Statement of Financial Accounting Standard (SFAS) No. 123,Accounting for Stock Based Compensation, requires the Company to provide pro forma information regarding net income as if compensation cost for Cimarex's stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123. To provide the required pro forma information, Cimarex estimated the theoretical fair value of each stock option at the grant date by using the Black Scholes option-pricing model.

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

        These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period and additional options may be granted in future years.

        There were no options granted in the quarters presented, accordingly the pro forma stock option expense was calculated using the assumptions described in our Form 10-K for the year ended December 31, 2002.

        The following summary reflects the status of stock options granted to employees and directors as of March 31,June 30, 2003, and changes during the period:

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        The following table summarizes information about Cimarex stock options held by employees and directors at March 31,June 30, 2003:

3.     Acquisition of Key Production Company, Inc.

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

        Our consolidated balance sheets include the assets and liabilities of Key as well as the adjustments required to record the acquisition in accordance with the purchase method of accounting. The final purchase price and the final allocation of the purchase price are subject to adjustment based on the actual fair value of current assets and liabilities, and long-term liabilities and final tax basis.liabilities. Key's final tax basis will not behas been determined until Key files its tax return forduring the tax period ending Septemberquarter ended June 30, 2002. Any adjustment to the Key2003 and was $3.9 million more than originally estimated. The increase in tax basis will bewas accounted for as an adjustment to goodwill. We expect thatat the purchase price will be finalizedsalutatory tax rate of 38% and resulted in the second quartera decrease in goodwill of 2003, upon completion of Key's final stand alone income tax return.$1.5 million. The results of operations of Key are included in our consolidated statements of operations for the period since the acquisition on September 30, 2002.

        The following unaudited pro forma financial information presents the combined results of Cimarex and Key for the three and six months ended March 31,June 30, 2002, and was prepared as if the acquisition had occurred at the beginning of the period presented. Included in the pro forma results for the three and six months ended March 31,June 30, 2002 is $4.2$0.7 million and $5.1 million, respectively, of merger and severance related expenses incurred by Key. The pro forma data presented is based on numerous assumptions and is not necessarily indicative of future results of operations.

4.     Asset Retirement Obligations

        On January 1, 2003, Cimarex 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.

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        The adoption of the Statement resulted in our recording an increase to the full cost pool of approximately $10.5 million, a decrease to accumulated depreciation, depletion and amortization of approximately $5.9 million, an increase to long-term liabilities for plugging and abandonment costs of approximately $13.8 million, an increase to the deferred tax liability of approximately $1.0 million and income reported as a cumulative effect of a change in accounting principle of approximately $1.6 million net of income taxes of $1.0 million. On a pro forma basis, the asset retirement obligation would have been approximately $12.6 million as of January 1, 2002.

        The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2003 (in thousands):

4.5.     Long-Term Debt

        At March 31,June 30, 2003, Cimarex had $5.0 millionno debt outstanding under its three year $400 million Credit Agreement. This facility has a borrowing base of $275 million and Cimarex has elected a $200 million commitment amount. The borrowing base is subject to redetermination each April and October. Borrowings under this facility bear interest at a LIBOR rate plus 1.25% to 2.00%, based on borrowing base usage. Unused borrowings are subject to a commitment fee of 0.375% to 0.50%, also depending on borrowing base usage. The credit facility is secured by mortgages on the Company's oil and gas properties and the stock of its subsidiaries. The Company is also subject to customary financial and non-financial covenants and is in compliance with all such covenants as of March 31,June 30, 2003.

5.6.     Income Taxes

        Federal income tax expense for the three and six months ended March 31,June 30, 2003 and March 31, 2002 differ from the amounts that would be provided by applying the U.S. Federal income tax rate due primarily to the effect of state income taxes and percentage depletion.

        TheA final determination of CimarexCimarex's tax basis will not be known until H&P files its tax return for its fiscal year end September 30, 2002, based on the terms of the tax sharing agreement between H&P and Cimarex. Any adjustment to the Cimarexhas been made resulting in a reduction in tax basis will beof $0.1 million. The adjustment was accounted for asat the statutory tax rate of 38% and resulted in a dividenddistribution to or contributionHelmerich & Payne, Inc. in retained earnings of $0.1 million.

        Key's final tax basis has been determined resulting in an increase of $3.9 million from H&P. As a resultthe original estimate made at the time of the merger with Cimarex, Key's final tax basis will not be determined until Key files its tax return for the tax period ending September 30, 2002. Any adjustment to the Key tax basis will beCimarex. The increase was accounted for as an adjustment to goodwill. Bothat the Cimarexstatutory tax rate of 38% and Key tax returns for the period ending September 30, 2002 are expected to be filed during second quarter 2003. Any adjustment to the tax basis will be made during the second quarter.resulted in a decrease in goodwill of $1.5 million.

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        Income tax expense consisted of the following for the three and six months ended March 31,June 30, (in thousands):

6.7.     Supplemental Disclosure of Cash Flow Information

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7.8.     Earnings Per Share

        The calculations of basic and diluted net earnings per common share is presented below:

        As of March 31,June 30, 2003, there were 3,535,8473,421,461 stock options outstanding, 1,633,8131,557,700 of which were vested and exercisable for purposes of the diluted calculation. All stock options were considered potentially dilutive securities for the three and six months ended March 31,June 30, 2003. There were no potentially dilutive securities outstanding for the three and six months ended March 31,June 30, 2002.

8.9.     Segment Information

        Cimarex operates in the oil and gas industry, and is comprised of an exploration and production segment and a natural gas marketing segment. Exploration and production activities are conducted primarily in Oklahoma, Kansas, Texas and Louisiana. The natural gas marketing segment markets most of the natural gas produced by the exploration and production segment as well as natural gas produced by third parties.

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        Summarized financial information of Cimarex'Cimarex's reportable segments for the three and six months ended March 31,June 30, 2003 and 2002 is shown in the following table:

*

Includes $10.6$11.1 million addition related to the adoption ofaccounting for SFAS No. 143.

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

9.10.   Commitments and Contingencies

Litigation

        Cimarex is a defendant to certain claims relating to drainage of gas from two properties that it operates. The royalty owner plaintiffs have filed suit on behalf of themselves and a class of similarly situated royalty owners in two 640-acre-spacing units. The plaintiffs allege that the two units have suffered approximately 1220 Bcf of gross gas drainage. AlthoughCimarex denies that the drainage, if any, was in an amount that significant. The plaintiffs have not specified in their pleadings the amount of damages alleged, the plaintiffs have orally stated that the royalty owner class has sustained actual

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damages of approximately $6.2$20 million exclusive of interest and costs. Cimarex estimates that the share of such alleged damages attributable to its working interest ownership would total approximately $1.0$3.0 million exclusive of interests and costs. Plaintiffs further allege that, as a former operator, Cimarex is liable for all damages attributable to the drainage. Cimarex believes that its liability, if any, should not exceed its working interest share of any actual damages attributable to the alleged drainage. In the event thatAs such, Cimarex is held liable for the full amount of any actual damages, Cimarex will seekseeking contribution, indemnification and/or other appropriate relief from all other working interest owners for their portion of the alleged drainage that is attributable to the interest of those other owners.

        Cimarex has other various litigation related matters in the normal course of business, none of which are material, individually or in aggregate. We are also party to certain litigation as plaintiffs that could result in potential gains of between $1.5$2.0 million to $2.5 million, net to our interest.

Parental Guarantees

        As of March 31,June 30, 2003, Cimarex had approximately $7.0$18.8 million of parental guarantees outstanding. These guarantee the credit of certain CESI agreements and are for the benefit of certain counterparties.

10.11.   New Accounting Standards

        On January 1, 2003, Cimarex adoptedThe Financial Accounting Standards Board (FASB) and representatives of the accounting staff of the Securities and Exchange Commission (SEC) are currently engaged in discussions regarding the application of certain provisions of SFAS No. 143,141,AccountingBusiness Combinationsand SFAS No. 142,Goodwill and Other Intangible Assetsto companies in the extractive industries, including oil and gas companies. The FASB and the SEC staff are considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.

        Historically, Cimarex has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event the FASB and SEC staff determine that costs associated with mineral rights are required to be classified as intangible assets, a portion of our oil and gas property acquisition costs since the June 30, 2001 effective date of SFAS Nos. 141 and 142 would be separately classified on our balance sheets as intangible assets. Cimarex's results of operations would not be affected, however, since such intangible assets would continue to be depleted and assessed for Asset Retirement Obligations.impairment in accordance with full cost accounting rules. We do not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on our compliance with covenants under our debt agreements.

        In April 2003 the FASB issued SFAS No. 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This Statement addressesamends and clarifies financial accounting and reporting for obligations associatedderivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.

        The changes in this Statement improve financial reporting by requiring that contracts with comparable characteristics be accounted for similarly In particular, this Statement (1) clarifies under what circumstances a contract with an initial net investment meets the retirementcharacteristic of tangible long-lived assetsa derivative discussed in paragraph 6(b) of SFAS No. 133, (2) clarifies when a derivative contains a financing component, (3) amends the definition of underlying to conform it to language used in FASB Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and (4) amends certain other existing pronouncements. Those changes will result in more consistent reporting of contracts as either derivatives or hybrid

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instruments. This Statement is effective for contracts entered into or modified after June 30, 2003, except as stated below and for hedging relationships designated after June 30, 2003. In addition, all provisions of this Statement should be applied prospectively. We do not expect the associated asset retirement costs. Theadoption of SFAS No. 149 to have an impact on the financial position or results of operations of Cimarex.

        In May 2003, the FASB issued SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that the fair value ofan issuer classify a financial instrument that is within its scope as a liability for(or an asset retirement obligation be recognized in some circumstances). Many of those instruments were previously classified as equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at 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 partbeginning of the carrying amountfirst interim period beginning after June 15, 2003. We do not expect the adoption of SFAS No. 150 to have an impact on the financial position or results of operations of the long-lived asset.Company.

        The adoption of the Statement resulted in our recording an increase to the full cost pool of approximately $10.5 million, a decrease to accumulated depreciation, depletion and amortization of approximately $5.9 million, an increase to long-term liabilities for plugging and abandonment costs of approximately $13.8 million, an increase to the deferred tax liability of approximately $1.0 million and income reported as a cumulative effect of a change in accounting principle of approximately $1.6 million, net of income taxes of $1.0 million. On a pro forma basis, the asset retirement obligation would have been approximately $12.6 million as of January 1, 2002.16

        The following table reflects the components of the change in the carrying amount of the asset retirement obligation from January 1, 2003 to March 31, 2003 (in thousands):

ITEM 2 — 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 Cimarex receives for its 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.

        The following is a discussion of Cimarex's financial operations for the three months and six months ended June 30, 2003 and 2002. The notes to the Company's consolidated financial statements included in this report, as well as our Annual Report on Form 10-K for the year ended December 31, 2002 (and the notes attached thereto), should be read in conjunction with this discussion.

GENERAL

Business Activities

        The Company is pursuing an active drilling program for 2003. During the first six months, 74 wells were drilled, with another 134 wells scheduled for the last half of the year.

        The majority of exploration and development activity in the first half of the year has been in the Mid-Continent region, mainly in the Anadarko basin of Oklahoma and the Hardeman basin of north Texas. The Company has drilled 59 wells in the region, with an additional 100 wells forecasted to be drilled during the second half of the year. The focus of this upcoming activity will include ongoing drilling in the Anadarko basin, acceleration of the program in the Hardeman area, and new projects in the Texas Panhandle and Mountain Front play in southern Oklahoma.

        The Company continues to be active in the Gulf Coast area, comprised of south Louisiana and coastal Texas, as well as the Mississippi Salt basin. To date, 13 wells have been drilled. An additional 22 wells are planned for this region during the second half of 2003.

        Cimarex's Western region is focusing on the Williston basin in North Dakota and Montana, and the Sacramento basin of California. Plans for the region anticipate the drilling of 12 wells during the second half of the year, versus 2 wells during the first half.

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        In August, Cimarex has 14 drilling rigs working on Company operated properties. This compares to an average of 5 rigs during the first six months of 2003. The Company plans to average 12 operated rigs through the remainder of the year. The 134 additional wells to be drilled during the second half of 2003 should provide the opportunity for growth in proved reserves and production.

Financial Results

Net Income

        We generated net income of $32.7$21.0 million, or $0.78$0.50 per diluted share, for the firstsecond quarter of 2003 compared with net income of $4.3$9.8 million, or $0.16$0.37 per diluted share, for the same quarter of 2002. For the six months ended June 30, 2003, we generated net income of $53.8 million, or $1.28 per diluted share, compared to net income of $14.1 million or $0.53 per diluted share, for the same period in 2002. Included in net income for the quartersix months ended March 31,June 30, 2003 is $1.6 million, or $0.04 per share, associated with the cumulative effect of a change in accounting principle required upon the adoption of SFAS No. 143,Accounting for Asset Retirement Obligations. Excluding the impact of this cumulative effect adjustment, our net income would have been $31.1$52.2 million or $0.74$1.24 per diluted share. The increase in net income for the three and six months ended March 31,June 30, 2003 is primarily the result of increased oil and gas prices and higher production volumes attributed to the acquisition of Key on September 30, 2002.

        Information about oil and gas sales, production volumes and prices are presented in the following table:

        FirstSecond quarter 2003 oil and gas sales increased $66.5$41.3 million, or 286126 percent, to $89.8$74.1 million. Compared to a year earlier, second quarter gas sales increased $50.9$29.4 million and oil sales increased $15.6$11.9 million. Combined oil and gas volumes during the three month period ended March 31,June 30, 2003 were 178.8172.2 MMcfe per day, a 5248 percent increase from 118.0116.5 MMcfe per day produced during the firstsecond quarter of 2002. Gas prices increased 185jumped 62 percent to $5.76$4.75 per Mcf and oil realizations jumped 38increased 5 percent

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to $30.14$27.91 per Bbl. Included in our second quarter 2003 production volumes are 41.137.6 MMcf per day and 5,0214,052 barrels per day from the acquisition of Key.

        First quarterFor the six months ended June 30, 2003, gas and oil sales increased by $50.9$107.9 million, or 264193 percent, to $70.2$163.9 million from $19.3$56.0 million during the first six months of 2002. Gas sales increased $80.3 million and oil sales increased $27.5 million compared to the six months ended June 30, 2002. A 112 percent increase in realized gas prices and 27 percent higher volumes contributed to the increase in gas sales for the six months ended June 30, 2003 compared to the same period in 2002. Revenues from oil sales were impacted by a 20 percent increase in oil prices and a 240 percent increase in volumes. Combined gas and oil production volumes were 175.5 MMcfe per day in the first six months of 2003 versus 117.3 MMcfe per day in the comparable period of 2002. Included in the six month production volumes are 39.1 MMcf per day and 4,582 barrels per day from Key.

        Gas sales in the second quarter 2003 increased by $29.4 million, or 106 percent, to $57.2 million from $27.8 million in the same quarter of 2002. Daily gas production increased 2827 percent to 135.5132.3 MMcf versus 105.9104.2 MMcf in the firstsecond quarter of 2002. Higher gas volumes resulted from the inclusion of 41.137.6 MMcf per day from Key, together with drilling results, and are offset by natural production declines in wells we owned in 2002. These increased production volumes resulted in a $5.4$7.5 million increase in sales, and sales increased $45.5$21.9 million as the result of higher gas prices. The average realized gas price for the firstsecond quarter of 2003 was $5.76$4.75 per Mcf, compared to $2.02$2.93 per Mcf during the same three months of 2002.

        FirstGas sales for the first six months of 2003 of $127.4 million were impacted by higher gas prices and production volumes. Gas prices increased to $5.26 per Mcf in 2003 from $2.48 per Mcf in 2002 causing a $67.4 million positive impact in sales. Gas production also increased to 133.9 MMcf per day for the first six months in 2003 from 105.0 MMcf per day in 2002.

        Second quarter oil sales of $19.6$16.9 million increased from $4.0$5.0 million in the same period of 2002. Oil production increased 257223 percent and generated $10.2$11.1 million of incremental sales. Higher oil prices further enhanced revenues by $5.4$0.8 million. We produced an average of 7,2126,650 barrels per day in the firstsecond quarter of 2003 compared to 2,0192,060 barrels per day in the first quartersame period of 2002. The most significant increase in the volumes was the 5,0214,052 barrels per day from the acquisition of Key. Oil prices averaged $30.14$27.91 per barrel in the firstsecond quarter of 2003 versus $21.80$26.60 per barrel in the first quartersame period of 2002.

        Oil sales increased $27.5 million to $36.5 million in the first six months of 2003 compared to $9.0 million in the same period of 2002. Average oil prices increased to $29.06 per barrel in 2003 from $24.24 per barrel in 2002, resulting in $6.0 million of the increase in sales. Oil production averaged 6,930 barrels per day, a 240 percent increase from the 2,039 barrels per day produced in 2002 as a result of 4,582 barrels per day from the acquisition of Key.

        As the prices for oil and gas change, the components of our oil and gas sales fluctuate. In the quarterthree and six months ended March 31,June 30, 2003, our revenues came from the following product mix: 77 percent gas and 23 percent oil and 78 percent gas and 22 percent oil.oil, respectively. This compares to 8385 percent gas and 1715 percent oil in the first threesecond quarter of 2002 and 84 percent gas and 16 percent of oil in the six months ofended June 30, 2002. On a volumetric basis, we produced 76 percent gas and 24 percent oil in 2003 and 90 percent gas and 10 percent oil in 2002.

        The prices we receive reflect the impact of market forces, which are influenced by many factors, including: geopolitical events, economic growth, Organization of Petroleum Exporting Countries policies, weather, electricity demand and others. We have not entered into any derivative contracts or hedges with respect to our production.

        Gas marketing revenues increased to $46.6$25.0 million for the firstsecond quarter of 2003 compared to $11.5$13.2 million a year earlier. Gas marketing purchases for the three months ended March 31,June 30, 2003 were $46.1

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$24.8 million versus $10.2$13.1 million for the three months ended March 31,June 30, 2002. These increases are due almost exclusively to the higher gas prices in 2003.

        Gas marketing revenues for the six months ended June 30, 2003 were $71.7 million compared to $24.7 million for the six months ended June 30, 2002. Gas marketing purchases for the six months ended June 30, 2003 were $70.9 million and $23.3 million for the six months ended June 30, 2002. The increases are due to higher average gas prices in 2003 compared to 2002.

Costs and Expenses

        Depreciation, depletion and amortization expense (DD&A) on oil and gas properties increased 143119 percent between the firstsecond quarters of 2002 and 2003. On a unit of production basis, DD&A for oil and gas properties was $1.28$1.30 per Mcfe in the firstsecond quarter of 2003 compared to $0.82$0.88 per Mcfe for the same period in 2002. The increases are a result of a larger asset base following the acquisition of Key and higher costs for reserves added. Fixed asset depreciation of $0.5$0.6 million was higher than the comparable quarter by $0.2$0.3 million.

        DD&A for the six months ended June 30, 2003 increased 134 percent to $1.29 per Mcfe compared to $0.85 per Mcfe for the same period in 2002. The increase is a result of a higher basis in our net oil and gas properties in 2003 as a result of the acquisition of Key. Fixed asset depreciation of $1.1 million increased slightly.

        The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices are low or if we have substantial downward revisions in our estimated proved reserves. Based on oil and gas prices in effect on March 31,June 30, 2003, we were not required to record a full cost ceiling write-down. Because of the volatility of oil and gas prices, we may be required to record a ceiling test write-down in future periods.

        Our production costs increased 63142 percent between the firstsecond quarter of 2003 and the same period of 2002. On a unit of production basis, firstsecond quarter production costs increased to $0.43$0.52 per Mcfe in 2003 from $0.40$0.32 per Mcfe in 2002. The per unit increase is owing to additional workover costs of $0.9 million and the change in the product mix; oil wells (acquired from Key) cost more to operate on a per unit basis because of additional pumping and electricity charges.

        For the six months ended June 30, 2003, production costs increased 98 percent between 2003 and 2002. Compared on a unit of production basis, year to date expenses increased to $0.48 per Mcfe in 2003 from $0.36 per Mcfe in 2002. The costs associated with new productive wells in 2003 together with the decrease in overall production and additional workover costs results in higher overall production and per Mcfe costs. The workovers performed in 2003 appear to be fairly successful.

Taxes other than income for the firstsecond quarter of 2003 increased 20388 percent to $7.2$6.1 million from $2.4$3.3 million last year. Taxes other than income for 2003 equates to 8.08.3 percent of oil and gas sales, or $0.45$0.39 per Mcfe. This compares to 10.29.9 percent of oil and gas sales, or $0.22$0.31 per Mcfe, in 2002. The increase on a per unit basis is the result of the 286126 percent increase in oil and gas sales stemming from higher product prices and volumes.

        Taxes other than income for the first six months of 2003 were 8.1 percent of gas and oil sales compared to 10.0 percent of sales for 2002, or $0.42 per Mcfe and $0.27 per Mcfe, respectively. The increase on a per unit basis is the result of the 131 percent increase in gas and oil sales stemming from higher product prices. We believe that production, property and other taxes will average from eight to ten percent of gas and oil sales going forward.

        General and administrative expense (G&A) increased 95275 percent between the firstsecond quarters of 2002 and 2003. On a unit basis, firstsecond quarter 2003 G&A increased to $0.25$0.26 per Mcfe compared to $0.20$0.10 per Mcfe a year earlier. The increase is attributable to the larger organization resulting from the

20

Key acquisition, integration costs and establishing an acquisition group. G&A for the first six months of 2003 increased 157 percent to $0.26 per Mcfe compared to $0.15 in 2002.

        Income tax expense totaled $19.0$13.1 million and $32.1 million for the first three and six months ofended June 30, 2003 versus $2.6$6.3 million and $8.9 million for the same periodperiods in 2002.2002, respectively. Tax expense was calculated using a combined Federal and state effective income tax rate of 38 percent in 2003 and 2002, adjusted for items that are deductible solely for income tax purposes. We estimate that $6.9$14.4 million of our 2003 income tax expense is current.

Cash FlowLiquidity and LiquidityCapital Resources

        We primarily need cash to fund exploration, development, and acquisition activities and to pay existing obligations and trade commitments related to our oil and gas operations. OurA primary source of liquidity is the cash flow generated from operating activities. The prices we receive for future oil and gas sales and the level of production will significantly impact future cash flows from operating activities. No prediction can be made as to the oil and gas prices we will receive in the future. Production volumes will be dependent upon, among other things, the amount of future capital expenditures (which are also dependent on product prices), the outcome of new wells that will be drilled in the future, and potential acquisitions of producing properties. Strategically, Cimarex plans to grow its oil and gas reserves and production volumes prudently, by taking advantage of its strong asset base through a moderate risk-drilling program, supplemented from time to time by acquisitions.

        Cash flows provided by operationsoperating activities for the threesix months ended March 31,June 30, 2003 were $53.8$119.3 million compared to $11.9$30.2 million for the same period in 2002. The $41.9$89.1 million increase was the result of higher prices and production in 2003 compared to 2002.

        Cash flows used in investing activities for the threesix months ended March 31,June 30, 2003 were $30.8$64.2 million compared to $12.6$26.6 million for the same period of 2002. The $18.2$37.6 million increase was due to an increased capital expenditure program resulting from the expanded post-merger exploration program of the combined company.

        Cash flows used by financing activities for the threesix months ended March 31,June 30, 2003 were $26.1$30.0 million versus $1.5$7.6 million in the same period of 2002. The most significant item that occurred in the first quartersix months of 2003 was the repayment of $27$32 million of our long-term facility afforded by the relatively higher oil and gas prices in 2003.

        In addition to the cash flow generated from operating activities, Cimarex also has access to funds available through its credit facility. At June 30, 2003, Cimarex had no debt outstanding under its three year $400 million Credit Agreement. This facility has a borrowing base of $275 million and Cimarex has elected a $200 million commitment amount. The borrowing base is subject to redetermination each April and October. Borrowings under this quarter.facility bear interest at a LIBOR rate plus 1.25% to 2.00%, based on borrowing base usage. Unused borrowings are subject to a commitment fee of 0.375% to 0.50%, also depending on borrowing base usage. The credit facility is secured by mortgages on the Company's oil and gas properties and the stock of its subsidiaries. The Company is also subject to customary financial and non-financial covenants and is in compliance with all such covenants as of June 30, 2003.

        At March 31,June 30, 2003, wethe Company had commitments on oil and gas wells approved for drilling or in the process of being drilled at March 31,June 30, 2003 of approximately $5.8$13.0 million. We also had lease commitments for office space totaling $1.3$0.8 million and $1.7 million for the remainder of 2003 and 2004, respectively. All of these commitments are routine and were made in the normal course of our business. We believe that cash on hand, net cash generated from operations and amounts available under our existing line of credit will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities.

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Critical Accounting Policies

        We rely on management 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. Actual results could differ from those estimates.

        Significant estimates with regard to our consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows. Each quarter end, proved oil and gas reserve quantities are based on estimates prepared by Cimarex's engineers, in accordance with guidelines established by the SEC. Although we engaged Ryder Scott Company, L.P., independent petroleum engineers, to review our year end oil and gas reserve estimates associated with the majority of the value of our oil and gas reserves we perform all the analysis in-house on a quarterly basis. There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. Future oil and gas prices may vary significantly from the prices in effect at the time the estimates are made. The estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows can affect the charge for DD&A and the net carrying value of our oil and gas properties, as discussed below.

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

        Our rate of recording DD&A is dependent upon our estimate of proved reserves. If the estimates of proved reserves decline, the rate at which we record DD&A increases. Such a decline in reserves may result from lower market prices, which may make it economically unfeasible to drill for and produce higher cost wells. We utilize the units-of-production method to calculate our DD&A expense.

        Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.

        In accordance with full cost accounting rules, we are subject to a limitation on the capitalized costs of our oil and gas properties. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related tax effects and deferred tax revenues (the "full cost ceiling limitation"). These rules generally require pricing future oil and gas production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and require a write-down if the "ceiling" is exceeded. A full cost ceiling write-down is a non-cash charge to earnings. Moreover, the expense may not be reversed in future periods, even if higher oil and gas prices subsequently increase

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the full cost ceiling limitation. Based on oil and gas prices in effect on March 31,June 30, 2003, we were not required to record a full cost ceiling write-down.

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

        Accordingly, our natural gas revenue is impacted by these price fluctuations. If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into various derivative or off-balance sheet arrangements, such as non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options, and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments or arrangements to mitigate commodity price changes. If we decide to use derivative arrangements in the future, they could have a significant impact, positive or negative, on our results of operations and cash flows.

        Cimarex recorded approximately $45.9$44.9 million of goodwill in conjunction with the purchase price allocation of the Key acquisition. Statement of Financial Accounting Standard (SFAS) No. 142,Goodwill and Other Intangibles, requires us to assess the carrying value of the goodwill on an annual basis. We perform our annual assessment as of December 31 of each year. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of the commodity prices may cause more frequent assessments.

        We use a two-component process to evaluate goodwill, a cash flow model and the equity value of the Company. The relative weight of the two measures and the cash flow assumptions is subjectively evaluated by management based on management's view of the going concern long-term fair value of the exploration and production segment. The weighting of the two measures could create different results, including a possible impairment.

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

        Prior to the spin-off of Cimarex from H&P on September 30, 2002, Cimarex's operating results historically had been included in consolidated federal and state income tax returns filed by H&P. A tax sharing agreement exists between Cimarex and H&P to allocate and settle among themselves the consolidated tax liability on a shared company basis through September 30, 2002 (see Note 56 of the Consolidated Financial Statements).

        Cimarex recognizes revenues from oil and gas sales on the sales method with revenue recognized based on actual volumes of oil and gas sold to purchasers.

Recent Accounting Pronouncements

        On January 1,In April 2003 Cimarex adoptedthe Financial Accounting Standards Board (FASB) issued SFAS No. 143,149, Amendment of Statement 133 onAccounting for Asset Retirement Obligations.Derivative Instruments and Hedging Activities. This Statement addressesamends and clarifies financial accounting and reporting for obligations associatedderivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.

        The changes in this Statement improve financial reporting by requiring that contracts with comparable characteristics be accounted for similarly In particular, this Statement (1) clarifies under what circumstances a contract with an initial net investment meets the retirementcharacteristic of tangible long-lived assetsa derivative

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discussed in paragraph 6(b) of SFAS No. 133, (2) clarifies when a derivative contains a financing component, (3) amends the definition of underlying to conform it to language used in FASB Interpretation No. 45,Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and (4) amends certain other existing pronouncements. Those changes will result in more consistent reporting of contracts as either derivatives or hybrid instruments. This Statement is effective for contracts entered into or modified after June 30, 2003, except as stated below and for hedging relationships designated after June 30, 2003. In addition, all provisions of this Statement should be applied prospectively. We do not expect the associated asset retirement costs. Theadoption of SFAS No. 149 to have an impact on the financial position or results of operations of Cimarex.

        In May 2003, the FASB issued SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that the fair value ofan issuer classify a financial instrument that is within its scope as a liability for(or an asset retirement obligation be recognized in some circumstances). Many of those instruments were previously classified as equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at 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 partbeginning of the carrying amountfirst interim period beginning after June 15, 2003. We do not expect the adoption of SFAS No. 150 to have an impact on the financial position or results of operations of the long-lived asset. The adoption of the Statement resulted in our recording an increase to the full cost pool of approximately $10.5 million, a decrease to accumulated depreciation, depletion and amortization of approximately $5.9 million, an increase to long-term liabilities for plugging and abandonment costs of approximately $13.8 million, an increase to the deferred tax liability of approximately $1.0 million and income reported as a cumulative effect of a change in accounting principle of approximately $1.6 million, net of income taxes of $1.0 million.Company.

Future Trends and Significant Events

        We continue to be on track to spend approximately $145 million on exploration and development for all of 2003.        The amount and allocation of our future capital expenditures depends on a number of factors, including the impact of oil and gas prices on available cash flow and exploration economics, the availability of rigs, the availability of debt and equity capital, the availability of attractive drilling opportunities, and our capability to evaluate these opportunities. We plan to fund these expenditures with cash provided by operating activities, supplemented by borrowings under our bank line of credit to the extent necessary.

        First half 2003 capital expenditures for exploration and development totaled $59.5 million, or 40.0 percent of total estimated annual expenditures of $150-$155 million. The beginnings of the drilling program were slower than originally anticipated. As such, though the projects and potential reserves remain in place, forecasted oil and gas production volumes for 2003 need to be revised. Second quarter aggregate production averaged 172.2 MMcfe per day, comprised of 132.3 MMcf per day of gas and 6,650 barrels of oil per day. Production for the third quarter should total 170-175 MMcfe per day, with fourth quarter production averaging 175-185 MMcfe per day.

ITEM 3 — 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Price Fluctuations

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

        If we wanted to attempt to smooth out the effect of commodity price fluctuations, we could enter into non-speculative hedge arrangements, commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements relating to natural gas and crude oil. To date, we have not used any of these financial instruments to mitigate commodity price changes.

        Oil and gas price realizations for the threesix months ended March 31,June 30, 2003 ranged from a monthly average low of $4.56$4.52 per Mcf and $28.66$26.03 per Bbl, and a monthly high of $7.30$7.11 per Mcf and $31.90$31.12 per Bbl, respectively. It is impossible to predict future oil and gas prices with any degree of certainty.

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

Interest Rate Risk

        Our reported earnings will be impacted by changes in interest rates. Any fluctuation in the rate will directly affect the amount of interest expense we report. At March 31,June 30, 2003, we had $5.0 million ofno debt outstanding athaving paid $27 million in the first quarter and another $5 million in the second quarter. For the outstanding debt during the six month period ended June 30, 2003, we realized an average interest rate of 2.62.62 percent. In addition, we paid $0.2$0.4 million in commitment fees and incurred amortization of deferred financing costs of $0.1 million for the three months ended March 31, 2003.six month period. At our election, our interest charges are based on either the prime rate or the LIBOR rate plus a margin predetermined by our debt agreement. As the interest rate is variable and is reflective of current market conditions, the carrying value of our debt approximateswill approximate its fair value.

ITEM 4 — 4—CONTROLS AND PROCEDURES