UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period ended June 30, 2006

Commission File No. 001-31446

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(303) 295-3995

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  x No  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 Exchange Act). (Check One)

Large accelerated filer   x                   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 Exchange Act). Yes   o  No   x.

The number of shares of Cimarex Energy Co. common stock outstanding as of June 30, 2006 was 82,714,939.

CIMAREX ENERGY CO.

Table of Contents

In this report, we use terms to discuss oil and gas producing activities as defined in Rule 4-10(a) of Regulation S-X. We express quantities of natural gas in terms of thousand cubic feet (Mcf), million cubic feet (MMcf) or billion cubic feet (Bcf). Oil is quantified in terms of barrels (Bbls), thousands of barrels (MBbls) and millions of barrels (MMBbls). Oil is compared to natural gas in terms of equivalent thousand cubic feet (Mcfe) or equivalent million cubic feet (MMcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

PART I

ITEM 1 - Financial Statements

CIMAREX ENERGY CO.

Consolidated Balance Sheets

(Unaudited)

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Consolidated Statements of Operation

(Unaudited)

See accompanying notes to consolidated financial statements.

4

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2006

(Unaudited)

1.             Basis of Presentation

The accompanying financial statements are unaudited and were prepared from the records of Cimarex Energy Co. (Cimarex or the Company). We believe these financial statements include all adjustments necessary for a fair presentation of our financial position and results of operations. We prepared these statements on a basis consistent with the annual audited statements and Regulation S-X. Regulation S-X allows us to omit some of the footnote and policy disclosures required by accounting principles generally accepted in the United States of America and normally included in annual reports on Form 10-K. These interim financial statements should be read in conjunction with the financial statements and notes in our Annual Report on Form 10-K for the year ended December 31, 2005.

 In June 2005, Cimarex acquired 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 June 30, 2006, Cimarex had 82.7 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.

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

We make certain estimates and assumptions to prepare our financial statements in conformity with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period and in disclosures of commitments and contingencies. 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.

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

Certain amounts in prior years’ financial statements have been reclassified to conform to the 2006 financial statement presentation. Most notably, the presentation of gas marketing and sales activities as discussed below under Revenue Recognition.

Segment Information

Cimarex has one reportable segment (exploration and production).

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Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production. We market and sell natural gas for working interest partners under short term sales and supply agreements and earn 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.

2.             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 Hunter’s common stockholders (excluding 2.5 million shares held in treasury). The results of operations of Magnum Hunter are included in our consolidated statements of operations for the period since the acquisition on June 7, 2005.

The allocation of the purchase price to oil and gas properties utilized prevailing oil and gas prices at the time of negotiations and announcement of the merger. The overall allocation of the purchase price has been finalized and the goodwill amount related to the purchase as of June 30, 2006 equals $646.4 million.

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 periods presented. The unaudited pro forma data is presented for illustrative purposes only, based on estimates and assumptions deemed appropriate by management, 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, 2005. The pro forma information also should not be used as an indication of future results or trends.

(1) Includes $19.2 million of income from Magnum Hunter derivative instruments.

3.             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 generally 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

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reflect the time value of money until settlement. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recorded as an expense. In connection with the Magnum Hunter merger, Cimarex 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 net gains for the quarter and six months ended June 30, 2006 of $3.2 million and $18.8 million, respectively. During the second quarter of 2005 we recorded a net loss of $2.0 million. 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 the quarter and six months ended June 30, 2006 totaled $4.1 million and $11.5 million, respectively. The derivative liability at June 30, 2006 equals $11.5 million. Cimarex will continue to recognize gains and losses as the remaining derivative instruments expire through December 31, 2006. Actual gains and losses to be recognized may differ materially from the current fair value of amounts recorded. The following is a summary of the company’s open derivative contracts as of June 30, 2006:

All of the $11.5 million of derivative liabilities is classified as current on our consolidated balance sheet at June 30, 2006. Weighted average NYMEX prices at June 30, 2006 for the remaining six months of 2006 approximate $7.15 per Mcf of gas and $75.40 per barrel of oil.

In July 2006, we entered into additional derivative contracts. These derivatives have been designated for hedge accounting treatment as cash flow hedges. Changes in fair value, to the extent the hedge is effective, will be recognized in other comprehensive income until the hedged item is settled and recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings. The table below sets forth the weighted average terms of the related derivative contracts through August 1, 2006.

4.             Stock Plans

Stock Options

Cimarex’s 2002 Stock Incentive Plan reserves 12.7 million shares of common stock for issuance to directors and employees, including officers. Options granted under the plan after December 5, 2002, expire ten years

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from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. All grants are made at the average of the high and low prices of our common stock as reported on the New York Stock Exchange on the date of grant.

Upon the exercise of the options for shares of common stock, the employee is required to hold at least 50 percent of the profit shares, as defined in the plan, until the eighth anniversary of the grant date. The incentive plan provides for accelerated vesting if there is a change in control (as defined in the plan).

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. No compensation cost had been recognized for stock options granted, as the option prices were equal to the market price of the underlying common stock on the date of grant.

Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share Based Payment on a 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. For the quarters ended June 30, 2006 and 2005, compensation expense related to stock options was approximately $0.5 million and $0.7 million or $0.3 million and $0.4 million after tax, respectively. For the six months ended June 30, 2006 and 2005, compensation expense related to stock options was approximately $0.9 million and $1.4 million or $0.6 million and $0.8 million after tax ($.01 and $.02 per diluted share), respectively.

As discussed more fully in the notes to the financial statements of our annual report on form 10-K for the year ended December 31, 2005, the merger with Magnum Hunter constituted a “change of control event” under the incentive plan. As a result, all participants became entitled to acceleration of vesting of their options. Cimarex obtained waivers of the accelerated vesting from certain option holders including the company’s CEO and other senior officers. Option holders who were not requested to or did not choose to execute a waiver became fully vested in their options on June 7, 2005. Compensation expense related to the accelerated vesting of options was approximately $1.1 million or $0.7 million after tax.

The fair value of each option award was estimated as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities were based on the historical volatility of our common stock. The risk free interest rate is based on U.S. Treasury Securities at a constant five year fixed maturity in effect at the date of the grant. Historical data was also used to estimate the probability of option exercise, expected years until exercise and employee termination within the valuation model.

There were no stock options granted to employees during the six months ended June 30, 2006 and 2005.

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The following summary reflects the status of stock options granted to employees and directors as of June 30, 2006, and changes during the period:

The total intrinsic value of options exercised during the three months ended June 30, 2006 and 2005 was $0.1 million and $3.4 million, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005 was $3.0 million and $4.1 million, respectively.

The following summary reflects the status of non-vested stock options granted to employees and directors as of June 30, 2006 and changes during the period:

As of June 30, 2006 there was $3.1 million of total unrecognized compensation cost related to non-vested stock options granted under our incentive plan. That cost is expected to be recognized pro rata over a weighted-average period of 2.4 years. The weighted average exercise price of the non-vested stock options was $18.59. Generally, options vest on the anniversary of the grant date.

Cash received from option exercises during the six months ended June 30, 2006 and 2005 was approximately $1.6 million and $4.1 million, respectively. The tax benefit realized for the tax deductions from option exercises totaled approximately $1.1 million and $2.9 million, for the six months ended June 30, 2006 and 2005, respectively, and was recorded in paid-in capital.

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Restricted Stock and Units

We have a long-term incentive program whereby grants of restricted stock and/or units are awarded to certain employees. The restrictions related to these awards are associated with the continued employment of the grantee for one to five years from the date of the original grant, at which time these shares will vest.

Awards of restricted stock units vest from one to five years from the date of grant and are payable in shares of stock on the eighth anniversary of the date of grant. In accordance with SFAS No 123R, deferred compensation of $13.9 million and the related unearned compensation were reclassified to paid-in capital. There were 696,641 restricted stock units outstanding as of June 30, 2006.

Awards of restricted stock vest from three to five years from the date of grant and are payable in shares of unrestricted stock on vesting. In accordance with SFAS No 123R, unearned compensation attributable to restricted stock was reclassified to paid-in-capital. At June 30, 2006 there were 663,607 shares of restricted stock outstanding.

The restricted stock and stock unit agreements provide that the grantees will be entitled to receive dividends, when and if declared.

The following summary reflects the status of restricted stock and units granted to employees and directors as of June 30, 2006, and changes during the year:

Compensation expense for restricted shares or units is based upon the market price of the restricted grant multiplied by the number of shares of restricted stock or units granted. Compensation cost is being recognized over the associated vesting period. For the six months ended June 30, 2006 and 2005, we recorded compensation expense of $3.1 million and $3.6 million, respectively. We also capitalized to oil and gas properties associated costs of $1.4 million and $0.6 million, respectively. At June 30, 2006, there was $29.6 million of unrecognized compensation cost related to grants of restricted stock and units.

Declared Dividends and Stock Repurchases

In December 2005, the Board of Directors declared the Company’s first quarterly dividend of $.04 per share payable on March 1, 2006 to shareholders of record as of February 15, 2006. In March 2006, a second quarterly dividend of $.04 per share was declared, payable on June 1, 2006 to shareholders of record as of May 15, 2006. In May 2006 a third quarterly dividend of $.04 per share was declared, payable on September 1, 2006 to shareholders of record as of August 15, 2006.

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In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. Through December 31, 2005, 68,000 shares had been repurchased at an average price of $43.03. Since December 31, 2005 and through June 2006, an additional 182,100 shares have been repurchased for an average price of $44.43 per share.

5.             Asset Retirement Obligations

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

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2006 (in thousands):

6.             Long-Term Debt

Prior to the Magnum Hunter merger, Cimarex had no debt. Debt at December 31, 2005 consisted of the following (in thousands):

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Debt at June 30, 2006 consisted of the following (in thousands):

(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. Paid-in-Capital was credited with $49.6 million related to the fair value of common stock associated with the convertible debt at date of acquisition.

Cimarex’s 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 June 30, 2006, there were outstanding borrowings of $53 million under the Revolving Credit Facility at a weighted average interest rate of approximately 6.43%. We also had letters of credit for approximately $2.7 million posted against the borrowing base, leaving an unused borrowing amount of approximately $444.3 million at June 30, 2006.

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.

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.

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 June 30, 2006, the interest rate equaled 5.33%.

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

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common stock has been trading above the fixed conversion price of $28.99 per share. On June 30, 2006, the closing price of our common stock traded on the New York Stock Exchange was $43.00. There is not an observable market for the notes. Based on an average common stock price of $43.00, management estimates the fair value of the notes at June 30, 2006 was approximately $185.4 million (or $1,480 per bond).

In addition to the 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 agreement 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.

All long-term debt is guaranteed by Cimarex and all of its subsidiaries, except Canvasback. Assets held by Canvasback consist primarily of 790 thousand shares of Cimarex stock, which is included in Cimarex’s Treasury stock.

Total borrowings at June 30, 2006 on the construction loan of Magnum Hunter’s 40% owned affiliate, Apple Tree Holdings, LLC (“Apple Tree”) were $20.6 million, of which our share was $8.2 million. We have provided a guarantee to the lender for this Construction Loan. In return for our guarantee, we received an up-front fee as well as the right to receive 55% of distributable cash flows from Apple Tree until certain financial tests are met. In the event that the Construction Loan goes into default and we have to perform under the guarantee, we will have recourse against the project and related subsidiaries.

7.             Income Taxes

Federal income tax expense for the periods ended June 30, 2006 and 2005 differ from the amounts that would be provided by applying the U.S. Federal income tax rate due to the effect of state income taxes and other deductible costs.

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

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8.                                      Supplemental Disclosure of Cash Flow Information (in thousands):

9.             Earnings per Share

The calculations of basic and diluted net earnings per common share are presented below (in thousands, except per share data):

There were stock options outstanding for 1,920,078 and 2,353,403 shares of Cimarex common stock at June 30, 2006 and 2005, respectively. All stock options and restricted units and shares were considered potentially dilutive securities for each of the periods presented.

10.          Commitments and Contingencies

Litigation

A liability for $6.5 million for estimated future litigation settlements was recorded in the third quarter of 2005. The proposed settlement will be reviewed by the court for approval.

Cimarex has various litigation related matters in the normal course of business, none of which are material individually or in aggregate.

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Other

At June 30, 2006, we had firm sales contracts to deliver approximately 2.8 Bcf of natural gas over the next four months.  If this gas is not delivered, our financial commitment would be approximately $14.9 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 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 $3.6 million.

The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at June 30, 2006 of approximately $69.5 million.

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

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. These forward-looking statements include, among others, statements concerning Cimarex’s outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil and gas and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts. The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.

These risks and uncertainties include, but are not limited to, fluctuations in the price we receive for our oil and  gas production, reductions in the quantity of oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated, and increased financing costs due to a significant increase in interest rates. In addition, exploration and development opportunities pursued by Cimarex may not result in productive oil and gas properties. There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. These and other risks and uncertainties affecting Cimarex are discussed in greater detail in this report and in other filings by Cimarex with the Securities and Exchange Commission.

INTRODUCTION

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our operations are presently focused primarily in Oklahoma, Texas, New Mexico, Kansas, Louisiana, and the Gulf of Mexico. We also have smaller projects underway in Michigan and California.

Our primary focus is to explore for and discover new reserves. To supplement our growth, we also consider mergers and acquisitions. On June 7, 2005, Cimarex acquired Magnum Hunter Resources, Inc, 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 (excluding 2.5 million shares held in treasury) and assumed $633 million of debt. The 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.

As a result of the merger, our proved reserves tripled and production doubled. Our common shares outstanding increased by 93 percent to 82.4 million and we went from having no debt to taking on $633 million of debt. Using proceeds from property sales and cash flow in excess of capital

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investments, we reduced our debt to $352 million by year end 2005. Debt at June 30, 2006 equals $404 million. Operationally we now have a large base of properties in the Permian Basin with operational characteristics similar to our Mid-Continent assets. The merger also extended our onshore Gulf Coast activities into the Gulf of Mexico. Overall, about 44 percent of our proved reserves are in the Permian Basin and 39 percent are in our Mid-Continent region. Our onshore Gulf Coast and Gulf of Mexico operations collectively make up 12 percent of our proved reserves.

Industry and Economic Factors

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

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

Profitable growth of our assets will largely depend upon our ability to successfully find and develop new proved 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 chance of failure. To further mitigate risk, we have chosen to seek geologic 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 July 2006, we entered into additional derivative contracts as discussed more fully below.

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities, periodic sales of non-core properties and external sources of capital.

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We project that 2006 exploration and development expenditures will approximate $1 billion, up from the $642 million invested in 2005. Approximately 30 percent of the expenditures will be in the Permian Basin, 29 percent in the Mid-Continent area, 22 percent in the Gulf Coast area and 15 percent in the Gulf of Mexico.

Exploration and development expenditures during the second quarter of 2006 totaled $281.7 million, up from $141.0 million for the second quarter of 2005. Capital expenditures for exploration and development during the first six months of 2006 were $554.9 million, up from $233.7 million during the first two quarters of 2005. In the first half of 2006, we participated in drilling 304 gross (188.9 net) wells, with an overall success rate of 89 percent.

Cash flow from operating activities for the six months ended June 30, 2006 totaled $461.8 million, helping 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 the remainder of 2006 and beyond.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 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.

Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production. We market and sell natural gas for working interest partners under short term sales and supply agreements and earn 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.

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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. For 2005, revisions of reserve estimates resulted in an increase of 270 MBbls of oil and an increase of 9.5 Bcf of gas, representing less than half of a percent and one percent of  proved oil and gas reserves, respectively, as of December 31, 2005.

We use the units-of-production method to amortize our oil and gas properties. Changes in reserve quantities will cause corresponding changes in depletion expense in periods subsequent to the quantity revision or, in some cases, a full cost ceiling limitation charge in the period of the revision. To date, changes in expense resulting from changes in previous estimates of reserves have not been material.

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.

Under full cost accounting rules, capitalized costs, less accumulated amortization and related deferred income taxes and excluding costs not subject to amortization, may not exceed an amount equal to the sum of the present value discounted at ten percent of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Cash flows used in the calculation of the full cost ceiling limitation are determined based upon estimates of proved oil and gas reserves, current prices (as adjusted for the effect of cash flow hedges that qualify for hedge accounting treatment), and the costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil and gas prices could cause us to reduce the carrying value of our oil and gas properties. If capitalized costs exceed this limit and excluding costs not subject to amortization, the excess must be charged to expense. This is referred to as the “full cost ceiling limitation.”  The expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase the full cost ceiling limitation. At the end of each quarter, a full cost ceiling limitation calculation is made.

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

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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. These factors are each individually weighted to estimate the total fair value of goodwill. 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. We recorded $45.0 million of goodwill in the purchase of Key on September 30, 2002 and $685.4 million of goodwill in the purchase of Magnum Hunter on June 7, 2005.

Allocation of Purchase Price

The allocation of the Magnum Hunter purchase price to oil and gas properties utilized prevailing oil and gas prices at the time of negotiations and announcement of the merger. The overall allocation of the purchase price has been finalized and the goodwill amount related to the purchase as of June 30, 2006 was $646.4 million.

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 generally determine the fair value of derivative contracts based on the stated contract prices and the current and projected underlying market prices at the determination date discounted to reflect the time value of money until settlement, using information we obtain from counter parties. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recorded as an expense. 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 have not been designated for hedge accounting treatment. As a result, Cimarex recognized a net gain of $18.8 million during the first six months of 2006. 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 the first six months of 2006 totaled $11.5 million. The net derivative liability at June 30, 2006 equals $11.5 million. Cimarex will continue to recognize gains and losses in future earnings until the derivative instruments mature on December 31, 2006.

In July 2006, we entered into additional derivative contracts. These derivatives have been designated for hedge accounting treatment as cash flow hedges. Changes in fair value, to the extent the hedge is effective, will be recognized in other comprehensive income until the hedged item is settled and recognized in earnings. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in earnings.

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

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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.

Asset Retirement Obligations

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

Stock Options

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. No compensation cost had been recognized for stock options granted, as the option prices were equal to the market price of the underlying common stock on the date of grant.

Effective January 1, 2005, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123R, Share Based Payment on a 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.

The fair value of each option award 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 option exercise, expected years until exercise and employee termination within the valuation model. The risk free interest rate is based on U.S. Treasury Securities at a constant five year fixed maturity in effect at the date of the grant.

Segment Information

Cimarex has one reportable segment (exploration and production).

Recent Accounting Developments

In May 2006, the FASB proposed Staff Position No. AUG AIR-a, Accounting for Planned Major Maintenance Activities. This Interpretation would prohibit accruing as a liability the future costs of periodic major overhauls and maintenance of plant and equipment under the “accrue-in-advance” methodology, as the costs for future planned major maintenance activities do not meet the definition of a liability. The final Staff Position would be effective for fiscal years beginning after December 15, 2006.

In July 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes, which defines the threshold for recognizing the benefits of tax-return positions in the financial

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statements as “more-likely-than-not” to be sustained by the taxing authority. The term “more-likely-than-not” means a likelihood of more than 50 percent. The interpretation also requires quantitative and qualitative disclosures of estimates of tax benefits of positions taken for tax-return purposes that have not been recognized for financial reporting, if it is “reasonably possible” the estimates will significantly change in the twelve months after the balance sheet date. 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).

Overview

Our results of operations are primarily impacted by changes in oil and gas prices and changes in our production volumes. Realized oil prices increased from $50.56 per barrel in the second quarter of 2005 to $65.67 per barrel in the second quarter of 2006. Realized gas prices decreased from $6.49 per Mcf in the second quarter  of 2005 to $6.22 per Mcf in the second quarter of 2006.

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

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.

Depreciation, depletion and amortization 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, while lower prices generally have the effect of decreasing reserves, which increases depletion. 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.

General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices. While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth. Expenses related to the merger are costs associated with the Magnum Hunter transaction.

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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. 123R.

Basis of Presentation

In June 2005, Cimarex acquired 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 June 30, 2006, Cimarex had 82.7 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. Most notably, the presentation of gas marketing and sales activities as discussed under Revenue Recognition.

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RESULTS OF OPERATIONS

Periods Ended June 30, 2006 Compared with Periods Ended June 30, 2005:

SUMMARY DATA:

Net income for the second quarter of 2006 was $82.9 million, or $0.98 per diluted share, compared to net income of $52.5 million, or $0.98 per diluted share for the same period in 2005. For the six months ended June 30, 2006, net income was $193.0 million, or $2.27 per diluted share, compared to net income of $95.8 million, or $1.98 per diluted share, for the first six months of 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.

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Oil and gas sales for the second quarter of 2006 totaled $300.5 million, compared to $185.0 million for the second quarter of 2005. The $115.5 million increase in sales between the two periods results from $16.8 million related to higher commodity prices and $98.7 million due to higher production volumes (due primarily to increased production resulting from the acquisition of Magnum Hunter). For the six months ended June 30, 2006, oil and gas sales increased by $300.1 million, or 93 percent, to $622.5 million from $322.4 million during the first six months of 2005. Higher production volumes increased sales by $229.0 million and higher commodity prices contributed $71.1 million to the increase between the two six-month periods.

Realized gas prices averaged $6.22 per Mcf for the three months ended June 30, 2006, compared to $6.49 per Mcf for the second quarter of 2005. This four percent change decreased sales by $8.3 million between the two periods. Realized oil prices averaged $65.67 per barrel for the second quarter of 2006, compared to $50.56 per barrel for the same period in 2005. The increase in sales between periods resulting from this 30 percent improvement in oil prices totaled $25.1 million.

For the six months ended June 30, 2006, realized gas prices increased to $6.72 per Mcf from $6.27 per Mcf realized in the first half of 2005. This price increase contributed $28.5 million to the increase in sales between the two six-month periods. Realized oil prices averaged $62.79 per barrel for the first half of 2006, compared to $49.21 per barrel for the same period in 2005, resulting in a $42.6 million increase in sales between periods. Changes in realized prices were the direct result of overall market conditions.

Sales also benefited from higher production volumes. Average gas volumes rose 106.4 MMcf per day in the second quarter of 2006 to 338.7 MMcf per day from 232.3 MMcf per day in the second quarter of 2005, resulting in $62.8 million of incremental revenues. Oil volumes averaged 18,213 barrels per day for the second three months of 2006, compared to 10,402 barrels per day in the same period of 2005, resulting in increased revenues of $35.9 million. For the first six months of 2006, gas volumes averaged 349.9 MMcf per day and oil volumes equaled 17,343 barrels per day, compared to first-half 2005 volumes of 214.2 MMcf per day and 8,911 barrels per day. The higher gas volumes increased sales between the two periods by $153.9 million, and higher oil volumes resulted in $75.1 million of additional revenues. The increase in sales volumes between the periods of 2006 and 2005 is due to positive drilling results during 2005 and the first half of 2006, and the inclusion of production from Magnum Hunter operations from June 7, 2005. Daily production volumes in the Gulf of Mexico and along the Texas and Louisiana Gulf Coast area were negatively impacted by approximately 10 to 15 MMcf equivalents during the second quarter of 2006 and 20 to 25 MMcf equivalents during the first quarter of 2006 as a result of hurricanes. 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. The majority of these volumes were restored by the end of the second quarter.

Gas gathering and processing revenues, net of related costs, equaled $5.7 million in the second quarter of 2006, compared to $0.9 million in the second quarter of 2005. For the six months ended June 30, 2006 and 2005, such revenues net of related costs totaled $10.5 million and $0.8 million, respectively. The increase is due to the inclusion of related activities from Magnum Hunter operations. 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 increased to $0.8 million from $0.3 million, net of related costs of $29.8 million and $62.2 million for the second quarters of 2006 and 2005, respectively. Gas marketing net revenues increased to $2.7 million from $0.9 million, net of related costs of $87.0

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million and $115.4 million for the first six months of 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.

Costs and Expenses

Net costs and expenses (not including gas gathering, marketing and processing costs) were $175.0 million in the second quarter of 2006 compared to $103.6 million in the second quarter of 2005. For the first six months of 2006 and 2005, these overall costs and expenses equaled $330.0 million and $173.7 million, respectively. Depreciation, depletion and amortization (DD&A) was the largest component of these increases between periods. DD&A equaled $94.8 million in the second quarter of 2006 compared to $51.6 million in the same period of 2005. For the first six months of 2006 and 2005, DD&A totaled $185.4 million and $89.7 million, respectively. On a unit of production basis, DD&A was $2.33 per Mcfe in the second quarter of 2006 compared to $1.92 per Mcfe for the second quarter of 2005. For the first six months of 2006 and 2005, DD&A on a unit of production basis equaled $2.26 per Mcfe and $1.85 per Mcfe, respectively. The increases largely stem from costs associated with Magnum Hunter operations and higher costs for reserves added during 2005 and 2006.

Production costs rose $26.4 million from $17.4 million ($0.65 per Mcfe) in the second three months of 2005 to $43.8 million ($1.07 per Mcfe) in the second quarter of 2006. For the first six months of 2006 and 2005, production costs equaled $85.6 million ($1.04 per Mcfe) and $27.6 million ($0.57 per Mcfe), respectively. The higher costs in 2006 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 $3.6 million, or $0.14 per Mcfe, in the second quarter of 2005 to $5.5 million, or $0.14 per Mcfe, in the second quarter of 2006. Transportation costs for the first half of 2006 equaled $9.8 million compared to $6.1 million for the same period 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 $8.3 million greater, rising from $13.6 million in the second quarter of 2005 to $21.9 million in the same period of 2006. For the first six months of 2006 and 2005, these costs totaled $45.5 million and $24.5 million, respectively. The increases 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 $2.3 million from $7.7 million in the second quarter of 2005 to $10.0 million in the second quarter of 2006. G&A expenses for the first half of 2006 equaled $20.9 million compared to $15.5 million for the same period of 2005. The increases between periods are 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 net of amounts capitalized. Stock compensation increased from $2.4 million in the first half of 2005 to $4.1 million in the first half of 2006. As of June 30, 2006, there was approximately $32.7 million of total unrecognized compensation cost related to compensation awards granted under our stock incentive plans.