86 | ||||
| General and Administrative | 0.28 - 0.32 | 0.30 | ||||
| Production taxes (% of oil and gas revenue) | 6.5% - 7.5 | % | 6.9 | % | ||
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. A complete list of our significant accounting policies are described in Note 4 to our Consolidated Financial Statements included in this report. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical accounting policies and estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee.
Oil and Gas Reserves
The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved undeveloped reserves can be subject
to an even greater possibility of revision. At year-end, 21 percent of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 62 percent are related to a project in Wyoming. Our reserve engineers review and revise our reserve estimates annually. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes.
We use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. It is also possible that a full cost ceiling limitation charge could occur in the period of the revision.
The following table presents information regarding reserve revisions largely resulting from items we do not control, such as revisions due to price, and other revisions resulting from better information due to production history, well performance and changes in production costs.
| | Years Ended December 31, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2007 | 2006 | 2005 | ||||||||||
| | Bcfe Change | Percent of total Reserves | Bcfe Change | Percent of total Reserves | Bcfe Change | Percent of total Reserves | |||||||
| Revisions resulting from price changes | 35.5 | 2.45 | % | (40.1 | ) | (2.88 | )% | 13.1 | 2.92 | % | |||
| Other changes in estimates | 22.0 | 1.52 | % | 3.5 | 0.25 | % | (1.9 | ) | (0.42 | %) | |||
| Total | 57.5 | 3.97 | % | (36.6 | ) | (2.63 | )% | 11.2 | 2.50 | % | |||
Non-price related revisions added 23.6 Bcfe over the three-year period 2005-2007, comprising 1.4 percent of total reserves added over the period of 1,669 Bcfe. An 8.5 Bcfe increase resulted from higher prices. See Note 17, Supplemental Oil and Gas Disclosures for additional reserve data.
Full Cost Accounting
We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to our full cost pool.
At the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and are adjusted for designated cash flow hedges. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the amount of full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial statements, these higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period.
Goodwill
We assess goodwill for impairment at least annually, and more often if volatility in oil and gas prices or other circumstances warrant. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the fair value of our nonproducing leases and other assets and liabilities. If our carrying amount for goodwill exceeds its estimated fair value, then a measurement of the loss must be performed and any deficiency is recorded as an impairment. To date, no related impairment has been recorded but we cannot predict when or if goodwill may be impaired in the future. Impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, materially lower oil and gas prices) reduce the fair value of our company.
Derivatives
We determine the fair value of derivative contracts based on the stated contract prices and current and projected market prices at the determination date discounted to reflect the time value of money until settlement. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled.
Depending on changes in oil and gas futures markets and management's view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions. See Note 5 to the Consolidated Financial Statements and Item 7A of this report for additional information regarding our derivative instruments.
Contingencies
A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us. In the normal course of business we have various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them we believe, individually or in aggregate, would not have a material adverse effect on our company.
Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. For example, as we analyze actual plugging and abandonment information, we may revise our estimates of current costs, the assumed annual inflation of these costs and/or the assumed productive lives of our wells. During 2007, we revised our existing estimated asset retirement obligation by $1.0 million, or approximately one percent of the asset retirement obligation at December 31, 2006, due to changes in the various related attributes. Over the past three years, revisions to the estimated asset retirement obligation averaged approximately 15% of the asset retirement obligation at the beginning of the year. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Recent Accounting Developments
In December 2007, the Financial Accounting Standards Board ("FASB") issued two new Statements. FASB Statement 141R,Business Combinations, requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at "full fair value". The Statement redefines various aspects related to the accounting for a business combination by now applying the acquisition method of accounting (previously referred to as the purchase method). FASB Statement 160,Noncontrolling Interests in Consolidated Financial Statements, requires noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both Statements are effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. We do not expect the adoption of either Statement to have a material impact on our financial statements.
ITEM 7A. Qualitative and Quantitative Disclosures about Market Risk
The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and value of our short-term investments. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.
Price Fluctuations
Our results of operations are highly dependent upon themajor market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and thoseunpredictable (See risk factors in Item 1).
Currently, we are largely accepting the volatility risk that the change in prices are constantly changing in response to market forces. Nearly allpresents. None of our revenuefuture oil production is subject to hedging. With regard to our future natural gas production, based on contracts currently in place, we have 40 MMBtu per day of gas production in 2008 that is subject to zero-cost collars (with weighted average floor and ceiling prices of $7.00 to $9.90). This amount represents approximately 12% of our estimated 2008 gas production (eight percent of our total Mcfe production).
While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. Mid-Continent gas would have to be above the sale of oil and gas, so these fluctuations, positive and negative, can$9.90 ceiling for us to have any downside risk. At December 31, 2007, the weighted average Mid-Continent prices for the 2008 contracts approximated $6.74. These contracts are not expected to have a significant impactmaterial effect on our results of operations and cash flows.
Monthly gas price realizations during 2006 ranged from $4.23 per Mcf to $8.43 per Mcf. Oil prices ranged from $54.85 per barrel to $70.61 per barrel. It is impossible to predict future oil andrealized gas prices with any degree of certainty.
In third quarter 2006, we entered into derivative contracts to mitigate a portion of our potential exposure to adverse market changes in the Mid-Continent region, in an environment of volatile gas prices. These arrangements, which were based on prices available in the financial markets at the time the contracts were entered into, will be settled in cash and will not require physical delivery of hydrocarbons. These hedges have been designated for hedge accounting treatment as cash flow hedges under SFAS No. 133 and therefore, gains and losses upon settlement of the hedges will be recognized in gas revenue in the period the contracts are settled. We believe that we have sufficient production volumes such that the hedge contract transactions will occur as expected.
The following tables reflect the volumes, weighted average contract prices and fair values of the contracts we have in place as of December 31, 2006. We are exposed to risks associated with these contracts arising from volatility in commodity prices and the unlikely event of non-performance by the counterparties to the agreements.2008. See Note 5 to the Consolidated Financial Statements and Derivative Instrumentsin Item 78 of this report for additional information regarding our derivative instruments.
|
|
|
|
|
|
|
| Mid-Continent |
| Fair Value |
| ||||||||
Commodity |
|
|
| Type |
| Volume/Day |
| Duration |
| Price |
| (000’s) |
| ||||||
Natural Gas |
| Collars |
| 80,000 MMBTU |
| Jan 07—Dec 07 |
|
| $ | 7.00 - $10.17 |
|
|
| $ | 41,945 |
|
| ||
Natural Gas |
| Collars |
| 40,000 MMBTU |
| Jan 08—Dec 08 |
|
| $ | 7.00 - $9.90 |
|
|
| 7,051 |
|
| |||
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|
|
|
|
|
|
|
|
|
|
|
| $ | 48,996 |
|
| |||
Interest Rate Risk
At December 31, 2006, the weighted average Mid-Continent prices for the 2007, and 2008 contracts approximated $6.13 and $7.02, respectively.
Interest Rate Risk
Fixed and Variable Rate Debt. Cimarex assumed fixed and variable ratewe had total debt as partoutstanding of the acquisition of Magnum Hunter. These agreements expose the company to market risk related to changes in interest rates. The company has a credit facility$487.2 million. Of this amount, $350 million is senior unsecured notes that bearsbear interest at either a Basefixed rate or a Eurodollarof 7.125% and will mature on May 1, 2017. The remaining debt is $125 million of unsecured convertible senior notes (face value) that mature on December 15, 2023. These convertible notes bear interest at an annual rate at the Company’s option.
equal to three-month LIBOR, reset quarterly. The following table presents the carrying and fairbook value of our debt approximates the company’s debt along with averagecurrent fair value.
We consider our interest ratesrate exposure to be minimal because as of December 31, 2006. The fair value2007 about 74% of our long-term debt obligations were at fixed rates. A 1% increase in the three-month LIBOR rate would increase annual interest expense by $1.25 million. This sensitivity analysis for the Convertible Notes was based on an average price per share of $36.50 for Cimarex common stock. The fair value for the fixed rate Senior Notes was valued at their last traded value before December 31, 2006.
Expected Maturity Dates |
|
|
| 2010 |
| 2012 |
| 2023 |
| Total |
| Book |
| Fair |
| ||||||
|
| (in thousands of dollars) |
| ||||||||||||||||||
Variable Rate Debt: |
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|
|
|
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|
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|
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| ||||||||
Bank debt(a) |
| $ | 95,000 |
| $ | — |
| $ | — |
| $ | 95,000 |
| $ | 95,000 |
| $ | 95,000 |
| ||
Convertible Notes(b) |
| $ | — |
| $ | — |
| $ | 125,000 |
| $ | 125,000 |
| $ | 137,921 |
| $ | 157,393 |
| ||
Fixed Rate Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Senior Notes(c) |
| $ | — |
| $ | 195,000 |
| $ | — |
| $ | 195,000 |
| $ | 210,746 |
| $ | 205,238 |
| ||
(a) At December 31, 2006, the weighted average interest rate on outstanding borrowings underrisk excludes accounts receivable, accounts payable and accrued liabilities because of the credit facility was approximately 6.75%.
(b) The interest rate on the convertible notes is 5.36%. The rate on these notes is equalshort-term maturity of such instruments. See Note 5 and Note 7 to the three month LIBOR, adjusted quarterly. A holderConsolidated Financial Statements in Item 8 of these notes has the right to require us to repurchase all or a portion of these notes on December 15, 2008, 2013, and 2018. The repurchase will be equal to the face value of the notes plus accrued and unpaid interest up to the date of repurchase. Included in Paid in Capital is $49.6 million related to the fair value of common stock associated with the convertiblethis report for additional information regarding debt.
(c)Market Value of Investments The interest rate
We currently have $14.4 million invested in an asset back securities fund. We expect to liquidate our investment in this fund within the next 12 months. A five percent change in these investments' market value would have a $0.7 million impact on the senior notes due 2012 is a fixed 9.6%.our investments.
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CIMAREX ENERGY CO.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES
All other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or related notes thereto.
Report of Independent Registered Public Accounting Firm The Board of Directors We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company) as of December 31, We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries as of December 31, We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the KPMG LLP Denver CIMAREX ENERGY CO. December 31, 2006 2005 Assets Current assets: Cash and cash equivalents $ 5,048 $ 61,647 Accounts receivable: Trade, net of allowance 62,866 66,723 Oil and gas sales, net of allowance 189,906 191,748 Gas gathering, processing, and marketing, net of allowance 8,083 30,471 Other 45,603 242 Inventories 39,397 34,784 Deferred income taxes 1,498 17,959 Derivative instruments 41,945 — Other current assets 22,411 25,454 Total current assets 416,757 429,028 Oil and gas properties at cost, using the full cost method of accounting: Proved properties 4,656,854 3,602,797 Unproved properties and properties under development, not being amortized 425,173 388,839 5,082,027 3,991,636 Less—accumulated depreciation, depletion and amortization (1,494,317 ) (1,114,677 ) Net oil and gas properties 3,587,710 2,876,959 Fixed assets, less accumulated depreciation of $33,273 and $17,171 88,924 86,916 Goodwill 691,432 717,391 Derivative instruments 7,051 — Other assets, net 37,876 70,041 $ 4,829,750 $ 4,180,335 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable: Trade $ 40,735 $ 50,529 Gas gathering, processing, and marketing 15,506 31,418 Accrued liabilities: Exploration and development 94,403 76,725 Taxes other than income 25,376 15,978 Other 82,384 86,373 Derivative instruments — 41,926 Revenue payable 96,184 94,469 Total current liabilities 354,588 397,418 Long-term debt 443,667 352,451 Deferred income taxes 921,665 717,790 Asset retirement obligation 124,821 97,558 Deferred compensation — 13,881 Other liabilities 8,866 5,784 Total liabilities 1,853,607 1,584,882 Commitments and contingencies Stockholders’ equity: Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued — — Common stock, $0.01 par value, 200,000,000 shares authorized, 83,962,132 and 83,524,285 shares issued, respectively 840 835 Treasury stock, at cost, 1,078,822 shares held (40,628 ) (43,554 ) Paid-in capital 1,867,448 1,865,597 Unearned compensation — (15,862 ) Retained earnings 1,117,402 788,356 Accumulated other comprehensive income 31,081 81 2,976,143 2,595,453 $ 4,829,750 $ 4,180,335 The accompanying notes are an integral part of these consolidated financial statements. CIMAREX ENERGY CO. For the Years Ended December 31, 2006 2005 2004 Revenues: Gas sales $ 810,894 $ 807,007 $ 366,260 Oil sales 404,517 265,415 106,129 Gas gathering and processing 47,879 44,238 101 Gas marketing, net of related costs of $144,702, $213,749 and $193,041 respectively 3,854 1,962 2,674 1,267,144 1,118,622 475,164 Costs and expenses: Depreciation, depletion and amortization 396,394 258,287 124,251 Asset retirement obligation accretion 7,018 3,819 1,241 Production 176,833 104,067 37,476 Transportation 21,157 15,338 10,003 Gas gathering and processing 27,410 31,890 284 Taxes other than income 91,066 73,360 37,761 General and administrative 42,288 33,497 22,483 Stock compensation, net 8,243 4,959 1,957 (Gain) loss on derivative instruments (22,970 ) 67,800 — Other operating, net 2,064 15,897 (3,394 ) 749,503 608,914 232,062 Operating income 517,641 509,708 243,102 Other (income) and expense: Interest expense net of capitalized interest of $24,248, $11,686 and $0, respectively 5,692 7,921 1,075 Amortization of fair value of debt (3,784 ) (2,132 ) — Other, net (28,591 ) (12,536 ) (4,291 ) Income before income tax expense 544,324 516,455 246,318 Income tax expense 198,605 188,130 92,726 Net income $ 345,719 $ 328,325 $ 153,592 Earnings per share: Basic $ 4.21 $ 5.07 $ 3.70 Diluted $ 4.11 $ 4.90 $ 3.59 Weighted average shares outstanding: Basic 82,066 64,761 41,466 Diluted 84,090 67,000 42,763 The accompanying notes are an integral part of these consolidated financial statements. CIMAREX ENERGY CO. Years Ended December 31, 2006 2005 2004 Cash flows from operating activities: Net income $ 345,719 $ 328,325 $ 153,592 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 396,394 258,287 124,251 Asset retirement obligation accretion 7,018 3,819 1,241 Deferred income taxes 220,539 112,890 66,849 Stock compensation, net 8,243 4,959 1,957 Derivative instruments (41,926 ) 3,483 — Gain on liquidation of equity investees (19,785 ) — — Other 1,540 12,844 798 Changes in operating assets and liabilities, net of effects of the acquisition of Magnum Hunter: (Increase) in receivables, net (9,811 ) (45,787 ) (35,696 ) (Increase) in inventory and other current assets (11,812 ) (27,293 ) (1,703 ) Increase (decrease) in accounts payable and accrued liabilities (18,293 ) 52,488 42,918 Increase in other noncurrent liabilities 593 719 1,646 Net cash provided by operating activities 878,419 704,734 355,853 Cash flows from investing activities: Oil and gas expenditures (1,030,791 ) (631,549 ) (281,407 ) Acquisition of oil and gas properties (23,790 ) (1,973 ) (324 ) Merger related costs (439 ) (13,740 ) — Cash received in connection with acquisition — 33,407 — Proceeds from sale of assets 10,705 141,842 926 Distributions received from equity investees 59,823 302 — Other expenditures (25,310 ) (25,742 ) (12,296 ) Net cash used by investing activities (1,009,802 ) (497,453 ) (293,101 ) Cash flows from financing activities: Borrowing (payments) on long-term debt, net 95,000 (273,501 ) — Treasury stock acquired and retired (11,016 ) — — Dividends paid (13,358 ) — — Proceeds from issuance of common stock and other 4,158 12,121 12,574 Net cash provided by (used in) financing activities 74,784 (261,380 ) 12,574 Net change in cash and cash equivalents (56,599 ) (54,099 ) 75,326 Cash and cash equivalents at beginning of period 61,647 115,746 40,420 Cash and cash equivalents at end of period $ 5,048 $ 61,647 $ 115,746 The accompanying notes are an integral part of these consolidated financial statements. CONSOLIDATED STATEMENTS OF (In thousands) Accumulated Other Total Common Stock Paid-in Unearned Retained Comprehensive Treasury Stockholders Shares Amount Capital Compensation Earnings Income Stock Equity Balance, December 31, 2003 41,064 $ 411 $ 237,430 $ (9,540 ) $ 306,439 $ — $ — $ 534,740 Issuance of restricted stock awards 15 — 400 (400 ) — — — — Issuance of restricted stock unit awards — — — (2,809 ) — — — (2,809 ) Common stock reacquired and retired (35 ) — (1,254 ) — — — — (1,254 ) Amortization of unearned compensation — — — 2,677 — — — 2,677 Exercise of stock options, net of tax benefit 691 6 13,822 — — — — 13,828 Shares of restricted stock exchanged for restricted stock units (6 ) — (150 ) — — — — (150 ) Comprehensive income: Net income — — — — 153,592 — — 153,592 Unrealized gain on marketable securities — — — — — 88 — 88 Total comprehensive income 153,680 Balance, December 31, 2004 41,729 $ 417 $ 250,248 $ (10,072 ) $ 460,031 $ 88 $ — $ 700,712 Issuance of common stock, net of offering costs 42,185 422 1,587,775 — — — — 1,588,197 Issuance of restricted stock awards 249 2 9,913 (9,915 ) — — — — Issuance of restricted stock unit awards — — — (2,856 ) — — — (2,856 ) Treasury Stock — — — — — — (96,161 ) (96,161 ) Common stock reacquired and retired (1,450 ) (14 ) (54,723 ) — — — 52,607 (2,130 ) Restricted stock forfeited and retired (2 ) — (80 ) 78 — — — (2 ) Amortization of unearned compensation — — — 4,259 — — — 4,259 Exercise of stock options, net of tax benefit 659 7 15,761 — — — — 15,768 Stock Option Compensation Expense — — 2,348 — — — — 2,348 Accelerated vesting of stock options, 154 1 4,713 2,644 — — — 7,358 Equity attributable to Floating rate — — 49,642 — — — — 49,642 Comprehensive income: Net income — — — — 328,325 — — 328,325 Unrealized loss on marketable securities — — — — — (7 ) — (7 ) Total comprehensive income 328,318 Balance, December 31, 2005 83,524 $ 835 $ 1,865,597 $ (15,862 ) $ 788,356 $ 81 $ (43,554 ) $ 2,595,453 Dividends — — — — (16,673 ) — — (16,673 ) Issuance of restricted stock awards 601 6 13,682 (13,688 ) — — — — Treasury Stock — — — — — — (8,090 ) (8,090 ) Common stock reacquired and retired (278 ) (3 ) (12,039 ) — — — 11,016 (1,026 ) Restricted stock forfeited and retired (55 ) (361 ) 314 — — — (47 ) Amortization of unearned compensation — — 7,019 2,262 — — — 9,281 Reclass restricted unit liability to unearned compensation 13,881 13,881 Reclass remaining unearned compensation (13,093 ) 13,093 — Exercise of stock options, net of tax benefit 170 2 4,313 — — — — 4,315 Stock Option Compensation Expense — — 2,330 — — — — 2,330 Comprehensive income: Net income — — — — 345,719 — — 345,719 Unrealized gain on derivatives, net of 30,954 30,954 Unrealized gain on marketable securities — — — — — 46 — 46 Total comprehensive income 376,719 Balance, December 31, 2006 83,962 $ 840 $ 1,867,448 $ — $ 1,117,402 $ 31,081 $ (40,628 ) $ 2,976,143 The accompanying notes are an integral part of these consolidated financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). In June of 2005, The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation. Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Our significant accounting policies are described in Note 4 to our Consolidated Financial Statements. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. Certain amounts in prior 2. DESCRIPTION OF BUSINESS Cimarex Energy Co. is an independent oil and gas exploration and production 3. BUSINESS COMBINATION On June 7, 2005, Cimarex completed the acquisition of Magnum Hunter Resources, Inc, an independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico. Terms of the merger agreement provided that Magnum Hunter stockholders receive 0.415 shares of Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Purchase Price (in millions): Shares of Cimarex common stock issued to Magnum Hunter stockholders 39.7 Average Cimarex stock price $ 37.66 Fair value of common stock issued $ 1,495.4 Plus: Merger costs incurred 7.4 Cash issued for fractional shares 0.1 Total purchase price 1,502.9 Plus: Liabilities assumed by Cimarex: Current liabilities 170.5 Fair value of long-term debt 627.3 Other non-current liabilities 78.5 Deferred income taxes 402.1 Value of common stock associated with convertible debt 49.6 Total purchase price plus liabilities assumed $ 2,830.9 Allocation of Purchase Price: Current assets $ 197.3 Proved oil and gas properties 1,514.2 Unproved oil and gas properties 308.0 Investments 61.2 Other property and equipment 57.0 Other non-current assets 46.8 Goodwill 646.4 $ 2,830.9 The following unaudited pro forma information has been prepared to give effect to the Magnum Hunter acquisition as if it had occurred at the beginning of the CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 3. BUSINESS COMBINATION (Continued) management, Years Ended December 31, 2005 2004 (Thousands of dollars, except per share data) Pro Forma Statement of Operations Data $ 1,393,715 $ 969,177 Net income 403,925 212,207 Net income per share: Basic $ 6.24 $ 2.61 Diluted 6.03 2.57 4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash and Cash Equivalents Cash and cash equivalents consist of cash in banks and investments readily convertible into cash which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates market value. Our short-term investments consist of investments in an asset-backed securities fund. The investments are classified as available-for-sale and are carried at fair value in our balance sheet. Unrealized holding gains and losses are reported in other comprehensive income. Inventories Inventories, primarily materials and supplies, are valued at the lower of cost or market. Oil and Gas Properties We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. At the end of each quarter, we make a full cost ceiling limitation calculation, CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) charged to expense. However, if commodity prices increase Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a quarterly basis, we evaluate such costs Goodwill We account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142,Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. If the Revenue Recognition Oil and Gas Sales Marketing Sales Gas Imbalances We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Oil and gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. In situations where there are insufficient reserves available to make-up an overproduced imbalance, then a liability is established. The natural gas imbalance liability at December 31, 2007 and 2006 CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) Oil and Gas Reserves The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although we make every reasonable effort We use the units-of-production method to amortize our oil and gas properties. Changes in reserve quantities and commodity prices will cause corresponding changes in depletion expense in periods subsequent to Transportation Costs Derivatives SFAS No.133,Accounting for Derivative Instruments and Hedging activities,requires that all derivatives be recorded on the balance sheet at fair value. We determine the fair value of derivative contracts based on the stated contract prices and current and projected market prices at the determination date discounted to reflect the time value of money until settlement. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled. CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) To mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas Income Taxes Deferred income taxes are computed using the liability method. Deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized. We adopted the Contingencies A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. At December 31, 2006, we Asset Retirement Obligations The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool. CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) Stock Options Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards Earnings per Share Basic earnings per share includes no dilution and is computed by dividing net income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the impact of potentially dilutive securities on weighted average number of shares. Comprehensive Income Comprehensive income is a term used to refer to net income plus other comprehensive income. Other comprehensive income is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of The components of other comprehensive income are as follows (in Net Net Unrealized Unrealized Gain (Loss) Accumulated Gain on On Marketable Other Derivative Securities of Comprehensive Instruments(1) Investments(1) Income Balance at January 1, 2004 $ — $ — $ — 2004 activity — 88 88 Balance at December 31, 2004 — 88 88 2005 activity — (7 ) (7 ) Balance at December 31, 2005 81 81 2006 activity 30,954 46 31,000 Balance at December 31, 2006 $ 30,954 $ 127 $ 31,081 CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) The table below sets forth the changes in the Unrealized derivative gain (loss) in comprehensive income, at January 1, 2006 $ — Change in fair value 48,996 Reclassification of net (gains) losses to income Net ineffectiveness 13 49,009 Related income tax effect (18,055 ) Unrealized derivative gain in comprehensive income atDecember 31, 2006 $ 30,954 Segment Information Cimarex has one reportable segment (exploration and production). In 5. Derivatives In connection with the Magnum Hunter merger, Cimarex derivative instruments were not designated for hedge accounting treatment. CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 5. FINANCIAL INSTRUMENTS (Continued) Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we Under the collar agreements, we receive the difference between an agreed upon index price and a floor price if the index price is below the floor price. We pay the difference between the agreed upon contracted ceiling price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. These Mid-Continent Fair Value Commodity Type Volume/Day Duration Price (000’s) Natural Gas Collars 80,000 MMBTU Jan 07—Dec 07 $7.00 - $10.17 $ 41,945 Natural Gas Collars 40,000 MMBTU Jan 08—Dec 08 $7.00 - $9.90 7,051 $ 48,996 At December 31, 2006, the At December 31, 2007, the fair value of the Short-term Investments In the fourth quarter of 2007 we invested $16 million in an asset-backed securities fund. The investments, which are expected to be liquidated in 2008, are classified as available-for-sale and marked-to-market at the end of each period, through other comprehensive income. As of December 31, 2007, we had liquidated $1.4 million of the investments with a realized loss of $17 thousand. We also recorded an unrealized loss of $183 thousand in other comprehensive income, resulting in a fair value attributable to the investments of $14.4 million. Debt Our revolving credit facility provides for $500 million of long-term committed credit. The carrying amount of the credit facility approximates the fair value because the interest rates on the credit facility are variable. At December 31, 2007, there were no outstanding borrowings under the credit facility. At December 31, 2006, the carrying amount of the outstanding borrowings was $95 million. CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 5. FINANCIAL INSTRUMENTS (Continued) The following table presents the carrying amounts and estimated fair values of our other debt instruments at December 31, 2007 and 2006. The carrying amounts for the convertible notes do not reflect $49.6 million of Paid in Capital attributable to the fair value of our common stock at the time we acquired the convertible notes in the Magnum Hunter merger. There is not an observable market for the convertible notes. The fair values of the convertible notes were based on the December 31st closing price per share for our common stock, which was $42.53 and $36.50 for 2007 and 2006, respectively. Therefore, the calculated fair value includes value attributable to both the face amount of the notes and the conversion feature. Other Financial Instruments The carrying amounts of our cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2007, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.6 million, $0.2 million, and zero, respectively. At December 31, 2006, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.7 million, $0.3 million, and zero, respectively. Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. 6. ASSET RETIREMENT OBLIGATIONS The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 6. ASSET RETIREMENT OBLIGATIONS (Continued) The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2006 2005 Asset retirement obligation at January 1 $ 101,128 $ 19,762 Liabilities incurred 15,318 5,735 Liabilities assumed in the Magnum Hunter merger — 68,908 Liabilities settled (4,337 ) (2,810 ) Accretion expense 6,391 3,699 Revisions of estimated liabilities 10,641 5,834 Asset retirement obligation at December 31 129,141 101,128 Less: Current asset retirement obligation 4,320 3,570 Long-term asset retirement obligation $ 124,821 $ 97,558 7. LONG-TERM DEBT Debt at December 31, Bank debt $ — 9.6% Notes due 2012 (face value $195,000) 213,770 (1) Floating rate convertible notes due 2023 (face value $125,000) 138,681 (2) Total long-term debt $ 352,451 Bank debt $ 95,000 9.6% Notes due 2012 (face value $195,000) 210,746 (1) Floating rate convertible notes due 2023, 5.36% at December 31, 2006 (face value $125,000) 137,921 (2) Total long-term debt $ 443,667 The 9.6% notes, which were assumed in the Magnum Hunter merger, were redeemed on May 18, 2007. The notes were redeemed at 104.8% of the principal amount plus accrued interest of $3.3 million through the redemption date, for a total of $207.6 million. At acquisition, the notes were recorded at a fair market value of $215.5 million. We recognized a gain on the early extinguishment of this debt of $5.1 million which is reflected on the income statement under Other income and expense. In May, 2007 we also sold $350 million of 7.125% senior unsecured notes that will mature May 1, 2017. The notes were sold to the public at par. Net proceeds from the sale were used to redeem the 9.6% notes and reduce borrowings under our credit facility. Interest on the notes is payable May 1 and November 1 of each year. The first interest payment was made on November 1, 2007. The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Year Percentage 2007 104.8 % 2008 103.2 % 2009 101.6 % 2010 and thereafter 100.0 % At any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price equal to 100% of the principal amount of the notes plus accrued and unpaid interest plus a "make-whole" premium. If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase. The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. At acquisition, the notes were recorded at a fair market value of $144.7 million, with an additional $49.6 million attributable to the conversion feature of the notes recorded in Paid in Capital. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. On December 31, Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above the fixed conversion price of $28.99 per share. On December conversion. In addition to the 8. INCOME TAXES Federal income tax expense for the years ended December 31, 2007, 2006, CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 8. INCOME TAXES (Continued) income taxes, and the Domestic Production Activities deduction. The components of the provision for income taxes are as follows (in thousands): Years Ended December 31, 2006 2005 2004 Current taxes: Federal $ (20,672 ) $ 66,994 $ 23,255 State (1,262 ) 8,246 2,622 (21,934 ) 75,240 25,877 Deferred taxes: Federal 211,534 108,487 61,571 State 9,005 4,403 5,278 220,539 112,890 66,849 $ 198,605 $ 188,130 $ 92,726 Reconciliations of the income tax expense calculated at the federal statutory rate of 35% to the total income tax expense are as follows (in thousands): Years Ended December 31, 2006 2005 2004 Provision at statutory rate $ 190,513 $ 180,759 $ 86,212 Effect of state taxes 7,564 9,301 6,472 Domestic Production Activities deduction — (2,095 ) — Other 528 165 42 Income tax expense $ 198,605 $ 188,130 $ 92,726 CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 8. INCOME TAXES (Continued) The components of December 31, 2006 2005 Long-term: Assets: Net operating loss carryforwards $ 24,176 $ 38,836 Credit carryforwards 1,627 1,207 Merger related accruals 25,762 40,124 Other 23,723 3,996 75,288 84,163 Liabilities: Property, plant and equipment (996,953 ) (801,953 ) Net, long-term deferred tax liability (921,665 ) (717,790 ) Current: Assets: Derivative instruments — 15,273 Other 1,498 2,686 1,498 17,959 Net deferred tax liabilities $ (920,167 ) $ (699,831 ) We have recorded deferred tax assets of We adopted the provisions of As of December 31, 2007, we made no provisions for interest or penalties related to uncertain tax positions. The tax years 2004 - 2006 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2003 - 2006 for examination. 9. CAPITAL STOCK Stock-based Compensation Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides for grants of stock options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common stock may be issued under the Plan. CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 9. CAPITAL STOCK (Continued) Restricted Stock and Units During The following table presents restricted stock activity during the last three years: Years Ended December 31, 2006 2005 2004 Outstanding beginning of period 249,905 14,145 24,086 Vested (7,915 ) (11,248 ) (19,086 ) Granted 600,589 249,008 9,145 Canceled (49,800 ) (2,000 ) — Outstanding end of period 792,779 249,905 14,145 The following table presents restricted unit activity during the last three years: Years Ended December 31, 2006 2005 2004 Outstanding beginning of period 697,937 780,787 693,600 Converted to Stock — (154,600 ) — Granted 4,954 71,750 87,187 Canceled (6,250 ) — — Outstanding end of period 696,641 697,937 780,787 Vested included in outstanding 172,617 128,550 84,480 Vesting of restricted stock and units granted in years Compensation expense for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 9. CAPITAL STOCK (Continued) to the restricted stock and unit awards is recognized ratably over the applicable vesting period. Unamortized compensation costs related to Stock Options There were no stock options granted during 2007. Information about outstanding stock options is summarized below: Weighted Weighted Average Average Aggregate Exercise Remaining Intrinsic Shares Price Term Value (000) Outstanding as of January 1, 2006 2,023,388 $ 15.64 Exercised (170,459 ) 15.83 Granted 60,600 34.63 Canceled — — Outstanding as of December 31, 2006 1,913,529 $ 16.23 4.7 Years $ 39,127 Exercisable as of December 31, 2006(1) 1,607,249 $ 14.93 4.2 Years $ 34,758 The total intrinsic value of stock options exercised during During The weighted-average grant-date fair value of stock options granted during the years ended December 31, 2006 CIMAREX ENERGY CO. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 9. CAPITAL STOCK (Continued) exercise, expected years until exercise and potential forfeitures. The risk-free interest rate used is the five-year U.S. Treasury bond in effect at the date of the grant. The following summarizes the assumptions used to determine the fair market value of options issued during the last three years: Years Ended December 31, 2006 2005 2004 Expected years until exercise 7.5 7.5 7.5 Expected stock volatility 32.2 % 25.5 % 25.4 % Dividend yield 0.1 % 0.0 % 0.0 % Risk-free interest rate 4.8 % 4.1 % 3.4 % Cash received from option exercises during the years ended December 31, 2007, 2006, The following summary reflects the status of non-vested stock options granted to employees and directors as of December 31, Weighted Average Grant Date Shares Fair Value Non-vested as of January 1, 2006 456,260 $ 8.75 Vested (216,640 ) 8.41 Granted 60,600 15.75 Forfeited — — Non-vested as of December 31, 2006 300,220 $ 10.41 As of December 31, The total grant-date fair value of options that vested during 2004 Net income, as reported $ 153,592 Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects 2,121 Pro forma net income $ 151,471 Earnings per share: Basic—as reported $ 3.70 Basic—pro forma $ 3.65 Diluted—as reported $ 3.59 Diluted—pro forma $ 3.54 Stockholder Rights Plan
Cimarex Energy Co.:20062007 and 2005,2006, and the related consolidated statements of operations, stockholders’stockholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006.2007. These consolidated financial statements are the responsibility of the Company’sCompany's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.20062007 and 2005,2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006,2007, in conformity with U.S. generally accepted accounting principles.effectiveness of the Company’sCompany's internal control over financial reporting as of December 31, 2006,2007, based on the criteria established inInternal Control-IntegratedControl—Integrated Framework issued by the Committee of the Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 200728, 2008 expressed an unqualified opinion on management’s assessmentthe effectiveness of and the effective operation of,Company's internal control over financial reporting.As discussed in Note 4 to the Consolidated Financial Statements, Cimarex Energy Co. adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payment, as of January 1, 2005.
February 28, 2008February 27, 200742
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share information) December 31, 2007 2006 Assets Current assets: Cash and cash equivalents $ 123,050 $ 5,048 Short-term investments 14,391 — Accounts receivable: Trade, net of allowance 64,600 62,866 Oil and gas sales, net of allowance 244,299 189,906 Gas gathering, processing, and marketing, net of allowance 6,428 8,083 Other — 45,603 Inventories 29,642 39,397 Deferred income taxes 5,697 1,498 Derivative instruments 12,124 41,945 Other current assets 64,346 22,411 Total current assets 564,577 416,757 Oil and gas properties at cost, using the full cost method of accounting: Proved properties 5,545,977 4,656,854 Unproved properties and properties under development, not being amortized 364,618 425,173 5,910,595 5,082,027 Less—accumulated depreciation, depletion and amortization (1,938,863 ) (1,494,317 ) Net oil and gas properties 3,971,732 3,587,710 Fixed assets, less accumulated depreciation of $49,629 and $33,273 90,584 88,924 Goodwill 691,432 691,432 Derivative instruments — 7,051 Other assets, net 44,469 37,876 $ 5,362,794 $ 4,829,750 Liabilities and Stockholders' Equity Current liabilities: Accounts payable: Trade $ 41,213 $ 40,735 Gas gathering, processing, and marketing 11,458 15,506 Accrued liabilities: Exploration and development 92,640 94,403 Taxes other than income 26,109 25,376 Other 121,638 82,384 Revenue payable 131,513 96,184 Total current liabilities 424,571 354,588 Long-term debt 487,159 443,667 Deferred income taxes 1,076,223 921,665 Asset retirement obligation 105,784 124,821 Other liabilities 9,770 8,866 Total liabilities 2,103,507 1,853,607 Commitments and contingencies Stockholders' equity: Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued — — Common stock, $0.01 par value, 200,000,000 shares authorized, 83,620,480 and 83,962,132 shares issued, respectively 836 840 Treasury stock, at cost, 1,078,822 shares held (40,628 ) (40,628 ) Paid-in capital 1,842,690 1,867,448 Retained earnings 1,448,763 1,117,402 Accumulated other comprehensive income 7,626 31,081 3,259,287 2,976,143 $ 5,362,794 $ 4,829,750
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data) For the Years Ended
December 31, 2007 2006 2005 Revenues: Gas sales $ 845,631 $ 810,894 $ 807,007 Oil sales 518,991 404,517 265,415 Gas gathering and processing 61,471 47,879 44,238 Gas marketing, net of related costs of $107,678, $144,702 and $213,749 respectively 5,073 3,854 1,962 1,431,166 1,267,144 1,118,622 Costs and expenses: Depreciation, depletion and amortization 461,791 396,394 258,287 Asset retirement obligation 8,937 7,018 3,819 Production 201,512 176,833 104,067 Transportation 26,361 21,157 15,338 Gas gathering and processing 30,513 27,410 31,890 Taxes other than income 93,630 91,066 73,360 General and administrative 49,260 42,288 33,497 Stock compensation, net 10,772 8,243 4,959 (Gain) loss on derivative instruments — (22,970 ) 67,800 Other operating, net 6,637 2,064 15,897 889,413 749,503 608,914 Operating income 541,753 517,641 509,708
Other (income) and expense:
Interest expense 37,966 29,940 19,607 Capitalized interest (19,680 ) (24,248 ) (11,686 ) Amortization of fair value of debt (1,908 ) (3,784 ) (2,132 ) Gain on early extinquishment of debt (5,099 ) — — Other, net (14,151 ) (28,591 ) (12,536 )
Income before income tax expense
544,625
544,324
516,455
Income tax expense 198,156 198,605 188,130 Net income $ 346,469 $ 345,719 $ 328,325 Earnings per share: Basic $ 4.23 $ 4.21 $ 5.07 Diluted $ 4.09 $ 4.11 $ 4.90 Weighted average shares outstanding: Basic 81,819 82,066 64,761 Diluted 84,632 84,090 67,000
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)thousands, except per share data) Years Ended
December 31, 2007 2006 2005 Cash flows from operating activites: Net income $ 346,469 $ 345,719 $ 328,325 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 461,791 396,394 258,287 Asset retirement obligation 8,937 7,018 3,819 Deferred income taxes 167,507 220,539 112,890 Stock compensation, net 10,772 8,243 4,959 Derivative instruments — (41,926 ) 3,483 Gain on liquidation of equity investees (3,015 ) (19,785 ) — Other (6,791 ) 1,540 12,844 Changes in operating assets and liabilities (Increase) in receivables, net (7,777 ) (9,811 ) (45,787 ) (Increase) in inventory and other current assets (32,180 ) (11,812 ) (27,293 ) Increase (decrease) in accounts payable and accrued liabilities 55,436 (18,293 ) 52,488 Increase (decrease) in other non-current liabilities (6,469 ) 593 719 Net cash provided by operating activities 994,680 878,419 704,734 Cash flows from investing activities: Oil and gas expenditures (1,021,456 ) (1,054,581 ) (633,522 ) Merger related costs — (439 ) (13,740 ) Cash received in connection with acquisition — — 33,407 Proceeds from sale of assets 177,195 10,705 141,842 Distributions received from equity investees 3,015 59,823 302 Purchases of short-term investments (16,000 ) — — Sales of short-term investments 1,424 — — Other expenditures (19,574 ) (25,310 ) (25,742 ) Net cash used by investing activities (875,396 ) (1,009,802 ) (497,453 ) Cash flows from financing activites: Net Increase (decrease) in bank debt (95,000 ) 95,000 — Increase in other long-term debt 350,000 — — Decrease in other long-term debt (204,360 ) — (273,501 ) Financing costs incurred (6,113 ) (153 ) (1,516 ) Treasury stock acquired and retired (42,266 ) (11,016 ) — Dividends paid (13,429 ) (13,358 ) — Proceeds from issuance of common stock and other 9,886 4,311 13,637 Net cash provided by (used in) financing activities (1,282 ) 74,784 (261,380 ) Net change in cash and cash equivalents 118,002 (56,599 ) (54,099 ) Cash and cash equivalents at beginning of period 5,048 61,647 115,746 Cash and cash equivalents at end of period $ 123,050 $ 5,048 $ 61,647 45STOCKHOLDERS’STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
of $4,805 recorded in paid-in capital
of investments, net of tax
of $6,442 recorded in paid-in capital
restricted stock and restricted stock
units
convertible notes
of investments, net of tax
to paid-in capital
of $1,618 recorded in paid-in capital
tax
of investments, net of tax Common Stock Accumulated
Other
Comprehensive
Income Paid-in
Capital Unearned
Compensation Retained
Earnings Treasury
Stock Total
Stockholders'
Equity Shares Amount Balance, December 31, 2004 41,729 $ 417 $ 250,248 $ (10,072 ) $ 460,031 $ 88 $ — $ 700,712
Issuance of common stock, net of offering costs
42,185
422
1,587,775
—
—
—
—
1,588,197
Issuance of restricted stock awards 249 2 9,913 (9,915 ) — — — — Issuance of restricted stock unit awards — — — (2,856 ) — — — (2,856 ) Treasury Stock — — — — — — (96,161 ) (96,161 ) Common stock reacquired and retired (1,450 ) (14 ) (54,723 ) — — — 52,607 (2,130 ) Restricted stock forfeited and retired (2 ) — (80 ) 78 — — — (2 ) Amortization of unearned compensation — — — 4,259 — — — 4,259 Exercise of stock options, net of tax benefit of $6,442 recorded in paid-in capital 659 7 15,761 — — — — 15,768 Stock Option Compensation Expense — — 2,348 — — — — 2,348 Accelerated vesting of stock options, restricted stock and restricted stock units 154 1 4,713 2,644 — — — 7,358 Equity attributable to Floating rate convertible notes — — 49,642 — — — — 49,642 Comprehensive income: Net income — — — — 328,325 — — 328,325 Unrealized loss on marketable securities of investments, net of tax — — — — — (7 ) — (7 ) Total comprehensive income 328,318 Balance, December 31, 2005 83,524 $ 835 $ 1,865,597 $ (15,862 ) $ 788,356 $ 81 $ (43,554 ) $ 2,595,453
Dividends
—
—
—
—
(16,673
)
—
—
(16,673
) Issuance of restricted stock awards 601 6 13,682 (13,688 ) — — — — Treasury Stock — — — — — — (8,090 ) (8,090 ) Common stock reacquired and retired (278 ) (3 ) (12,039 ) — — — 11,016 (1,026 ) Restricted stock forfeited and retired (55 ) (361 ) 314 — — — (47 ) Amortization of unearned compensation — — 7,019 2,262 — — — 9,281 Reclass restricted unit liability to unearned compensation — — — 13,881 — — — 13,881 Reclass remaining unearned compensation to paid-in capital — — (13,093 ) 13,093 — — — — Exercise of stock options, net of tax benefit of $1,618 recorded in paid-in capital 170 2 4,313 — — — — 4,315 Stock Option Compensation Expense — — 2,330 — — — — 2,330 Comprehensive income: Net income — — — — 345,719 — — 345,719 Unrealized gain on derivatives, net of tax — — — — — 30,954 — 30,954 Unrealized gain on marketable securities of investments, net of tax — — — — — 46 — 46 Total comprehensive income 376,719 Balance, December 31, 2006 83,962 $ 840 $ 1,867,448 $ — $ 1,117,402 $ 31,081 $ (40,628 ) $ 2,976,143
Dividends
—
—
—
—
(15,108
)
—
—
(15,108
) Issuance of restricted stock awards 572 5 (5 ) — — — — — Treasury Stock — — — — — — (42,266 ) (42,266 ) Common stock reacquired and retired (1,306 ) (13 ) (49,270 ) — — — 42,266 (7,017 ) Restricted stock forfeited and retired (61 ) (1 ) 1 — — — — — Amortization of unearned compensation — — 12,738 — — — — 12,738 Exercise of stock options, net of tax benefit of $4,026 recorded in paid-in capital 454 5 9,881 — — — — 9,886 Stock Option Compensation Expense — — 1,897 — — — — 1,897 Comprehensive income: Net income — — — — 346,469 — — 346,469 Net change from hedging activity — — — — — (23,302 ) — (23,302 ) Unrealized loss on short-term investments and other, net of tax — — — — — (153 ) — (153 ) Total comprehensive income 323,014 Balance, December 31, 2007 83,621 $ 836 $ 1,842,690 $ — $ 1,448,763 $ 7,626 $ (40,628 ) $ 3,259,287 46As a result of a dividend in the form of Cimarex common stock declared and paid by H&P onOn September 30, 2002, Cimarex was spun-off and became a stand-alone company. Also on September 30, 2002, Cimarex acquired 100 percent100% of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange.Cimarexwe acquired Magnum Hunter Resources, Inc. Termsin a stock-for-stock merger. Magnum Hunter's results of the merger agreement provided that Magnum Hunter stockholders receive 0.415 sharesoperations are included in our consolidated statements of Cimarex common stock for each share of Magnum Hunter common stock. As a result of the merger, Cimarex issued 39.7 million common shares to Magnum Hunter’s common stockholders. The merger was accounted for as a purchase of Magnum Hunter by Cimarex.operations beginning June 7, 2005.years’years' financial statements have been reclassified to conform to the 20062007 financial statement presentation.company.company with operations entirely located in the United States. Our oil and gas reserves and operations are presently focused primarilymainly located in Texas, Oklahoma, Texas, New Mexico, Kansas, Louisiana, and the Gulf of Mexico.Wyoming.Hunter’sHunter's common stockholders. The merger was accounted for as a purchase of Magnum Hunter by Cimarex and the results of operations of Magnum Hunter are included in our consolidated statements of operations for the periodperiods since the acquisition on June 7, 2005.acquisition.The purchase price of Magnum Hunter’s assets was based on the value of Cimarex common stock issued to the Magnum Hunter stockholders and the fair value of assumed liabilities. The value of the common stock issued is based on the weighted average price of Cimarex’s common stock for the period beginning two days before and ending two days after the announcement of the merger, or $37.66 per share. The purchase price also includes merger costs incurred, which include investment banking expenses, legalCIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)and accounting fees, printing expenses, and other related costs. Below is the final purchase price allocation:Included in current assets on the acquisition date of June 7, 2005 were assets available for sale of approximately $8.5 million acquired in the Magnum Hunter merger. These assets were sold during the third quarter of 2005 for approximately $8.1 million.CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)periods presented.year. The unaudited pro forma data is presented for illustrative purposes only, based on estimates and assumptions deemed appropriate by including the preliminary purchase allocation and interest on Magnum Hunter debt assumed, and should not be relied upon as an indication of the operating results that Cimarex would have achieved if the transaction had occurred on January 1, 2004. The pro forma information also should not be used as an indication of future results or trends.2005.For the year ended December 31, 2005: Revenues $ 1,393,715 Net income 403,925 Net income per share: Basic $ 6.24 Diluted 6.03 InventoriesShort-term Investments is made whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used in the calculation of the full cost ceiling limitation are determined based on current oil and gas prices and isare adjusted for designated cash flow hedges if it is determined that net capitalized costs exceedhedges. Increases and decreases in proved reserve estimates, due to quantity revisions or fluctuations in commodity prices, will result in corresponding changes to the full cost ceiling limit.limitation. If net capitalized costs subject to amortization were to exceed this limit, the excess would be charged to expense.subsequent toafter period end and prior tobefore issuance of the financial statements, thesethe higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period. are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.Proceeds from the sale of oil and gas properties are credited against capitalized costs, unless such proceeds would significantly alter the amortization base. Expenditures for maintenance and repairs are charged to production expense in the period incurred.estimated fair value exceeds its carrying amount, goodwill is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. To date, no related impairment has been recorded.Revenue Revenues from the sale of oil and gas is recognized when title passes, net of royalties. This is known assales are based on the sales method, (versus the entitlement method). Under the sales method,with revenue is recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production.Cimarex markets We market and sellssell natural gas for working interest partners under short term sales and supply agreements and earnsearn a fee for such services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the accompanying consolidated statement of operations.CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)and 2005 was $3.2$3.6 million and $2.7$3.2 million, respectively. At December 31, 2007 and 2006, we arewere also in an under-produced position relative to certain other third parties. is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Revisions of previous estimates increased our proved reserves by 57.5 Bcfe, or 4% of total proved reserves, at December 31, 2007. Estimations of proved undeveloped reserves can be subject to an even greater possibility of revision. At year-end, 21.4% of our total proved reserves are categorized as proved undeveloped. Of these proved undeveloped reserves, 62% are related to a project in Wyoming.the quantity revisionthese changes, or, in some cases, a full cost ceiling limitation charge in the period of the revision. To date, changes in expense resulting from changes in previous estimates of reserves have not been material.Cimarex accounts We account for transportation costs under Emerging Issues Task Force (“EITF”("EITF") 00-10Accounting for Shipping and Handling Fees and Costs.Amounts paid for transportation are classified as an operating expense and are not netted against gas sales.In connection with Existing commodity derivatives acquired in the Magnum Hunter merger Cimarex recognized a $39.3 million net liability associated with Magnum Hunter’s existing commodity derivatives at the merger date (June 7, 2005). These derivative instruments havedid not been designatedqualify for hedge accounting treatment. As a result, Cimarex recognized a net gain for the year ended December 31, 2006 of $23.0 million. Activity included both non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts that settled in the year ended December 31, 2006 was $19.0 million. As of December 31, 2006, all derivativeof the contracts assumed with the Magnum Hunter merger had matured.have expired.51In the third quarter of 2006, we entered into additional derivative contracts to4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)prices. Using zero-cost collars with Mid-Continent weighted average floor and ceiling prices, of $7.00 to $10.17 for 2007 and $7.00 to $9.90 for 2008, we hedged 29.2 million MMBTU and 14.6 million MMBTU of our anticipated Mid-Continent gas production for 2007 and 2008, respectively. At December 31, 2006, this represented approximately 51% and 31% of our current anticipated Mid-Continent gas production for 2007 and 2008, respectively.Under the collar agreements, we will receive the difference between an agreed upon Mid-Continent index price and a floor price if the index price is below the floor price. We will pay the difference between the agreed upon contracted ceiling price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices.entered into additional derivative contracts in 2006. These contracts have beenwere designated for hedge accounting treatment as cash flow hedges.hedges for accounting treatment purposes.For the year ended December 31, 2006, Depending on changes in oil and gas futures markets and management's view of underlying oil and natural gas supply and demand trend, we recorded an unrealized loss of $13 thousand related to the ineffective portion of the hedges. At December 31, 2006, $41.9 million and $7.1 million of the contracts were recorded asmay increase or decrease our current and long-term assets, respectively, and an unrealized gain (net of deferred income taxes) of $31.0 million was recorded in other comprehensive income.hedging positions. See Note 5 to the Consolidated Financial Statements and Item 7 of this report for additional information regarding our derivative instruments. In July 2006,FASB issuedprovisions of Financial Accounting Standards Board Interpretation No. 48 Accounting"Accounting for Uncertainty in Income Taxes, whichTaxes" ("FIN 48") an interpretation of FASB Statement No. 109 "Accounting for Income Taxes", on January 1, 2007. The interpretation clarifies the accounting for uncertainty in income taxes recognized in the Company’sour financial statements in accordance with SFAS 109 “Accounting for Income Taxes”. The Interpretation alsoand provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The Interpretation is effective as of the beginning of the first fiscal year beginning after December 15, 2006 (January 1, 2007 for calendar-year companies). We are currently evaluating the effects of implementing this interpretation and do not believe the adoption of this interpretation willFIN 48 resulted in no impact to our consolidated financial statements and we have a materialno unrecognized tax benefits that would impact on our financial statements.effective rate.Contingencies As ofhavehad accrued $7.1$8.6 million for a mediated litigation settlement pertaining to post-production deductionssettlements which were paid in 2007 with associated interest. In the normal course of business, we have various other litigation related matters and associated accruals, the resolution of which we believe, individually or in aggregate, would not have a material adverse effect on properties operated by Cimarex. We have also accrued an additional $1.5 million for a mediated litigation settlement pertaining to oil and gas property title issues. We anticipate payment of both settlements during 2007.CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)our company.(“SFAS”("SFAS") No. 123R,Share Based Paymenton a modified prospective basis. SFAS No. 123R requires companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation to employees.Fair Value of Financial InstrumentsThe carrying amounts of our cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities of these assets and liabilities. At December 31, 2006, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.7 million, $0.3 million, and $0.0 million, respectively. At December 31, 2005, the allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $3.9 million, $1.2 million, and $0.7 million, respectively. The fair value of our variable and fixed rate debt at December 31, 2006 and 2005 was $457.6 million and $405.8 million, respectively.shareholders’shareholders' equity instead of net income.CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)000’s)000's): Net
Unrealized
Gain on
Derivative
Instruments(1) Net
Unrealized
Gain (Loss)
On Short-Term
Investments
and Other(1) Accumulated
Other
Comprehensive
Income Balance at January 1, 2005 $ — $ 88 $ 88 2005 activity — (7 ) (7 ) — 81 81 30,954 46 31,000 30,954 127 31,081 2007 activity (23,302 ) (153 ) (23,455 ) Balance at December 31, 2007 $ 7,652 $ (26 ) $ 7,626 Company’sCompany's unrealized gains on derivative instruments included as a component of comprehensive income infor the years ended December 31, 2007 and 2006 (in 000’s)000's): 2007 2006 Unrealized derivative gain in comprehensive income, at January 1 $ 49,009 $ — (9,043 ) 48,996 Reclassification of net gains to income (27,829 ) — (49 ) 13 12,088 49,009 (4,436 ) (18,055 ) Unrealized derivative gain in comprehensive income at December 31 $ 7,652 $ 30,954 RecentRecently Issued Accounting StandardsSeptember 2006December 2007, the SecuritiesFinancial Accounting Standards Board ("FASB") issued two new Statements. FASB Statement 141R,Business Combinations, requires most identifiable assets, liabilities, noncontrolling interests, and Exchange Commission issued Staff Accounting Bulletin No. 108 regarding the process of quantifying misstatements withingoodwill acquired in a financial statement, addressing in particular materiality analysisbusiness combination to be recorded at "full fair value". The Statement redefines various aspects related to the correctionaccounting for a business combination, by now applying the acquisition method of errors. The impactaccounting (previously referred to as the purchase method). FASB Statement 160,Noncontrolling Interests in Consolidated Financial Statements, requires noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both Statements are effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. We do not expect the current year financial statementsadoption of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, must be quantified. Adjustment would be required if the misstatement is deemed material, after considering all relevant quantitative and qualitative factors. The periods in which the coorrection would be recorded would be dependent on the materiality considerations for each affected period. This did noteither Statement to have a material impact on our financial statements.DERIVATIVESFINANCIAL INSTRUMENTSrecognized a $39.3 million liability associated withacquired Magnum Hunter’sHunter's existing commodity derivatives at the merger date (June 7, 2005).derivatives. TheseCIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)As a result,During 2006, Cimarex recognized a net gain during 2006 of $23.0 million. In 2005, we recorded a total net loss of $67.8 million. Activity includesin both years included non-cash mark-to-market derivative gains and losses as well as cash settlements. Cash payments related to these contracts for 2006 totaled $19.0 million, and $83.3$83.4 million from the date of the merger through the fourth quarter of 2006. There is no derivative liability atAs of December 31, 2006, related to these contracts as all derivative instruments havecontracts assumed with the merger had expired.To In 2006, we entered into additional derivative contracts to mitigate a portion of theour potential exposure to adverse market changes in an environment of volatile gas prices. Using zero-cost collars withentered into additional derivativehedged 29.2 million MMBtu and 14.6 million MMBtu of our anticipated Mid-Continent gas production for 2007 and 2008, respectively. At December 31, 2007, the remaining contracts in July 2006.outstanding represented approximately 24% of our current anticipated Mid-Continent gas production for 2008.derivativescontracts have been designated for hedge accounting treatment as cash flow hedges.During Settlements received during the quarteryear ended December 31, 2007 equaled $27.8 million which were recorded in gas sales and increased the average realized price for the year by $0.23 per Mcf. During the periods ended December 31, 2007 and 2006, we recognized an unrealized gain of $47$49 thousand and an unrealized loss of $13 thousand, respectively, related to the ineffective portion of the derivative contracts. The following table sets forth the terms of the related derivative contracts at December 31, 2006:
Weighted Average$49.0fair value of $41.9 million and $7.1 million of the contracts were recorded as current and long-term assets, respectively, and an unrealized gain (net of deferred income taxes) of $31 million was recorded in other comprehensive income.derivativeremaining contracts was approximately $12.1 million and was recorded as a current asset of $41.9 million and a long term asset of $7.1 million on our consolidated balance sheet.asset. An unrealized gain (net of deferred income taxes) of $31.0$7.7 million was recorded in other comprehensive income. Based on the estimated fair values of the derivative contracts at December 31, 2006,2007, the amount of unrealized gain (net of deferred income taxes) to be reclassified from accumulated other comprehensive income to gas revenue in the next twelve months would be approximately $26.5 million; however, actual gains and losses recognized may differ significantly. At December 31, 2006, the weighted average Mid-Continent prices for the 2007 and 2008 contracts approximated $6.13 and $7.02, respectively.$7.7 million. We believe that we have sufficient production volumes such that the hedge contract transactions will occur as expected. 2007 2006 Carrying
Amount Fair
Value Carrying
Amount Fair
Value (In thousands) 7.125% Notes due 2017(1) $ 350,000 $ 346,504 $ — $ — 9.6% Notes due 2012 (face value $195,000)(1) — — 210,746 205,238 Floating rate convertible notes due 2023 (face value $125,000) 137,159 183,395 137,921 157,393 20062007 and 20052006 (in thousands): 2007 2006 Asset retirement obligation at January 1 $ 129,141 $ 101,128 Liabilities incurred 5,063 15,318 Liabilitiy settlements and disposals (25,880 ) (4,337 ) Accretion expense 6,628 6,391 Revisions of estimated liabilities (1,898 ) 10,641 Asset retirement obligation at December 31 113,054 129,141 Less: Current asset retirement obligation 7,270 4,320 Long-term asset retirement obligation $ 105,784 $ 124,821 2005 consisted of the following (in thousands):Debt at December 31,2007 and 2006 consisted of the following (in thousands): 2007 2006 Bank debt $ — $ 95,000 9.6% Notes due 2012 (face value $195,000) — 210,746 7.125% Notes due 2017 350,000 — Floating rate convertible notes due 2023 (face value $125,000) 137,159 137,921 Total long-term debt $ 487,159 $ 443,667 (1) Fair market value at June 7, 2005 (date of acquisition of Magnum Hunter) equaled $215.5 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value.(2) Fair market value at June 7, 2005 equaled $144.75 million. The subsequent noted balances represent the fair market value at date of acquisition less amortization of the premium of fair market value over face value.Cimarex’s Revolving Credit Facility Our revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At December 31, 2006,2007, there were no outstanding borrowings of $95 million under the Revolving Credit Facility at a weighted average interest rate of approximately 6.75%.revolving credit facility. We also had letters of credit for approximately $5$2.7 million posted against the borrowing base, leaving an unused borrowing amount of approximately $400$497.3 million at December 31, 2006.2007.56 The credit facility agreement contains both financial and non-financial covenants which we do not view as materially restrictive.The Credit Facility agreement contains both financial and non-financial covenants. Cimarex continues to comply with these covenants and does not view them as materially restrictive.7. LONG-TERM DEBT (Continued)The 9.6% notes assumed in the Magnum Hunter merger have a face value of $195 million and are due March 15, 2012. The notes are unsecured and are redeemable, as a whole or in part, at Cimarex’s option, on and after March 15, 2007 at the following redemption prices (expressed as percentages of the principal amount), plus accrued interest, if any, thereon to the date of redemption.Year Percentage 2012 103.6 % 2013 102.4 % 2014 101.2 % 2015 and thereafter 100.0 % 2006,2007, the interest rate equaled 5.36%4.99%.29, 2006,31, 2007, the closing price of our common stock traded on the New York Stock Exchange was $36.50. There is not an observable market$42.53. To date, no holders have surrendered their notes for the notes. Based on an average common stock price of $36.50, management estimates the fair value of the notes at December 31, 2006 was approximately $157.4 million (or $1,259 per bond).holders’holders' right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require Cimarex to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013, and 2018. The indenture agreementindentureagreement also provides Cimarex with an option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount (plus accrued interest) anytime after December 22, 2008.CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)2005 and 20042005 differ from the amounts that would be provided by applying the U.S. Federal income tax rate, due to the effect of state Years Ended December 31, 2007 2006 2005 Current taxes: Federal $ 26,993 $ (20,672 ) $ 66,994 State 3,656 (1,262 ) 8,246 30,649 (21,934 ) 75,240 Deferred taxes: Federal 162,122 211,534 108,487 State 5,385 9,005 4,403 167,507 220,539 112,890 $ 198,156 $ 198,605 $ 188,130 Years Ended December 31, 2007 2006 2005 $ 190,619 $ 190,513 $ 180,759 9,041 7,564 9,301 (1,723 ) — (2,095 ) 219 528 165 $ 198,156 $ 198,605 $ 188,130 Cimarex’sCimarex's net deferred tax liabilities are as follows (in thousands): December 31, 2007 2006 Long-term: Assets: Net operating loss carryforwards $ — $ 24,176 Credit carryforwards 3,587 1,627 Merger related accruals — 25,762 Other 1,474 23,723 5,061 75,288 Liabilities: Property, plant and equipment (1,081,284 ) (996,953 ) Net, long-term deferred tax liability (1,076,223 ) (921,665 ) Current: Assets: Derivative instruments 4,445 — Other 1,252 1,498 5,697 1,498 Net deferred tax liabilities $ (1,070,526 ) $ (920,167 ) The company has a net tax operating loss (NOL) carryforward of approximately $66.3 million at December 31, 2006. The NOL carryforward expires from 2017 through 2022. The NOL carryforward was acquired as part of an acquisition, and therefore, is subject to annual limitations on its use. We believe that the carryforward will be utilized before it expires. The Company has an alternative minimum tax credit carryfoward of approximately $1.6 million at December 31, 2006.$76.8$10.8 million of which $24.2$3.6 million is attributable to the NOL carryforward. Realizationalternative minimum credit carryforward which does not expire. The realization is dependent on generating sufficient taxable income in the future. Although realization is not assured, we believe it is more likely than not all the deferred tax assets will be realized.In July 2006, the Financial Accounting Standards Board issued Interpretation No. 48 Accounting"Accounting for Uncertainty in Income Taxes (FIN 48)Taxes" ("FIN 48") an interpretation of FASB Statement No. 109 "Accounting for Income Taxes", whichon January 1, 2007. The interpretation clarifies the accounting for uncertainuncertainty in income tax positionstaxes recognized in theour financial statements. The Interpretation alsostatements and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The effective dateadoption of this Interpretation is for fiscal years beginning after December 15, 2006. Cimarex is currently evaluating the effects of implementing FIN 48 resulted in no impact to our consolidated financial statements and does not believe it willwe have a materialno unrecognized tax benefits that would impact on its financial statements.our effective rate.CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)20062007 we issued a total of 600,589572,009 restricted shares and 4,9545,274 restricted units to non-employee directors, officers, and other employees. Included in that amount are 228,000 shares issued to certain executives that are subject to market condition-based vesting determined by Cimarex’sour stock price performance relative to a defined peer group’sgroup's stock price performance. After three years of continued service, the executive will be entitled to and vest in 50% to 100% of the award. The market conditionmaterial terms of performance goals applicable to these awards were approved by stockholders in May 2006. The remainder of theremaining shares and units granted in 2006 has2007 have requisite service-based vesting schedules ranging from one to five years. Years Ended December 31, 2007 2006 2005 Outstanding beginning of period 792,779 249,905 14,145 Vested (13,693 ) (7,915 ) (11,248 ) Granted 572,009 600,589 249,008 Canceled (61,400 ) (49,800 ) (2,000 ) Outstanding end of period 1,289,695 792,779 249,905 Years Ended December 31, 2007 2006 2005 Outstanding beginning of period 696,641 697,937 780,787 Converted to Stock — — (154,600 ) Granted 5,274 4,954 71,750 Canceled — (6,250 ) — Outstanding end of period 701,915 696,641 697,937 Vested included in outstanding 559,839 172,617 128,550 prior tobefore 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, there is also a three year required holding period subsequent to vesting.following vesting also applies. A restricted unit represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods. The restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares.award, net of an estimated forfeiture rate.award. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the end of the three-year period. Compensation expense relatedFor the years ended December 31, 2006, 2005, and 2004, weWe recorded compensation expense of $5.9 million, $5.2 million, and $2.7 million, respectively. Stock-basedCIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)compensation costs capitalizedrelated to oil and gas properties during 2006, 2005 and 2004 were $3.3 million, $1.7 million, and $0.7 million, respectively.In accordance with SFAS No 123R, all deferred compensation and the unearned compensation amounts associated with restricted stock and unit grants have been reclassifiedunits as follows (in thousands): Years Ended December 31, 2007 2006 2005 Compensation costs: Recorded as expense $ 8,875 $ 5,913 $ 5,177 Capitalized to oil and gas properties $ 3,863 $ 3,320 $ 1,725 paid-in-capital.unvested restricted shares and units at December 31, 2007, 2006, and 2005 was $31.7 million, $30.6 million, and $39.8 million, respectively.During 2006 we issued 60,600 non-qualified stock options. Options granted under our plan expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. The plan provides that all grants have an exercise price equal to the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. Upon the exercise of stock options granted after October 1, 2002, grantee’sgrantees are required to hold at least 50 percent50% of the profit shares, as defined in the plan, until the eighth anniversary of the grant date. Shares Weighted
Average
Exercise
Price Weighted
Average
Remaining
Term Aggregate
Intrinsic
Value
(000)Outstanding as of January 1, 2007 1,913,529 $ 16.23 Exercised (454,263 ) 12.90 Granted — — Canceled (1 ) 7.91 Outstanding as of December 31, 2007 1,459,265 $ 17.26 4.5 Years $ 36,919 Exercisable as of December 31, 2007 1,387,805 $ 16.29 4.3 Years $ 36,430 (1) Does not include 6,060 vested options that have an exercise price exceeding our December 31, 2006 stock price20062007 was $4.4$11.0 million. In 20052006 and 20042005 the intrinsic value of stock options exercised was $17.7$4.4 million and $12.6$17.7 million, respectively.20062007 compensation expense related to stock options was approximately $2.3 million, or $1.5 million after tax ($0.02 per basic$1.9 million. In 2006 and diluted share). In 2005 compensation expense was $2.3 million and $3.4 million, or $2.2 million after tax. Included in 2005 is $1.1 million, or $0.7 after tax, related to acceleration of vesting due to the Magnum Hunter merger.respectively. Compensation expensecost for stock options is determined pursuant to SFAS No. 123R. Historical amounts may not be representative of future amounts as additional options may be granted.2005, and 20042005 was $15.75 $17.20, and $12.24,$17.20, respectively. The fair value of options is estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. Historical data is also used to estimate the probability of optionCIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Years Ended December 31, 2007 2006 2005 N/A 7.5 7.5 N/A 32.2 % 25.5 % N/A 0.1 % 0.0 % N/A 4.8 % 4.1 % 2005, and 20042005 was approximately $5.9 million, $2.7 million, $9.3 million, and $9.0$9.3 million, respectively. The related tax benefits realized from option exercises totaled approximately $4.0 million, $1.6 million, $6.4 million, and $4.8$6.4 million, respectively, and waswere recorded againstto paid-in capital.20062007 and changes during the year: Shares Weighted Average
Grant Date
Fair ValueNon-vested as of January 1, 2007 300,220 $ 10.41 Vested (228,760 ) 8.80 Granted — — Forfeited — — Non-vested as of December 31, 2007 71,460 $ 15.57 20062007 there was $2.9$1.0 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. ThatWe expect to recognize that cost is expected to be recognized pro rata over a weighted-average period of 3.83.5 years. The weighted average exercise price of the non-vested stock options is $22.62.$36.09.20062007 was $1.8$2.0 million. The grant-date fair value of options that vested in 2006 and 2005 and 2004 was $3.6$1.8 million and $3.5$3.6 million, respectively.For periods prior to January 1, 2005, we applied Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations to account for all stock option grants. Prior to 2005, we did not recognize compensation expense for stock options because the exercise prices were equal to the grant-date fair market value of the underlying common stock.Had compensation expense for stock options been determined based on amortization of the grant-date fair value of the awards, consistent with SFAS No. 123R, such compensation expense would have been $2.1 million for 2004.Pro forma net income for 2004 would have been as indicated below (in thousands except per share amounts).CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cimarex has We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock of the Company.Stock. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent15% or more of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15 percent15% or more of our common
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. CAPITAL STOCK (Continued)
stock. The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases to prevent dilution.
Cimarex We generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time prior tobefore the close of business on the tenth business day after there has been a public announcement of the acquisition of the beneficial ownership by any person or group of 15 percent15% or more of our common stock. The Rights may not be exercised until our Board’sBoard's right to redeem the stock has expired. Unless redeemed earlier, the Rights expire on February 23, 2012.
Dividends and Stock Repurchases
In December 2005, the Board of Directors declared the Company’sour first quarterly cash dividend of $.04$0.04 per share. A $.04$0.04 per share cash dividend was also declared to shareholders in every quarter of 2006.through third quarter 2007. In December 2007, the dividend was increased to $0.06 per share. Future dividend payments will depend on the Company’sCompany's level of earnings, financial requirements and other factors considered relevant by the Board of Directors.
In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. Through December 31, 2005, 68,0002007, we have repurchased and canceled a total of 1,364,300 shares had been repurchased at an overall average price of $43.03. In 2006, an additional 182,100$39.05. The shares were repurchased at an average price of $44.43 per share. All repurchased shares have been cancelled.acquired as follows:
| Period | Total Number of Shares Purchased | Average Price Paid per Share | |||
|---|---|---|---|---|---|
| Year ended December 31, 2005 | 68,000 | $ | 43.03 | ||
| Year ended December 31, 2006 | 182,100 | $ | 44.43 | ||
| Year ended December 31, 2007 | 1,114,200 | $ | 37.93 | ||
| 1,364,300 | $ | 39.05 | |||
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. CAPITAL STOCK (Continued)
A summary of the Company’sCompany's Common Stock activity follows:
|
| Number of Shares (in thousands) |
| ||||||||
|
| Issued |
| Treasury |
| Outstanding |
| ||||
December 31, 2003 |
| 41,064 |
|
| — |
|
|
| 41,064 |
|
|
Shares issued under compensation plans, net of cancellations |
| 5 |
|
| — |
|
|
| 5 |
|
|
Option exercises, net of cancellations |
| 660 |
|
| — |
|
|
| 660 |
|
|
December 31, 2004 |
| 41,729 |
|
| — |
|
|
| 41,729 |
|
|
Shares issued for Magnum Hunter acquisition |
| 42,185 |
|
| (2,476 | ) |
|
| 39,709 |
|
|
Shares issued under compensation plans, net of cancellations |
| 401 |
|
| — |
|
|
| 401 |
|
|
Option exercises, net of cancellations |
| 606 |
|
| — |
|
|
| 606 |
|
|
Treasury shares purchased |
| — |
|
| (68 | ) |
|
| (68 | ) |
|
Treasury shares cancelled |
| (1,397 | ) |
| 1,397 |
|
|
| — |
|
|
December 31, 2005 |
| 83,524 |
|
| (1,147 | ) |
|
| 82,377 |
|
|
Shares issued under compensation plans, net of cancellations |
| 546 |
|
| — |
|
|
| 546 |
|
|
Option exercises, net of cancellations |
| 142 |
|
| — |
|
|
| 142 |
|
|
Treasury shares purchased |
| — |
|
| (182 | ) |
|
| (182 | ) |
|
Treasury shares cancelled |
| (250 | ) |
| 250 |
|
|
| — |
|
|
December 31, 2006 |
| 83,962 |
|
| (1,079 | ) |
|
| 82,883 |
|
|
| | Number of Shares (in thousands) | |||||||
|---|---|---|---|---|---|---|---|---|
| | Issued | Treasury | Outstanding | |||||
| December 31, 2004 | 41,729 | — | 41,729 | |||||
| Shares issued for Magnum Hunter acquisition | 42,185 | (2,476 | ) | 39,709 | ||||
| Shares issued under compensation plans, net of cancellations | 401 | — | 401 | |||||
| Option exercises, net of cancellations | 606 | — | 606 | |||||
| Treasury shares purchased | — | (68 | ) | (68 | ) | |||
| Treasury shares cancelled | (1,397 | ) | 1,397 | — | ||||
| December 31, 2005 | 83,524 | (1,147 | ) | 82,377 | ||||
| Shares issued under compensation plans, net of cancellations | 546 | — | 546 | |||||
| Option exercises, net of cancellations | 142 | — | 142 | |||||
| Treasury shares purchased | — | (182 | ) | (182 | ) | |||
| Treasury shares cancelled | (250 | ) | 250 | — | ||||
| December 31, 2006 | 83,962 | (1,079 | ) | 82,883 | ||||
| Shares issued under compensation plans, net of cancellations | 511 | — | 511 | |||||
| Option exercises, net of cancellations | 262 | — | 262 | |||||
| Treasury shares purchased | — | (1,114 | ) | (1,114 | ) | |||
| Treasury shares cancelled | (1,114 | ) | 1,114 | — | ||||
| December 31, 2007 | 83,621 | (1,079 | ) | 82,542 | ||||
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. EARNINGS PER SHARE
The calculations of basic and diluted net earnings per common share for the years ended December 31, 2007, 2006, 2005 and 20042005 are presented in the table below (in thousands, except per share data):
|
| December 31, |
| |||||||
|
| 2006 |
| 2005 |
| 2004 |
| |||
Basic earnings per share: |
|
|
|
|
|
|
| |||
Income available to common stockholders |
| $ | 345,719 |
| $ | 328,325 |
| $ | 153,592 |
|
Weighted average basic share outstanding |
| 82,066 |
| 64,761 |
| 41,466 |
| |||
Basic earnings per share |
| $ | 4.21 |
| $ | 5.07 |
| $ | 3.70 |
|
Diluted earnings per share: |
|
|
|
|
|
|
| |||
Income available to common stockholders |
| $ | 345,719 |
| $ | 328,325 |
| $ | 153,592 |
|
Weighted average basic shares outstanding |
| 82,066 |
| 64,761 |
| 41,466 |
| |||
Incremental shares assuming the exercise of stock options, vesting of restricted stock units and conversion of the floating rate convertible notes |
| 2,024 |
| 2,239 |
| 1,297 |
| |||
Weighted average diluted shares outstanding |
| 84,090 |
| 67,000 |
| 42,763 |
| |||
Diluted earnings per share |
| $ | 4.11 |
| $ | 4.90 |
| $ | 3.59 |
|
| | 2007 | 2006 | 2005 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Basic earnings per share: | ||||||||||
| Income available to common stockholders | $ | 346,469 | $ | 345,719 | $ | 328,325 | ||||
| Weighted average basic shares outstanding | 81,819 | 82,066 | 64,761 | |||||||
| Basic earnings per share | $ | 4.23 | $ | 4.21 | $ | 5.07 | ||||
| Diluted earnings per share: | ||||||||||
| Income available to common stockholders | $ | 346,469 | $ | 345,719 | $ | 328,325 | ||||
| Weighted average basic shares outstanding | 81,819 | 82,066 | 64,761 | |||||||
| Incremental shares assuming the exercise of stock options and the vesting of restricted stock and units | 1,438 | 1,274 | 1,388 | |||||||
| Incremental shares assuming the conversion of the floating rate convertible notes | 1,375 | 750 | 851 | |||||||
| Weighted average diluted shares outstanding | 84,632 | 84,090 | 67,000 | |||||||
| Diluted earnings per share | $ | 4.09 | $ | 4.11 | $ | 4.90 | ||||
ThereAll stock options and restricted units and shares were stockconsidered potentially dilutive securities for each of the periods presented except for 30,300 options outstanding for 1,913,529, 2,023,388 and 2,657,082 shareseach of Cimarexthe periods which were anti-dilutive because the exercise price of the options was greater than the average market price of our common stock at December 31, 2006, 2005 and 2004, respectively.
CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)stock.
11. EMPLOYEE BENEFIT PLANS
Cimarex maintains We maintain and sponsors contributory health care plans andsponsor a contributory 401(k) plan. Cimarex employees participate in these plans and costsplan for our employees. Costs related to these plansthe plan were $12.1$5.2 million, $6.8$3.2 million, and $4.7$1.9 million in the years ended December 31, 2007, 2006, 2005 and 2004,2005, respectively.
12. RELATED PARTY TRANSACTIONS
Helmerich & Payne, Inc. provides contract drilling services to Cimarex. Drilling costs of approximately $21.5 million, $20.5 million, $15.4 million and $10.4$15.4 million were incurred by Cimarex related to such services for the years ended December 31, 2007, 2006, 2005 and 2004,2005, respectively. Hans Helmerich, a director of Cimarex, is President and Chief Executive Officer of Helmerich & Payne, Inc. Glenn A. Cox, a director of Cimarex, is also a director of Helmerich & Payne, Inc.
Certain subsidiaries of Newpark Resources, Inc. have provided various drilling services to Cimarex. Costs of such services were $15.6 million, $19.0 million, and $16.0 million for the years ended December 31, 2007, 2006, and 2005, respectively. Jerry Box, a director of Cimarex is a director and Chairman of the Board of Newpark Resources, Inc.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. MAJOR CUSTOMERS
During 2006, sales to one purchaser represented approximately 11 percent of our revenues. No individual purchasers represented more than 10 percent10% of our revenues for the years ended December 31, 20052007 and 2004.
Most2005. During 2006, sales to one purchaser represented approximately 11% of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.revenues.
14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (in thousands)
|
| For the Years Ended December 31, |
| |||||||
|
| 2006 |
| 2005 |
| 2004 |
| |||
Cash paid during the period for: |
|
|
|
|
|
|
| |||
Interest (net of amounts capitalized) |
| $ | 5,268 |
| $ | 2,367 |
| $ | 972 |
|
Income taxes (net of refunds received) |
| $ | 36,767 |
| $ | 49,824 |
| $ | 20,932 |
|
| | For the Years Ended December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | 2007 | 2006 | 2005 | |||||||
| Cash paid during the period for: | ||||||||||
| Interest (net of amounts capitalized) | $ | 19,006 | $ | 5,268 | $ | 2,367 | ||||
| Income taxes | $ | 2,408 | $ | 37,774 | $ | 50,515 | ||||
| Cash received during the period for: | ||||||||||
| Income taxes | $ | 46,518 | $ | 1,007 | $ | 691 | ||||
15. COMMITMENTS AND CONTINGENCIES
Litigation
As of December 31, 2006, we have accrued $7.1 million for a mediated litigation settlement pertaining to post-production deductions on properties operated by Cimarex. We have also accrued an additional $1.5 million for a mediated litigation settlement pertaining to oil and gas property title issues. We anticipate payment of both settlements during 2007. Cimarex has other various litigation related matters in the normal course of business, none of which that can be estimated are deemed to be material, individually or in aggregate. We are also party to certain litigation as plaintiffs that could result in potential gains. Net settlements of $3.4 million were received during 2004 related to litigation in which we were plaintiffs. Litigation settlements are recorded in other operating, net in the Consolidated Statements of Operations.
CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Shown below are the five year debt maturities and five year lease commitments as of December 31, 2006:2007:
| | Payments Due by Period | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Total | Less than 1 Year | 1-3 Years | 4-5 Years | More than 5 Years | ||||||||||
| | (In thousands) | ||||||||||||||
| Long term debt (face value) | $ | 475,000 | $ | — | $ | — | $ | — | $ | 475,000 | |||||
| Operating leases | $ | 32,491 | $ | 5,855 | $ | 10,778 | $ | 9,585 | $ | 6,273 | |||||
Litigation
As of December 31, 2007, in the normal course of business, we have various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them we believe, individually or in aggregate, would not have a material adverse effect on our company.
|
| Payments Due by Period |
| |||||||||||||||
|
|
|
| Less than |
| 1-3 |
| 3-5 |
| More than |
| |||||||
|
| Total |
| 1 Year |
| Years |
| Years |
| 5 Years |
| |||||||
|
| (In thousands) |
| |||||||||||||||
Long term debt (face value)(1) |
| $ | 415,000 |
|
| $ | — |
|
| $ | — |
| $ | 95,000 |
| $ | 320,000 |
|
Operating leases |
| $ | 31,278 |
|
| $ | 5,158 |
|
| $ | 10,074 |
| $ | 7,868 |
| $ | 8,178 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. COMMITMENTS AND CONTINGENCIES (Continued)
Other
At December 31, 2007, we had commitments of $102.8 million relating to construction of a gas processing facility adjacent to our Riley Ridge gas field in Sublette County, Wyoming. Pursuant to the next five years, $95terms of our operating agreement with our partners in this project, we will be reimbursed by them for approximately 43% of the construction costs, which will effectively reduce our net cash commitment to $59.1 million.
We have approximately $98.2 million of debtcontractual commitments related to our credit facility is due in 2010.drilling obligations at December 31, 2007.
At December 31, 2006,2007, we had a firm sales contract to deliver approximately fourone Bcf of natural gas over the next eightthree months. If this gas is not delivered, our financial commitment would be approximately $22.3$2.9 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our reserves and current production levels.
Cimarex has We have other various delivery commitments in the normal course of business, none of which are individually material. In aggregate these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $2.8$3.1 million.
Cimarex has We have non-cancelable operating leases for office and parking space in Denver, Tulsa, Dallas, and for small district and field offices. Rental expense for the operating leases totaled $5.9 million, $5.2 million, $3.5 million, and $2.5$3.5 million for the years ended December 31, 2007, 2006, 2005, and 2004,2005, respectively.
The Company has contractual commitments for drilling rigs and on oil and gas wells approved for drilling or in the process of being drilled at December 31, 2006 of approximately $55.3 million.
All of the noted commitments were routine and were made in the normal course of our business.
66
CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company’s limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties during the quarter ended September 30, 2006. Cimarex’s investments in these partnerships had been reflected in other assets, net. The net consideration received to date via distributions from the partnerships equaled $59.3 million. The excess distributions of $19.8 million have been recorded in other income.
Various interests in oil and gas properties were sold during 20062007 and 2005,2006, with net consideration equaling $4.5$176.7 million and $149.3$4.5 million, respectively. Proceeds from the sales were recorded as a reduction to oil and gas properties, as prescribed under the full cost method of accounting.
In September 2006, our limited partnership affiliates, Teal Hunter L.P. and Mallard Hunter L.P., sold all of their interests in oil and gas properties. Our investments in these partnerships had been reflected in other assets, net. The net consideration received to date via distributions from the partnerships equaled $62.7 million. Distributions in excess of the carrying amount of our investments of $3 million in 2007 and $19.8 million in 2006 have been recorded in other income.
17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES
Oil and Gas Operations—The following tables contain direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated. We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income taxes
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued)
related to our oil and gas operations are computed using the effective tax rate for the period (in thousands):
|
| Years Ended December 31 |
| |||||||
|
| 2006 |
| 2005 |
| 2004 |
| |||
Oil and gas revenues from production |
| $ | 1,215,411 |
| $ | 1,072,422 |
| $ | 472,389 |
|
Less operating costs and income taxes: |
|
|
|
|
|
|
| |||
Depletion |
| 379,640 |
| 248,017 |
| 120,499 |
| |||
Asset retirement obligation accretion |
| 7,018 |
| 3,819 |
| 1,241 |
| |||
Production |
| 176,833 |
| 104,067 |
| 37,476 |
| |||
Transportation |
| 21,157 |
| 15,338 |
| 10,003 |
| |||
Taxes other than income |
| 91,066 |
| 73,360 |
| 37,761 |
| |||
Income taxes |
| 196,935 |
| 228,527 |
| 99,794 |
| |||
|
| 872,649 |
| 673,128 |
| 306,774 |
| |||
Results of operations from oil and gas producing activities |
| $ | 342,762 |
| $ | 399,294 |
| $ | 165,615 |
|
Amortization rate per Mcfe |
| $ | 2.32 |
| $ | 1.92 |
| $ | 1.52 |
|
| | Years Ended December 31 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | 2007 | 2006 | 2005 | |||||||
| Oil and gas revenues from production | $ | 1,364,622 | $ | 1,215,411 | $ | 1,072,422 | ||||
| Less operating costs and income taxes: | ||||||||||
| Depletion | 444,546 | 379,640 | 248,017 | |||||||
| Asset retirement obligation | 8,937 | 7,018 | 3,819 | |||||||
| Production | 201,512 | 176,833 | 104,067 | |||||||
| Transportation | 26,361 | 21,157 | 15,338 | |||||||
| Taxes other than income | 93,630 | 91,066 | 73,360 | |||||||
| Income taxes | 214,510 | 196,935 | 228,527 | |||||||
| 989,496 | 872,649 | 673,128 | ||||||||
| Results of operations from oil and gas producing activities | $ | 375,126 | $ | 342,762 | $ | 399,294 | ||||
| Amortization rate per Mcfe | $ | 2.70 | $ | 2.32 | $ | 1.92 | ||||
CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Costs Incurred—The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities (in thousands):
|
| Years Ended December 31, |
| |||||||
|
| 2006 |
| 2005 |
| 2004 |
| |||
Costs incurred during the year: |
|
|
|
|
|
|
| |||
Acquisition of properties |
|
|
|
|
|
|
| |||
Proved |
| $ | 25,970 |
| $ | 1,523,356 |
| $ | 324 |
|
Unproved |
| 64,421 |
| 338,557 |
| 17,177 |
| |||
Exploration |
| 292,336 |
| 225,297 |
| 57,485 |
| |||
Development |
| 691,946 |
| 375,616 |
| 222,105 |
| |||
Oil and gas expenditures |
| 1,074,673 |
| 2,462,826 |
| 297,091 |
| |||
Property sales |
| (4,459 | ) | (149,262 | ) | (662 | ) | |||
Asset retirement obligation, net |
| 20,177 |
| 9,118 |
| 2,059 |
| |||
|
| $ | 1,090,391 |
| $ | 2,322,682 |
| $ | 298,488 |
|
| | Years Ended December 31, | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2007 | 2006 | 2005 | |||||||||
| Costs incurred during the year: | ||||||||||||
| Acquisition of properties | ||||||||||||
| Proved | $ | 17,334 | $ | 25,970 | $ | 1,523,356 | ||||||
| Unproved | 102,572 | 64,421 | 338,557 | |||||||||
| Exploration | 236,866 | 292,336 | 225,297 | |||||||||
| Development | 666,662 | 691,946 | 375,616 | |||||||||
| Oil and gas expenditures | 1,023,434 | 1,074,673 | 2,462,826 | |||||||||
| Property sales | (176,659 | ) | (4,459 | ) | (149,262 | ) | ||||||
| 846,775 | 1,070,214 | 2,313,564 | ||||||||||
| Asset retirement obligation, net | (18,207 | ) | 20,177 | 9,118 | ||||||||
| $ | 828,568 | $ | 1,090,391 | $ | 2,322,682 | |||||||
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued)
Aggregate Capitalized Costs—The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at December 31, 20062007 (in thousands):
Proved properties |
| $ | 4,656,854 |
| $ | 5,545,977 | ||
Unproved properties and properties under development, not being amortized |
| 425,173 |
| 364,618 | ||||
|
| 5,082,027 |
| |||||
| 5,910,595 | ||||||||
Less-accumulated depreciation, depletion and amortization |
| (1,494,317 | ) | (1,938,863 | ) | |||
Net oil and gas properties |
| $ | 3,587,710 |
| $ | 3,971,732 | ||
Costs Not Being Amortized—The following table summarizes oil and gas property costs not being amortized at December 31, 2006,2007, by year that the costs were incurred (in thousands):
| 2007 | $ | 181,999 | |||||
2006 |
| $ | 146,918 |
| 40,696 | ||
2005 |
| 271,924 |
| 141,435 | |||
2004 |
| 5,329 |
| ||||
2003 and prior |
| 1,002 |
| ||||
| 2004 and prior | 488 | ||||||
|
| $ | 425,173 |
| |||
| $ | 364,618 | ||||||
Costs not being amortized include the costs of wells in progress and certain unevaluated properties. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized.
Oil and Gas Reserve Information (Unaudited)—Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC). DeGolyer and MacNaughton, independent petroleum engineers, reviewed the proved
CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
reserve estimates associated with at least 80 percent80% of the discounted future net cash flows before income taxes for the yearyears ended December 31, 2007 and 2006. Ryder Scott Company, L.P., independent petroleum engineers, and DeGolyer and MacNaughton collectively reviewed the proved reserve estimates associated with at least 80 percent80% of the discounted future net cash flows before income taxes for the year ended December 31, 2005. Ryder Scott Company, L.P reviewed the proved reserve estimates associated with at least 80 percent of the discounted future net cash flows before income taxes for the year ended December 31, 2004.
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The following reserve
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued)
data at December 31, 2007, 2006 2005 and 20042005 represents estimates only and should not be construed as being exact. All of our reserves are located in the continental United States or the Gulf of Mexico.
|
| December 31, 2006 |
| December 31, 2005 |
| December 31, 2004 |
| ||||||
|
| Gas |
| Oil |
| Gas |
| Oil |
| Gas |
| Oil |
|
|
| (MMcf) |
| (MBbl) |
| (MMcf) |
| (MBbl) |
| (MMcf) |
| (MBbl) |
|
Total proved reserves—Developed and undeveloped Beginning of year |
| 1,004,482 |
| 64,710 |
| 364,641 |
| 14,063 |
| 337,344 |
| 14,137 |
|
Revisions of previous estimates |
| (14,498 | ) | (3,684 | ) | 9,534 |
| 270 |
| 20,068 |
| 1,154 |
|
Extensions, discoveries & improved recovery |
| 170,933 |
| 5,018 |
| 209,758 |
| 4,477 |
| 70,748 |
| 1,443 |
|
Purchases of reserves |
| 55,046 |
| 551 |
| 531,862 |
| 59,288 |
| 134 |
| 2 |
|
Production |
| (124,733 | ) | (6,529 | ) | (100,272 | ) | (4,804 | ) | (63,611 | ) | (2,641 | ) |
Sales of properties |
| (868 | ) | (269 | ) | (11,041 | ) | (8,584 | ) | (42 | ) | (32 | ) |
End of year |
| 1,090,362 |
| 59,797 |
| 1,004,482 |
| 64,710 |
| 364,641 |
| 14,063 |
|
Proved developed reserves |
| 851,213 |
| 50,202 |
| 820,244 |
| 51,521 |
| 364,566 |
| 13,372 |
|
| | December 31, 2007 | December 31, 2006 | December 31, 2005 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Gas | Oil | Gas | Oil | Gas | Oil | ||||||||
| | (MMcf) | (MBbl) | (MMcf) | (MBbl) | (MMcf) | (MBbl) | ||||||||
| Total proved reserves—Developed and undeveloped Beginning of year | 1,090,362 | 59,797 | 1,004,482 | 64,710 | 364,641 | 14,063 | ||||||||
| Revisions of previous estimates | 50,027 | 1,251 | (14,498 | ) | (3,684 | ) | 9,534 | 270 | ||||||
| Extensions, discoveries & improved recovery | 162,136 | 13,361 | 170,933 | 5,018 | 209,758 | 4,477 | ||||||||
| Purchases of reserves | 10,571 | 99 | 55,046 | 551 | 531,862 | 59,288 | ||||||||
| Production | (119,937 | ) | (8,812 | ) | (124,733 | ) | (6,529 | ) | (100,272 | ) | (4,804 | ) | ||
| Sales of properties | (70,465 | ) | (7,446 | ) | (868 | ) | (269 | ) | (11,041 | ) | (8,584 | ) | ||
| End of year | 1,122,694 | 58,250 | 1,090,362 | 59,797 | 1,004,482 | 64,710 | ||||||||
| Proved developed reserves | 848,001 | 51,497 | 851,213 | 50,202 | 820,244 | 51,521 | ||||||||
Standardized Measure of Future Net Cash Flows (Unaudited)—The “Standardized"Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves”Reserves" (Standardized Measure) is a disclosure requirement under FASB Statement No. 69,Disclosures About Oil and Gas Producing Activities. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’scompany's proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.
Under the Standardized Measure, future cash inflows are estimated by applying year-end prices to the forecast of future production of year-end proved reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a ten percent annual discount rate to arrive at the Standardized Measure.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued)
The following summary sets forth the Company’sCompany's Standardized Measure (in thousands):
|
| December 31, |
| December 31, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
| 2006 |
| 2005 |
| 2004 |
| 2007 | 2006 | 2005 | ||||||||||
Cash inflows |
| $ | 9,397,265 |
| $ | 11,502,690 |
| $ | 2,570,347 |
| $ | 12,674,941 | $ | 9,397,265 | $ | 11,502,690 | ||||
Production costs |
| (2,760,771 | ) | (2,957,911 | ) | (658,658 | ) | (3,673,259 | ) | (2,760,771 | ) | (2,957,911 | ) | |||||||
Development costs |
| (581,855 | ) | (504,686 | ) | (9,246 | ) | (540,555 | ) | (581,855 | ) | (504,686 | ) | |||||||
Income tax expense |
| (1,943,773 | ) | (2,682,075 | ) | (641,485 | ) | (2,689,836 | ) | (1,943,773 | ) | (2,682,075 | ) | |||||||
Net cash flow |
| 4,110,866 |
| 5,358,018 |
| 1,260,958 |
| 5,771,291 | 4,110,866 | 5,358,018 | ||||||||||
10% annual discount rate |
| (1,909,977 | ) | (2,329,918 | ) | (462,925 | ) | (2,873,660 | ) | (1,909,977 | ) | (2,329,918 | ) | |||||||
Standardized measure of discounted future net cash flow |
| $ | 2,200,889 |
| $ | 3,028,100 |
| $ | 798,033 |
| $ | 2,897,631 | $ | 2,200,889 | $ | 3,028,100 | ||||
The following are the principal sources of change in the Standardized Measure (in thousands):
|
| December 31, |
| December 31, | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
| 2006 |
| 2005 |
| 2004 |
| 2007 | 2006 | 2005 | ||||||||||
Standardized measure, beginning of period |
| $ | 3,028,100 |
| $ | 798,033 |
| $ | 711,581 |
| $ | 2,200,889 | $ | 3,028,100 | $ | 798,033 | ||||
Sales, net of production costs |
| (929,638 | ) | (879,657 | ) | (387,150 | ) | (1,043,121 | ) | (929,638 | ) | (879,657 | ) | |||||||
Net change in sales prices, net of production costs |
| (1,168,787 | ) | 629,462 |
| 45,614 |
| 976,912 | (1,168,787 | ) | 629,462 | |||||||||
Extensions, discoveries and improved recovery, net of future production and development costs |
| 468,854 |
| 988,001 |
| 313,417 |
| 858,632 | 468,854 | 988,001 | ||||||||||
Net change in future development costs |
| 193,280 |
| 17,777 |
| 16,380 |
| 136,413 | 193,280 | 17,777 | ||||||||||
Revision of quantity estimates |
| (88,023 | ) | 45,895 |
| 71,374 |
| 168,877 | (88,023 | ) | 45,895 | |||||||||
Accretion of discount |
| 435,888 |
| 117,223 |
| 103,034 |
| 308,660 | 435,888 | 117,223 | ||||||||||
Change in income taxes |
| 445,073 |
| (956,585 | ) | (55,438 | ) | (459,777 | ) | 445,073 | (956,585 | ) | ||||||||
Purchases of reserves in place |
| 64,538 |
| 2,379,099 |
| 221 |
| 31,278 | 64,538 | 2,379,099 | ||||||||||
Sales of properties |
| (7,216 | ) | (136,102 | ) | (289 | ) | (123,268 | ) | (7,216 | ) | (136,102 | ) | |||||||
Change in production rates and other |
| (241,180 | ) | 24,954 |
| (20,711 | ) | (157,864 | ) | (241,180 | ) | 24,954 | ||||||||
Standardized measure, end of period |
| $ | 2,200,889 |
| $ | 3,028,100 |
| $ | 798,033 |
| $ | 2,897,631 | $ | 2,200,889 | $ | 3,028,100 | ||||
Impact of Pricing (Unaudited)—The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future gas sales are covered by contracts at specified prices. Fluctuations in prices are due to supply and demand and are beyond our control.
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Continued)
The following average prices were used in determining the Standardized Measure as of:
|
| December 31, |
| December 31, | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
|
| 2006 |
| 2005 |
| 2004 |
| 2007 | 2006 | 2005 | |||||||||
Price per Mcf |
| $ | 5.54 |
| $ | 7.89 |
| $ | 5.58 |
| $ | 6.51 | $ | 5.54 | $ | 7.89 | |||
Price per Bbl |
| $ | 56.91 |
| $ | 57.65 |
| $ | 40.76 |
| $ | 93.66 | $ | 56.91 | $ | 57.65 | |||
Under SEC rules, companies that follow full cost accounting methods are required to make quarterly “ceiling test”"ceiling test" calculations. Under this test, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at ten percent, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects. We calculate the projected income tax effect using the “year-by-year”"year-by-year" method for purposes of the supplemental oil and gas disclosures and use the “short-cut”"short-cut" method
CIMAREX ENERGY CO.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
for the ceiling test calculation. Application of these rules during periods of relatively low oil and gas prices, even if of short-term duration, may result in write-downs.
18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA
2006 |
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| First |
| Second |
| Third |
| Fourth |
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| (In thousands, except for per share data) |
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Revenues |
| $ | 335,250 |
| $ | 313,381 |
| $ | 322,882 |
| $ | 295,631 |
| ||
Expenses, net |
| 225,099 |
| 230,515 |
| 228,925 |
| 236,886 |
| ||||||
Net income |
| $ | 110,151 |
| $ | 82,866 |
| $ | 93,957 |
| $ | 58,745 |
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Earnings per common share: |
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Basic |
| $ | 1.33 |
| $ | 1.01 |
| $ | 1.15 |
| $ | 0.72 |
| ||
Diluted |
| $ | 1.29 |
| $ | 0.98 |
| $ | 1.11 |
| $ | 0.70 |
| ||
| 2007 | First | Second | Third | Fourth | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | (In thousands, except for per share data) | ||||||||||||
| Revenues | $ | 306,875 | $ | 342,084 | $ | 343,753 | $ | 438,454 | |||||
| Expenses, net | 242,247 | 263,377 | 270,597 | 308,476 | |||||||||
| Net income | $ | 64,628 | $ | 78,707 | $ | 73,156 | $ | 129,978 | |||||
| Earnings per common share: | |||||||||||||
| Basic | $ | 0.79 | $ | 0.96 | $ | 0.90 | $ | 1.60 | |||||
| Diluted | $ | 0.77 | $ | 0.93 | $ | 0.87 | $ | 1.54 | |||||
| 2006 | First | Second | Third | Fourth | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | (In thousands, except for per share data) | ||||||||||||
| Revenues | $ | 335,250 | $ | 313,381 | $ | 322,882 | $ | 295,631 | |||||
| Expenses, net | 225,099 | 230,515 | 228,925 | 236,886 | |||||||||
| Net income | $ | 110,151 | $ | 82,866 | $ | 93,957 | $ | 58,745 | |||||
| Earnings per common share: | |||||||||||||
| Basic | $ | 1.33 | $ | 1.01 | $ | 1.15 | $ | 0.72 | |||||
| Diluted | $ | 1.29 | $ | 0.98 | $ | 1.11 | $ | 0.70 | |||||
2005 |
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| First |
| Second |
| Third |
| Fourth |
| ||||
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| (In thousands, except for per share data) |
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|
|
|
|
|
|
| ||||||
Revenues |
| $ | 137,944 |
| $ | 188,058 |
| $ | 363,094 |
| $ | 429,526 |
| ||
Expenses, net |
| 94,579 |
| 135,581 |
| 299,019 |
| 261,118 |
| ||||||
Net income |
| $ | 43,365 |
| $ | 52,477 |
| $ | 64,075 |
| $ | 168,408 |
| ||
Earnings per common share: |
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|
|
|
|
|
| ||||||
Basic |
| $ | 1.04 |
| $ | 1.01 |
| $ | 0.78 |
| $ | 2.04 |
| ||
Diluted |
| $ | 1.00 |
| $ | 0.98 |
| $ | 0.76 |
| $ | 1.98 |
| ||
The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share because each period’speriod's computation is based on the weighted average number of shares outstanding during that period.
71CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
18. UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Continued)
ITEM 9. CHANGES IN AND DISAGREEMENT WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Cimarex’s Cimarex's management, with the participation of the Chief Executive Officer (“CEO”("CEO") and Chief Financial Officer (“CFO”("CFO"), have evaluated the effectiveness of Cimarex’sCimarex's disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of December 31, 20062007 and concluded that the disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’sSEC's rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There was no change in our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
MANAGEMENT’SMANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Cimarex Energy Co. (the “Company”"Company") is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company’sCompany's internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles.
Because of the inherent limitations of internal control over financial reporting, misstatements may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As of December 31, 2006,2007, management assessed the effectiveness of the Company’sCompany's internal control over financial reporting based on the criteria established in “Internal Control - "Internal Control—Integrated Framework”Framework", issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, the Company maintained effective internal control over financial reporting as of December 31, 2006.2007.
Report of Independent Registered Public Accounting Firm
The Company’s independent registered public accounting firm has issued an attestation report on management’s assessmentBoard of the effectiveness of the Company’sDirectors and Stockholders
Cimarex Energy Co:
We have audited Cimarex Energy Co. and subsidiaries (the Company's) internal control over financial reporting as of December 31, 2006. That report immediately follows this report.
72
Report of Independent Registered Public Accounting Firm
The Board of Directors and StockholdersCimarex Energy Co.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Cimarex Energy Co. maintained effective internal control over financial reporting as of December 31, 2006,2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”)(COSO). Cimarex Energy Co.’sEnergy's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting.reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’sCompany's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment,assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control andbased on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’scompany's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’scompany's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’scompany's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Cimarex Energy Co. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the COSO. Also, in our opinion, Cimarex Energy Co.Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006,2007, based on criteria established in Internal Control—Integrated Framework issued by the COSO.Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidatedbalance sheets of Cimarex Energy Co. and subsidiariesthe Company as of December 31, 20062007 and 2005,2006, and the related consolidated statements of operations, stockholders’stockholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2006,2007, and our report dated February 27, 200728, 2008 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Denver, Colorado
February 27, 200728, 2008
None.
None.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF CIMAREX
Information concerning the directors of Cimarex is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 16, 200721, 2008 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2007.29, 2008. Information concerning the executive officers of Cimarex is set forth under Item 4A in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 16, 200721, 2008 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2007.29, 2008.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 16, 200721, 2008 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2007.29, 2008.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 16, 200721, 2008 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2007.29, 2008.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 16, 200721, 2008 Annual Meeting of Stockholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than April 30, 2007.29, 2008.
74
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES AND REPORTSON FORM 8-K
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(a) | (1) | The following financial statements are included in Item 8 to this 10-K: | |||||||||||
Consolidated balance sheets as of December 31, |
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Consolidated statements of operations for the years ended December 31, 2007, 2006, |
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(2) | Financial statement schedules—None | ||||||||||||
(3) | Exhibits: |
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.
2.1 | Agreement and Plan of Merger, dated as of February 23, 2002, among Helmerich & Payne, Inc., Cimarex Energy Co., Mountain Acquisition Co., and Key Production Company, Inc. (filed as Exhibit 2.1 to the | ||
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4.13 | Form of Senior Notes due 2017 included in Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 2, 2007 and incorporated herein by reference. |
10.1 | Amended and Restated Credit Agreement dated as of June 13, 2005, among Cimarex Energy Co., the Lenders listed on the signature pages thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, U.S. Bank National Association, as Co-Syndication Agent, Bank of America, N.A., as Co-Syndication Agent, Wells Fargo Bank, N.A., as Documentation Agent, and J.P. Morgan Securities Inc., as Lead Arranger and SoleBook Runner (filed as Exhibit 10.1 to | |
10.2 |
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(b) Form 8-K filed October 13, 2006, reporting the adoption of stock ownership guidelines for executive officers and directors and providing guidelines for the number of public boards that its Chief Executive Officers and directors should serve on.SIGNATURE
Form 8-K filed November 6, 2006, reporting third quarter earnings.
Form 8-K/A filed November 6, 2006, amending the third quarter earnings Form 8-K
Form 8-K filed December 22, 2006, announcing the declaration of a March 1, 2007 dividend payment.
78
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Date: February 28, 20072008
| CIMAREX ENERGY CO. | |||
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| /s/ F.H. MERELLI | |
F.H. Merelli | |||
| |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
/s/ F.H. MERELLI F.H. Merelli | Director, Chairman, President and Chief Executive Officer (Principal Executive Officer) | February 28, | ||||||||||||
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Paul Korus |
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| Treasurer (Principal Financial Officer) | February 28, 2008 | ||||||||||||
James H. Shonsey |
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/s/ F.H. MERELLI Attorney-in-Fact Jerry Box |
Director | February 28, 2008 | ||||||||||||
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/s/ F.H. MERELLI Attorney-in-Fact Hans Helmerich | Director | February 28, 2008 | ||||||||
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| Director | February 28, 2008 | ||||||||
80