Edgar Filing: CIMAREX ENERGY CO

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x 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 June 30, 2008

Commission File No. 001-31446

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The number of shares of Cimarex Energy Co. common stock outstanding as of June 30, 2008 was 83,077,382.

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CIMAREX ENERGY CO.

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		Page
PART I

Item 1 – Financial Statements		3

	Consolidated balance sheets (unaudited) as of June 30, 2008 and December 31, 2007	3

	Consolidated statements of operations (unaudited) for the three and six months ended June 30, 2008 and 2007	4

	Consolidated statements of cash flows (unaudited) for the three and six months ended June 30, 2008 and 2007	5

	Notes to consolidated financial statements	6

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3 – Qualitative and Quantitative Disclosures About Market Risk		31

Item 4 – Controls and Procedures		32

PART II

Item 4 – Submission of Matters to a Vote of Security Holders		33

Item 6 – Exhibits		33

Signatures		34

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). MMBtu is one million British Thermal Units, a common energy measurement. 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.

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PART I

ITEM 1 - Financial Statements

CIMAREX ENERGY CO.

Consolidated Balance Sheets

(Unaudited)

	June 30,			December 31,
	2008			2007
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	168,801		$	123,050
Restricted cash	685			—
Short-term investments	7,393			14,391
Receivables, net	418,464			315,327
Inventories	74,874			29,642
Deferred income taxes	365			5,697
Derivative instruments	—			12,124
Prepaid expenses	18,992			8,117
Other current assets	5,679			56,229
Total current assets	695,253			564,577
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	6,195,685			5,545,977
Unproved properties and properties under development, not being amortized	388,020			364,618
	6,583,705			5,910,595
Less – accumulated depreciation, depletion and amortization	(2,188,611		)	(1,938,863		)
Net oil and gas properties	4,395,094			3,971,732
Fixed assets, net	101,647			90,584
Goodwill	691,432			691,432
Other assets, net	85,846			44,469
	$	5,969,272		$	5,362,794
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	107,697		$	52,671
Accrued liabilities	236,830			240,387
Derivative instruments	16,555			—
Revenue payable	184,819			131,513
Total current liabilities	545,901			424,571
Long-term debt	486,778			487,159
Deferred income taxes	1,178,369			1,076,223
Other liabilities	136,959			115,554
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued	—			—
Common stock, $0.01 par value, 200,000,000 shares authorized, 83,962,774 and 83,620,480 shares issued, respectively	840			836
Treasury stock, at cost, 885,392 and 1,078,822 shares held, respectively	(33,344		)	(40,628		)
Paid-in capital	1,846,365			1,842,690
Retained earnings	1,817,902			1,448,763
Accumulated other comprehensive income	(10,498		)	7,626
	3,621,265			3,259,287
	$	5,969,272		$	5,362,794

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Consolidated Statements of Operations

(Unaudited)

	For the Three Months							For the Six Months
	Ended June 30,							Ended June 30,
	2008				2007			2008			2007
	(In thousands, except per share data)
Revenues:
Gas sales	$	339,965			$	214,937		$	598,920		$	411,227
Oil sales	248,741				110,830			444,191			207,994
Gas gathering, processing and other	26,610				15,013			47,981			27,652
Gas marketing, net	1,067				1,304			2,367			2,086
	616,383				342,084			1,093,459			648,959
Costs and expenses:
Depreciation, depletion and amortization	133,201				112,797			258,757			221,681
Asset retirement obligation	1,862				2,399			3,456			4,990
Production	49,092				50,916			101,144			95,921
Transportation	10,621				6,294			18,930			12,228
Gas gathering and processing	12,361				7,825			22,402			15,136
Taxes other than income	39,749				23,802			70,356			44,429
General and administrative	13,876				11,958			25,460			24,609
Stock compensation, net	2,366				2,598			4,641			5,268
Other operating, net	85				2,586			1,121			2,315
	263,213				221,175			506,267			426,577

Operating income	353,170				120,909			587,192			222,382

Other (income) and expense:
Interest expense	7,748				10,297			16,168			19,462
Capitalized interest	(4,653			)	(4,898		)	(9,259		)	(9,989		)
Amortization of fair value of debt	(190			)	(580		)	(381		)	(1,527		)
Gain on early extinguishment of debt	—				(5,099		)	—			(5,099		)
Other, net	(5,507			)	(3,457		)	(8,524		)	(6,906		)

Income before income tax expense	355,772				124,646			589,188			226,441
Income tax expense	126,464				45,939			210,045			83,106

Net income	$		229,308		$	78,707		$	379,143		$	143,335

Earnings per share:
Basic	$		2.81		$	0.96		$	4.66		$	1.74
Diluted	$		2.68		$	0.93		$	4.44		$	1.69

Weighted average shares outstanding:
Basic	81,474				82,282			81,380			82,252
Diluted	85,589				84,836			85,482			84,745

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Six Months
	Ended June 30,
	2008			2007
	(In thousands)

Cash flows from operating activities:
Net income	$	379,143		$	143,335
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	258,757			221,681
Asset retirement obligation	3,456			4,990
Deferred income taxes	124,462			83,106
Stock compensation, net	4,641			5,268
Other	(126		)	(6,676		)
Changes in operating assets and liabilities (Increase) decrease in receivables, net	(103,137		)	11,741
Increase in other current assets	(46,047		)	(8,968		)
Increase (decrease) in accounts payable and accrued liabilities	77,752			(18,862		)
Decrease in other non-current liabilities	(1,349		)	(2,352		)
Net cash provided by operating activities	697,552			433,263
Cash flows from investing activities:
Oil and gas expenditures	(641,067		)	(473,229		)
Proceeds from sale of assets	354			21,530
Sales of short-term investments	7,061			—
Other expenditures	(21,086		)	(7,390		)
Net cash used by investing activities	(654,738		)	(459,089		)
Cash flows from financing activities:
Net decrease in bank debt	—			(95,000		)
Increase in other long-term debt	—			350,000
Decrease in other long-term debt	—			(204,360		)
Financing costs incurred	(50		)	(6,098		)
Treasury Stock acquired	—			(5,623		)
Dividends paid	(9,974		)	(6,747		)
Proceeds from issuance of common stock and other	12,961			8,017
Net cash provided by financing activities	2,937			40,189
Net change in cash and cash equivalents	45,751			14,363
Cash and cash equivalents at beginning of period	123,050			5,048
Cash and cash equivalents at end of period	$	168,801		$	19,411

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

1. Basis of Presentation

The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in annual reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our 2007 Annual Report on Form 10-K/A-1.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods shown.

Full Cost Accounting Method and Ceiling Limitation

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

At the end of each quarter, we make a full cost ceiling limitation calculation, whereby net capitalized costs related to proved properties less associated deferred income taxes may not exceed an amount equal to the present value discounted at ten percent of estimated future net revenues from proved reserves less estimated future production and development costs and related income tax expense. Future net revenues used in the calculation of the full cost ceiling limitation consider significant changes in quantities and are determined based on current oil and gas prices which are adjusted for designated cash flow hedges. Increases and decreases in proved reserve estimates, due to quantity revisions or fluctuations in commodity prices, will result in corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. However, if commodity prices increase after period end and before issuance of the financial statements, the higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period.

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The costs of wells in progress and certain unevaluated properties are not being amortized. On a quarterly basis, we evaluate such costs for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

Use of Estimates

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, liabilities, revenues, and expenses during the reporting period and in disclosures of commitments and contingencies. We analyze our estimates, including those related to oil and gas revenues, reserves and properties, as well as goodwill and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

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

Certain amounts in prior years’ financial statements have been reclassified to conform to the 2008 financial statement presentation.

2. Financial Instruments

Derivatives

In 2006, we entered into derivative contracts to mitigate a portion of our potential exposure to adverse market changes in an environment of volatile gas prices. Using zero-cost collars with Mid-Continent weighted average floor and ceiling prices of $7.00 to $10.17 for 2007 we hedged 29.2 million MMBtu of our anticipated Mid-Continent gas production for 2007. For 2008 we hedged 14.6 million MMBtu. The following table sets forth the terms of the related derivative contracts for the remaining six months:

				Mid-Continent		Fair Value
Commodity	Type	Volume/Day	Duration	Price		(000’s)
Natural Gas	Collar	20,000 MMBTU	Jul 08 - Dec 08	$7.00	- $ 9.80	$	(8,556	)
Natural Gas	Collar	10,000 MMBTU	Jul 08 – Dec 08	$7.00	- $10.10	(3,861		)
Natural Gas	Collar	10,000 MMBTU	Jul 08 – Dec 08	$7.00	- $ 9.90	(4,138		)
						$	(16,555	)

At June 30, 2008, the remaining contracts outstanding represented approximately 22% of our current anticipated Mid-Continent gas production for 2008.

Under the collar agreements, we receive the difference between an agreed upon index price and a floor price if the index price is below the floor price. We pay the difference between the agreed upon contracted ceiling price and the index price only if the index price is above the contracted ceiling price.

No amounts are paid or received if the index price is between the contracted floor and ceiling prices. These contracts have been designated for hedge accounting treatment as cash flow hedges.

No settlements were received or paid during the second quarter of 2008. Settlements received during the quarter ended June 30, 2007 equaled $3.4 million, which were recorded in gas sales and increased the average realized price for the period by $0.11 per Mcf. Settlements received during the six months ended June 30, 2008 and 2007 equaled $1.0 million and $8.5 million, respectively, which were recorded in gas sales and increased the average realized price for the periods by $0.02 and $0.14 per Mcf, respectively. During the

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

quarters ended June 30, 2008 and 2007, we recognized an unrealized loss of $234 thousand and a $96 thousand gain, respectively, related to the ineffective portion of the derivative contracts. During the six months ended June 30, 2008 and 2007, we recognized an unrealized loss of $588 thousand and a $17 thousand gain, respectively, related to the ineffective portion of the derivative contracts.

At December 31, 2007, the fair value of the remaining contracts was $12.1 million, recorded as a current asset and an unrealized gain of $7.7 million (net of deferred income taxes) was included in other comprehensive income.

At June 30, 2008, the fair value calculation of the remaining contracts resulted in a current liability of approximately $16.6 million. An unrealized loss (net of deferred income taxes) of $10.3 million was recorded in other comprehensive income. These contracts will expire during the remaining six months of 2008. We believe that we have sufficient production volumes such that the hedge contract transactions will occur as expected.

Short-term Investments

In the fourth quarter of 2007, we invested $16 million in a securities fund. The investments, which are expected to be liquidated within the next twelve months, are classified as current assets, available-for-sale and are marked-to-market at the end of each period, through other comprehensive income. As of June 30, 2008, we had liquidated $8.3 million of the investments with a realized loss of $146 thousand. We also recorded an unrealized loss of $225 thousand in other comprehensive income, resulting in a fair value attributable to the investments of $7.4 million.

Debt

Our revolving credit facility provides for $500 million of long-term committed credit. The carrying amount of the credit facility approximates the fair value because the interest rates on the credit facility are variable. At June 30, 2008 and December 31, 2007, there were no outstanding borrowings under the credit facility.

The following table presents the carrying amounts and estimated fair values of our other debt instruments:

	June 30,				December 31,
	2008				2007
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.125% Notes due 2017(1)	$	350,000	$	345,625	$	350,000	$	346,504
Floating rate convertible notes due 2023 (face value $125,000)	$	136,778	$	303,335	$	137,159	$	183,395

(1) The fair values for the fixed rate notes were based on their last traded value before period end.

The carrying amounts for the convertible notes do not reflect $49.6 million of Paid in Capital attributable to the fair value of our common stock at the time we acquired the convertible notes. There is not an observable market for these notes. The fair values of the convertible notes were based on the closing price per share for our common stock, which was $69.67 at June 30, 2008 and $42.53 at December 31, 2007. Therefore, the calculated fair value includes value attributable to both the face amount of the notes and the conversion feature.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities of these assets and liabilities. Adoption of Statement of Financial Accounting Standards No. 157, Fair Value Measurements, had no material impact on our financial statements.

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. At June 30, 2008 and December 31, 2007, our aggregate allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $5.8 million.

3. Capital Stock

Stock-based Compensation

Our 2002 Stock Incentive Plan was approved by stockholders in May 2003 and is effective until October 1, 2012. The plan provides for grants of stock options, restricted stock and restricted stock units to non-employee directors, officers and other eligible employees. A total of 12.7 million shares of common stock may be issued under the Plan.

Restricted Stock and Units

During the six months ended June 30, 2008, we issued a total of 258,370 restricted shares to non-employee directors, officers, and other employees. Included in that amount are 228,000 shares issued to certain executives that are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. The material terms of performance goals applicable to these awards were approved by stockholders in May 2006. The remaining shares granted in 2008 have service-based vesting schedules of five years.

The following table presents restricted stock activity as of June 30, 2008, and changes during the year:

Outstanding as of January 1, 2008	1,289,695
Vested	(23,713	)
Granted	258,370
Canceled	(18,600	)
Outstanding as of June 30, 2008	1,505,752

The following table presents restricted unit activity as of June 30, 2008 and changes during the year:

Outstanding as of January 1, 2008	701,915
Converted to Stock	(45,500	)
Granted	3,790
Canceled	—
Outstanding as of June 30, 2008	660,205
Vested included in outstanding	569,247

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

Vesting of restricted stock and units granted in years before 2006 is exclusively related to continued service of the grantee for one to five years. In certain cases, a three-year required holding period following vesting also applies. A restricted unit represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods. The restricted stock and stock unit agreements provide that grantees are entitled to receive dividends on unvested shares.

Compensation costs for service-based vesting restricted shares or units is based upon amortization of the grant-date market value of the award. The fair value of the market condition-based restricted stock awards is based on the grant-date market value of the award, utilizing a Monte Carlo simulation model to estimate the percentage of awards that will vest at the end of a three-year period. Compensation costs related to the restricted stock and units is recognized ratably over the applicable vesting period. For the quarter ended June 30, 2008 and 2007, total compensation costs (including capitalized amounts) equaled $4.1 million and $3.0 million, respectively. For the six months ended June 30, 2008 and 2007, compensation costs (including capitalized amounts) equaled $7.7 million and $5.9 million, respectively.

Unamortized compensation costs related to unvested restricted shares and units at June 30, 2008 and 2007 was $31.7 million and $27.8 million, respectively.

Stock Options

Options granted under our plan expire ten years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. The plan provides that all grants have an exercise price equal to the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. Upon the exercise of stock options granted after October 1, 2002, grantees are required to hold at least 50 percent of the profit shares, as defined in the plan, until the eighth anniversary of the grant date.

There were no stock options granted to employees during the six months ended June 30, 2008 and 2007.

Information about outstanding stock options is summarized below:

			Weighted		Weighted	Aggregate
			Average		Average	Intrinsic
			Exercise		Remaining	Value
	Shares		Price		Term	(000)

Outstanding as of January 1, 2008	1,489,565		$	17.73
Exercised	(404,449	)	15.47
Granted	—		—
Canceled	—		—
Outstanding as of June 30, 2008	1,085,116		$	18.58	4.4 Years	$	55,443
Exercisable as of June 30, 2008	983,356		$	16.63	3.9 Years	$	52,154

The total intrinsic value of stock options exercised during the three months ended June 30, 2008 and 2007 was $15.6 million and $0.5 million, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2008 and 2007 was $18.7 million and $9.2 million, respectively

Compensation costs for stock options is determined pursuant to SFAS No. 123R. Historical amounts may not be representative of future amounts as additional options may be granted. We recognize compensation costs related to stock options ratably over the vesting period. For the quarter ended June 30, 2008 and 2007, compensation costs (including capitalized amounts) equaled $136 thousand and $502 thousand, respectively.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

For the six months ended June 30, 2008 and 2007, compensation costs (including capitalized amounts) equaled $218 thousand and $998 thousand, respectively.

We estimate the fair value of options as of the date of grant using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. The risk-free interest rate we use is the five-year U.S. Treasury bond in effect at the date of the grant.

Cash received from option exercises during the six months ended June 30, 2008 and 2007 was $6.3 million and $4.7 million, respectively. The related tax benefits realized from option exercises totaled $6.7 million and $3.3 million, respectively, and were recorded to paid-in capital.

The following summary reflects the status of non-vested stock options granted to employees and directors as of June 30, 2008 and changes during the year:

		Weighted Average
		Grant Date
	Shares	Fair Value

Non-vested as of January 1, 2008	101,760	$	15.59
Vested	—	—
Granted	—	—
Forfeited	—	—
Non-vested as of June 30, 2008	101,760	$	15.59

As of June 30, 2008, there was $1.3 million of unrecognized compensation cost related to non-vested stock options granted under our stock incentive plan. We expect to recognize that cost pro rata over a weighted-average period of 3.5 years. The weighted average exercise price of the non-vested stock options is $37.36.

Stockholder Rights Plan

We have a stockholder rights plan. The plan is designed to improve the ability of our board to protect the interests of our stockholders in the event of an unsolicited takeover attempt. For every outstanding share of Cimarex common stock, there exists one purchase right (the Right). Each Right represents a right to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock. The Rights will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more of our common stock, or a person or group commences a tender offer or exchange offer that, if successfully consummated, would result in such person or group beneficially owning 15 percent or more of our common stock. The purchase price for each one one-hundredth of a share of Preferred Stock pursuant to the exercise of a Right is $60.00, subject to adjustment in certain cases to prevent dilution.

We generally will be entitled to redeem the Rights under certain circumstances at $0.01 per Right at any time before the close of business on the tenth business day after there has been a public announcement of the acquisition of beneficial ownership by any person or group of 15 percent or more of our common stock. The Rights may not be exercised until our Board’s right to redeem the stock has expired. Unless redeemed earlier, the Rights expire on February 23, 2012.

Dividends and Stock Repurchases

In December 2005, the Board of Directors declared our first quarterly cash dividend of $0.04 per share. A dividend has been authorized in every quarter since then. In December 2007, the quarterly dividend was

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

increased to $0.06 per share. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

Issuer Purchases of Equity Securities for the Quarter Ended June 30, 2008

	Total Number of Shares purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of shares that may yet be Purchased Under the Plans or Programs

April, 2008	None	NA	None	2,635,700
May, 2008	None	NA	None	2,635,700
June, 2008	None	NA	None	2,635,700	(1)

(1) In December 2005, the Board of Directors authorized the repurchase of up to four million shares of our common stock. The authorization is currently set to expire on December 31, 2009. Through December 31, 2007, we had repurchased and cancelled a total of 1,364,300 shares at an overall average price of $39.05. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice. There were no shares repurchased in the second quarter of 2008, or since the quarter ended September 30, 2007.

A summary of our common stock activity for the six months ended June 30, 2008, follows:

	Number of Shares (in thousands)
	Issued		Treasury		Outstanding
December 31, 2007	83,621		(1,079	)	82,542
Restricted shares issued under compensation plans, net of cancellations	270		—		270
Option exercised, net of cancellations	266		—		266
Treasury shares cancelled	(194	)	194		—
June 30, 2008	83,963		(885	)	83,078

4. Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2008 (in thousands):

Balance as of January 1, 2008	$	113,054
Liabilities incurred	2,139
Liability settlements and disposals	(2,317		)
Accretion expense	3,336
Revisions of estimated liabilities	3,582
Balance as of June 30, 2008	$	119,794
Current asset retirement obligation	$	10,270
Long-term asset retirement obligation	$	109,524

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

5. Long-Term Debt

Debt at June 30, 2008 and December 31, 2007 consisted of the following (in thousands):

	June 30,		December 31,
	2008		2007
Bank debt	$	—	$	—
7.125% Notes due 2017	350,000		350,000
Floating rate convertible notes due 2023 (face value $125,000)	136,778		137,159
Total long-term debt	$	486,778	$	487,159

Our revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At June 30, 2008, there were no outstanding borrowings under the revolving credit facility. We had letters of credit for approximately $2.8 million posted against the borrowing base, leaving an unused borrowing amount of approximately $497.2 million at June 30, 2008.

The credit facility agreement contains both financial and non-financial covenants which we are in compliance with at period end.

In May, 2007 we sold $350 million of 7.125% senior unsecured notes that will mature May 1, 2017. The notes were sold to the public at par. Net proceeds from the sale were used to redeem our 9.6% notes and reduce outstanding borrowings under our credit facility. Interest is payable May 1 and November 1 of each year. The first interest payment was made on November 1, 2007. The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal amount) plus accrued interest, if any, thereon to the date of redemption.

Year	Percentage

2012	103.6	%
2013	102.4	%
2014	101.2	%
2015 and thereafter	100.0	%

At any time prior to May 1, 2010, we may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings of our shares of common stock at a redemption price of 107.125% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption.

At any time prior to May 1, 2012, we may also redeem all, but not part, of the notes at a price equal to 100% of the principal amount of the notes plus accrued and unpaid interest plus a “make-whole” premium.

If a specified change of control occurs, subject to certain conditions, we must make an offer to purchase the notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. At acquisition, the notes were recorded at a fair market value of $144.7 million, with an additional $49.6 million attributable to the conversion feature of the notes recorded in Paid in Capital.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

The notes are senior unsecured obligations and bear interest at an annual rate equal to the three-month LIBOR rate, reset quarterly. The interest rate in effect on June 30, 2008 was 2.8%.

Holders of the convertible notes may surrender their notes for conversion into a combination of cash and shares of our common stock upon the occurrence of certain circumstances, including if the price of our common stock has been trading above the fixed conversion price of $28.71 per share. On June 30, 2008, the closing price of our common stock on the New York Stock Exchange was $69.67. To date, no holders have surrendered their notes for conversion. In addition to the holders’ right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require us to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013, and 2018. The indenture agreement also provides us with an option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount and shares for the value of the convertible feature (plus accrued interest) anytime after December 22, 2008.

6. Income Taxes

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Current provision (benefits)	$	57,665	$	—	$	85,583	$	—
Deferred taxes	68,799		45,939		124,462		83,106
	$	126,464	$	45,939	$	210,045	$	83,106

We adopted the provisions of Financial Accounting Standards Board Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”) an interpretation of FASB Statement No. 109 “Accounting for Income Taxes”, on January 1, 2007. The adoption of FIN 48 resulted in no impact to our consolidated financial statements and we have no unrecognized tax benefits that would impact our effective rate.

As of June 30, 2008, we made no provisions for interest or penalties related to uncertain tax positions. The tax years 2004 – 2007 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2003-2007 for examination.

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes, non-deductible expenses, and special deductions. The effective income tax rate for the six months ended June 30, 2008 was 35.6%.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Cash paid during the period for:
Interest expense (net of amounts capitalized)	$	9,047	$	1,882	$	6,652	$	10,626
Interest capitalized	4,653		4,898		9,259		9,989
Income taxes	100,438		186		126,860		188
Cash received for income taxes	1,885		—		2,064		692

8. Earnings per Share and Comprehensive Income

Earnings per Share

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Net Income available to common stockholders for basic diluted shares	$	229,308	$	78,707	$	379,143	$	143,335

Basic weighted-average shares outstanding	81,474		82,282		81,380		82,252
Incremental shares from assumed exercise of stock options and vesting of restricted stock and units	1,865		1,429		1,852		1,368
Incremental shares from assumed conversion of the convertible senior notes	2,250		1,125		2,250		1,125
Diluted weighted-average shares outstanding	85,589		84,836		85,482		84,745
Earnings per share:
Basic	$	2.81	$	0.96	$	4.66	$	1.74
Diluted	$	2.68	$	0.93	$	4.44	$	1.69

The following table presents the amounts of outstanding stock options, restricted stock and units.

	June 30,
	2008	2007

Stock options	1,085,116	1,536,382
Restricted stock	1,505,752	1,005,213
Restricted units	660,205	696,641

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

All stock options and restricted units and shares were considered potentially dilutive securities for each of the periods presented except for those determined to be anti-dilutive as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2008	2007	2008	2007
Stock options	—	90,900	—	90,900
Restricted stock	5,584	5,558	7,037	16,403
Restricted stock units	1,708	—	854	—
	7,292	96,458	7,891	107,303

Comprehensive Income

Comprehensive income is a term used to refer to net income plus other comprehensive income. Other comprehensive income is comprised of revenues, expenses, gains and losses that under generally accepted accounting principles are reported as separate components of stockholders’ equity instead of net income.

The components of comprehensive income are as follows (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Net Income	$	229,308		$	78,707		$	379,143		$	143,335
Other comprehensive income:
Cash flow hedges
Increase (decrease) in fair value	(9,549		)	12,005			(27,099		)	(18,889		)
Settlements reflected in gas sales	—			(3,369		)	(992		)	(8,477		)
Sub-total	(9,549		)	8,636			(28,091		)	(27,366		)
Related income tax effect	3,376			(3,134		)	10,167			10,153
Total cash flow hedges	(6,173		)	5,502			(17,924		)	(17,213		)
Change in fair value of short-term investments and other, net of tax	3			76			(200		)	46
Total comprehensive income	$	223,138		$	84,285		$	361,019		$	126,168

9. Commitments and Contingencies

Litigation

In the normal course of business, we have various litigation related matters and associated accruals. Though some of the related claims may be significant, the resolution of them we believe, individually or in aggregate, would not have a material adverse effect on our company.

Other

At June 30, 2008, we had commitments of $191.4 million relating to construction of a gas processing facility adjacent to our Riley Ridge gas field in Sublette County, Wyoming. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for approximately 43% of the construction costs, which will effectively reduce our net cash commitment to $110.1 million.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

June 30, 2008

(Unaudited)

We have drilling commitments of approximately $178.8 million consisting of obligations to complete drilling wells in progress at June 30, 2008. We also have minimum expenditure commitments of $64.8 million to secure the use of drilling rigs.

At June 30, 2008, we had firm sales contracts to deliver approximately 2.6 Bcf of natural gas over the next nine months. If this gas is not delivered, our financial commitment would be approximately $29.4 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our proved oil and gas reserves and current production levels.

We have other various normal course of business gas delivery commitments, none of which are individually material. In aggregate these commitments have a maximum amount that would be payable, if no gas is delivered, of approximately $6.7 million.

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

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

Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. These forward-looking statements include, among others, statements concerning our 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 that we pursue 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 us are discussed in greater detail in this report and in our other filings with the Securities and Exchange Commission.

OVERVIEW

The following highlights our performance for the three months and six months ended June 30, 2008 compared to the three months and six months ended June 30, 2007:

· Production increased 10% in the second quarter of 2008 and increased 9% for the first half of 2008.

· Second quarter oil and gas sales revenues increased 81% to $588.7 million; first half 2008 oil and gas sales increased 68% to $1.0 billion.

· Net income for the quarter increased 191% to $229.3 million and increased 165% during the first half to $379.1 million.

· Earnings per share for the second quarter 2008 increased 193% to $2.81 and increased 168% to $4.66 during the first half of 2008.

· Net cash provided by operating activities increased 61% to $697.6 million during the first half of 2008.

· Capital expenditures for oil and gas exploration and development were $666.9 million during the first six months of the year.

· We drilled 252 gross (158 net) wells in the first half of the year, completing 94% as producers.

· We currently have 39 operated rigs running.

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We are an independent oil and gas exploration and production company with operations entirely located in the United States. We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed.

We seek to achieve profitable growth in proved reserves and production primarily through exploration and development. We generally fund our growth with cash flow provided by our operating activities. To achieve a consistent rate of growth and mitigate risk, we maintain a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. Our oil and gas reserves and operations are mainly located in Texas, Oklahoma, New Mexico, Kansas, Louisiana and Wyoming.

To supplement our growth and to provide for new drilling opportunities, we also consider mergers and acquisitions. Through second quarter 2008 we purchased $1.4 million of assets. For the year 2007 we purchased $40.9 million of assets, with the largest acquisition being in the Texas Panhandle area for $35.8 million. This transaction added over 50 locations to our already active Texas Panhandle drilling program and eight Bcfe of proved reserves. In 2005 we acquired Magnum Hunter Resources, Inc, in a stock-for-stock merger with a total transaction value of approximately $2.1 billion. Magnum Hunter was an independent oil and gas exploration and production company with operations concentrated in the Permian Basin of West Texas and New Mexico and in the Gulf of Mexico.

From time to time we also consider selling certain assets. During 2008 we have had no asset sales. For the year 2007, we sold $177.0 million of non-core properties. The two largest sales were $87.5 million for our West Texas Spraberry oil properties and $53.5 million for our Gulf of Mexico Main Pass area operated properties. We continue to evaluate alternatives for the rest of our Gulf of Mexico assets.

Oil and Gas Prices

Our revenues are a function of both production and prices, but wide swings in prices have had the greatest impact on our results of operations. Our average realized gas price increased from $7.30 per Mcf in second quarter 2007 to $10.57 per Mcf in 2008. Oil prices increased from $61.51 per barrel in second quarter 2007 to $121.64 per barrel in 2008. In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. We have made limited use of hedging transactions to somewhat reduce price volatility as discussed further below.

	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Gas Prices:
Average Henry Hub price ($/Mcf)	$	10.94	$	7.55	$	9.49	$	7.16
Average realized sales price – including hedge effect ($/Mcf)	$	10.57	$	7.30	$	9.49	$	7.01
Effect of hedges ($/Mcf)	$	—	$	0.11	$	0.02	$	0.14
Oil Prices:
Average WTI Cushing price ($/Bbl)	$	123.98	$	65.03	$	110.94	$	61.60
Average realized sales price ($/Bbl)	$	121.64	$	61.51	$	107.93	$	58.40

On an energy equivalent basis, 72% of our 2008 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a $6.3 million change in our gas revenues. Similarly 28% of our production was crude oil. A $1.00 per barrel change in our average realized crude oil sales price would have resulted in approximately a $4.1 million change in our oil revenues.

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To mitigate a portion of our exposure to potentially adverse gas market changes, in July 2006 we entered into certain derivative contracts. Those contracts covered 24% of our overall 2007 gas production and approximately 11% of our estimated 2008 gas volumes. We executed cash flow effective hedges by purchasing $7.00/MMbtu put options on a portion of our 2007 and 2008 Mid-Continent gas production. We used the proceeds from selling call options on the same volume of gas to pay for the puts, thus establishing what is commonly known as a “zero-cost collar.” We hedged 29.2 million MMbtu and 14.6 million MMbtu for 2007 and 2008, respectively. See Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

Production and other operating expenses

The costs associated with finding and producing oil and gas are substantial. Some of these costs vary with oil and gas prices, some trend with production volume and some are a function of the number of wells we own. At the end of 2007, we owned interests in 12,841 wells.

Production expense generally consists of the cost of power and fuel, direct labor, third-party field services, compression, water disposal, and certain maintenance activity necessary to produce oil and gas from existing wells.

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

Depreciation, depletion and amortization (DD&A) of our producing properties is computed using the units-of-production method. Because the economic life of each producing well depends upon the assumed price for future sales of production, fluctuations in oil and gas prices may impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense, while lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, changes in estimates of reserve quantities and estimates of future development costs or reclassifications from unproved properties to proved properties will impact depletion expense.

General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices and not directly associated with exploration, development or production activities. While we expect these costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth.

Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad valorem and excise taxes.

Significant expenses that generally do not trend with production

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and restricted stock units to certain employees and the expensing of stock options resulting from the adoption of SFAS No. 123R, Share Based Payment. Net stock compensation expense in the first six months of 2008 was $4.6 million compared to $5.3 million in the first six months of 2007.

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RESULTS OF OPERATIONS

Three months and six months ended June 30, 2008 vs. June 30, 2007

Net income for the second quarter of 2008 was $229.3 million, or $2.68 per diluted share. This compares to net income of $78.7 million, or $0.93 per diluted share for the same period in 2007. For the six months ended June 30, 2008, net income was $379.1, or $4.44 per diluted share, compared to net income of $143.3 million, or $1.69 per diluted share, for the first six months of 2007. The change in net income is generally the result of higher oil and gas sales.

					Percent
					Change
Oil and Gas Sales					Between	Price/Volume Analysis
(In thousands or as indicated)	2008		2007		2008/2007	Price		Volume		Variance

For the Three Months Ended June 30,
Gas sales	$	339,965	$	214,937	58%	$	105,202	$	19,826	$	125,028
Oil sales	248,741		110,830		124%	122,966		14,945		137,911
Total oil and gas sales	$	588,706	$	325,767		$	228,168	$	34,771	$	262,939
For the Six Months Ended June 30,
Gas sales	$	598,920	$	411,227	46%	$	156,443	$	31,250	$	187,693
Oil sales	444,191		207,994		114%	203,865		32,332		236,197
Total oil and gas sales	$	1,043,111	$	619,221		$	360,308	$	63,582	$	423,890

	For the Three Months				Percent Change	For the Six Months				Percent Change
	Ended June 30,				Between	Ended June 30,				Between
	2008		2007		2008/2007	2008		2007		2008/2007
Total gas volume – MMcf	32,172		29,462		9%	63,082		58,639		8%
Gas volume - MMcf per day	353.5		323.8			346.6		324.0
Average gas price - per Mcf	$	10.57	$	7.30	45%	$	9.49	$	7.01	35%
Effect of hedges – per Mcf	$	—	$	0.11		$	0.02	$	0.14

Total oil volume - thousand barrels	2,045		1,802		13%	4,116		3,562		16%
Oil volume - barrels per day	22,471		19,800			22,614		19,677
Average oil price - per barrel	$	121.64	$	61.51	98%	$	107.93	$	58.40	85%

Oil and gas sales for the second quarter of 2008 totaled $588.7 million, compared to $325.8 million in 2007. Of the $262.9 million increase in sales between the two periods, $34.8 million related to higher production volumes and $228.2 million resulted from higher prices. For the six months ended June 30, 2008, oil and gas sales increased by $423.9 million, to $1.0 billion from $619.2 million during the first six months of 2007. Increased commodity prices resulted in a $360.3 million increase in oil and gas sales and higher oil and gas production volumes resulted in a $63.6 million increase between the two six-month periods.

When compared to the second quarter of 2007, our second quarter 2008 oil production increased by 13% to an average of 22,471 barrels per day. This increase resulted in $14.9 million of incremental revenues. Second quarter gas volumes averaged 353.5 MMcf per day in 2008 compared to 323.8 MMcf per day in the second quarter of 2007, resulting in an increase in revenues of $19.8 million. For the first six months of 2008, gas volumes averaged 346.6 MMcf per day and oil volumes equaled 22,614 barrels per day, compared to first half 2007 volumes of 324.0 MMcf per day and 19,677 barrels per day. The higher gas volumes increased sales between the two periods by $31.3 million, and the higher oil volumes resulted in $32.3 million of additional revenues.

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Total 2008 oil and gas production volumes were 482.3 MMcfe per day, up 40.3 MMcfe per day from 2007. The increase in production volumes between the periods is due to positive drilling results. We have seen our largest increase in gas production from the Mid Continent region, up 28.1 MMcf per day from 2007. The largest increase in oil production is attributable to our Permian Basin region which has seen a 2,206 barrel per day increase when compared to the first six months of 2007.

Average realized gas prices increased by 45% to $10.57 per Mcf for the three months ended June 30, 2008, compared to $7.30 per Mcf for the second quarter of 2007. This price increase boosted gas sales by $105.2 million between the two periods. In 2007 we had cash flow hedges at a floor price of $7.00/MMBtu on 80,000 MMBtu per day of Mid-Continent gas production. Included in our second quarter 2007 realized gas price is $3.4 million of cash receipts (a positive $0.11 per Mcf effect) from settlement of these cash flow hedges. At year end 2007 half of the contracts expired dropping our 2008 hedged position to 40,000 MMBtu per day. These hedges had no impact on our second quarter 2008 realized gas price. For the six months ended June 30, 2008, realized gas prices increased 35% to $9.49 per Mcf from $7.01 per Mcf. This price change increased sales by $156.4 million. Included in our first half 2008 realized gas price is $1.0 million of cash receipts (a positive $0.02 per Mcf effect) and in first half 2007 is $8.5 million of cash receipts (a positive $0.14 per Mcf effect) from settlement of cash flow hedges.

Realized oil prices averaged $121.64 per barrel during the second quarter of 2008, compared to $61.51 per barrel for the same period in 2007. The increase in oil sales resulting from this 98% improvement in oil prices totaled $123.0 million. For the six months ended June 30, 2008, realized oil prices increased 85% to $107.93 per barrel, from $58.40 per barrel, in the first six months of 2007. This oil price increase boosted sales $203.9 million.

Changes in realized gas and oil prices were mostly the result of overall market conditions.

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2008			2007			2008			2007
Gas Gathering, Processing, Marketing and Other (in thousands):
Gas gathering, processing and other revenues	$	26,610		$	15,013		$	47,981		$	27,652
Gas gathering and processing costs	(12,361		)	(7,825		)	(22,402		)	(15,136		)
Gas gathering, processing and other margin	$	14,249		$	7,188		$	25,579		$	12,516

Gas marketing revenues, net of related costs	$	1,067		$	1,304		$	2,367		$	2,086

We sometimes transport, process and market third-party gas that is associated with our gas. In the second quarter of 2008, third-party gas gathering, processing and other contributed $14.2 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $7.2 million in 2007. For the six months ended June 30, 2008 and 2007, such revenues less direct cash expenses totaled $25.6 million and $12.5 million, respectively. Our gas marketing margin (revenues less purchases) decreased to $1.1 million in the second quarter of 2008 from $1.3 million in the second quarter of 2007. Gas marketing margin increased to $2.4 million from $2.1 million for the first six months of 2008 and 2007, respectively. Changes in net margins from gas gathering, processing, marketing and other activities are the direct result of volumes and overall market conditions.

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	For the Three Months				Variance			For the Six Months				Variance
	Ended June 30,				Between			Ended June 30,				Between
	2008		2007		2008/2007			2008		2007		2008/2007
Operating costs and expenses (in thousands):
Depreciation, depletion and amortization	$	133,201	$	112,797	$	20,404		$	258,757	$	221,681	$	37,076
Asset retirement obligation	1,862		2,399		(537		)	3,456		4,990		(1,534		)
Production	49,092		50,916		(1,824		)	101,144		95,921		5,223
Transportation	10,621		6,294		4,327			18,930		12,228		6,702
Taxes other than income	39,749		23,802		15,947			70,356		44,429		25,927
General and administrative	13,876		11,958		1,918			25,460		24,609		851
Stock compensation	2,366		2,598		(232		)	4,641		5,268		(627		)
Other operating net	85		2,586		(2,501		)	1,121		2,315		(1,194		)
	$	250,852	$	213,350	$	37,502		$	483,865	$	411,441	$	72,424

Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $250.9 million in the second quarter of 2008 compared to $213.4 million in the second quarter of 2007. For the first six months of 2008 and 2007, these operating costs and expenses equaled $483.9 million and $411.4 million, respectively.

DD&A was the largest component of the increase between periods. DD&A equaled $133.2 million in the second quarter of 2008 compared to $112.8 million in the same period of 2007. On a unit of production basis, second quarter DD&A was $3.00 per Mcfe in 2008 compared to $2.80 per Mcfe for 2007. For the first six months of 2008 and 2007, DD&A totaled $258.8 million and $221.7 million, respectively. On a unit of production basis, DD&A was $2.95 per Mcfe for the first six months in 2008 compared to $2.77 per Mcfe for 2007. The increase stems from replacement costs for reserves added being higher than costs of reserves produced. Service costs to drill and complete wells have been increasing and we are drilling deeper and more complex wells.

Production costs decreased $1.8 million from $50.9 million ($1.26 per Mcfe) in the second quarter of 2007 to $49.1 million ($1.10 per Mcfe) in the second quarter of 2008. The decrease between the two periods was primarily caused by lower insurance premiums due to the sale of our Gulf of Mexico Main Pass operated properties in fourth quarter 2007. Production costs rose $5.2 million from $95.9 million ($1.20 per Mcfe) in the first six months of 2007 to $101.1 million ($1.15 per Mcfe) in the first six months of 2008. The increase between the two six month periods is primarily due to higher direct labor and overhead costs, fuel costs, and greater water disposal costs than in the past. These higher costs are caused by increased industry demand for services and experienced personnel as well as our positive drilling results which have increased our number of producing properties.

Transportation costs increased from $6.3 million in the second quarter of 2007 to $10.6 million in the second quarter of 2008. Transportation costs for the first half of 2008 equaled $18.9 million compared to $12.2 million for the same period in 2007. The increase is the result of higher sales volumes, increased market rates and a rising fuel cost component.

General and administrative (G&A) expenses increased $1.9 million from $12.0 million in the second quarter of 2007 to $13.9 million in the second quarter of 2008. G&A expense for the first half of 2008 equaled $25.5 million compared to $24.6 million for the same period of 2007. The increase between periods is primarily due to higher employee-benefit costs.

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Other Operating, net decreased from $2.6 million for the second quarter of 2007 to $0.1 million in the same period of 2008. For the first six months of 2008, Other Operating, net decreased by $1.2 million from $2.3 in 2007 to $1.1 million in 2008. The decrease between periods resulted primarily from fewer litigation settlements and accruals pertaining mostly to resolution of oil and gas property title and royalty issues.

Other income and expense

Interest expense was $3.3 million lower in the first half of the year, decreasing from $19.5 million in 2007 to $16.2 million in 2008. Interest expense for the second quarter decreased from $10.3 million in 2007 to $7.7 million in 2008. This change resulted primarily from a $3.5 million decrease in interest expense on bank debt as we had no borrowings on our credit facility during the first half of 2008.

In the second quarter of 2007 we recognized a gain on the early extinguishment of debt. The $5.1 million gain was from the redemption of our $195 million face value of old 9.6% senior unsecured notes. We replaced the old notes with new ten-year, 7.125% senior unsecured notes.

Other, net increased from $3.5 million of income in the second quarter of 2007 to $5.5 million of income in the second quarter of 2008. Other, net for the six months ended June 30, 2008 and 2007 equaled $8.5 million and $6.9 million, respectively. Components consist of miscellaneous income and expense items that will vary from period to period, including income and loss in equity investees, gain or loss on sale of inventory and interest income. The change from 2007 to 2008 primarily consisted of a $0.9 million increase in interest income and a $2.8 million increase in gain on sale of inventory.

Income tax expense

Income tax expense totaled $126.5 million, of which $57.7 million is current, for the second quarter of 2008 versus $45.9 million for the second quarter of 2007. Tax expense equaled a combined federal and state effective income tax rate of 35.5% and 36.9% in the second quarters of 2008 and 2007, respectively. Income tax expense for the first six months of 2008 equaled $210.0 million, of which $85.6 million is current, compared to $83.1 million for the same period of 2007, equating to combined Federal and state effective income tax rates of 35.6% and 36.7%, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our primary sources of liquidity and capital resources are cash flow from operating activities, occasional property sales, borrowings under our bank credit facility and public offerings of debt securities. Our primary uses of funds are exploration and development, property acquisitions, common stock dividends and occasional share repurchases.

Exploration and development expenditures and dividend payments have generally been funded by cash flow provided by operating activities. We believe that our cash flow from operating activities and other capital resources will be adequate to fund our remaining planned 2008 capital expenditures.

Analysis of Cash Flow Changes

Cash flow provided by operating activities for the first six months of 2008 was $697.6 million, compared to $433.3 million for the six months ended June 30, 2007. The increase in the first half of 2008 resulted primarily from higher gas prices, higher oil prices and increased production.

Cash flow used in investing activities for the first six months of 2008 was $654.7 million, compared to $459.1 million for the six months ended June 30, 2007. Changes in the cash flow used in investing activities

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are generally the result of changes in our exploration and development programs, acquisitions and property sales. The increase from first six months of 2007 to 2008 was mostly caused by increased oil and gas expenditures resulting from increased activity in our drilling and exploitation programs.

Net cash flow provided by financing activities in the first six months of 2008 was $2.9 million versus $40.2 million provided in the same period of 2007. In 2008, cash flow was provided by proceeds of $13.0 million from the issuance of common stock which were partially offset by the payment of dividends. The cash provided from financing activities in 2007 resulted primarily from the net proceeds from the sale of $350 million of 7.125% notes after the redemption of the outstanding $195 million 9.6% notes and the payment of outstanding borrowings under our credit facility.

Capital Expenditures

The following table sets forth certain historical information regarding capitalized expenditures by us in our oil and gas acquisition, exploration, and development activities (in thousands):

	For Three Months Ended					For Six Months Ended
	June 30,					June 30,
	2008		2007			2008		2007
Acquisitions:
Proved	$	324	$	—		$	1,369	$	23
Unproved	—`		—			—		—
	324		—			1,369		23
Exploration and development:
Land and seismic	33,955		23,629			57,126		44,772
Exploration and development	325,943		213,245			609,727		437,607
	359,898		236,874			666,853		482,379

Property sales	—		(20,630		)	—		(20,880		)
	$	360,222	$	216,244		$	668,222	$	461,522

Our exploration and development expenditures increased 45 percent in the first half of 2008 compared to the first half of 2007. The increase in 2008 resulted primarily from an increase in exploration activity in our Permian Basin and Mid-Continent regions. Overall, we drilled a total of 252 gross (158 net) wells during the first six months of 2008 versus 225 gross (137 net) wells in the same period of 2007.

We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations and not an extraordinary cost of compliance. We do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending regulatory changes that would have a material impact.

Financial Condition

Total assets increased by $0.6 billion in the first half of 2008 from $5.4 billion at the beginning of the year to reach $6.0 billion by second quarter end. This change was primarily due to a $423 million increase in our net oil and gas assets because of our drilling program. As of June 30, 2008, stockholders’ equity totaled $3.6 billion, up from $3.3 billion at December 31, 2007. The increase resulted primarily from first half net income of $379.1 million.

Dividends

In December 2005, the Board of Directors declared the Company’s first quarterly cash dividend of $.04 per share payable to shareholders. A dividend has been authorized in every quarter since then. On

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December 12, 2007 the Board of Directors increased the regular cash dividend on our common stock from $0.04 to $0.06 per common share.

Common Stock Repurchase Program

In December 2005, the Board of Directors authorized the repurchase of up to four million shares of common stock. During 2007 we repurchased a total of 1,114,200 shares at an average purchase price of $37.93. Cumulative purchases through December 31, 2007 total 1,364,300 shares at an average price of $39.05. No purchases have been made in the first half of 2008.

Working Capital

Working capital increased $9.4 million from year-end 2007 to $149.4 million at second quarter-end 2008. Working capital increased primarily because of the following:

· Accounts Receivables increased by $103.1 million and cash and cash equivalents increased by $45.8 million due to higher production volumes and higher prices.

· Inventories increased by $45.2 million due to increased steel prices and a planned increase in the amount of pipe inventory in our yards.

These working capital increases were mostly offset by:

· Accounts payable increased by $55.0 million due to increased costs and activity and revenue payable increased by $53.3 million due to increased production and prices.

· Other current assets decreased by $50.6 million, due primarily to our Riley Ridge field development project in Wyoming, which is now anticipated to be completed in 2010. Also, the $12.1 million current asset associated with derivative contracts outstanding at December 31, 2007 is now a $16.6 million current liability due to increased natural gas prices in the current year.

Our receivables are a major component of our working capital and are made up of a diverse group of companies including major energy companies, pipeline companies, local distribution companies and end-users in various industries. The collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been significant.

Financing

Debt at June 30, 2008 and December 31, 2007 consisted of the following (in thousands):

	June 30,		December 31,
	2008		2007
Bank debt	$	—	$	—
7.125% Notes due 2017	350,000		350,000
Floating rate convertible notes due 2023 (face value $125,000)	136,778		137,159
Total long-term debt	$	486,778	$	487,159

Our revolving credit facility provides for $500 million of long-term committed credit. The facility is scheduled to mature on July 1, 2010 and is secured by mortgages on certain oil and gas properties and the stock of certain wholly-owned operating subsidiaries. At June 30, 2008, there were no outstanding borrowings under the revolving credit facility. We had outstanding letters of credit for approximately $2.8 million posted against the borrowing base, leaving an unused borrowing amount of approximately $497.2 million.

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The credit facility agreement contains both financial and non-financial covenants. We are in compliance with these covenants and do not view them as materially restrictive.

In May 2007 we sold $350 million of new 7.125% senior unsecured notes that will mature May 1, 2017. The notes were sold to the public at par. Net proceeds from the sale were used to redeem our 9.6% notes and reduce borrowings under our credit facility. Interest on the new notes is payable May 1 and November 1 of each year. The first interest payment was made on November 1, 2007. The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at the following redemption prices (expressed as percentages of the principal amount) plus accrued interest, if any, thereon to the date of redemption.

Year	Percentage
2012	103.6	%
2013	102.4	%
2014	101.2	%
2015 and thereafter	100.0	%

The floating rate convertible senior notes were assumed in the Magnum Hunter merger and mature on December 15, 2023. The notes are senior unsecured obligations and bear interest at an annual rate equal to three-month LIBOR, reset quarterly. The interest rate in effect on June 30, 2008 was 2.8%.

In addition to the holders’ right to redeem the notes if our common stock price is above the conversion price, the holders also have the right to require us to repurchase all or a portion of the notes at a repurchase price equal to 100% of the principal amount (plus accrued interest) on December 15, 2008, 2013, and 2018. The indenture agreement also provides us with an option to redeem some or all of the notes at a redemption price equal to 100% of the principal amount and shares for the value of the convertible feature (plus accrued interest) anytime after December 22, 2008.

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Contractual Obligations and Material Commitments

At June 30, 2008, we had contractual obligations and material commitments as follows:

	Payments Due by Period
Contractual obligations	Total		Less Than 1 Year		1-3 Years			4-5 Years			More than 5 Years
	(In thousands)
Long-term debt(1)	$	475,000	$	—	$	—		$	—		$	475,000
Fixed-Rate interest payments(1)	224,438		24,938		49,875			49,875			99,750
Operating leases	30,196		5,603		10,601			9,912			4,080
Drilling commitments(2)	243,584		243,584		—			—			—
Gas processing facility(3)	131,547		63,062		68,485			—			—
Asset retirement obligation	119,794		10,270		—		(4)	—		(4)	—		(4)
Other liabilities(5)	74,241		34,288		13,251			13,251			13,451

(1) See Item 3: Interest Rate Risk for more information regarding fixed and variable rate debt.

(2) We have drilling commitments of approximately $178.8 million consisting of obligations to complete drilling wells in progress at June 30, 2008. We also have minimum expenditure commitments of $64.8 million to secure the use of drilling rigs.

(3) At June 30, 2008, we had committed to construction of a gas processing facility adjacent to our Riley Ridge gas field in Sublette County, Wyoming. The total estimated remaining cost of the facility is $191.4 million, of which $131.5 million is subject to a construction contract for the facility. Pursuant to the terms of our operating agreement with our partners in this project, we will be reimbursed by them for approximately 43% of all costs related to the facility.

(4) We have excluded the long term asset retirement obligations because we are not able to reasonably predict the timing of these amounts.

(5) Other liabilities include the fair value of our liabilities associated with our gas derivative contracts, benefit obligations and other miscellaneous commitments.

At June 30, 2008, we had a firm sales contract to deliver approximately 2.6 Bcf of natural gas over the next nine months. If this gas is not delivered, our financial commitment would be approximately $29.4 million. This commitment may fluctuate due to either price volatility or volumes delivered. However, we do not anticipate that a financial commitment will be due.

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

Based on current commodity prices and anticipated levels of production, we believe that the estimated net cash generated from operations, coupled with the cash on hand and amounts available under our existing bank credit facility will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and exploration and development activities.

2008 Outlook

Our exploration and development expenditures program for 2008 are projected to range from $1.3 billion to $1.5 billion. Though there are a variety of factors that could curtail, delay or even cancel

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some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects. Approximately 43% of the expenditures will be in the Mid-Continent area, 37% in the Permian Basin, 14% in the Gulf Coast area, and 6% in our other areas.

Production estimates for 2008 range from 480 to 495 MMcfe per day. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2007, our realized prices averaged $7.05 per Mcf of gas and $69.71 per barrel of oil. Prices can be very volatile and the possibility of 2008 realized prices being different than they were in 2007 is high.

Costs of operations on a per Mcfe basis for 2008 are currently estimated as follows:

	2008
Production expense	$ 1.15		-	$ 1.25
Transportation expense	0.20		-	0.25
DD&A and Asset retirement obligation	3.05		-	3.20
General and Administrative	0.30		-	0.34
Production taxes (% of oil and gas revenue)	6.50	%	-	7.50	%

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We consider accounting policies related to oil and gas reserves, full cost accounting, goodwill, derivatives, contingencies and asset retirement obligations to be critical policies and estimates. These critical policies and estimates are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K/A-1 for the year ended December 31, 2007, and in the footnote disclosures included in Part 1, Item 1 of this report.

Recent Accounting Developments

In May, 2008 the Financial Accounting Standards Board (“FASB”) issued a new Staff Position (No. APB 14-1), Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), that will impact the accounting for the components of convertible debt that can be settled wholly or partly in cash upon conversion. The new requirements apply not only to new instruments, but also would be applied retrospectively to previously issued convertible instruments. The debt and equity components of the instruments are to be accounted for separately. The value assigned to the debt component is the estimated value of similar debt without a conversion feature as of the issuance date, with the remaining proceeds allocated to the equity component and recorded as additional paid-in capital. The debt component is recorded at a discount and is subsequently accreted to its par value, thereby reflecting an overall market rate of interest in the income statement. This Staff Position is effective for both new and previously issued instruments for current and comparative periods in fiscal years beginning after December 15, 2008, and interim periods within those years. We are currently evaluating the effects of implementing this pronouncement on our financial statements.

Also in May 2008 the Securities and Exchange Commission (“SEC”) issued a proposal that would require companies to submit XBRL-formatted financial statements as exhibits to their filed financial statements, phasing in the requirement over three years based on company size. The requirement would apply to annual and quarterly reports, transition reports, registration statements, and corporate websites. XBRL is an abbreviation of “Extensible Business Reporting Language”. XBRL computer language would enable investors, through the use of defined labels (tags), to search, sort and otherwise process and analyze data without identifying needed information by reading and then re-keying the data. The proposed effective date, as it pertains to Cimarex, would be for fiscal periods ending on or after December 15, 2008.

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In June 2008 the FASB issued a new Staff Position (EITF 03-6-1), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which holds that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents are “participating securities” (as defined by EITF 03-6 as securities that may participate in undistributed earnings with common stock, whether that participation is conditioned upon the occurrence of a specified event or not, regardless of the form of participation),and therefore should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. This Staff Position is effective for financial statements issued in fiscal years beginning after December 15, 2008, and interim periods within those years. Once effective, the requirements will be applied by restating previously reported earnings per share data. We are currently evaluating the effects of implementing this pronouncement on our earnings per share disclosures.

In June 2008 the SEC proposed for public comment revised reporting requirements for oil and gas reserves that a company holds. The proposed changes include: 1) permitting use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; 2) enabling companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; 3) allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves rather than mining reserves; 4) requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; 5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and 6) requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. If approved, changes would be effective for the fiscal year ending December 31, 2009. The comment period to the SEC ends September 8, 2008.

Also in June 2008 the FASB issued an Exposure Draft, Disclosure of Certain Loss Contingencies, which would amend Statement of Financial Accounting Standards (“SFAS”) Nos. 5, Accounting for Contingencies, and 141(R), Business Combinations. The announced objective of the proposal is to improve disclosures about loss contingencies, including pending and threatened claims, and unasserted claims and assessments. The proposed amendments would not affect the thresholds to be met to accrue a loss contingency in the financial statements, but would significantly increase disclosures for loss contingencies that are not required to be accrued. If adopted, the new requirements will be effective for fiscal years ending after December 15, 2008.

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ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and value of our short-term investments. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Price Fluctuations

Our major market risk is pricing applicable to our oil and gas production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil and gas production has been volatile and unpredictable.

Currently, we are largely accepting the volatility risk that the change in prices presents. None of our future oil production is subject to hedging. With regard to our future natural gas production, based on contracts currently in place, the following table details the remaining contracts:

Mid-Continent

Fair Value

Commodity

Type

Volume/Day

Duration

Price

(000’s)

Natural Gas

Collar

20,000 MMBTU

Jul 08 - Dec 08

$7.00 - $ 9.80

(8,556

)

Natural Gas

Collar

10,000 MMBTU

Jul 08 - Dec 08

$7.00 - $ 10.10

(3,861

)

Natural Gas

Collar

10,000 MMBTU

Jul 08 - Dec 08

$7.00 - $ 9.90

(4,138

)

(16,555

)

This amount represents approximately 11% of our estimated 2008 gas production (eight percent of our total Mcfe production).

While hedging limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. Mid-Continent gas would have to be above the $9.80 ceiling for us to have any downside risk. At June 30, 2008, the weighted average Mid-Continent prices for the 2008 contracts approximated $11.68 (which would equate to a $2.2 million cash payment if the July contracts were settled at this price). These contracts are not expected to have a material effect on our realized gas prices for 2008. Through the first six months of 2008 we have received $1.0 million in hedge settlements (a positive $0.02 per Mcf effect on our realized gas prices). See Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.

Interest Rate Risk

At June 30, 2008, we had total debt outstanding of $487 million. Of this amount, $350 million is senior unsecured notes that bear interest at a fixed rate of 7.125% and will mature on May 1, 2017. The remaining debt is $125 million of unsecured convertible senior notes (face value) that mature on December 2023. These convertible notes bear interest at an annual rate equal to three-month LIBOR, reset quarterly. The book value of our debt approximates the current fair value.

We consider our interest rate exposure to be minimal because as of June 30, 2008 about 74% of our long-term debt obligations were at fixed rates. A 1% increase in the three-month LIBOR rate would increase annual interest expense by $1.25 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 2 and Note 5 to the Consolidated Financial Statements in this report for additional information regarding debt.

Market Value of Investments

We currently have $7.4 million invested in a securities fund. We expect to liquidate our investment in this fund within the next 12 months. A five percent change in these investments’ market value would have a $0.4 million impact on our investments.

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ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of June 30, 2008 and concluded that the disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is also based upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of June 30, 2008, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended June 30, 2008, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II

ITEM 4 – SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The annual meeting of Cimarex was held on May 21, 2008. Two proposals were voted upon at the annual meeting. Following are the results of voting on each proposal:

Proposal 1. Election of three Class III directors with terms expiring in 2011.

	For	Against	Abstain
David A. Hentschel	74,412,796	1,739,705	69,193
F. H. Merelli	74,353,326	1,794,685	73,683
L. Paul Teague	74,455,488	1,679,995	86,211

Proposal 2. Ratify the appointment of KPMG LLP as independent auditors for 2008.

For		Against		Abstain
74,281,876		1,499,555		440,263

ITEM 6 – EXHIBITS

10.1	Amendment No. 4 effective July 11, 2008 to Cimarex Energy Co. 2002 Stock Incentive Plan.

10.2	Form of Non-Qualified Stock Option Agreement adopted July 11, 2008 by Cimarex Energy Co. Compensation Committee.

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.

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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.

August 5, 2008


		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
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)