CIMAREX ENERGY CO - 10-Q Quarterly Report

CIMAREX ENERGY CO.
707 Seventeenth Street, Suite 3300
Denver, Colorado 80202-3404
(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 ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý No o

The number of shares Cimarex Energy Co. common stock outstanding as of September 30, 2003 was 41,638,226.

			Page
PART I		3
Item 1—	Financial Statements		3
	Consolidated balance sheets (unaudited) as of September 30, 2003 and December 31, 2002		3
	Consolidated statements of operations (unaudited) for the three and nine months ended September 30, 2003 and September 30, 2002		4
	Consolidated statements of cash flows (unaudited) for the nine months ended September 30, 2003 and September 30, 2002		6
	Consolidated statement of stockholders' equity (unaudited) for the nine months ended September 30, 2003		7
	Notes to consolidated financial statements		8
Item 2—	Management's Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3—	Quantitative and Qualitative Disclosures About Market Risk		25
Item 4—	Controls and Procedures		25
PART II		26
Item 6—	Exhibits and Reports on Form 8-K		26

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.

CIMAREX ENERGY CO.

Consolidated Statement of Stockholders' Equity

For the Nine Months Ended September 30, 2003

(Unaudited)

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2003

(Unaudited)

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. Cimarex 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, 2002.

Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). In July 2002, H&P contributed its oil and gas exploration and production operations and the common stock of Cimarex Energy Services, Inc. (CESI), which is involved in natural gas marketing, to Cimarex. As a result of a dividend declared and paid by H&P on September 30, 2002, in the form of Cimarex common stock, Cimarex was spun-off and became a stand-alone company. All par value, common stock and per share amounts have been retroactively restated in the accompanying consolidated financial statements to reflect the spin-off.

Also on September 30, 2002, Cimarex acquired 100 percent of the outstanding common stock of Key Production Company, Inc. (Key) in a tax-free exchange. Cimarex issued one share of its common stock for each share of Key common stock outstanding as of that date. The consolidated results of operations and cash flows subsequent to September 30, 2002 include the acquisition of Key.

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. Actual results could differ from those estimates.

The more significant areas requiring the use of management's estimates and judgments relate to preparation of estimated 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 the ceiling test limitations and estimates of abandonment obligations used in such calculations. Estimates and judgments are also required in determining the reserves for bad debts, the impairments of undeveloped properties, the assessment of goodwill and the valuation of deferred tax assets.

Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to the current year presentation.

Cimarex applies Accounting Principles Board (APB) Opinion 25, Accounting for Stock Issued to Employees, and related interpretations to account for all stock option grants and grants of restricted

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

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.

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

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

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 were finalized at September 30, 2003 based on the actual fair value of current assets and liabilities, and long-term liabilities. 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 nine months ended September 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 nine months ended September 30, 2002 is $5.8 million and $11.0 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.

	Three Months Ended September 30, 2002		Nine Months Ended September 30, 2002
	(In thousands, except per share amounts)
Total revenues	$	72,318	$	191,101
Net income	$	6,657	$	16,432
Basic and diluted income per share	$	0.16	$	0.40

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.

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 nine months ended September 30, 2003 (in thousands):

Initial adoption amount as of January 1, 2003		$	13,784
	Liabilities incurred in the current period		1,027
	Liabilities settled in the current period		(229	)
	Accretion expense		737

Balance as of September 30, 2003		$	15,319

At September 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 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 September 30, 2003.

Federal income tax expense for the three and nine months ended September 30, 2003 and 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.

A final determination of Cimarex's tax basis has been made resulting in a reduction in tax basis of $0.1 million. The adjustment was accounted for at the statutory tax rate of 38% and resulted in a distribution to Helmerich & 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 the original estimate made at the time of the merger with Cimarex. The increase was accounted for at the statutory tax rate of 38% and resulted in a decrease in goodwill of $1.5 million.

Income tax expense consisted of the following for the three and nine months ended September 30, (in thousands):

		Three Months Ended September 30,				Nine Months Ended September 30,
		2003		2002		2003		2002
Current taxes:
	Federal	$	5,555	$	—	$	18,083	$	—
	State		1,199		27		3,025		30

			6,754		27		21,108		30
Deferred taxes			6,410		3,997		24,137		12,929

		$	13,164	$	4,024	$	45,245	$	12,959

		Nine Months Ended September 30,
		2003		2002
		(In thousands)
Cash paid during the period for:
	Interest (net of amounts capitalized)	$	591	$	918
	Income taxes (net of refunds received)	$	14,733	$	—

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

As of September 30, 2003, there were 3,427,705 stock options outstanding, 1,543,133 of which were vested and exercisable for purposes of the diluted calculation. All stock options were considered potentially dilutive securities for the three and nine months ended September 30, 2003. The weighted average common shares of diluted earnings per share calculation for the three and nine months ended September 30, 2002 excludes the incremental effect related to outstanding stock options exercisable for 225,601 shares of Cimarex common stock whose exercise price was in excess of the average price of Cimarex's stock for the period the options were outstanding.

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.

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

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).

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 20 Bcf of gross gas drainage. Cimarex denies that the drainage, if any, was in an amount that significant. The plaintiffs have stated that the royalty owner class has sustained actual damages of approximately $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 $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. As such, Cimarex is seeking 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 $2.0 million to $2.5 million, net to our interest.

As of September 30, 2003, Cimarex had approximately $19.1 million of parental guarantees outstanding. These guarantee the credit of certain CESI agreements and are for the benefit of certain counterparties.

The Financial Accounting Standards Board (FASB) is currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets, to companies in the extractive industries, including oil and gas companies. The FASB is 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 determines that costs associated with mineral rights are required to be classified as intangible assets, approximately $7.6 million, net of $10.1 million in accumulated depreciation, depletion and amortization, of our proved oil and gas property acquisition costs and approximately $23.5 million of the Company's unproved properties 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 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 amends and clarifies financial accounting and reporting for derivative 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 characteristic of a 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 instruments. This Statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. In addition, all provisions of this Statement should be applied prospectively. The adoption of SFAS No. 149 did not 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 an issuer classify a financial instrument that is within its scope as a liability (or an asset 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 beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS No. 150 did not have an impact on the financial position or results of operations of the Company.

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 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 nine months ended September 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.

During the third quarter of 2003, Cimarex participated in 48 gross (30 net) wells, of which 34 (20 net) were successful. This compares to 37 gross (17 net) wells drilled during the second quarter of 2003.

For the first nine months of 2003, 118 gross (61 net) wells were drilled, with a gross success rate of 78 percent (70 percent net). We expect to drill approximately 60 gross wells in the fourth quarter.

The majority of our exploration and development activity has been focused in the Mid-Continent region, mainly in western Oklahoma and the Hardeman basin of north Texas. In the third quarter we drilled 40 gross (25 net) wells in this region, achieving a 78 percent success rate.

Other third quarter highlights include activity in the Gulf Coast area. The Mauboules #1 well (64 percent working interest) on the West Gueydan prospect in Vermilion Parish, Louisiana, reached total depth and electric logs were taken from the Miogyp formation. Plans are being made to complete this well and drill an offsetting development well.

Two new producing wells were also drilled in Mississippi. The Collins #1 (62 percent working interest) began producing at net daily rates approximating 1.0 MMcf of gas and 100 barrels of condensate. The Morris #1 (55 percent working interest) came on at 1.4 net MMcf of gas per day.

Cimarex's Western region is focusing on projects in California's northern San Joaquin Valley and the Williston basin of North Dakota. In California, the Col de Tourmalet well (100 percent working interest) was tested at a rate of 1 MMcf of gas per day. A successful offset well has also been drilled. In North Dakota, the Gasho 1-22 horizontal well targeting the Nisku formation was not successful.

At quarter end, Cimarex had 14 drilling rigs working on operated properties and working interests in 5 additional wells that are operated by others. We plan to have 12-17 operated rigs through the remainder of the year.

		Three Months Ended September 30,				Nine Months Ended September 30,
		2003		2002		2003		2002
		(In thousands, except per share amounts)
Revenues		$	112,113	$	51,808	$	347,560	$	132,517
Net income			22,541		9,930		76,329		24,032
	Per share—basic		0.54		0.37		1.84		0.90
	Per share—diluted		0.53		0.37		1.81		0.90

Third quarter 2003 net income totaled $22.5 million, or $0.53 per diluted share compared to net income of $9.9 million, or $0.37 per diluted share, for the same quarter of 2002. For the nine months ended September 30, 2003, net income was $76.3 million, or $1.81 per diluted share, compared to net income of $24.0 million or $0.90 per diluted share, for the same period in 2002. Included in net income for the nine months ended September 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 $74.7 million or $1.77 per diluted share. The increase in net income for the three and nine months ended September 30, 2003 is primarily the result of increased oil and gas prices and higher production volumes principally resulting from the acquisition of Key on September 30, 2002.

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

		Three Months Ended September 30,				Nine Months Ended September 30,
		2003		2002		2003		2002
		(In thousands or as indicated)
Gas sales		$	59,956	$	26,626	$	187,364	$	73,695
Oil sales			17,652		4,870		54,105		13,816

	Total oil and gas sales	$	77,608	$	31,496	$	241,469	$	87,511

Total gas volume—Mcf			12,965,858		9,378,361		37,200,195		28,386,378
Gas volume—MMcf per day			140.9		101.9		136.3		104.0
Gas price—per Mcf		$	4.62	$	2.84	$	5.04	$	2.60
Total oil volume—barrels			611,400		198,179		1,865,662		567,274
Oil volume—barrels per day			6,646		2,154		6,834		2,078
Oil price—per barrel		$	28.87	$	24.57	$	29.00	$	24.36

Third quarter 2003 oil and gas sales increased $46.1 million, or 146 percent, to $77.6 million. This was the result of increases in production and prices for both oil and gas. Combined oil and gas volumes produced during the three month period ended September 30, 2003 were 180.8 MMcfe per day, a 57 percent increase from 114.9 MMcfe per day during the third quarter of 2002. This increase in production was primarily the result of the September 30, 2002 acquisition of Key. Included in our third quarter 2003 production volumes are 65.9 MMcfe per day from wells owned by Key at the time of the merger or drilled on Key's acreage subsequent to the merger.

For the nine months ended September 30, 2003, oil and gas sales increased by $154.0 million, or 176 percent, to $241.5 million from $87.5 million during the first nine months of 2002. Gas sales increased $113.7 million and oil sales increased $40.3 million compared to the nine months ended September 30, 2002. A 94 percent increase in realized gas prices and 31 percent higher volumes contributed to the increase in gas sales for the nine months ended September 30, 2003 compared to the same period in 2002. Revenues from oil sales were impacted by a 19 percent increase in oil prices and a 229 percent increase in volumes. Combined oil and gas production volumes were 177.3 MMcfe per day in the first nine months of 2003 versus 116.4 MMcfe per day in the comparable period of 2002. Included in nine month 2003 production volumes are 39.8 MMcf per day of gas and 4,425 barrels per day of oil from producing properties owned by Key or drilled on Key's acreage subsequent to the merger.

Gas sales in the third quarter 2003 increased by $33.4 million, or 126 percent, to $60.0 million from $26.6 million in the same quarter of 2002. Higher production volumes resulted in a $10.2 million increase in sales, and higher prices boosted sales by $23.2 million. Daily gas production increased 38 percent to 140.9 MMcf and included 41.2 MMcf from Key properties. The average realized gas price for the third quarter of 2003 was $4.62 per Mcf, compared to $2.84 per Mcf during the same three months of 2002.

Gas sales for the first nine months of 2003 of $187.4 million were also impacted by higher prices and volumes. Gas prices increased to $5.04 per Mcf in 2003 from $2.60 per Mcf in 2002 causing a $90.8 million positive impact in sales. Gas production increased to 136.3 MMcf per day in 2003 from 104.0 MMcf per day during the first nine months of 2002, due in large part to the inclusion of volumes from Key's properties.

Third quarter oil sales of $17.7 million increased from $4.9 million in the same period of 2002. Oil production increased 209 percent and generated $10.2 million of incremental sales. Higher oil prices enhanced revenues by $2.6 million. We produced an average of 6,646 barrels per day in the third quarter of 2003 compared to 2,154 barrels per day in the same period of 2002. The increase in volumes mostly stems from the 4,116 barrels per day produced from Key's properties. Oil prices averaged $28.87 per barrel in the third quarter of 2003 versus $24.57 per barrel in the same period of 2002.

Oil sales increased $40.3 million to $54.1 million in the first nine months of 2003 compared to $13.8 million in the same period of 2002. Average oil prices increased to $29.00 per barrel in 2003 from $24.36 per barrel in 2002, resulting in $8.7 million of the increase in sales. Oil production averaged 6,834 barrels per day, a 229 percent increase from the 2,078 barrels per day produced in 2002. Nine month 2003 output includes 4,425 barrels per day from Key's properties.

The components of our oil and gas sales have fluctuated between periods. In the three and nine months ended September 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, respectively. This compares to 85 percent gas and 15 percent oil in the third quarter of 2002 and 84 percent gas and 16 percent oil in the nine months ended September 30, 2002. This fluctuation results primarily from the acquisition of Key, which had an oil component of approximately 40 percent of its total production.

The prices we receive for oil and gas generally reflect the impact of market forces, which are influenced by many factors, including: geopolitical events, economic growth, Organization of Petroleum Exporting Countries policies, North American gas supply and demand, and others. We have not entered into any derivative contracts or other commodity price hedges with respect to our production.

Gas marketing revenues increased to $34.3 million for the third quarter of 2003 compared to $20.2 million a year earlier. Gas marketing purchases for the three months ended September 30, 2003 were $34.2 million versus $19.3 million for the three months ended September 30, 2002. These increases are due almost exclusively to the higher gas prices in 2003.

Gas marketing revenues for the nine months ended September 30, 2003 were $106.0 million compared to $44.9 million for the nine months ended September 30, 2002. Gas marketing purchases for the nine months ended September 30, 2003 were $105.1 million and $42.6 million for the nine months ended September 30, 2002. The increases are due to higher average gas prices in 2003 compared to 2002.

Depreciation, depletion and amortization expense (DD&A) on oil and gas properties increased 120 percent between the third quarters of 2002 and 2003. On a unit of production basis, DD&A for oil and gas properties was $1.32 per Mcfe in the third quarter of 2003 compared to $0.94 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 $0.6 million was higher than the comparable quarter by $0.4 million.

DD&A on oil and gas properties for the nine months ended September 30, 2003 increased 129 percent to $1.30 per Mcfe compared to $0.86 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 $1.8 million increased $1.1 million due to upgrading and acquiring additional fixed assets after the acquisition of Key.

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 September 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 108 percent between the third quarter of 2003 and the same period of 2002. On a unit of production basis, third quarter production costs increased to $0.50 per Mcfe in 2003 from $0.38 per Mcfe in 2002. The overall and per unit increase is largely the result of the acquisition of Key properties. Apart from the costs associated with Key's wells, its production mix included proportionately more oil wells, which generally cost more to operate on a per unit basis because of additional pumping and electricity charges. Included in third quarter 2003 production costs are $1.6 million of workover costs, which equate to $0.10 per Mcfe.

For the nine months ended September 30, production costs increased 101 percent between 2003 and 2002. Compared on a unit of production basis, year to date expenses increased to $0.49 per Mcfe in 2003 from $0.37 per Mcfe in 2002. The costs associated with Key's wells together with additional workover costs result in higher overall production and per Mcfe costs.

Taxes other than income for the third quarter of 2003 increased 124 percent to $6.1 million from $2.7 million last year. Taxes other than income for 2003 equates to 7.9 percent of oil and gas sales, or $0.37 per Mcfe. This compares to 8.7 percent of oil and gas sales, or $0.26 per Mcfe, in 2002. The increase on a per unit basis is the result of the 146 percent increase in oil and gas sales stemming from higher product prices and volumes.

Taxes other than income for the first nine months of 2003 were 8.1 percent of gas and oil sales compared to 9.6 percent of sales for 2002, or $0.40 per Mcfe and $0.26 per Mcfe, respectively. The increase on a per unit basis is the result of the 176 percent increase in gas and oil sales stemming from higher product prices and volumes.

General and administrative expense (G&A) increased 146 percent between the third quarters of 2002 and 2003. On a unit basis, third quarter 2003 G&A increased to $0.25 per Mcfe compared to $0.16 per Mcfe a year earlier. The increase is attributable to the larger organization resulting from the Key acquisition. G&A for the first nine months of 2003 increased 153 percent to $0.26 per Mcfe compared to $0.15 per Mcfe in 2002.

As of September 30, 2003, Cimarex had no debt. This compares to debt of $32 million at December 31, 2002. We reduced our debt, all of which was in the form of bank debt, by $27 million during the first quarter of 2003 and paid off the remaining $5 million during the second quarter. During the six months of 2003 that we did have debt outstanding, our average interest rate was 2.6 percent. We also incurred $0.6 million in bank commitment fees and amortized $0.2 million of deferred financing costs during the first nine months of 2003. During the third quarter commitment fees and deferred financing cost amortization totaled $0.3 million.

Income tax expense totaled $13.2 million and $45.2 million for the three and nine months ended September 30, 2003 versus $4.0 million and $13.0 million for the same periods in 2002, respectively. Tax expense was calculated using a combined Federal and state effective income tax rate of 38 percent and 38.5 percent in 2003 and 2002, respectively, adjusted for items that are deductible solely for income tax purposes. We estimate that $21.1 million of our 2003 income tax expense is current.

Cimarex plans to grow its oil and gas reserves and production volumes through exploration and development supplemented from time to time by acquisitions. 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. Our primary source of liquidity is cash flow provided by operating activities. The prices we receive for our 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.

Cash flows provided by operating activities for the nine months ended September 30, 2003 were $171.2 million compared to $71.6 million for the same period in 2002. The $99.6 million increase was the result of higher prices and production in 2003 compared to 2002.

Cash flows used in investing activities for the nine months ended September 30, 2003 were $106.9 million compared to $49.6 million for the same period of 2002. The $57.3 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 nine months ended September 30, 2003 were $29.7 million versus $13.9 million in the same period of 2002. The most significant item that occurred in the first nine months of 2003 was the repayment of $32.0 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 September 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 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 September 30, 2003.

At September 30, 2003, the Company had commitments on oil and gas wells approved for drilling or in the process of being drilled of approximately $15.5 million. We also had lease commitments for office space totaling $0.4 million and of $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 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 the full cost ceiling limitation. Based on oil and gas prices in effect on September 30, 2003, we were not required to record a full cost ceiling write-down.

Cimarex recorded approximately $45.0 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 6 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.

be classified as intangible assets, approximately $7.6 million, net of $10.1 million in accumulated depreciation, depletion and amortization, of our proved oil and gas property acquisition costs and approximately $23.5 million of the Company's unproved properties 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 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 amends and clarifies financial accounting and reporting for derivative 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 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, and, if necessary, cash on hand and borrowings under our credit facility.

Capital expenditures for exploration and development during the first nine months of 2003 totaled $104.6 million. We expect to invest approximately $50 million in exploration and development during the fourth quarter, which would result in $150-155 million of expenditures for the year. Our preliminary expectations for 2004 capital expenditures range from $175-200 million.

Third quarter aggregate production averaged 180.8 MMcfe per day, comprised of 140.9 MMcf per day of gas and 6,646 barrels of oil per day. Projected production for the fourth quarter of 2003 is

estimated to average 175-185 MMcf equivalent per day, despite a pipeline disruption in western Oklahoma that is expected to negatively impact our net gas production by approximately 5 MMcf per day for six or more weeks.

Our results of operations, proved oil and gas reserve estimates, standardized measure of discounted future net cash flows and financial position may all be materially affected by lower oil and gas prices. In periods of sharply lower prices we may also curtail production and reduce exploration and development activity.

Crude oil prices remain volatile and on time to be affected by worldwide political events, OPEC pricing and production policies, and other global supply and demand factors. U.S. natural gas prices have been even more volatile, impacted by weather, changes in industrial demand, gas storage injection and withdrawal patterns, declining overall U.S. gas supply, rising gas imports and trading patterns in the commodity futures market.

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 nine months ended September 30, 2003 ranged from a monthly average low of $26.03 per Bbl and $4.19 per Mcf to a monthly high of $32.12 per Bbl and $7.11 per Mcf, respectively. We do not believe that we can predict future oil and gas prices with any degree of certainty.

Cimarex may be exposed to risk resulting from changes in interest rates as a result of our variable rate bank credit facility. However, because we presently have no debt outstanding, the potential effect that changes in interest rates could have on our results of operations and the fair value of our debt is not material.

As of the end of the period covered by this report, with the participation of management, Cimarex's Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of Cimarex's disclosure controls and procedures (as defined in Securities Exchange Act Rules 13a-14(c) and 15d-14(c)) to ensure that information required to be disclosed by Cimarex under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that Cimarex's disclosure controls and procedures are effective.

There were no significant changes in Cimarex's internal controls or in other factors that could significantly affect these controls subsequent to the Evaluation Date.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

(Mark One)
ý	Quarterly Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934
o	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period ended September 30, 2003

			September 30, 2003			December 31, 2002
			(Unaudited)
			(In thousands, except share data)
Assets
Current assets:
	Cash and cash equivalents		$	56,858		$	22,327
	Receivables, net			56,510			58,276
	Inventories			6,744			3,986
	Deferred income taxes			1,741			2,073
	Other current assets			3,533			2,949

		Total current assets		125,386			89,611

Oil and gas properties at cost, using the full cost method of accounting:
	Proved properties			1,268,952			1,172,488
	Unproved properties and properties under development, not being amortized			43,325			23,941

				1,312,277			1,196,429
	Less—accumulated depreciation, depletion and amortization			(722,693	)		(665,711	)

		Net oil and gas properties		589,584			530,718

Fixed assets, net				11,617			6,849
Goodwill				44,967			45,836
Other assets, net				1,011			1,272

			$	772,565		$	674,286

Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable		$	18,160		$	22,339
	Accrued liabilities			38,574			21,892
	Revenue payable			22,580			24,022

		Total current liabilities		79,314			68,253

Long-term debt				—			32,000

Deferred income taxes				149,641			127,023

Other liabilities				17,830			2,130

Stockholders' equity:
	Preferred stock, $0.01par value, 15,000,000 shares authorized, no shares issued			—			—
	Common stock, $0.01par value, 100,000,000 shares authorized, 41,638,226 and 41,410,308 shares issued and outstanding, respectively			416			414
	Paid-in capital			247,188			243,420
	Unearned compensation			(9,959	)		(10,814	)
	Retained earnings			288,135			211,860

				525,780			444,880

			$	772,565		$	674,286

				For the Three Months Ended September 30,						For the Nine Months Ended September 30,
				2003			2002			2003			2002
				(In thousands, except per share data)
Revenues:
	Gas sales			$	59,956		$	26,626		$	187,364		$	73,695
	Oil sales				17,652			4,870			54,105			13,816
	Marketing, gathering and transportation				34,337			20,222			105,989			44,888
	Other				168			90			102			118

					112,113			51,808			347,560			132,517

Operating expenses:
	Depreciation, depletion and amortization				22,672			10,158			64,676			28,145
	Asset retirement obligation accretion				241			—			737			—
	Marketing, gathering and transportation				34,192			19,339			105,063			42,606
	Production				8,364			4,015			23,507			11,671
	Taxes other than income				6,131			2,733			19,449			8,360
	General and administrative				4,181			1,699			12,320			4,868
	Stock compensation				448			—			1,350			—
	Financing costs—
		Interest expense			302			(12	)		998			70
		Capitalized interest			—			—			(304	)		—
		Interest income			(123	)		(78	)		(205	)		(194	)

					76,408			37,854			227,591			95,526

Income before income tax expense and cumulative effect of a change in accounting principle					35,705			13,954			119,969			36,991
Income tax expense					13,164			4,024			45,245			12,959

Income before cumulative effect of a change in accounting principle					22,541			9,930			74,724			24,032
Cumulative effect of a change in accounting principle, net of tax					—			—			1,605			—

			Net income	$	22,541		$	9,930		$	76,329		$	24,032

Earnings per share:
	Basic—
		Income before cumulative effect of a change in accounting principle		$	0.54		$	0.37		$	1.80		$	0.90
		Cumulative effect of a change in accounting principle, net of tax			—			—			0.04			—

		Net income		$	0.54		$	0.37		$	1.84		$	0.90

	Diluted—
		Income before cumulative effect of a change in accounting principle		$	0.53		$	0.37		$	1.77		$	0.90
		Cumulative effect of a change in accounting principle, net of tax			—			—			0.04			—

		Net income		$	0.53		$	0.37		$	1.81		$	0.90

Weighted average basic shares outstanding					41,612			26,745			41,545			26,643

Weighted average diluted shares outstanding					42,297			26,749			42,195			26,644

			For the Three Months Ended September 30,				For the Nine Months Ended September 30,
			2003		2002		2003		2002
			(as reported)		(pro forma)		(as reported)		(pro forma)
			(In thousands, except per share data)
Pro forma amounts assuming new method of accounting for asset retirement obligations is applied retroactively
	Net income		$	22,541	$	9,781	$	74,724	$	23,564
	Earnings per share
		Basic	$	0.54	$	0.37	$	1.80	$	0.88
		Diluted	$	0.53	$	0.37	$	1.77	$	0.88

				For the Nine Months Ended September 30,
				2003			2002
				(In thousands)
Cash flows from operating activities:
	Net income			$	76,329		$	24,032
	Adjustment to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			64,676			28,145
		Cumulative effect of a change in accounting principle, net of taxes			(1,605	)		—
		Deferred income taxes			24,137			12,929
		Asset retirement obligation accretion			737			—
		Amortization of restricted stock			1,416			—
		Income tax benefit related to stock options exercised			561			—
		Other			236			(22	)
	Changes in operating assets and liabilities:
		(Increase) decrease in accounts receivables			1,621			(2,480	)
		(Increase) decrease in inventories			(2,758	)		1,199
		(Increase) decrease in other current assets			(615	)		1,326
		Increase (decrease) in accounts and revenue payables			(5,740	)		4,700
		Increase in accrued liabilities			12,308			1,944
		Decrease in other non-current liabilities			(143	)		(144	)

			Net cash provided by operating activities		171,160			71,629

Cash flows from investing activities:
	Capital expenditures				(97,896	)		(45,918	)
	Acquisition of proved oil and gas properties				(2,531	)		—
	Cash cost of acquisition				—			(4,900	)
	Cash received in connection with acquisition of Key Production Company, Inc.				—			2,135
	Proceeds from sale of assets				231			—
	Other capital expenditures				(6,691	)		(902	)

			Net cash used by investing activities		(106,887	)		(49,585	)

Cash flows from financing activities:
	Payments on long-term debt				(32,000	)		—
	Change in amount due to Helmerich & Payne, Inc.				—			(13,908	)
	Common stock reacquired and retired				(8	)		—
	Proceeds from issuance of common stock				2,266			—

			Net cash used by financing activities		(29,742	)		(13,908	)

Net change in cash and cash equivalents					34,531			8,136
Cash and cash equivalents at beginning of period					22,327			7,170

Cash and cash equivalents at end of period				$	56,858		$	15,306

	Common Stock
	Common Stock				Paid-in Capital			Unearned Compensation			Retained Earnings
	Shares		Amount		Paid-in Capital			Unearned Compensation			Retained Earnings
	(In thousands)
Balance, December 31, 2002	41,410		$	414	$	243,420		$	(10,814	)	$	211,860
Net income	—			—		—			—			76,329
Issuance of restricted stock awards	55			1		1,137			(1,138	)		—
Common stock reacquired and retired	(16	)		—		(261	)		229			—
Amortization of unearned compensation	—			—		—			1,764			—
Exercise of stock options	189			1		2,265			—			—
Acceleration of vesting	—			—		66			—			—
Net distribution to Helmerich & Payne, Inc.	—			—		—			—			(54	)
Tax benefit related to stock options exercised	—			—		561			—			—

Balance, September 30, 2003	41,638		$	416	$	247,188		$	(9,959	)	$	288,135

		Options Outstanding		Weighted Average Exercise Price		Options Exercisable
Outstanding as of January 1, 2003		3,632,087		$	14.14
	Exercised	(188,515	)		12.02
	Granted	24,000			20.36
	Forfeited/Expired	(39,867	)		16.02

Outstanding as of September 30, 2003		3,427,705		$	14.28	1,543,133

	Outstanding Stock Options				Exercisable Stock Options
Range of Exercise Prices	Options	Weighted- Average Remaining Contractual Life	Weighted- Average Exercise Price		Options	Weighted- Average Exercise Price
$6.11 to $8.14	198,457	4.8 Years	$	7.78	198,457	$	7.78
$8.15 to $10.17	230,500	5.9 Years		9.69	230,500		9.69
$10.18 to $12.21	546,571	4.7 Years		11.53	457,806		11.50
$12.22 to $14.24	590,215	7.2 Years		13.61	290,445		13.21
$14.25 to $16.28	363,553	7.2 Years		15.20	155,205		15.20
$16.29 to $18.31	1,429,409	8.6 Years		16.77	165,720		17.37
$18.32 to $20.36	69,000	8.4 Years		19.32	45,000		18.77

			External Sales		Operating Profit (Loss)			Depreciation, Depletion and Amortization		Total Assets		Additions to Long-Lived Assets
			(In thousands)
Three Months Ended September 30, 2003:
	Exploration and Production		$	77,608	$	35,850		$	22,613	$	747,613	$	36,302
	Natural Gas Marketing			34,337		(134	)		59		24,952		(101	)

		Total	$	111,945	$	35,716		$	22,672	$	772,565	$	36,201

Three Months Ended September 30, 2002:
	Exploration and Production		$	31,496	$	14,047		$	10,111	$	627,133	$	20,673
	Natural Gas Marketing			20,222		(303	)		47		23,604		25

		Total	$	51,718	$	13,744		$	10,158	$	650,737	$	20,698

Nine Months Ended September 30, 2003:
	Exploration and Production		$	241,469	$	120,347		$	64,511	$	747,613	$	110,810*
	Natural Gas Marketing			105,989		9			165		24,952		177

		Total	$	347,458	$	120,356		$	64,676	$	772,565	$	110,987

Nine Months Ended September 30, 2002:
	Exploration and Production		$	87,511	$	35,330		$	28,003	$	627,133	$	45,810
	Natural Gas Marketing			44,888		1,419			142		23,604		108

		Total	$	132,399	$	36,749		$	28,145	$	650,737	$	45,918

		CIMAREX ENERGY CO.
		By:		/s/ PAUL KORUS Paul Korus Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
		By:		/s/ JAMES H. SHONSEY James H. Shonsey Chief Accounting Officer and Controller (Principal Accounting Officer)