Edgar Filing: CIMAREX ENERGY CO

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 September 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 .

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
(Do not check if a smaller
reporting company)

Smaller reporting company o

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

The number of shares of Cimarex Energy Co. common stock outstanding as of September 30, 2008 was 83,271,632.

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CIMAREX ENERGY CO.

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	Page
PART I

Item 1 – Financial Statements

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

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

Consolidated statements of cash flows (unaudited) for the three and nine months ended September 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	33

Item 4 – Controls and Procedures	34

PART II

Item 6 – Exhibits	35

Signatures	36

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)

		September 30, 2008			December 31, 2007
		(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	201,383		$	123,050
Restricted cash		500			—
Short-term investments		5,133			14,391
Receivables, net		336,089			315,327
Inventories		112,972			29,642
Deferred income taxes		4,543			5,697
Derivative instruments		7,156			12,124
Other current assets		6,555			64,346
Total current assets		674,331			564,577
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties		6,569,058			5,545,977
Unproved properties and properties under development, not being amortized		434,550			364,618
		7,003,608			5,910,595
Less - accumulated depreciation, depletion and amortization		(2,988,075	)		(1,938,863	)
Net oil and gas properties		4,015,533			3,971,732
Fixed assets, net		116,875			90,584
Goodwill		691,432			691,432
Other assets, net		80,869			44,469
	$	5,579,040		$	5,362,794
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	62,793		$	52,671
Accrued liabilities		304,266			240,387
Revenue payable		160,063			131,513
Total current liabilities		527.122			424,571
Long-term debt		486,587			487,159
Deferred income taxes		1,027,949			1,076,223
Other liabilities		133,958			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, 84,157,024 and 83,620,480 shares issued, respectively		842			836
Treasury stock, at cost, 885,392 and 1,078,822 shares held, respectively		(33,344	)		(40,628	)
Paid-in capital		1,851,031			1,842,690
Retained earnings		1,580,728			1,448,763
Accumulated other comprehensive income		4,167			7,626
		3,403,424			3,259,287
	$	5,579,040		$	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 Ended September 30,						For the Nine Months Ended September 30,
		2008			2007			2008			2007
		(In thousands, except per share data)
Revenues:
Gas sales	$	313,523		$	192,423		$	912,443		$	603,650
Oil sales		238,918			135,335			683,109			343,329
Gas gathering, processing and other		23,245			14,773			71,226			42,425
Gas marketing, net		863			1,222			3,230			3,308
		576,549			343,753			1,670,008			992,712
Costs and expenses:
Impairment of oil and gas properties		657,146			—			657,146			—
Depreciation, depletion and amortization		147,432			117,634			406,189			339,315
Asset retirement obligation		1,978			2,124			5,434			7,114
Production		55,362			55,945			156,506			151,866
Transportation		10,621			6,882			29,551			19,110
Gas gathering and processing		11,882			6,859			34,284			21,995
Taxes other than income		39,097			22,397			109,453			66,826
General and administrative		12,377			10,922			37,837			35,531
Stock compensation, net		2,791			2,800			7,432			8,068
Other operating, net		11,871			3,867			12,992			6,182
		950,557			229,430			1,456,824			656,007

Operating income (loss)		(374,008	)		114,323			213,184			336,705

Other (income) and expense:
Interest expense		7,795			9,274			23,963			28,736
Capitalized interest		(5,671	)		(4,990	)		(14,930	)		(14,979	)
Amortization of fair value of debt		(191	)		(191	)		(572	)		(1,718	)
Gain on early extinguishment of debt		—			—			—			(5,099	)
Other, net		(8,086	)		(5,316	)		(16,610	)		(12,222	)

Income (loss) before income tax		(367,855	)		115,546			221,333			341,987
Income tax expense (benefit)		(135,726	)		42,390			74,319			125,496

Net income (loss)	$	(232,129	)	$	73,156		$	147,014		$	216,491

Earnings (loss) per share:
Basic	$	(2.85	)	$	0.90		$	1.81		$	2.64
Diluted	$	(2.85	)	$	0.87		$	1.74		$	2.56

Weighted average shares outstanding:
Basic		81,572			81,568			81,445			82,022
Diluted		81,572			84,025			84,389			84,418

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.
Condensed Consolidated Statements of Cash Flows
(Unaudited)

		For the Nine Months Ended September 30,
		2008			2007
		(In thousands)

Cash flows from operating activities:
Net income	$	147,014		$	216,491
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of oil and gas properties		657,146			—
Depreciation, depletion and amortization		406,189			339,315
Asset retirement obligation		5,434			7,114
Deferred income taxes		(38,332	)		125,496
Stock compensation, net		7,432			8,068
Gain on liquidation of equity investees		—			(3,015	)
Other		(375	)		(6,512	)
Changes in operating assets and liabilities:
(Increase) decrease in receivables, net		(20,762	)		19,643
Increase in other current assets		(59,669	)		(4,451	)
Increase (decrease) in accounts payable and accrued liabilities		39,747			(1,255	)
Decrease in other non-current liabilities		(3,115	)		(7,725	)
Net cash provided by operating activities		1,140,709			693,169
Cash flows from investing activities:
Oil and gas expenditures		(1,026,719	)		(753,491	)
Proceeds from sale of assets		434			23,196
Distributions received from equity investees		—			3,015
Sales of short-term investments		9,288			—
Other expenditures		(43,253	)		(10,991	)
Net cash used by investing activities		(1,060,250	)		(738,271	)
Cash flows from financing activities:
Net decrease in hank debt		—			(56,000	)
Increase in other long-term debt		—			350,000
Decrease in other long-term debt		—			(204,360	)
Financing costs incurred		(50	)		(6,099	)
Treasury Stock acquired		—			(42,266	)
Dividends paid		(15,007	)		(10,095	)
Issuance of common stock and other		12,931			8,897
Net cash provided by (used in) financing activities		(2,126	)		40,077
Net change in cash and cash equivalents		78,333			(5,025	)
Cash and cash equivalents at beginning of period		123,050			5,048
Cash and cash equivalents at end of period	$	201,383		$	23

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 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 is charged to expense. If commodity prices increase after period end and before issuance of the financial statements, the higher commodity prices would be used to determine if the capital costs were impaired as of the end of the period. Because subsequent commodity prices did not increase, we used oil and gas prices at September 30, 2008 for the ceiling limitation calculation which resulted in excess capitalized costs of $657 million before tax ($417 million after tax), for which we recorded a non-cash impairment of oil and gas properties at September 30, 2008.

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 expected to be produced based on current prices. 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

September 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. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues, and expenses. Our estimates are based on historical experience and various other analysis and assumptions that we believe to be reasonable under the circumstances. Changes in our assumptions and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results may be different from previous estimates.

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 and other investments, purchase price allocation, valuation of deferred tax assets, commitments and contingencies.

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 with weighted average floor and ceiling prices of $7.00 to $9.90. The following table sets forth the terms of the related derivative contracts for the remaining three months:

Mid-Continent

Fair Value

Commodity

Type

Volume/Day

Duration

Price

(000’s)

Natural Gas

Collar

20,000 MMBTU

Oct 08 - Dec 08

$7.00 - $

9.80

3,576

Natural Gas

Collar

10,000 MMBTU

Oct 08 – Dec 08

$7.00 - $

10.10

1,791

Natural Gas

Collar

10,000 MMBTU

Oct 08 – Dec 08

$7.00 - $

9.90

1,789

7,156

At September 30, 2008, the remaining contracts outstanding represented approximately 21% of our current anticipated Mid-Continent gas production for the remainder of 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.

Net settlements paid during the quarter ending September 30, 2008 totaled $1.1 million, which were recorded in gas sales and decreased the average realized price for the quarter by $0.03 per Mcf. For the same quarter ending September 30, 2007 we received settlements of $11.5 million, which were recorded in gas sales and increased the average realized price for the period by $0.39 per Mcf. Net settlements paid during the nine months ended September 30, 2008 equaled $72 thousand, which were recorded in gas sales and had no effect on the average realized price for the period. For the same period ending September 30,

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

2007 we received settlements equaling $20 million, which were recorded in gas sales and increased the average realized price for the period by $0.23 per Mcf. During the quarters ended September 30, 2008 and 2007 we recognized an unrealized gain of $553 thousand and a $4 thousand loss, respectively, related to the ineffective portion of the derivative contracts. During the nine months ended September 30, 2008 and 2007, we recognized an unrealized loss of $35 thousand and a $13 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 September 30, 2008, the fair value calculation of the remaining contracts resulted in a current asset of approximately $7.2 million. An unrealized gain (net of deferred income taxes) of $4.6 million was recorded in other comprehensive income. These contracts will expire during the remaining three 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 September 30, 2008, we had liquidated $10.4 million of the investments with a realized loss of $228 thousand ($147 thousand after tax.) We also recorded an unrealized loss of $230 thousand in other comprehensive income, resulting in a fair value attributable to the investments of $5.1 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 September 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:

	September 30,		December 31,
	2008		2007
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
	(In thousands)
7.125% Notes due 2017⁽¹⁾	$350,000	$322,000	$350,000	$346,504
Floating rate convertible notes due 2023 (face value $125,000)	$136,587	$212,948	$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 so the fair values of the convertible notes were based on the closing price per share for our common stock, which was $48.91 at September 30, 2008 and $42.53 at December 31,

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

2007. Calculated in this manner, there is value attributable to both the face amount of the notes and the conversion feature.

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. Our equity investments are recorded at historical cost and are subject to periodic reviews to determine if the carrying value is in excess of the fair value of the investment. 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 September 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 nine months ended September 30, 2008, we issued a total of 464,620 restricted shares and 3,790 restricted units to non-employee directors, officers, and other employees. Included in that amount are 244,000 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 and units granted in 2008 have service-based vesting schedules of three to five years.

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

Outstanding as of January 1, 2008	1,289,695
Vested	(28,192	)
Granted	464,620
Canceled	(30,600	)
Outstanding as of September 30, 2008	1,695,523

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

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

Outstanding as of January 1, 2008	701,915
Converted to Stock	(45,500	)
Granted	3,790
Canceled	(5,000	)
Outstanding as of September 30, 2008	655,205
Vested included in outstanding	591,247

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 September 30, 2008 and 2007, total compensation costs (including capitalized amounts) equaled $4.0 million and $3.4 million, respectively. For the nine months ended September 30, 2008 and 2007, compensation costs (including capitalized amounts) equaled $11.7 million and $9.2 million, respectively.

Unamortized compensation costs related to unvested restricted shares and units at September 30, 2008 and 2007 was $38.3 million and $34.7 million, respectively.

Stock Options

Options granted under our plan expire ten years from the grant date and have service-leased vesting schedules of three to five years. 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 certain 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 483,500 stock options granted to employees during the nine months ended September 30, 2008. There were no stock options granted to employees during the nine months ended September 30, 2007.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

Information about outstanding stock options is summarized below:

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

Outstanding as of January 1, 2008	1,489,565			$17.73
Exercised	(404,449		)	15.47
Granted	483,500			56.70
Canceled		(2,100	)		56.74
Outstanding as of September 30, 2008		1,566,516			$30.29		5.9 Years		$32,916
Exercisable as of September 30, 2008		994,216			$16.82		3.7 Years		$31,906

There were no options exercised during the three months ended September 30, 2008. The total intrinsic value of stock options exercised during the three months ended September 30, 2007 was $0.7 million. The total intrinsic value of options exercised during the nine months ended September 30, 2008 and 2007 was $18.7 million and $9.9 million, respectively.

Compensation cost 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 cost related to stock options ratably over the vesting period. For the quarter ended September 30, 2008 and 2007, compensation cost (including capitalized amounts) equaled $692 thousand and $507 thousand, respectively. For the nine months ended September 30, 2008 and 2007, compensation cost (including capitalized amounts) equaled $910 thousand and $1.5 million, 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 nine months ended September 30, 2008 and 2007 was $6.3 million and $5.3 million, respectively. The related tax benefits realized from option exercises totaled $6.7 million and $3.6 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 September 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	(10,860	)	12.98
Granted	483,500		19.44
Forfeited	(2,100	)	19.43
Non-vested as of September 30, 2008	572,300		$	18.88

As of September 30, 2008, there was approximately $10 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 2.9 years. The weighted average exercise price of the non-vested stock options is $53.70.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

Stockholder Rights Plan

We have a stockholder rights plan that 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 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 September 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

July, 2008	None	NA	None	2,635,700
August, 2008	None	NA	None	2,635,700
September, 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 third quarter of 2008, or since the quarter ended September 30, 2007.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

A summary of our common stock activity for the nine months ended September 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	464		—		464
Option exercised, net of cancellations	266		—		266
Treasury shares cancelled	(194	)	194		—
September 30, 2008	84,157		(885	)	83,272

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 nine months ended September 30, 2008 (in thousands):

Balance as of January 1, 2008	$	113,054
Liabilities incurred	2,993
Liability settlements and disposals	(5,236		)
Accretion expense	5,007
Revisions of estimated liabilities	3,582
Balance as of September 30, 2008	$	119,400
Current asset retirement obligation	$	10,270
Long-term asset retirement obligation	$	109,130

5. Long-Term Debt

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

	September 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)	136,587		137,159
Total long-term debt	$	486,587	$	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 September 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 September 30, 2008.

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

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. 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 September 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 $28.65 per share. On September 30, 2008, the closing price of our common stock on the New York Stock Exchange was $48.91. 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.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

6. Income Taxes

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Current provision	$	27,068	$	—	$	112,651	$	—
Deferred tax (benefit)	(162,794)		42,390		(38,332)		125,496
	$	(135,726)	$	42,390	$	74,319	$	125,496

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 September 30, 2008, we made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005 – 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 2004-2007 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 nine months ended September 30, 2008 was 33.6%.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008		2007
Cash paid during the period for:
Interest expense (net of amounts capitalized)	$	(4,390	)	$	(2,170	)	$	2,263	$	8,456
Interest capitalized	5,671			4,990			14,930		14,979
Income taxes	1,457			352			128,318		540

Cash received for income taxes	2,121			225			4,185		17,162

8. Earnings (Loss) per Share and Comprehensive Income (Loss)

Earnings (Loss) per Share

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008		2007
Net Income (loss) available to common stockholders for basic and diluted shares	$(232,129		)	$	73,156	$147,014		$	216,491

Basic weighted-average shares outstanding	81,572			81,568		81,445		82,022
Incremental shares from assumed exercise of stock options and vesting of restricted stock and units	—(1)			1,457		1,819		1,396
Incremental shares from assumed conversion of the convertible senior notes	—(1)			1,000		1,125		1,000
Diluted weighted-average shares outstanding	81,572			84,025		84,389		84,418
Earnings (Loss) per share:
Basic	$	(2.85	)	$	0.90	$	1.81	$	2.64
Diluted	$	(2.85	)	$	0.87	$	1.74	$	2.56

(1)No potential common shares are included in the diluted share computation when a loss from continuing operations exists.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

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

	September 30,
	2008	2007

Stock options	1,566,516	1,500,382
Restricted stock	1,695,523	1,278,522
Restricted units	655,205	701,915

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2008	2007	2008	2007
Stock options	1,566,516	90,900	121,394	90,900
Restricted stock	1,695,523	185,691	61,405	83,008
Restricted stock units	655,205	745	1,840	251
Convertible notes	1,125,000	—	—	—
	5,042,244	277,336	184,639	174,159

Comprehensive Income (Loss)

Comprehensive income (loss) is a term used to refer to net income (loss) 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 (loss).

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Net Income (loss)	$	(232,129	)	$	73,156		$	147,014		$	216,491
Other comprehensive income:
Cash flow hedges
Increase (decrease) in fair value	22,095			11,432			(5,004		)	(7,457		)
Settlements reflected in gas sales	1,064			(11,522		)	72			(19,999		)
Sub-total	23,159			(90		)	(4,932		)	(27,456		)
Related income tax effect	(8,282		)	(8		)	1,885			10,145
Total cash flow hedges	14,877			(98		)	(3,047		)	(17,311		)
Change in fair value of short-term investments and other, net of tax	(213		)	33			(413		)	79
Total comprehensive income (loss)	$	(217,465	)	$	73,091		$	143,554		$	199,259

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

September 30, 2008

(Unaudited)

9. Commitments and Contingencies

Litigation

In the normal course of business, we have various litigation related matters and associated accruals. We periodically assess the probability of estimable amounts, as required by Financial Accounting Standard No. 5 (Accounting for Contingencies), and adjust our accruals accordingly. 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 financial condition or results of operations.

Other

At September 30, 2008, we had commitments of $173.3 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 $99.7 million.

We have drilling commitments of approximately $194.7 million consisting of obligations to complete drilling wells in progress at September 30, 2008. We also have minimum expenditure commitments of $91.2 million to secure the use of drilling rigs. We are currently evaluating damages to our wells and platforms caused by hurricanes Gustav and Ike, which occurred during the third quarter of 2008. It is not presently determinable what our share of the total damages will be after insurance proceeds.

At September 30, 2008, we had firm sales contracts to deliver approximately 6.2 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial commitment would be approximately $26.1 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.

In connection with a gas gathering and processing agreement, we have commitments to deliver 63.2 Bcf of gas over the next six years. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately $47.8 million.

We have various other gas delivery commitments in the normal course of business that have a maximum amount that would be payable, if no gas is delivered, of approximately $6.6 million.

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

10. Property Sales

Various interests in oil and gas properties and related assets were sold during the first nine months of 2007 for $23.0 million which was recorded as a reduction to oil and gas properties. We have not had any property sales during 2008.

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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 nine months ended September 30, 2008 compared to the three months and nine months ended September 30, 2007:

· Production was up 8% in the third quarter of 2008 and for the first nine months of 2008.

· Third quarter oil and gas sales revenues increased 69% to $552.4 million; for the first nine months of 2008 oil and gas sales increased 68% to $1.6 billion.

· Including a non-cash full cost ceiling write down of $657.1 million ($417.4 million after tax) we reported a net loss of $232.1 million for the quarter and net income of $147.0 million for the nine months ended September 30, 2008.

· Net cash provided by operating activities increased 65% to $1.1 billion during the first nine months of 2008.

· Capital expenditures for oil and gas exploration and development were $1.1 billion during the first nine months of the year.

· We drilled 376 gross (232 net) wells in the first nine months of the year, completing 95% as producers.

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

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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 third quarter 2008 we purchased $1.5 million of assets. Subsequent to quarter end, in October 2008, we expanded our Woodford Shale position in the Anadarko basin through a $180.0 million acquisition of 38,000 net acres located in Blaine and Canadian Counties. This transaction will increase our position to 88,000 net Anadarko-Woodford acres. 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. Through third quarter 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 $6.43 per Mcf in third quarter 2007 to $9.76 per Mcf in 2008. Oil prices increased from $71.63 per barrel in third quarter 2007 to $114.87 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 September 30,					Nine Months Ended September 30,
	2008			2007		2008		2007
Gas Prices:
Average Henry Hub price ($/Mcf)	$	10.25		$	6.16	$	9.74	$	6.83
Average realized sales price – including hedge effect ($/Mcf)	$	9.76		$	6.43	$	9.58	$	6.82
Effect of hedges ($/Mcf)	$	(0.03	)	$	0.39	$	—	$	0.23
Oil Prices:
Average WTI Cushing price ($/Bbl)	$	117.95		$	75.38	$	113.28	$	66.19
Average realized sales price ($/Bbl)	$	114.87		$	71.63	$	110.26	$	62.99

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 $9.5 million change in our gas revenues. Similarly 28% of our production was crude oil. A $1.00 per barrel change in our

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average realized crude oil sales price would have resulted in approximately a $6.2 million change in our oil revenues.

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 nine months of 2008 was $7.4 million compared to $8.1 million in the first nine months of 2007.

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RESULTS OF OPERATIONS

Three months and nine months ended September 30, 2008 vs. September 30, 2007

We recognized a net loss for the third quarter of 2008 of $232.1 million. This compares to net income of $73.2 million, or $0.87 per diluted share for the same period in 2007. For the nine months ended September 30, 2008, net income was $147.0, or $1.74 per diluted share, compared to net income of $216.5 million, or $2.56 per diluted share, for the first nine months of 2007. The decrease in net income is the result of a non-cash full cost ceiling write-down recorded in September 2008. The full cost ceiling impairment is discussed further in the operating costs and expenses section below.

					Percent
					Change
					Between	Price/Volume Analysis
Oil and Gas Sales	2008		2007		2008/2007	Price		Volume		Variance
(In thousands or as indicated)
For the Three Months Ended September 30,
Gas sales	$	313,523	$	192,423	63%	$	107,013	$	14,087	$	121,100
Oil sales	238,918		135,335		77%	89,939		13,644		103,583
Total oil and gas sales	$	552,441	$	327,758		$	196,952	$	27,731	$	224,683
For the Nine Months Ended September 30,
Gas sales	$	912,443	$	603,650	51%	$	262,802	$	45,991	$	308,793
Oil sales	683,109		343,329		99%	292,885		46,895		339,780
Total oil and gas sales	$	1,595,552	$	946,979		$	555,687	$	92,886	$	648,573

	For the Three Months				Percent Change	For the Nine Months				Percent Change
	Ended September 30,				Between	Ended September 30,				Between
	2008		2007		2008/2007	2008		2007		2008/2007

Total gas volume – MMcf	32,136		29,921		7%	95,218		88,560		8%
Gas volume - MMcf per day	349.3		325.2			347.5		324.4
Average gas price - per Mcf	$	9.76	$	6.43	52 %	$	9.58	$	6.82	40 %
Effect of hedges – per Mcf	$	(0.03)	$	0.39		$	—	$	0.23

Total oil volume - thousand barrels	2,080		1,889		10 %	6,196		5,451		14 %
Oil volume - barrels per day	22,607		20,537			22,611		19,967
Average oil price - per barrel	$	114.87	$	71.63	60 %	$	110.26	$	62.99	75 %

Oil and gas sales for the third quarter of 2008 totaled $552.4 million, compared to $327.8 million in 2007. Of the $224.7 million increase in sales between the two periods, $27.7 million related to higher production volumes and $197.0 million resulted from higher prices. For the nine months ended September 30, 2008, oil and gas sales increased by $648.6 million, to $1.6 billion from $947.0 million during the first nine months of 2007. Increased commodity prices resulted in a $555.7 million increase in oil and gas sales and higher oil and gas production volumes resulted in a $92.9 million increase between the two nine-month periods.

When compared to the third quarter of 2007, our third quarter 2008 oil production increased by 10% to an average of 22,607 barrels per day. This increase resulted in $13.7 million of incremental revenues. Third quarter gas volumes averaged 349.3 MMcf per day in 2008 compared to 325.2 MMcf per day in the third quarter of 2007, resulting in an increase in revenues of $14.1 million. For the first nine months of 2008, gas volumes averaged 347.5 MMcf per day and oil volumes equaled 22,611 barrels per day, compared to first nine months of 2007 volumes of 324.4 MMcf per day and 19,967 barrels per day. The higher gas volumes

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increased sales between the two periods by $46.0 million, and the higher oil volumes resulted in $46.9 million of additional revenues.

Total 2008 oil and gas production volumes were 483.2 MMcfe per day, up 39.0 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 30.6 MMcf per day from 2007. The largest increase in oil production is attributable to our Permian Basin region which has seen a 2,372 barrel per day increase when compared to the first nine months of 2007.

Average realized gas prices increased by 52% to $9.76 per Mcf for the three months ended September 30, 2008, compared to $6.43 per Mcf for the third quarter of 2007. This price increase boosted gas sales by $107.0 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 third quarter 2007 realized gas price is $11.5 million of cash receipts (a positive $0.39 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 reduced our third quarter 2008 realized gas price by $0.03 as we had net payments of $1.1 million during the quarter. For the nine months ended September 30, 2008, realized gas prices increased 40% to $9.58 per Mcf from $6.82 per Mcf for the nine months ended September 30, 2007. This price change increased sales by $262.8 million. Included in our first nine months of 2008 realized gas price is $72 thousand of net cash receipts and in the first nine months of 2007 is $20.0 million of cash receipts (a positive $0.23 per Mcf effect) from settlement of cash flow hedges.

Realized oil prices averaged $114.87 per barrel during the third quarter of 2008, compared to $71.63 per barrel for the same period in 2007. The increase in oil sales resulting from this 60% improvement in oil prices totaled $89.9 million. For the nine months ended September 30, 2008, realized oil prices increased 75% to $110.26 per barrel, from $62.99 per barrel, in the first nine months of 2007. This oil price increase boosted sales $292.9 million.

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007
Gas Gathering, Processing, Marketing and Other (in thousands):
Gas gathering, processing and other revenues	$	23,245	$	14,773	$	71,226	$	42,425
Gas gathering and processing costs	(11,882)		(6,859)		(34,284)		(21,995)
Gas gathering, processing and other margin	$	11,363	$	7,914	$	36,942	$	20,430

Gas marketing revenues, net of related costs	$	863	$	1,222	$	3,230	$	3,308

We sometimes transport, process and market third-party gas that is associated with our gas. In the third quarter of 2008, third-party gas gathering, processing and other contributed $11.4 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $7.9 million in 2007. For the nine months ended September 30, 2008 and 2007, such revenues less direct cash expenses totaled $36.9 million and $20.4 million, respectively. Our gas marketing margin (revenues less purchases) decreased to $0.9 million in the third quarter of 2008 from $1.2 million in the third quarter of 2007. Gas marketing margin decreased to $3.2 million from $3.3 million for the first nine 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 Nine Months				Variance
	Ended September 30,				Between		Ended September 30,				Between
	2008		2007		2008/2007		2008		2007		2008/2007
Operating costs and expenses (in thousands):
Impairment of oil and gas properties	$	657,146	$	—	$	657,146	$	657,146	$	—	$	657,146
Depreciation, depletion and amortization	147,432		117,634		29,798		406,189		339,315		66,874
Asset retirement obligation	1,978		2,124		(146)		5,434		7,114		(1,680		)
Production	55,362		55,945		(583)		156,506		151,866		4,640
Transportation	10,621		6,882		3,739		29,551		19,110		10,441
Taxes other than income	39,097		22,397		16,700		109,453		66,826		42,627
General and administrative	12,377		10,922		1,455		37,837		35,531		2,306
Stock compensation	2,791		2,800		(9)		7,432		8,068		(636		)
Other operating net	11,871		3,867		8,004		12,992		6,182		6,810
	$	938,675	$	222,571	$	716,104	$	1,422,540	$	634,012	$	788,528

Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased to $938.7 million in the third quarter of 2008 compared to $222.6 million in the third quarter of 2007. For the first nine months of 2008 and 2007, these operating costs and expenses equaled $1.4 billion and $634.0 million, respectively.

The largest component of the increase between periods is the non-cash impairment of oil and gas properties in the amount of $657.1 million ($417.4 million, net of tax) that was recorded as a result of declines in natural gas and oil prices on September 30, 2008. Quarter end gas prices fell sharply to an average of approximately $4.50 per Mcf in the Permian and Mid-Continent where we produce over 80% of our gas. Due to the volatility of oil and gas prices and because the ceiling calculation requires that prices in effect as of the last day of the period be held constant in valuing proved reserves, we may be required to record a ceiling test write-down in future periods. The full cost method of accounting is discussed in detail under “Critical Accounting Policies and Estimates”.

DD&A equaled $147.4 million in the third quarter of 2008 compared to $117.6 million in the same period of 2007. On a unit of production basis, third quarter DD&A was $3.30 per Mcfe in 2008 compared to $2.85 per Mcfe for 2007. For the first nine months of 2008 and 2007, DD&A totaled $406.2 million and $339.3 million, respectively. On a unit of production basis, DD&A was $3.07 per Mcfe for the first nine months in 2008 compared to $2.80 per Mcfe for 2007. The increase stems primarily from the replacement costs for reserves added being higher than costs of reserves produced as service costs to drill and complete wells have been increasing and we are drilling deeper and more complex wells. Also, the significant decrease in oil and gas prices at September 30, 2008 reduced the amount of estimated reserve quantities (future production), causing an increase in our depletion rate. Due to the reduction to the carrying value of oil and gas properties recorded at the end of the current quarter, we expect the DD&A rate to be lower in the fourth quarter of the current year in comparison to the third quarter of 2008.

Production costs decreased $0.5 million from $55.9 million ($1.36 per Mcfe) in the third quarter of 2007 to $55.4 million ($1.24 per Mcfe) in the third 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. This decrease was mostly offset by an increase in workover expense in the current quarter. Production costs rose $4.6 million from $151.9 million ($1.25 per Mcfe) in the first nine months of 2007 to $156.5 million ($1.18 per Mcfe) in the first nine months of 2008. The increase between the two nine month periods is primarily due to higher direct labor and overhead 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.

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Transportation costs increased from $6.9 million in the third quarter of 2007 to $10.6 million in the third quarter of 2008. Transportation costs for the first nine months of 2008 equaled $29.6 million compared to $19.1 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 $1.5 million from $10.9 million in the third quarter of 2007 to $12.4 million in the third quarter of 2008. G&A expense for the first nine months of 2008 equaled $37.8 million compared to $35.5 million for the same period of 2007. The increase between periods is primarily due to higher employee-benefit costs.

Other Operating, net increased from $3.9 million of expense for the third quarter of 2007 to $11.9 million during the same period of 2008. For the first nine months of 2008, Other Operating, net increased by $6.8 million from $6.2 million in 2007 to $13.0 million of expense in 2008. The increase between periods results primarily from settlements and an increase in accruals derived from the periodic assessment of the probability of estimable amounts as required by Financial Accounting Standard No. 5 (Accounting for Contingencies) pertaining to various litigation related matters arising in the normal course of business. Though some claims may be significant, we believe, individually or in the aggregate, the claims would not have a material adverse effect on our financial condition or results of operations.

Other income and expense

Interest expense was $4.7 million lower in the first nine months of the year, decreasing from $28.7 million in 2007 to $24.0 million in 2008. Interest expense for the third quarter decreased from $9.3 million in 2007 to $7.8 million in 2008. This change resulted primarily from a $3.9 million decrease in interest expense on bank debt as we had no borrowings on our credit facility during the first nine months 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 $5.3 million of income in the third quarter of 2007 to $8.1 million of income in the second quarter of 2008. Other, net for the nine months ended September 30, 2008 and 2007 equaled $16.6 million and $12.2 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 consisted of a $1.4 million increase in interest income and a $8.3 million increase in gain on sale of inventory and other assets. These increases were partially offset by a $4.2 million decrease in income from equity investees and $1.1 million less in other miscellaneous income items.

Income tax expense

During the third quarter of 2008 a net deferred income tax benefit of $135.7 million was recognized (the third quarter deferred tax benefit included $27.1 million of income tax expense) This compares with the third quarter 2007 deferred income tax expense of $42.4 million. The combined Federal and state effective income tax rates were 36.9% and 36.7% in the third quarters of 2008 and 2007, respectively. Income tax expense for the first nine months of 2008 equaled $74.3 million (the income tax expense for the first nine months of 2008 included a deferred income tax benefit of $38.3 million). For the first nine months of 2007 income tax expense equaled $125.5 million which was deferred. The combined Federal and state effective income tax rates were 33.6% and 36.7% for the first nine months of 2008 and 2007, respectively. The effective tax rate of 33.6% for the first nine months of 2008 differs from the statutory rate due to effects of the domestic production activities deduction and percentage depletion.

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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 nine months of 2008 was $1.1 billion, compared to $693.2 million for the nine months ended September 30, 2007. The increase in the first nine months of 2008 resulted primarily from higher gas prices, higher oil prices and increased production.

Cash flow used in investing activities for the first nine months of 2008 was $1.1 billion, compared to $738.3 million for the nine months ended September 30, 2007. Changes in the cash flow used in investing activities are generally the result of changes in our exploration and development programs, acquisitions and property sales. The increase from first nine 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 nine months of 2008 was $2.1 million used versus $40.1 million provided in the same period of 2007. In 2008, $15.0 million of cash flow was used for the payment of dividends which were mostly offset by proceeds of $13.0 million from the issuance of common stock. 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 Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Acquisitions:
Proved	$	120	$	17,531	$	1,489	$	17,554
Unproved	—		23,580		—		23,580
	120		41,111		1,489		41,134
Exploration and development:
Land and seismic	52,485		28,086		109,611		72,858
Exploration and development	366,456		206,102		976,183		643,709
	418,941		234,188		1,085,794		716,567

Property sales	—		(1,825)		—		(22,705)
	$	419,061	$	273,474	$	1,087,283	$	734,996

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Our exploration and development expenditures increased 52 percent in the first nine months of 2008 compared to the first nine months 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 376 gross (232 net) wells during the first nine months of 2008 versus 345 gross (199 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 $0.2 billion in the first nine months of 2008 from $5.4 billion at the beginning of the year to reach $5.6 billion by third quarter end. This change was primarily due to a $109.8 million increase in our current assets (increase in our cash and cash equivalents and our pipe inventory) and $43.8 million increase in our net oil and gas assets. As of September 30, 2008, stockholders’ equity totaled $3.4 billion, up from $3.3 billion at December 31, 2007. The increase resulted primarily from current year net income of $147.0 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 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 nine months of 2008.

Working Capital

Working capital increased $7.2 million from year-end 2007 to $147.2 million at third quarter-end 2008. Working capital increased primarily because of the following:

· Cash and cash equivalents increased by $78.3 million due to higher production volumes and higher prices.

· Inventories increased by $83.3 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:

· Accrued liabilities increased by $63.9 million due to increased drilling activity and revenue payable increased by $28.6 million due to increased production and prices.

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· Other current assets decreased by $57.8 million, due primarily to our Riley Ridge field development project in Wyoming, which is now anticipated to be completed in 2010.

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

	September 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)	136,587		137,159
Total long-term debt	$	486,587	$	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 September 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.

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%

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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 September 30, 2008 was 2.8%.

In addition to the holders’ right to surrender 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.

Contractual Obligations and Material Commitments

At September 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	28,987		5,556		10,677			9,719			3,035
Drilling commitments(2)	285,950		285,950		—			—			—
Gas processing facility(3)	111,369		54,095		57,274			—			—
Asset retirement obligation	119,400		10,270		—		(4)	—		(4)	—		(4)
Other liabilities(5)	51,417		8,830		17,646			17,646			7,295

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

⁽²⁾ We have drilling commitments of approximately $194.7 million consisting of obligations to complete drilling wells in progress at September 30, 2008. We also have minimum expenditure commitments of $91.2 million to secure the use of drilling rigs. Hurricanes Gustav and Ike occurred during the third quarter of 2008. We are currently evaluating damages to our wells and platforms. It is not presently determinable what our share of the total damages will be after insurance proceeds.

⁽³⁾ At September 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 $173.3 million, of which $111.4 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 benefit obligations and other miscellaneous commitments.

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At September 30, 2008, we had a firm sales contract to deliver approximately 6.2 Bcf of natural gas over the next twelve months. If this gas is not delivered, our financial commitment would be approximately $26.1 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.

We have commitments to deliver 63,209 Mmcf of gas over the next six years. If no gas was delivered, the maximum amount that would be payable under these commitments would be approximately $47.8 million.

We have various other gas delivery commitments in the normal course of business that have a maximum amount that would be payable, if no gas is delivered, of approximately $6.6 million.

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 be approximately $1.4 billion. Though there are a variety of factors that could curtail, delay or even cancel 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 44% of the expenditures will be in the Mid-Continent area, 38% in the Permian Basin, 13% in the Gulf Coast area, and 5% in our other areas.

Production estimates for 2008 range from 484 to 487 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 are 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	2.75		-	2.95
General and Administrative	0.28		-	0.32
Production taxes (% of oil and gas revenue)	6.50	%	-	7.50	%

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operation are based upon Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following to be our most critical

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accounting policies and estimates that involve significant judgments and discuss the selection and development of these policies and estimates with our Audit Committee.

Oil and Gas Reserves

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. Estimations of proved undeveloped reserves can be subject to an even greater possibility of revision. Our reserve engineers review and revise our reserve estimates annually. Additionally, we annually engage an independent petroleum engineering firm to review our proved reserve estimates associated with at least 80% of the discounted future net cash flows before income taxes.

We use the units-of-production method to amortize our oil and gas properties. For depletion purposes, reserve quantities are adjusted at interim quarterly periods for the estimated impact of additions, dispositions and price changes. Changes in reserve quantities cause corresponding changes in depletion expense in periods subsequent to the quantity revision. Due to the reduction to the carrying value of oil and gas properties recorded at the quarter ended September 30, 2008, we expect the depletion rate to be lower in the fourth quarter of the current year in comparison to the third quarter of 2008.

Full Cost Accounting

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized in earnings unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to our full cost pool.

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 are determined based on current oil and gas prices and are adjusted for designated cash flow hedges. Changes in proved reserve estimates (whether based upon quantity revisions or oil and gas prices) will cause corresponding changes to the amount of 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, these higher commodity prices will be used to determine if the capital costs are in fact impaired as of the end of the period.

At quarter ended September 30, 2008, we recorded a ceiling test impairment of $657.1 million ($417.4 million, net of tax) as a result of declines in natural gas and oil prices on September 30, 2008. This

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impairment of oil and gas properties is not reversible at a later date, even if oil and gas prices increase. Should commodity prices continue to decrease, the possibility of ceiling impairment at a future date exists.

Goodwill

We assess goodwill for impairment at least annually, and more often if volatility in oil and gas prices or other circumstances warrant. The impairment assessment requires us to make estimates regarding the fair value of goodwill. The estimated fair value is based on numerous factors, including future net cash flows of our estimates of proved reserves as well as the fair value of our nonproducing leases and other assets and liabilities. If our carrying amount for goodwill exceeds its estimated fair value, then a measurement of the loss must be performed and any deficiency is recorded as an impairment. To date, no related impairment has been recorded but we cannot predict when or if goodwill may be impaired in the future. Impairment charges may occur if we are unable to replace the value of our depleting asset base or if other adverse events (for example, materially lower oil and gas prices) reduce the fair value of our company.

Derivatives

We determine the fair value of derivative contracts based on the stated contract prices and current and projected market prices at the determination date discounted to reflect the time value of money until settlement. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. For derivatives designated as cash flow hedges, changes in the fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is settled. Changes in the fair value of the hedge resulting from ineffectiveness are recognized currently as unrealized gains or losses in other income and expense in the consolidated statements of operations. Gains and losses upon settlement of the cash flow hedges will be recognized in gas revenues in the period the contracts are settled. Depending on changes in oil and gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record probable losses for these items based on information available to us using the principles of Financial Accounting Standard No. 5 (Accounting for Contingencies). 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.

Asset Retirement Obligation

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.

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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.

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 non forfeitable 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.

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. In September 2008 the FASB agreed that the effective date for the proposal would be no sooner than for fiscal years ending after December 15, 2009, a year later than the originally proposed effective date. The FASB is to develop an alternative model for loss-contingency disclosures, to address constituent concerns about the originally proposed disclosure requirements, and then conduct field tests. A public roundtable is expected to be held in early 2009, after which the FASB will reconsider the proposal.

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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	Oct 08 - Dec 08	$7.00	-	$	9.80		$	3,576
Natural Gas	Collar	10,000 MMBTU	Oct 08 - Dec 08	$7.00	-	$	10.10		1,791
Natural Gas	Collar	10,000 MMBTU	Oct 08 - Dec 08	$7.00	-	$	9.90		1,789
									$	7,156

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 September 30, 2008, weighted average Mid-Continent index prices for the 2008 contracts approximated $5.03. These contracts are not expected to have a material effect on our realized gas prices for 2008. Through the first nine months of 2008 we have paid a net $72 thousand in hedge settlements. See Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.

Interest Rate Risk

At September 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 September 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 $5.1 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 $0.3 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 September 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 September 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 September 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 6 – EXHIBITS

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

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

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

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

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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.

November 4, 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)