CIMAREX ENERGY CO - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(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 March 31, 2004

Commission File No. 001-31446

CIMAREX ENERGY CO.

707 Seventeenth Street, Suite 3300

Denver, Colorado 80202-3404

(303) 295-3995

Incorporated in the		Employer Identification
State of Delaware		No. 45-0466694

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 March 31, 2004 was 41,370,235.

CIMAREX ENERGY CO.

Table of Contents

PART I

Item 1 –	Financial Statements

	Consolidated balance sheets (unaudited) as of March 31, 2004 and December 31, 2003

	Consolidated statements of operations (unaudited) for the three months ended March 31, 2004 and 2003

	Consolidated statements of cash flows (unaudited) for the three months ended March 31, 2004 and 2003

	Consolidated statement of stockholders’ equity (unaudited) for the three months ended March 31, 2004

	Notes to consolidated financial statements

Item 2 –	Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3 –	Qualitative and Quantitative Disclosures About Market Risk

Item 4 –	Controls and Procedures

PART II

Item 6 –	Exhibits and Reports on Form 8-K

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

PART I

ITEM 1 - Financial Statements

CIMAREX ENERGY CO.

Consolidated Balance Sheets

(Unaudited)

	March 31, 2004			December 31, 2003
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	38,493		$	40,420
Receivables, net	81,767			68,293
Inventories	9,377			6,700
Deferred income taxes	1,557			1,631
Other current assets	4,323			6,160
Total current assets	135,517			123,204
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	1,386,258			1,331,095
Unproved properties and properties under development, not being amortized	53,410			39,370
	1,439,668			1,370,465
Less – accumulated depreciation, depletion and amortization	(771,743		)	(746,161		)
Net oil and gas properties	667,925			624,304
Fixed assets, net	13,256			12,092
Goodwill	44,967			44,967
Other assets, net	865			941
	$	862,530		$	805,508
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	22,208		$	18,394
Accrued liabilities	49,556			48,339
Revenue payable	24,316			18,776
Total current liabilities	96,080			85,509
Deferred income taxes	164,568			155,293
Other liabilities	31,147			29,966

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, 41,370,235 and 41,063,653 shares issued and outstanding, respectively	413			411
Paid-in capital	243,254			237,430
Unearned compensation	(9,236		)	(9,540		)
Retained earnings	336,304			306,439
	570,735			534,740
	$	862,530		$	805,508

See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Consolidated Statements of Operations

(Unaudited)

	For the Three Months Ended March 31,
	2004			2003
	(In thousands, except per share data)
Revenues:
Gas sales	$	74,332		$	71,489
Oil sales	21,178			19,672
Marketing sales	36,761			45,407
Other	3,648			(9		)
	135,919			136,559
Costs and expenses:
Depreciation, depletion and amortization	26,338			21,117
Asset retirement obligation accretion	290			241
Production	9,469			6,988
Transportation	2,355			1,259
Taxes other than income	8,365			7,171
Marketing purchases	36,300			44,993
General and administrative	4,509			4,067
Stock compensation	468			466
Financing costs -
Interest expense	296			422
Capitalized interest	—			(265		)
Interest income	(87		)	(29		)
	88,303			86,430
Income before income tax expense and cumulative effect of a change in accounting principle	47,616			50,129
Income tax expense	17,751			18,986
Income before cumulative effect of a change in accounting principle	29,865			31,143
Cumulative effect of a change in accounting principle, net of tax	—			1,605
Net income	$	29,865		$	32,748

Earnings per share:
Basic -
Income before cumulative effect of a change in accounting principle	$	0.72		$	0.75
Cumulative effect of a change in accounting principle, net of tax	—			0.04
Net income	$	0.72		$	0.79
Diluted -
Income before cumulative effect of a change in accounting principle	$	0.70		$	0.74
Cumulative effect of a change in accounting principle, net of tax	—			0.04
Net income	$	0.70		$	0.78

Weighted average basic shares outstanding	41,305			41,479
Weighted average diluted shares outstanding	42,615			42,027

See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Consolidated Statements of Cash Flows

(Unaudited)

	For the Three Months Ended March 31,
	2004			2003
	(In thousands)

Cash flows from operating activities:
Net income	$	29,865		$	32,748
Adjustment to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	26,338			21,117
Amortization of restricted stock compensation	468			466
Cumulative effect of a change in accounting principle, net of taxes	—			(1,605		)
Deferred income taxes	10,924			12,136
Asset retirement obligation accretion	290			241
Income tax benefit related to stock options exercised	1,576			257
Other	(9		)	195
Changes in operating assets and liabilities:
Increase in accounts receivables	(13,435		)	(15,460		)
Increase in inventories	(2,677		)	(1,016		)
(Increase) decrease in other current assets	1,837			(964		)
Increase in accounts payable	9,354			277
Increase (decrease) in accrued liabilities	(1,511		)	5,414
Increase in other non-current liabilities	27			27
Net cash provided by operating activities	63,047			53,833
Cash flows from investing activities:
Capital expenditures	(67,376		)	(24,769		)
Acquisition of proved oil and gas properties	(9		)	(576		)
Proceeds from sale of assets	113			47
Other capital expenditures	(1,952		)	(5,210		)
Net cash provided by (used in) investing activities	(69,224		)	(30,508		)
Cash flows from financing activities:
Payments on long-term debt	—			(27,000		)
Common stock reacquired and retired	(121		)	(1		)
Proceeds from issuance of common stock	4,371			938
Net cash provided by (used in) financing activities	4,250			(26,063		)
Net change in cash and cash equivalents	(1,927		)	(2,738		)
Cash and cash equivalents at beginning of period	40,420			22,327
Cash and cash equivalents at end of period	$	38,493		$	19,589

See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Consolidated Statement of Stockholders’ Equity

For the Three Months Ended March 31, 2004

(Unaudited)

					Paid-in Capital			Unearned Compensation			Retained Earnings		Total Stockholders’ Equity
	Common Stock
	Shares		Amount
	(In thousands)
Balance, December 31, 2003	41,064		$	411	$	237,430		$	(9,540	)	$	306,439	$	534,740

Net income	—		—		—			—			29,865		29,865
Issuance of restricted stock unit awards	—		—		—			(312		)	—		(312		)
Common stock reacquired and retired	(5	)	—		(121		)	—			—		(121		)
Amortization of unearned compensation	—		—		—			616			—		616
Exercise of stock options	311		2		4,369			—			—		4,371
Tax benefit related to stock options exercised	—		—		1,576			—			—		1,576
Balance, March 31, 2004	41,370		$	413	$	243,254		$	(9,236	)	$	336,304	$	570,735

See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

March 31, 2004

(Unaudited)

1. Basis of Presentation

The accompanying financial statements are unaudited and were prepared from the records of Cimarex Energy Co. (Cimarex or the Company). We believe these financial statements include all adjustments necessary for a fair presentation of our financial position and results of operations. We prepared these statements on a basis consistent with the annual audited statements and Regulation S-X. Regulation S-X allows us to omit some of the footnote and policy disclosures required by accounting principles generally accepted in the United States of America and normally included in annual reports on Form 10-K. These interim financial statements should be read in conjunction with the financial statements and notes in our Annual Report on Form 10-K for the year ended December 31, 2003.

Cimarex was formed in February 2002 as a wholly-owned subsidiary of Helmerich & Payne, Inc. (H&P). 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. 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.

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. Changes in facts and circumstances may result in revised estimates and 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 and in recording asset retirement obligations. 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.

2. Stock Options

We apply 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, as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, requires us to provide pro forma information regarding net income as if the compensation cost for our stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. 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 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, pro forma net income would have been as indicated below:

	Three Months Ended March 31,
	2004			2003

Net income, as reported	$	29,865		$	32,748
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(538		)	(607		)

Pro forma net income	$	29,327		$	32,141

Earnings per share:
Basic – as reported	$	0.72		$	0.79
Basic – pro forma	$	0.71		$	0.77

Diluted – as reported	$	0.70		$	0.78
Diluted – pro forma	$	0.69		$	0.76

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 March 31, 2004, and changes during the period:

	Options Outstanding	Weighted Average Exercise Price		Options Exercisable

Outstanding as of January 1, 2004	3,321,299	$	14.39
Exercised	311,069	14.09
Granted	—	—
Forfeited/Expired	—	—
Outstanding as of March 31, 2004	3,010,230	$	14.42	1,681,292

The following table summarizes information about Cimarex stock options held by employees and directors at March 31, 2004:

	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	171,532	4.4 Years	$	7.80	171,532	$	7.80
$8.15 to $10.17	138,200	5.4 Years	9.69		138,200	9.69
$10.18 to $12.21	490,497	4.0 Years	11.51		490,497	11.51
$12.22 to $14.25	506,131	7.1 Years	13.78		306,287	13.62
$14.26 to $16.28	340,965	6.7 Years	15.20		236,788	15.20
$16.29 to $18.32	1,313,905	8.5 Years	16.72		312,988	16.83
$18.33 to $20.36	49,000	8.2 Years	19.54		25,000	18.77

3. Asset Retirement Obligations

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

The adoption of the Statement resulted in our recording 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.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the three months ended March 31, 2004 (in thousands):

Balance as of January 1, 2004	$	16,463
Liabilities incurred in the current period	552
Liabilities settled in the current period	—
Accretion expense	290
Balance as of March 31, 2004	$	17,305

4. Long-Term Debt

At March 31, 2004, we had no debt outstanding. We have the capability to borrow on our Senior Secured Revolving Credit Facility led by Bank One, N.A. This facility presently has a borrowing base of $275 million and we have commitments from our lenders totaling $200 million. 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 percent, based on borrowing base usage. Unused borrowings are subject to a commitment fee of 0.375 to 0.50 percent, also depending on the borrowing base usage.

The credit facility is secured by mortgages on certain of our oil and gas properties and the stock of our operating subsidiaries. We are also subject to customary financial and non-financial covenants and are in compliance with those covenants. The term of the credit facility expires in October 2005.

5. Income Taxes

Federal income tax expense for the three months ended March 31, 2004 and 2003 differ from the amounts that would be provided by applying the U.S. Federal income tax rate due to the effect of state income taxes and percentage depletion.

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

	Three Months Ended March 31,
	2004		2003

Current taxes	$	6,827	$	6,850
Deferred taxes	10,924		12,136
	$	17,751	$	18,986

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

	Three Months Ended March 31,
	2004		2003

Cash paid during the period for:
Interest (net of amounts capitalized)	$	434	$	169
Income taxes (net of refunds received)	$	1,706	$	256

7. Earnings Per Share

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

	Three Months Ended March 31,
	2004		2003
Income before cumulative effect of a change in accounting principle	$	29,865	$	31,143
Cumulative effect of a change in accounting principle	—		1,605
Net income available to common stockholders for basic and diluted	$	29,865	$	32,748

Basic weighted-average shares outstanding	41,305		41,479
Incremental shares from assumed exercise of stock options and vesting of restricted stock units	1,310		548
Diluted weighted-average shares outstanding	42,615		42,027

Basic:
Before cumulative effect of a change in accounting principle	$	0.72	$	0.75
Cumulative effect of a change in accounting principle	—		0.04
Earnings per share	$	0.72	$	0.79

Diluted:
Before cumulative effect of a change in accounting principle	$	0.70	$	0.74
Cumulative effect of a change in accounting principle	—		0.04
Earnings per share	$	0.70	$	0.78

There were stock options outstanding for 3,010,230 and 3,535,847 shares of Cimarex common stock at March 31, 2004 and 2003, respectively. All stock options were considered potentially dilutive securities for the three months ended March 31, 2004 and 2003.

8. 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 located primarily in Oklahoma, Kansas, Texas, Louisiana and Wyoming. We have a wholly owned subsidiary, Cimarex Energy Services, Inc. (CESI) through which we conduct a majority of our gas marketing activity. Information presented for our natural gas marketing segment represents business conducted with third parties, usually incidental to sales of our own production.

Summarized financial information of Cimarex’s reportable segments for the three months ended March 31, 2004 and 2003 is shown in the following table:

	External Sales		Operating Profit Before Income Taxes		Depreciation, Depletion and Amortization		Total Assets		Additions to Long- Lived Assets
	(In thousands)

Three Months Ended March 31, 2004:
Exploration and Production	$	95,510	$	43,778	$	26,278	$	829,060	$	70,267
Natural Gas Marketing	36,761		399		60		33,470		312

Total	$	132,271	$	44,177	$	26,338	$	862,530	$	70,579

Three Months Ended March 31, 2003:
Exploration and Production	$	91,161	$	49,905	$	21,065	$	682,931	$	38,508
Natural Gas Marketing	45,407		361		52		33,953		273

Total	$	136,568	$	50,266	$	21,117	$	716,884	$	38,781

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).

	Three Months Ended March 31,
	2004			2003
Segment operating profit, including depreciation, depletion and amortization	$	44,177		$	50,266
Unallocated amounts:
Other revenue (expense)	3,648			(9		)
Interest expense, net	(209		)	(128		)

Income before income taxes and cumulative effect of a change in accounting principle	$	47,616		$	50,129

9. 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 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. We estimate that the share of such alleged damages attributable to our 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. We believe that our liability, if any, should not exceed our working interest share of any actual damages attributable to the alleged drainage. We have received confirmation from the court that any claim against Cimarex will be limited to our proportionate interest in the two properties. We cannot predict the outcome of this litigation, and accordingly, no accrual has been recorded in connection with this action.

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 $.5 million to $1.0 million, net to our interest. Settlements of $3.0 million, which exceeded our initial estimates, were received in the first quarter of 2004 related to this type of litigation for which we were plaintiffs. Such amounts were recorded as other income.

Transportation and Gas Deliveries

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004. We have a right to extend this contract annually. The maximum amount that would be payable if deliveries are not made would be $0.3 million.

We have also guaranteed delivery of 3.3 Bcf of natural gas from seven wells over a three-year period as reimbursement for connection costs to a pipeline. If the minimum delivery is not met, our maximum exposure is less than $0.3 million. We have agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well or a prorated payment based on the total reserves on 18 wells. The maximum amount that would be payable if no gas is delivered would be $0.7 million.

Additionally, we have firm sales contracts to deliver fixed volumes of gas based on an index price. These contracts vary in length from two months to one year. As of March 31, 2004, we had an obligation to deliver approximately 2.1 Bcf of natural gas. If this gas is not delivered our financial commitment would approximate $3.1 million based on index prices as of March 31, 2004. This commitment will fluctuate due to price volatility and actual volumes delivered. We believe no financial commitment will be due based on our proved reserves and current production levels.

Parental Guarantees

As of March 31, 2004, Cimarex had $11.0 million of parental guarantees outstanding. These guarantee the credit of certain CESI agreements and are for the benefit of certain counterparties.

Drilling Commitments

The Company has contractual commitments on oil and gas wells approved for drilling or in the process of being drilled at March 31, 2004 of approximately $19.1 million.

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

Tax Sharing Agreement

On September 30, 2002, Cimarex entered into an agreement with H&P that imposes certain restrictions on Cimarex’s ability to redeem or issue a material number of shares of its common stock or to undergo a change of control. These restrictions expire on October 1, 2004. Such actions by Cimarex could cause the spin off of Cimarex by H&P to be deemed a taxable event, potentially resulting in a substantial amount of taxable income to H&P. Under the terms of the agreement, if Cimarex takes or permits an action to be taken that causes the spin off to be taxable, Cimarex would generally be liable for all or a portion of the resultant tax liability. It is expected that any such taxes allocated to Cimarex would be material.

Cimarex has also provided indemnification of H&P in connection with any future tax claims that may be made relating to the oil and gas exploration and production assets contributed to Cimarex by H&P.

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

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

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

INTRODUCTION

Cimarex Energy Co. is an independent oil and gas exploration and production company. Our primary focus is to explore for and discover new reserves. To supplement our growth, from time to time we also consider acquisitions and mergers. Our operations are presently focused in Oklahoma, Texas, Kansas and Louisiana.

Industry and Economic Factors

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

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

The oil and gas industry is highly competitive. We compete with major and diversified energy companies, independent oil and gas businesses, and individual operators. In addition, the industry as a whole competes with other businesses that supply energy to industrial and commercial end users.

Extensive Federal, state and local regulation of the industry significantly affects our operations. In particular, our activities are subject to stringent environmental regulations. These regulations have

increased the costs of planning, designing, drilling, installing, operating, and abandoning oil and gas wells and related facilities. These regulations may become more demanding in the future.

Approach to the Business

Profitable growth of our assets will largely depend upon our ability to successfully find and develop new proved reserves. To accommodate an overall acceptable rate of growth, we maintain a blended portfolio of low, moderate and higher risk exploration and development projects. We believe that this approach allows for consistent increases in our oil and gas reserves, while minimizing the chance of failure. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We may also consider the use of transaction-specific hedging of oil and gas prices to reduce price risk. However, to date the use of hedging has not been implemented.

Implementation of our business approach relies on our ability to fund ongoing exploration and development projects with cash flow provided by operating activities and external sources of capital.

We project that 2004 exploration and development expenditures will approximate $200-220 million, up from $161 million in 2003. We are expanding our 2004 program as a result of successful exploration wells drilled in 2003, growth in our western Oklahoma development projects and entry into new basins. Similar to 2003, a large portion of our 2004 expenditures will be directed to our projects in Oklahoma, Texas and Louisiana. A total of $100 million is anticipated to be spent in the mid-continent area of Oklahoma and north Texas. In the coastal regions of Texas, Louisiana and Mississippi, we plan to spend $75 million during 2004. The remainder of our projected expenditures will be focused in the Permian basin, California and other western states.

Exploration and development expenditures during the first quarter of 2004 totaled $68.6 million, up from $27.0 million for the first quarter of 2003. Of these 2004 expenditures, 61 percent ($42 million) was invested in projects in the mid-continent area, with 31 percent, or $21 million, directed toward prospects in our coastal region areas of focus. In the first three months of 2004, we participated in drilling 44 gross wells, with an overall success rate of 86 percent. On a net basis, 18 of 22 wells drilled during the first quarter were successful.

Cash flow from operating activities for the three months ended March 31, 2004 totaled $63 million, helping to fund our exploration and development expenditure program. Due to positive drilling results during 2003 and the first quarter of 2004, seven percent of our first quarter oil and gas production contributing to this cash flow was generated from new wells going on line within the quarter.

Based on expected production levels, current commodity prices, and existing operating conditions, we believe we are well positioned to fund the projects identified for the remainder of 2004 and beyond. We also have available a cash balance of $38.5 million as well as the existing borrowing capacity from our Senior Credit Facility.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 3 to our consolidated financial statements included in our Form 10-K for the year ended December 31, 2003. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues,

reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

Revenue Recognition

Revenues from oil and gas sales are recognized based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for oil and gas, with sales occurring soon after production.

Oil and Gas Reserves

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Revisions of reserve estimates as of December 31, 2003 equaled an increase of 41 MBbls of oil and an increase of 6.7 Bcf of gas, representing 0.3 percent and 2.0 percent of total proved oil and gas reserves, respectively, as of the end of 2003.

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

Carrying Value of Long-Lived Assets

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

We perform an impairment analysis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. Cash flows used in the full cost ceiling limitation are determined based upon estimates of proved oil and gas reserves, future prices, and the costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil and gas prices could cause us to reduce the carrying amounts of our properties. In accordance with the full cost accounting rules, capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization 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. This is referred to as the “full cost ceiling limitation.” At the end of each quarter, a full cost ceiling limitation calculation is made. To date, the only reduction in the carrying value of oil and gas properties was incurred during the year ended September 30, 2001.

Goodwill

We account for goodwill in accordance with Statement of Financial Accounting Standard (SFAS) No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment. A more frequent assessment is required if certain events occur that reasonably indicate an impairment may have occurred. The volatility of oil and gas prices may cause more frequent assessments. The impairment assessment requires us to make estimates regarding the fair value of the reporting unit. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the success of future exploration for and development of unproved reserves. These factors are each individually weighted to estimate the total fair value of the reporting unit. If the estimated fair value of the reporting unit exceeds its carrying amount, goodwill of the unit is considered not impaired. If the carrying amount exceeds the estimated fair value, then a measurement of the loss must be performed, with any deficiency recorded as an impairment. We recorded $45.0 million of goodwill in the purchase of Key on September 30, 2002. To date, no related impairment has been recorded, nor is any currently anticipated.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us. As of March 31, 2004, no liabilities have been accrued for known contingencies. See Note 9 of Notes to Consolidated Financial Statements.

Recent Accounting Developments

The 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. The FASB has proposed a staff position that would amend SFAS No. 141 and 142 to eliminate the characterization of mineral rights as intangible assets. Ratification of the consensus in this EITF 04-2 is subject to the issuance of the final release.

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 $21.2 million, less $11.8 million in accumulated depreciation, depletion and amortization, of our proved oil and gas property costs would be separately classified as intangible assets. In addition, approximately $24.0 million of unproved properties would be classified as intangible assets. Income and other results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. The classification of oil and gas lease acquisition costs as intangible assets would not have any impact on our compliance with covenants under our debt agreements.

The FASB formally proposed to require companies to recognize the fair value of stock options and other stock-based compensation to employees for 2005 reporting periods. Comments on the exposure draft are due by June 30, 2004. We currently provide in our Notes to Consolidated Financial Statements pro forma information regarding net income as if the compensation cost for our stock option plans had been determined in accordance with the fair value based method prescribed in SFAS No. 123, Accounting for

Stock Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure.

Overview

Our results of operations are impacted by oil and gas prices, which are volatile. Realized oil prices increased from $30.31 per barrel in the first quarter of 2003 to $33.80 per barrel in the first three months of 2004, while gas prices decreased from $5.86 per Mcf to $5.26 per Mcf for the respective periods. The majority of our revenues are from oil and gas sales, so price fluctuations can significantly affect our financial results.

Marketing sales and related purchases pertain to activities with third parties conducted by our marketing group. Natural gas sales transactions are conducted with various purchasers under a variety of terms and conditions and supplied by purchasing gas from other producers and marketing companies. For the sales transactions in which the gas is supplied by our own production, related sales and costs are reflected in Cimarex’s gas sales and transportation expense.

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

Production costs are generally composed of pumpers’ salaries, utilities, maintenance and other expenses necessary to operate our producing properties.

Taxes other than income are taxes assessed by applicable taxing authorities pertaining to production, revenues or the value of our properties. These typically include production severance, ad valorem and excise taxes.

Depreciation, depletion and amortization of our producing properties is computed using the unit-of-production method. Because the economic life of each producing well depends upon the assumed price for production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion.

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

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees.

Basis of Presentation

RESULTS OF OPERATIONS

Three Months Ended March 31, 2004 Compared with Three Months Ended March 31, 2003

SUMMARY DATA:	For the Three Months Ended March 31,
(in thousands or as indicated)	2004		2003

Net income	$	29,865	$	32,748
Per share-basic	0.72		0.79
Per share-diluted	0.70		0.78

Gas sales	$	74,332	$	71,489
Oil sales	21,178		19,672
Total oil and gas sales	$	95,510	$	91,161

Total gas volume-MMcf	14,130		12,197
Gas volume-MMcf per day	155.3		135.5
Average gas price-per Mcf	$	5.26	$	5.86

Total oil volume-thousand barrels	627		649
Oil volume-barrels per day	6,886		7,212
Average oil price-per barrel	$	33.80	$	30.31

Marketing sales	$	36,761	$	45,407
Marketing purchases	36,300		44,993
Marketing margin	$	461	$	414

Other revenues	$	3,648	$	(9	)

Costs and expenses:
Depreciation, depletion and amortization	$	26,338	$	21,117
Production	9,469		6,988
Transportation	2,355		1,259
Taxes other than income	8,365		7,171
General and administrative	4,509		4,067
Stock compensation	468		466
Asset retirement obligation accretion	290		241
Financing costs, net	209		128

We reported net income of $29.9 million, or $0.70 per diluted share in the first quarter of 2004 compared to net income of $32.8 million, or $0.78 per diluted share for the same period in 2003. Included in first-quarter 2003 net income is $1.6 million of earnings (net of income taxes) from the cumulative effect of change in accounting principle resulting from the adoption of SFAS 143, Accounting for Asset Retirement Obligations. The remainder of the decrease results from the net effect of changes in revenues and costs, as discussed further.

Oil and gas sales for first quarter of 2004 totaled $95.5 million, compared to $91.2 million for the first quarter of 2003. The $4.3 million increase in sales between the two periods results from a $10.6 million increase due to higher production volumes, offset by a net decrease of $6.3 million related to lower commodity prices.

Realized gas prices averaged $5.26 per Mcf for the three months ended March 31 2004, compared to $5.86 per Mcf for the first quarter of 2003. This ten percent decrease reduced sales by $8.5 million between the two periods. Realized oil prices averaged $33.80 per barrel for the first quarter of 2004, compared to $30.31 per barrel for the same period in 2003. The increase in sales between periods resulting from this twelve percent improvement in oil prices totaled $2.2 million. Changes in realized prices were the direct result of overall market conditions. We have not entered into any derivative contracts or hedges with respect to our production.

Gas sales benefited from higher production volumes. Average gas volumes rose 19.8 MMcf per day in the first quarter of 2004 to 155.3 MMcf per day from 135.5 MMcf per day in the first quarter of 2003, resulting in $11.3 million of incremental revenues. Oil volumes averaged 6,886 barrels per day for the first three months of 2004, compared to 7,212 barrels per day in the same period of 2003, resulting in decreased revenues of $0.7 million. The increase in gas sales volumes between the two periods is due to positive drilling results during 2003 and the first quarter of 2004. The drop in oil volumes is due to natural declines.

Marketing sales net of related purchases equaled $0.5 million in the first quarter of 2004 compared to $0.4 million in the first quarter of 2003. These sales relate to marketing activities with outside parties conducted by our marketing group. The financial impact from these activities is small relative to our overall results of operations. Revenues and costs related to marketing of our own production are eliminated in consolidation.

Other revenues of $3.6 million in the first quarter of 2004 consist of $3.0 million of settlements related to litigation for which we were plaintiffs. The remaining $0.6 million pertains to gains on the sale of miscellaneous equipment.

Costs and Expenses (Other than Income tax expense)

Overall costs and expenses (not including income taxes) were $52.0 million in the first quarter of 2004 compared to $41.4 million in the same period of 2003. The largest component of this $10.6 million increase between periods is a $5.2 million increase in depreciation, depletion and amortization expense (DD&A) from $21.1 million in the first three months of 2003 to $26.3 million in the first three months of 2004. On a unit of production basis, DD&A was $1.47 per Mcfe in the first quarter of 2004 compared to $1.31 per Mcfe for the first three months of 2003. The increase largely stems from higher costs for reserves added during 2003.

Production costs rose $2.5 million from $7.0 million ($0.43 per Mcfe) in the first three months of 2003 to $9.5 million ($0.53 per Mcfe) in the first quarter of 2004 due to costs associated with the installation and operation of over 80 compressors (primarily in Kansas) to enhance production, higher field operating expenses from an expanded number of properties, and higher maintenance costs.

Transportation costs increased from $1.3 million, or $0.08 per Mcfe, in the first quarter of 2003 to $2.4 million, or $0.13 per Mcfe, in the first quarter of 2004. The increase is the result of expiring contracts being renewed with increased current market rates. The cost of $0.13 per Mcfe in the first three months of 2004 is consistent with the last three quarters of 2003.

Taxes other than income were $1.2 million greater, rising from $7.2 million in the first quarter of 2003 to $8.4 million in the same period of 2004. This change resulted from a five percent increase in oil and gas sales stemming from higher gas volumes and oil prices.

General and administrative (G&A) expenses increased $0.4 million from $4.1 million in the first quarter of 2003 to $4.5 million in the first quarter of 2004, due mainly to an expansion of staff and higher employee-benefit costs.

Income tax expense

Income tax expense totaled $17.8 million for the first quarter of 2004 versus $19.0 million for the first three months of 2003. Tax expense equaled a combined Federal and state effective income tax rate of 37.3 percent and 37.9 percent in the first quarters of 2004 and 2003, respectively. The change in effective rates results from utilization of tax credits. We estimate that $6.8 million of our first-quarter 2004 income tax expense is current.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our primary source of capital is cash flow generated from operating activities. Prices we receive for future oil and gas sales and our level of production will impact these future cash flows. No prediction can be made as to the prices we will receive. Production volumes will in part be dependent upon the amount and results of future capital expenditures. In turn, actual levels of capital expenditures may vary due to many factors, including drilling results, oil and gas prices, industry conditions, prices and availability of goods and services, and the extent to which proved properties are acquired.

Cash flow provided by operating activities for the three months ended March 31, 2004 was $63.0 million, compared to $53.8 million for the three months ended March 31, 2003. The increase in 2004 from the earlier period results primarily from higher oil prices and gas production.

Higher revenues from oil and gas sales facilitated the funding of our exploration and development expenditure program for the quarter.

Cash flow used in investing activities for the three months ended March 31, 2004 was $69.2 million, compared to $30.5 million for the three months ended March 31, 2003. The increase in the first quarter of 2004 stems from a larger exploration and development program.

Cash flow provided by financing activities in the first three months of 2004 was $4.3 million versus cash used in financing activities of $26.1 million in the first three months of 2003, a change of $30.4 million. The most significant item that occurred during the first quarter of 2003 was the repayment of $27.0 million of our long-term credit facility. The cash provided by financing activities in the first quarter of 2004 resulted from the exercise of employee stock options.

Financial Condition

As of March 31, 2004, stockholders’ equity totaled $570.7 million, up from $534.7 million at December 31, 2003. The increase resulted primarily from first-quarter 2004 net income of $29.9 million and the exercise of employee stock options. At March 31, 2004 our cash balance equaled $38.5 million.

Working Capital

Working capital at March 31, 2004 totaled $39.4 million, compared to $37.7 million at December 31, 2003. The largest component of this increase was the higher receivables balance from other joint interest owners that resulted from increased drilling activities in the first quarter of 2004. Our receivables are from a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. The collection of receivables during the period

presented has been timely. Historically, losses associated with uncollectible receivables have not been significant.

Financing

In October 2002, we closed on a three-year $400 million Senior Secured Revolving Credit Facility. The Facility has a borrowing base of $275 million and we have 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 percent to 2.00 percent, based on borrowing base usage. Unused borrowings are subject to a commitment fee of 0.375 percent to 0.50 percent, also depending on borrowing base usage. The Credit Facility is secured by mortgages on our oil and gas properties and the stock of our subsidiaries. We are also subject to customary financial and non-financial covenants. We are in compliance with all such covenants. There were no borrowings under the Facility at December 31, 2003. Because we have no publicly-traded debt, we have not sought a corporate credit rating.

Contractual Obligations and Material Commitments

We have issued parental guarantees of $11.0 million related to our marketing business for the benefit of companies we purchase gas from.

We have one firm transportation contract to transport 10,000 MMBtus per day, at $0.09 per MMBtu through December 31, 2004. We have a right to extend this contract annually. Maximum amount that would be payable if deliveries are not made would be $0.3 million.

We have also guaranteed delivery of 3.3 Bcf of natural gas from seven wells over a three-year period as reimbursement for connection costs to a pipeline. If the minimum delivery is not met, the maximum exposure is $0.3 million. We have agreed to reimburse another gatherer for connection costs to its pipeline via delivery of 1 Bcf of natural gas per well or a prorated payment based on the total reserves on 18 wells. The maximum amount that would be payable if we deliver no natural gas would be $0.7 million.

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

Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts available under our existing line 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 projected 2004 exploration and development expenditure program of $200-220 million will require a great deal of coordination and effort. Though there are a variety of factors that could curtail, delay or even cancel some of our drilling operations, we believe our projected program has a high degree of occurrence. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts in these areas warrant pursuit of the projects.

Costs of operations on a per Mcfe basis for 2004 are estimated to approximate or slightly exceed levels realized in 2003. Should factors beyond our control fluctuate, our program and realized costs will

vary from current projections. These factors could include volatility in commodity prices, changes in the supply of and demand for oil and gas, weather conditions, governmental regulations and more.

Estimated production for 2004 ranges between 195 to 210 MMcfe per day. The revenues to be realized from the sale of this production will be highly dependent on oil and gas prices. During 2003, the average price realized for our gas sales was $4.96 per Mcf and our average oil price was $29.30 per barrel. Current indications are that 2004 prices should approximate or perhaps exceed 2003 levels. During the first quarter of 2004, average prices realized from our sales were $5.26 per Mcf of gas and $33.80 per barrel of oil. Prices can be highly volatile, and the probability of realized prices for 2004 to vary from current estimates is high.

ITEM 3. Qualitative and Quantitative Disclosures about Market Risk

Price Fluctuations

Our results of operations are highly dependent upon the prices we receive for oil and gas 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.

Monthly gas price realizations during the first quarter of 2004 ranged from $4.86 per Mcf to$5.70 per Mcf. Oil prices ranged from $32.71 per barrel to $35.66 per barrel. It is impossible to predict future oil and gas prices with any degree of certainty.

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, or similar arrangements using commodity futures contracts or options. To date, we have not used any of these financial instruments to mitigate commodity price changes.

Any sustained weakness in 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

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 for changes in interest rates would have no affect on our results of operations.

ITEM 4. CONTROLS AND PROCEDURES

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 15(d)-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.

PART II – OTHER INFORMATION

ITEM 6 – EXHIBITS AND REPORTS ON FORM 8-K

(a)	Exhibits:

	31.1	Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31.2	Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32.1	Certification of F.H. Merelli, Chief Executive Officer of Cimarex Energy Co. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

	32.2	Certification of Paul Korus, Chief Financial Officer of Cimarex Energy Co. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

(b)	Reports on Form 8-K:

	Current Report on Form 8-K filed with the Securities and Exchange Commission on February 11, 2004 attaching a copy of Registrant’s fourth quarter financial and operating results under Item 12.

	Current Report on Form 8-K filed with the Securities and Exchange Commission on February 3, 2004 updating the Registrant’s production volume guidance under Item 9.

SIGNATURE

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.

May 5, 2004


	CIMAREX ENERGY CO.


	/s/ Paul Korus
	Paul Korus
	Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)


	/s/ James H. Shonsey
	James H. Shonsey
	Chief Accounting Officer and Controller (Principal Accounting Officer)