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 March 31, 2012

Commission File No. 001-31446

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(303) 295-3995

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o.

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

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 o No x.

The number of shares of Cimarex Energy Co. common stock outstanding as of March 31, 2012 was 85,718,280.

Table of Contents

CIMAREX ENERGY CO.

Table of Contents

		Page
PART I

Item 1 — Financial Statements

Condensed consolidated balance sheets (unaudited) as of March 31, 2012 and December 31, 2011		4

Consolidated comprehensive statements of operations (unaudited) for the three months ended March 31, 2012 and 2011		5

Condensed consolidated statements of cash flows (unaudited) for the three months ended March 31, 2012 and 2011		6

Notes to consolidated financial statements (unaudited)		7

Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3 — Qualitative and Quantitative Disclosures About Market Risk		35

Item 4 — Controls and Procedures		36

PART II

Item 6 — Exhibits		38

Signatures		39

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GLOSSARY

Bbl/d—Barrels (of oil or natural gas liquids) per day

Bbls—Barrels (of oil or natural gas liquids)

Bcf—Billion cubic feet

Bcfe—Billion cubic feet equivalent

Btu—British thermal unit

MBbls—Thousand barrels

Mcf—Thousand cubic feet (of natural gas)

Mcfe—Thousand cubic feet equivalent

MMBbls—Million barrels

MMBtu—Million British Thermal Units

MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

Net Acres—Gross acreage multiplied by Cimarex’s working interest percentage

Net Production—Gross production multiplied by Cimarex’s net revenue interest

NGL—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

WTI—West Texas Intermediate

One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

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.

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PART I

ITEM 1 - Financial Statements

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

	March 31,
	2012			December 31,
	(Unaudited)			2011
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	4,406		$	2,406
Receivables, net	361,553			359,409
Oil and gas well equipment and supplies	84,808			85,141
Deferred income taxes	5,876			2,723
Other current assets	8,480			8,216
Total current assets	465,123			457,895
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	10,302,527			9,933,517
Unproved properties and properties under development, not being amortized	642,506			607,219
	10,945,033			10,540,736
Less — accumulated depreciation, depletion and amortization	(6,525,077		)	(6,414,528		)
Net oil and gas properties	4,419,956			4,126,208
Fixed assets, net	123,534			118,215
Goodwill	691,432			691,432
Other assets, net	36,404			34,827
	$	5,736,449		$	5,428,577
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	61,462		$	79,788
Accrued liabilities	364,804			385,651
Derivative instruments	4,333			245
Revenue payable	157,159			150,655
Total current liabilities	587,758			616,339
Long-term debt	572,000			405,000
Deferred income taxes	1,041,257			974,932
Other liabilities	304,972			301,693
Total liabilities	2,505,987			2,297,964
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, 85,718,280 and 85,774,084 shares issued, respectively	857			858
Paid-in capital	1,912,125			1,908,506
Retained earnings	1,317,095			1,221,263
Accumulated other comprehensive income (loss)	385			(14		)
	3,230,462			3,130,613
	$	5,736,449		$	5,428,577

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Consolidated Comprehensive Statements of Operations

(Unaudited)

	For the Three Months
	Ended March 31,
	2012			2011
	(In thousands, except per share data)
Revenues:
Gas sales	$	85,153		$	131,323
Oil sales	267,084			220,499
NGL sales	59,014			62,190
Gas gathering, processing and other	11,707			12,517
Gas marketing, net	78			67
	423,036			426,596
Costs and expenses:
Depreciation, depletion and amortization	118,262			85,026
Asset retirement obligation	3,525			1,938
Production	67,625			58,480
Transportation	15,606			13,446
Gas gathering and processing	2,561			4,551
Taxes other than income	25,160			33,597
General and administrative	14,147			14,727
Stock compensation, net	4,534			4,750
Loss on derivative instruments, net	4,088			18,244
Other operating, net	2,340			3,374
	257,848			238,133

Operating income	165,188			188,463

Other (income) and expense:
Interest expense	8,668			8,980
Capitalized interest	(7,804		)	(7,225		)
Other, net	(4,726		)	(604		)

Income before income tax	169,050			187,312
Income tax expense	62,943			69,150

Net income	$	106,107		$	118,162

Earnings per share to common stockholders:
Basic
Distributed	$	0.12		$	0.10
Undistributed	1.12			1.28
	$	1.24		$	1.38

Diluted
Distributed	$	0.12		$	0.10
Undistributed	1.11			1.27
	$	1.23		$	1.37

Comprehensive income:
Net income	$	106,107		$	118,162
Other comprehensive income:
Change in fair value of investments, net of tax	399			159
Total comprehensive income	$	106,506		$	118,321

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Three Months
	Ended March 31,
	2012			2011
	(In thousands)
Cash flows from operating activities:
Net income	$	106,107		$	118,162
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	118,262			85,026
Asset retirement obligation	3,525			1,938
Deferred income taxes	62,943			69,698
Stock compensation, net	4,534			4,750
Derivative instruments, net	4,088			20,278
Changes in non-current assets and liabilities	2,239			2,738
Other, net	1,258			2,030
Changes in operating assets and liabilities:
(Increase) decrease in receivables, net	(2,144		)	2,022
(Increase) decrease in other current assets	69			(3,005		)
Decrease in accounts payable and accrued liabilities	(48,989		)	(38,360		)
Net cash provided by operating activities	251,892			265,277
Cash flows from investing activities:
Oil and gas expenditures	(398,103		)	(310,182		)
Sales of oil and gas and other assets	1,322			12,037
Other expenditures	(13,160		)	(24,506		)
Net cash used by investing activities	(409,941		)	(322,651		)
Cash flows from financing activities:
Net increase in bank debt	167,000			—
Dividends paid	(8,576		)	(6,849		)
Issuance of common stock and other	1,625			4,243
Net cash provided by (used in) financing activities	160,049			(2,606		)
Net change in cash and cash equivalents	2,000			(59,980		)
Cash and cash equivalents at beginning of period	2,406			114,126
Cash and cash equivalents at end of period	$	4,406		$	54,146

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

March 31, 2012

(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 2011 Annual Report on Form 10-K.

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. Certain amounts in prior years’ financial statements have been reclassified to conform to the 2012 financial statement presentation. We have evaluated subsequent events through the date of this filing.

Oil and Gas Properties

We use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly analysis of the carrying value of our oil and gas properties for possible impairment. The primary components impacting this analysis are commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. Holding all factors constant, other than commodity prices, a 10% decline in prices at March 31, 2012 would not have resulted in an impairment.

However, if prices decrease significantly, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

Use of 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 assets, purchase price allocation, valuation of deferred tax assets, fair value measurements and commitments and contingencies.

Accounts Receivable, Accounts Payable, and Accrued Liabilities

The components of our receivable accounts, accounts payable, and accrued liabilities are shown below.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

	March 31, 2012		December 31, 2011
	(in thousands)
Receivables, net of allowance
Trade	$	79,331	$	58,519
Oil and gas sales	229,880		245,681
Gas gathering, processing, and marketing	5,503		7,565
Other	46,839		47,644
Receivables, net	$	361,553	$	359,409

Accounts payable
Trade	$	50,229	$	64,856
Gas gathering, processing, and marketing	11,233		14,932
Accounts payable	$	61,462	$	79,788

Accrued liabilities
Exploration and development	$	174,050	$	173,549
Taxes other than income	19,608		33,946
Other	171,146		178,156
Accrued liabilities	$	364,804	$	385,651

Recently Issued Accounting Standards

No significant accounting standards applicable to Cimarex have been issued during the quarter ended March 31, 2012.

The Financial Accounting Standards Board (“FASB”) issued new accounting guidance which eliminates the option to present other comprehensive income and its components in the statement of changes in equity. The new guidance requires comprehensive income to be reported in either a single statement that presents the components of net income, the components of other comprehensive income and total comprehensive income, or in two consecutive statements. We adopted this financial statement presentation requirement effective January 1, 2012 with retrospective application to all prior periods presented.

2. Derivative Instruments/Hedging

We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity prices and the corresponding negative impact on cash flow available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes.

For 2012 and 2013, management has been authorized to hedge up to 50% of our anticipated equivalent oil and gas production. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our current hedging positions.

At March 31, 2012, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges.

Oil Contracts

Weighted Average Price

Fair Value

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

(000’s)

Apr 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

(4,333

)

(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

We have hedged about half of our anticipated oil production for 2012. We do not have any of our gas or NGL production hedged.

Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the 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 floor and ceiling prices.

Our derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms.

The fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk, and the fair value of instruments in a liability position includes a measure of our own nonperformance risk. These credit risks are based on current published credit default swap rates.

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. The following tables present the estimated fair value of our derivatives as of March 31, 2012 and December 31, 2011.

	Balance Sheet Location	Asset		Liability
		(In thousands)
March 31, 2012:

Oil contracts	Current liabilities — Derivative instruments	$	—	$	4,333

	Balance Sheet Location	Asset		Liability
		(In thousands)
December 31, 2011:

Oil contracts	Current liabilities — Derivative instruments	$	—	$	245

Because we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized settlements and unrealized changes in fair value in earnings. Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows.

The following table summarizes the realized and unrealized gains and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying financial statements.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

	Three Months Ended March 31,
	2012			2011
Settlements gains (losses):
Natural gas contracts	$	—		$	2,034
Oil contracts	—			—
Total settlements gains (losses)	—			2,034

Unrealized gains (losses) from change in fair value:
Natural gas contracts	—			(1,756		)
Oil contracts	(4,088		)	(18,522		)
Total net unrealized gains (losses) from change in fair value	(4,088		)	(20,278		)
Gain (loss) on derivative instruments, net	$	(4,088	)	$	(18,244	)

We are exposed to financial risks associated with these contracts from nonperformance by our counterparties. Counterparty risk is also a component of our estimated fair value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our hedge liability positions.

3. Fair Value Measurements

The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability.

The following tables provide fair value measurement information for certain assets and liabilities as of March 31, 2012 and December 31, 2011.

	Carrying Amount			Fair Value
	(In thousands)
March 31, 2012:

Financial Assets (Liabilities):
Bank debt	$	(222,000	)	$	(222,000	)
7.125% Notes due 2017	$	(350,000	)	$	(362,600	)
Derivative instruments — liabilities	$	(4,333	)	$	(4,333	)

	Carrying Amount			Fair Value
	(In thousands)
December 31, 2011:

Financial Assets (Liabilities):
Bank Debt	$	(55,000	)	$	(55,000	)
7.125% Notes due 2017	$	(350,000	)	$	(366,772	)
Derivative instruments — liabilities	$	(245	)	$	(245	)

Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

Debt

The fair value of our bank debt at March 31, 2012 and December 31, 2011 was estimated to approximate the carrying amount because the floating rate interest paid on such debt was set for periods of three months or less.

The fair value for our 7.125% fixed rate notes was based on their last traded value before period end.

Derivative Instruments (Level 2)

The fair value of our derivative instruments was estimated using internal discounted cash flow calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to nonperformance for both our counterparties and our liability positions. Please see Note 2 for further information on the fair value of our derivative instruments.

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 and/or liquid nature of these assets and liabilities. At both March 31, 2012 and December 31, 2011, the aggregate allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $6.4 million.

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.

4. Capital Stock

A summary of our common stock activity for the three months ended March 31, 2012 follows (in thousands):

Issued and outstanding as of December 31, 2011	85,774
Restricted shares issued under compensation plans, net of reacquired stock and cancellations	(98	)
Option exercises, net of cancellations	42
Issued and outstanding as of March 31, 2012	85,718

Dividends

In February 2012, the Board of Directors increased our quarterly dividend to $0.12 per share from $0.10 per share. The dividend is payable on June 1, 2012 to stockholders of record on May 15, 2012. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

5. Stock-based Compensation

Our 2011 Equity Incentive Plan (the “2011 Plan”) was approved by stockholders in May 2011. The 2011 Plan replaces the 2002 Stock Incentive Plan (the “2002 Plan”). No new grants will be made under the 2002 Plan. The 2011 Plan provides for the grant of stock options, restricted stock, restricted stock units, performance stock and performance stock units to officers, other eligible employees and nonemployee directors. A total of 5.3 million shares of common stock may be issued under the 2011 Plan.

The 2011 Plan is modeled after the 2002 Plan, with two major changes: we have reduced the maximum term of any option granted under the 2011 Plan from ten years to seven years, and dividends will be accrued on all shares subject to performance awards and will only be paid at the time of vesting of the award, and then only with respect to shares that are issued upon attainment of the performance goals. Service-based restricted awards will continue to receive dividends on unvested shares.

We have recognized non-cash stock-based compensation cost as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Restricted stock and units	$	6,821		$	6,524
Stock options	793			1,065
	7,614			7,589
Less amounts capitalized to oil and gas properties	(3,080		)	(2,839		)
Compensation expense	$	4,534		$	4,750

Historical amounts may not be representative of future amounts as additional awards may be granted.

Restricted Stock and Units

The following table provides information about restricted stock awards granted during 2012 and 2011. No restricted unit awards were granted during the noted periods.

	Three Months Ended March 31, 2012			Three Months Ended March 31, 2011
	Number of Shares	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Grant-Date Fair Value
Performance-based stock awards	—	$	—	363,758	$	73.01
Service-based stock awards	18,500	$	60.49	14,500	$	104.73
Total restricted stock awards	18,500	$	60.49	378,258	$	74.23

The performance-based awards were issued to certain executive officers and 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. In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. The material terms of performance goals applicable to these awards were approved by stockholders in May 2010. The other restricted shares granted in 2012 and 2011 have service-based vesting schedules of five years.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

A restricted unit represents a right to an unrestricted share of common stock upon satisfaction of defined vesting and holding conditions. Restricted units have a five-year vesting schedule and an additional three-year holding period following vesting, prior to payment in common stock.

Compensation cost for the performance-based stock awards is based on the grant date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for the service-based vesting restricted shares and units is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period.

The following table reflects the non-cash compensation cost related to our restricted stock and units (in thousands):

	Three Months Ended March 31,
	2012			2011
Performance-based stock awards	$	3,589		$	3,991
Service-based stock awards	3,232			2,511
Restricted unit awards	—			22
	6,821			6,524
Less amounts capitalized to oil and gas properties	(2,730		)	(2,190		)
Restricted stock and units compensation expense	$	4,091		$	4,334

Unamortized compensation cost related to unvested restricted shares and units at March 31, 2012 was $56.2 million, which we expect to recognize over a weighted average period of approximately 2 years.

The following table provides information on restricted stock and unit activity as of March 31, 2012 and changes during the year:

	Restricted Stock		Restricted Units
Outstanding as of January 1, 2012	2,019,552		59,470
Vested	(237,000	)	—
Converted to stock	—		(632	)
Granted	18,500		—
Canceled	(19,850	)	—
Outstanding as of March 31, 2012	1,781,202		58,838
Vested included in outstanding	N/A		58,838

Stock Options

Options granted under our 2011 and 2002 plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years. The plans provide that all grants have an exercise price of 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. No options were granted during the first quarters of 2012 and 2011.

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair value 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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.

Non-cash compensation cost related to our stock options is reflected in the following table (in thousands):

	Three Months Ended March 31,
	2012			2011
Stock option awards	$	793		$	1,065
Less amounts capitalized to oil and gas properties	(350		)	(649		)
Stock option compensation expense	$	443		$	416

As of March 31, 2012, there was $4.6 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost pro rata over a weighted-average period of approximately 2 years.

Information about outstanding stock options is summarized below:

	Options		Weighted Average Exercise Price		Weighted Average Remaining Term	Aggregate Intrinsic Value (000’s)
Outstanding as of January 1, 2012	1,113,334		$	37.94
Exercised	(42,075	)	$	50.32
Granted	—		$	—
Forfeited	(6,403	)	$	68.23
Outstanding as of March 31, 2012	1,064,856		$	37.27	3.9 Years	$	41,495
Exercisable as of March 31, 2012	764,514		$	28.10	2.7 Years	$	36,120

The following table provides information regarding the options exercised (dollars in thousands):

	Three Months Ended March 31,
	2012			2011
Number of options exercised	42,075			36,193
Cash received from option exercises	$	2,117		$	1,432
Tax benefit from option exercises included in paid-in-capital	$	—	(1)	$	797
Intrinsic value of options exercised	$	1,261		$	2,185

(1) No tax benefit is recorded until the benefit reduces current taxes payable.

The following summary reflects the status of non-vested stock options as of March 31, 2012 and changes during the year:

	Options		Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price
Non-vested as of January 1, 2012	308,411		$	23.37	$	60.75
Vested	(1,666	)	$	24.61	$	62.07
Forfeited	(6,403	)	$	27.47	$	68.23
Non-vested as of March 31, 2012	300,342		$	23.28	$	60.59

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

6. 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. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the three months ended March 31, 2012 (in thousands):

Asset retirement obligation at January 1, 2012	$	183,361
Liabilities incurred	1,106
Liability settlements and disposals	(7,119		)
Accretion expense	2,473
Revisions of estimated liabilities	2,639
Asset retirement obligation at March 31, 2012	182,460
Less current obligation	(42,911		)
Long-term asset retirement obligation	$	139,549

7. Long-Term Debt

Debt at March 31, 2012 and December 31, 2011 consisted of the following (in thousands):

	March 31, 2012		December 31, 2011
Bank debt	$	222,000	$	55,000
7.125% Senior Notes due 2017	350,000		350,000
Total long-term debt	$	572,000	$	405,000

In April, 2012 we issued $750 million of 5.875% senior notes due 2022, with interest payable semiannually in May and November. The notes were sold to the public at par. We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and thereafter.

Net proceeds from the offering approximated $737 million, after deducting underwriting discounts, commissions and estimated expenses of the offering. We will use a portion of the net proceeds to retire our 7.125% senior notes. The remaining net proceeds will be used for general corporate purposes, including repayment of amounts outstanding under our revolving credit facility.

Bank Debt

We have a five-year senior unsecured revolving credit facility (“Credit Facility”). The Credit Facility provides for a borrowing base of $2 billion with aggregate commitments of $800 million from 14 lenders. The facility matures July 14, 2016.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

The borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. Our borrowing base of $2 billion was reaffirmed by the lenders in April, 2012. The next regular annual redetermination date is on April 15, 2013.

At Cimarex’s option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio.

The Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to: incur additional indebtedness, pay dividends, repurchase our common stock, or sell assets. As of March 31, 2012, we were in compliance with all of the financial and nonfinancial covenants.

As of March 31, 2012, there were $222 million of borrowings outstanding under the Credit Facility at a prime rate of 4%. We also had letters of credit outstanding of $2.5 million leaving an unused borrowing availability of $575.5 million.

7.125% Notes due 2017

In May, 2007, we issued $350 million of 7.125% senior unsecured notes that mature May 1, 2017 at par. Interest on the notes is payable May 1 and November 1 of each year. The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. The notes are redeemable at our option, in whole or in part, at any time on and after May 1, 2012 at 103.563% of the principal amount as of May 1, 2012, declining to 100% on May 1, 2015 and thereafter.

On March 22, 2012 we commenced a cash tender offer (the “Tender Offer”) to purchase all of the outstanding 7.125% senior notes. Under the terms of the Tender Offer, holders who tendered their notes prior to the deadline on April 4, 2012 would receive (i) $1,035.63 per $1,000.00 in principal amount of notes tendered plus (ii) a consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. Holders tendering their notes after April 4, 2012 but prior to expiration of the Tender Offer on April 18, 2012 would not be eligible for the consent payment. Through April 18, 2012 a total of $300,163,000 of notes had been redeemed. We intend to call for redemption, in May 2012, the remaining $49,837,000 of notes that were not tendered.

In connection with the Tender Offer, holders who tendered their notes were deemed to consent to proposed amendments to eliminate or modify certain covenants and events of default and other provisions contained in the indenture governing the 7.125% senior notes.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

8. Income Taxes

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

	Three Months Ended March 31,
	2012		2011
Current provision (benefit)	$	—	$	(548	)
Deferred tax expense	62,943		69,698
	$	62,943	$	69,150

At December 31, 2011 the company had a U.S. net tax operating carryforward of approximately $107 million which would expire in 2031. We believe that the carryforward will be utilized before it expires. We also had an alternative minimum tax credit carryfoward of approximately $2.9 million.

At March 31, 2012 we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2005-2011 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 2005-2011 for examination.

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and nondeductible expenses. The effective income tax rate for the three months ended March 31, 2012 and March 31, 2011 was 37.2% and 36.9%, respectively.

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

	Three Months Ended March 31,
	2012		2011
Cash paid during the period for:
Interest expense (including capitalized amounts)	$	1,759	$	1,062
Interest capitalized	1,584		854
Income taxes	11		171
Cash received for income taxes	816		25,004

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

10. Earnings per Share

The calculations of basic and diluted net earnings per common share under the two-class method are presented below (in thousands, except per share data):

	Three Months Ended March 31,
	2012			2011
Net income	$	106,107		$	118,162
Less distributed earnings (dividends declared during the period)	(10,296		)	(8,561		)
Undistributed earnings for the period	$	95,811		$	109,601

Allocation of undistributed earnings
Basic allocation to unrestricted common stockholders	$	93,756		$	106,938
Basic allocation to participating securities	$	2,055		$	2,663
Diluted allocation to unrestricted common stockholders	$	93,765		$	106,952
Diluted allocation to participating securities	$	2,046		$	2,649

Basic Shares Outstanding
Unrestricted outstanding common shares	83,937			83,546
Add participating securities:
Restricted stock outstanding	1,781			1,994
Restricted stock units outstanding	59			86
Total participating securities	1,840			2,080
Total Basic Shares Outstanding	85,777			85,626

Fully Diluted Shares
Unrestricted outstanding common shares	83,937			83,546
Incremental shares from assumed exercise of stock options	370			438
Fully diluted common stock	84,307			83,984
Participating securities	1,840			2,080
Total Fully Diluted Shares	86,147			86,064

Basic earnings per share
Unrestricted common stockholders:
Distributed earnings	$	0.12		$	0.10
Undistributed earnings	1.12			1.28
	$	1.24		$	1.38
Participating securities:
Distributed earnings	$	0.12		$	0.10
Undistributed earnings	1.12			1.28
	$	1.24		$	1.38
Fully diluted earnings per share
Unrestricted common stockholders:
Distributed earnings	$	0.12		$	0.10
Undistributed earnings	1.11			1.27
	$	1.23		$	1.37
Participating securities:
Distributed earnings	$	0.12		$	0.10
Undistributed earnings	1.11			1.27
	$	1.23		$	1.37

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

	March 31,
	2012	2011
Stock options	1,064,856	982,499
Restricted stock	1,781,202	1,993,781
Restricted units	58,838	86,470

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

Certain stock options considered to be anti-dilutive for the three months ended March 31, 2012 and 2011 were 167,467 and 9,228, respectively.

11. Commitments and Contingencies

Litigation

H.B. Krug, et al versus H&P

In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus Helmerich & Payne, Inc. (“H&P”) case. This lawsuit was originally filed in 1998 and addressed H&P’s conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P’s exploration and production business. In 2008 we recorded litigation expense of $119.6 million for this lawsuit. We have accrued additional expense for associated post-judgment interest and costs that have accrued during the appeal of the District Court’s judgments.

On August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On October 27, 2011, Cimarex filed a petition with the Oklahoma Supreme Court requesting review of the affirmed portion of the judgment. This case is subject to further appeal and the final outcome cannot be determined at this time. If the District Court’s original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then determined amount of post-judgment interest and costs would become payable.

The following table reflects the change in the accrued liability for this lawsuit for the three months ended March 31, 2012 (in thousands):

Outstanding at January 1, 2012	$	146,310
Accrued post-judgment interest and costs	2,256
Outstanding at March 31, 2012	$	148,566

Other litigation

In the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.

Other

We have drilling commitments of approximately $268.6 million consisting of obligations to finish drilling and completing wells in progress at March 31, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are $34.4 million to secure the use of drilling rigs and $21.5 million to secure certain dedicated services associated with completion activities.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2012

(Unaudited)

We have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At March 31, 2012, we had commitments of $9.9 million relating to this construction.

At March 31, 2012, we had firm sales contracts to deliver approximately 22.1 Bcf of natural gas over the next 12 months. If this gas is not delivered, our financial commitment would be approximately $52.3 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 current reserves and production levels.

We have other various transportation and delivery commitments in the normal course of business, which approximate $8.3 million.

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

12. Property Sales and Acquisitions

There were no significant property sales during the first quarter of 2012. During the first quarter of 2011, we sold various interests in oil and gas properties for approximately $11.8 million. We had no significant property acquisitions during the first quarters of 2012 and 2011.

We intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our Cana-Woodford shale play and in the Permian Basin.

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

OVERVIEW

We are an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in Oklahoma, New Mexico, Texas and Kansas.

Our principle business objective is to achieve profitable growth in proved reserves and production for the long-term benefit of our shareholders, primarily through exploration and development. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development drilling.

To supplement our growth and to provide for new drilling opportunities, we also consider property acquisitions and mergers that allow us to enhance our competitive position in existing core areas or to add new areas. In order to achieve a consistent rate of growth and mitigate risk we have historically maintained 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. We intend to deal with volatility in the current commodity price environment by maintaining flexibility in our planned capital investment program for 2012.

Our operations are currently focused in two main areas: the Mid-Continent region and the Permian Basin. The Mid-Continent region consists of Oklahoma, northern Texas and southwest Kansas. Our Permian Basin region encompasses west Texas and southeast New Mexico. We also have operations in the Gulf Coast area, primarily in southeast Texas.

Our growth is generally funded with cash flow provided by our operating activities together with occasional sales of non-strategic assets. Conservative use of leverage has long been a part of our financial strategy.

Our revenue, profitability and future growth are highly dependent on the commodity prices we receive. Oil and gas prices affect the amount of cash flow available for capital expenditures, our ability to raise additional capital and the fair market value of our assets. We use the full cost method of accounting for oil and gas activities. Any extended decline in oil and gas prices could have an adverse effect on our financial position and results of operations, including the determination of full-cost accounting ceiling test writedowns.

The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities, equity and proved reserves.

First quarter 2012 summary operating and financial results:

· First quarter production volumes averaged 603.5 MMcfe per day, up 2% from 590.0 MMcfe per day for first quarter 2011.

· Oil, gas and NGL sales for the first quarter of 2012 were $411.3 million, compared to $414.0 million a year earlier.

· Our average realized oil price increased 9% to $99.28 per barrel compared to $91.46 per barrel in 2011.

· Our average realized gas price decreased 34% to $2.92 per Mcf versus $4.45 per Mcf in 2011.

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· Our average realized NGL price decreased 10% to $36.66 per barrel compared to $40.77 per barrel in 2011

· Our first quarter cash flow from operating activities was $251.9 million versus $265.3 million in the prior year.

· Net income of $106.1 million ($1.23 per diluted share) declined from net income of $118.2 million ($1.37 per diluted share) in 2011.

· Total debt increased by $167 million to $572 million compared to $405 million at year-end 2011.

· We drilled and completed 73 gross (40 net) wells during the first quarter of 2012 compared to 67 gross (36.7 net) wells with 65 gross (34.7 net) completed as producers a year earlier.

Revenues

Our revenues are derived from the sale of our oil, gas and NGL production and do not include the effects of the settlements of our commodity hedging contracts. While our revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our results of operations. Compared to 2011, our 2012 average realized gas price decreased by 34% and our average realized NGL price decreased by 10%. The average price we received for oil increased by 9%. Since March 31, 2012 gas prices have declined further, primarily as a result of an oversupply. Like gas, NGL prices have also declined. Oil prices continue to fluctuate as a result of concerns about economic and geopolitical instability.

The following table presents our average realized prices for the first quarter of 2012 compared to the same period of 2011.

	Three Months Ended March 31,
	2012		2011
Gas Prices:
Average Henry Hub price ($/Mcf)	$	2.72	$	4.11
Average realized sales price ($/Mcf)	$	2.92	$	4.45
Oil Prices:
Average WTI Cushing price ($/Bbl)	$	102.93	$	94.15
Average realized sales price ($/Bbl)	$	99.28	$	91.46
NGL Prices:
Average realized sales price ($/Bbl)	$	36.66	$	40.77

On an energy equivalent basis, 53% of our first quarter 2012 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a $2.9 million change in our gas revenues. Similarly, 47% of our production was crude oil and NGL. A $1.00 per barrel change in our average realized sales price would have resulted in a $4.3 million change in our combined oil and NGL revenues.

Production and other operating expenses

Costs associated with finding and producing oil and gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production and some are a function of the number of wells we own. At the end of 2011, we owned interests in 12,701 gross wells.

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Production expense generally consists of the cost of water disposal, power and fuel, direct labor, third-party field services, compression and certain maintenance activity (workovers) 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. The economic life of each producing well depends upon the assumed price for future sales of production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Lower prices generally have the effect of decreasing reserves, which increases depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and 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.

Stock compensation expense consists of noncash charges resulting from the issuance of restricted stock, restricted stock units and stock options. In accordance with our stock incentive plan, such grants are periodically made to nonemployee directors, officers and other eligible employees.

The net gain or loss on derivative instruments is the net realized and unrealized gain or loss on derivative contracts, to which we did not apply hedge accounting treatment. That amount will fluctuate based on changes in the fair value of the underlying commodities.

Hedging

From time to time, we attempt to mitigate a portion of our price risk through the use of hedging transactions. Management has been authorized to hedge up to 50% of our anticipated 2012 and 2013 equivalent production.

During 2010, we entered into oil and gas contracts relative to our 2011 production which approximated 40 to 45% of our anticipated 2011 oil production and 5 to 6% of projected gas production. Those contracts had net cash settlements in the first quarter of 2011 of $2.0 million.

For 2012, we have hedged about half of our anticipated oil production. We do not have any of our gas or NGL production hedged. We had no cash settlements on 2012 contracts in the first quarter of 2012. We had the following contracts outstanding at March 31, 2012:

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Oil Contracts

Weighted
Average Price

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

Apr 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our current hedging positions. While the use of such instruments limits the downside risk of adverse price changes, this use may also limit future income from favorable price changes.

We have chosen not to apply hedge accounting treatment to the derivative contracts we entered into. Therefore, settlements on our derivative contracts do not impact our realized commodity prices during the periods they cover. Instead, any settlements on the contracts are shown as a component of operating costs and expenses as either a net gain or loss on derivative instruments. See Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

RESULTS OF OPERATIONS

Quarter ended March 31, 2012 vs. March 31, 2011

Net income for the first quarter of 2012 was $106.1 million, or $1.23 per diluted share. This compares to $118.2 million, or $1.37 per diluted share, for the same period in 2011. In 2012, increased revenue from higher oil sales was more than offset by lower gas and NGL sales and higher DD&A expense. A lower net loss on 2012 derivative instruments compared to 2011 partially offset the increase in DD&A expense. These changes are discussed further in the analysis that follows.

	For the Three Months Ended March 31,				Percent Change Between	Price / Volume Analysis
(In thousands or as indicated)	2012		2011		2012/2011	Price			Volume			Variance
Gas sales	$	85,153	$	131,323	-35%	$	(44,549	)	$	(1,621	)	$	(46,170	)
Oil sales	267,084		220,499		21%	21,036			25,549			46,585
NGL Sales	59,014		62,190		-5%	(6,617		)	3,441			(3,176		)
Total sales	$	411,251	$	414,012	-1%	$	(30,130	)	$	27,369		$	(2,761	)

Total gas volume—MMcf	29,117		29,486		-1%
Gas volume—MMcf per day	320.0		327.6
Average gas price—per Mcf	$	2.92	$	4.45	-34%
Total oil volume—thousand barrels	2,690		2,411		12%
Oil volume—barrels per day	29,562		26,788
Average oil price—per barrel	$	99.28	$	91.46	9%
Total NGL volume—thousand barrels	1,610		1,525		6%
NGL volume—barrels per day	17,687		16,947
Average NGL price—per barrel	$	36.66	$	40.77	-10%

Commodity sales for the first quarter of 2012 totaled $411.3 million, compared to $414.0 million in 2011. Increased oil sales of $46.6 million during 2012 were more than offset by lower realized sales prices for natural gas and NGL.

In 2012, our aggregate production volumes were 603.5 MMcfe per day, up 2% from 590.0 MMcfe per day in 2011. Production volumes continue to increase from our Permian Basin operations and our Cana-Woodford shale play as a result of our successful drilling programs. However, these increases

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have been offset by decreased Gulf Coast production. The lower output from the Gulf Coast results from natural declines in wells we drilled in previous years.

Our 2012 gas production averaged 320.0 MMcf per day, down slightly from 327.6 MMcf per day in 2011. This decrease resulted in $1.6 million of lower gas revenue.

Oil production for 2012 averaged 29,562 barrels per day, compared to 26,788 barrels per day in 2011. The increase in oil production resulted in $25.5 million of additional oil revenue in 2012.

In 2012 our average daily NGL production was 17,687 barrels per day, compared to 16,947 barrels per day for 2011. The increase in NGL volume added $3.4 million of revenue.

Our average realized gas price for 2012 fell to $2.92 per Mcf, compared to $4.45 per Mcf in 2011. The 34% decrease in our realized gas price resulted in $44.5 million of lower gas revenue in 2012.

Realized oil prices in 2012 averaged $99.28 per barrel, an increase of 9% over the average price received for oil in 2011 of $91.46. This increase resulted in an additional $21.0 million of oil sales in 2012.

The average NGL price we received in 2012 was $36.66 per barrel, down from $40.77 per barrel in 2011. The decrease in the NGL price resulted in lower NGL sales of $6.6 million.

	For the Three Months Ended March 31,
	2012			2011
Gas Gathering, Processing, Marketing and Other (in thousands):
Gas gathering, processing and other revenues	$	11,707		$	12,517
Gas gathering and processing costs	(2,561		)	(4,551		)
Gas gathering, processing and other margin	$	9,146		$	7,966

Gas marketing revenues, net of related costs	$	78		$	67

We sometimes transport, process and market third-party gas that is associated with our gas. In the first quarter of 2012, third-party gas gathering, processing and other contributed $9.1 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $8.0 million in 2011. Our gas marketing margin (revenues less purchases) increased to $78 thousand in the first quarter of 2012 from $67 thousand in the first quarter of 2011. Changes in net margins from gas gathering, processing, marketing and other activities are the direct result of volumetric changes and overall market conditions.

	For the Three Months Ended March 31,				Variance Between
	2012		2011		2012/2011
Operating Costs and Expenses (In thousands):
Depreciation, depletion and amortization	$	118,262	$	85,026	$	33,236
Asset retirement obligation	3,525		1,938		1,587
Production	67,625		58,480		9,145
Transportation	15,606		13,446		2,160
Taxes other than income	25,160		33,597		(8,437		)
General and administrative	14,147		14,727		(580		)
Stock compensation, net	4,534		4,750		(216		)
(Gain) loss on derivative instruments, net	4,088		18,244		(14,156		)
Other operating, net	2,340		3,374		(1,034		)
	$	255,287	$	233,582	$	21,705

Total operating costs and expenses (not including gas gathering, marketing, and processing costs or income tax expense) increased $21.7 million to $255.3 million for the first quarter of 2012 compared to

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$233.6 million in the first quarter of 2011. Analyses of the quarter over quarter differences are discussed below.

DD&A increased 39% from $85.0 million in the first quarter of 2011 to $118.3 million in the same period of 2012. On a unit of production basis, DD&A was $2.15 per Mcfe in 2012 compared to $1.60 per Mcfe for 2011. The increase in DD&A is primarily the result of increasing the cost of reserves added at a greater rate than the increase in future production.

Production costs rose 16% from $58.5 million ($1.10 per Mcfe) in the first quarter of 2011 to $67.6 million ($1.23 per Mcfe) in the first quarter of 2012. Our production costs consist of lease operating expense and workover expense as follows (in thousands):

	For the Three Months Ended March 31,				Variance Between
	2012		2011		2012/2011
Lease operating expense	$	56,552	$	49,950	$	6,602
Workover expense	11,073		8,530		2,543
	$	67,625	$	58,480	$	9,145

About 60% of the $6.6 million increase in our lease operating expense relates to higher water disposal costs associated with wells coming on line from our successful Permian Basin and Cana-Woodford shale drilling programs. Increased costs for labor and supplies have also contributed to the increase in 2012. Workover expense for 2012 was $2.5 million higher than 2011 due to more activity being necessary in 2012.

Transportation costs rose to $15.6 million ($0.28 per Mcfe) for 2012 from $13.4 million ($0.25 per Mcfe) in 2011. Transportation costs will fluctuate regionally, based on increases or decreases in sales volumes, compression charges and fluctuation in the price of the fuel cost component.

Taxes other than income decreased 25% from $33.6 million in 2011 to $25.2 million in 2012. Generally, taxes other than income will vary based on increases or decreases in production volumes and changes in commodity prices. In addition, the first quarter of 2012 benefited from certain horizontal drilling and deep well tax credits.

Stock compensation expense, net consists of noncash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards net of amounts capitalized. We have recognized noncash stock-based compensation cost as follows (in thousands):

	For the Three Months Ended March 31,						Variance Between
	2012			2011			2012/2011
Performance-based restricted stock awards	$	3,589		$	3,991		$	(402	)
Service-based restricted stock awards	3,232			2,511			721
Restricted unit awards	—			22			(22		)
Restricted stock and units	6,821			6,524			297
Stock option awards	793			1,065			(272		)
Total stock compensation	7,614			7,589			25
Less amounts capitalized to oil and gas properties	(3,080		)	(2,839		)	(241		)
Stock compensation, net	$	4,534		$	4,750		$	(216	)

Expense associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of awards granted. See Note 5 to the Consolidated Financial Statements for further discussion regarding our stock-based compensation.

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Our net (gain) or loss on derivative instruments includes both realized gains and losses on settlements of our derivative contracts and unrealized gains and losses stemming from changes in the fair value of our outstanding derivative instruments.

We estimate the fair value of these instruments based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. The fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk, and the fair value of instruments in a liability position includes a measure of our own nonperformance risk. These credit risks are based on current published credit default swap rates.

We did not elect to use hedge accounting treatment for derivative contracts outstanding in 2012 and 2011. Therefore we recognized all realized settlements and unrealized changes in fair value in our operating costs and expenses. The following table reflects our net realized and unrealized (gains) and losses on our derivative instruments (in thousands):

	For the Three Months Ended March 31,					Variance Between
	2012		2011			2012/2011
Realized (gain) on settlement of derivative instruments	$	—	$	(2,034	)	$	2,034
Unrealized loss from changes to the fair value of the derivative instruments	4,088		20,278			$	(16,190	)
Loss on derivative instruments, net	$	4,088	$	18,244		$	(14,156	)

Realized and unrealized gains or losses on derivative contracts are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments. See Note 2 to the Consolidated Financial Statements for further details regarding our derivative instruments.

Other operating, net expense consists of costs related to various legal matters most of which pertain to litigation and contract settlements and title and royalty issues.

Other income and expense

Interest expense for the first quarter of 2012 was $8.7 million compared to $9.0 million for the same period of 2011. Our interest expense includes interest on outstanding borrowings, amortization of financing costs and miscellaneous interest expense. Our 7.125% senior notes accounted for 72% and 69% of our 2012 and 2011 interest expense, respectively.

Components of other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well equipment, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income. Other, net increased from $0.6 million of income in the first quarter of 2011 to $4.7 million of income in the first quarter of 2012. The $4.1 million increase was mainly due to sales of oil and gas well equipment and supplies and income from other non-operating activities.

Income tax expense

In the first quarter of 2012 we recognized $62.9 million of income tax expense, which did not include any provision for current taxes. This compares with 2011 first quarter income tax expense of $69.2 million, which included $0.5 million of current tax benefit. The combined Federal and state effective income tax rates was 37.2% for the first quarter of 2012 compared to 36.9% for the first quarter of 2011. Our 2012 provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and nondeductible expenses.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Our liquidity is highly dependent on the commodity prices we receive. Oil and gas prices are market-driven and historically have been very volatile. We cannot predict future commodity prices. The prices we receive for our production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth.

Prices for natural gas have continued to decline since year-end 2011, primarily as a result of an oversupply of natural gas and an exceptionally mild winter. With demand expected to remain low, prices could decline even further. The prices we receive for oil and NGL may fluctuate during 2012, depending on global supply and demand, seasonality and other geopolitical and economic factors.

Historically our exploration and development expenditures have generally been funded by cash flow provided by operating activities (“operating cash flow”). We expect our 2012 E&D capital expenditures to be funded by operating cash flow, long-term debt and property sales. We have hedged a portion of our 2012 oil production to protect our operating cash flow for reinvestment.

From time to time we consider acquisition opportunities. However, the timing and size of acquisitions are unpredictable. To stay prepared for potential acquisitions and possible declines in commodity prices, we have a revolving credit facility, which provides for bank commitments of $800 million. Our credit facility is described in more detail under “Long-Term Debt” below.

At March 31, 2012, our total debt outstanding was $572 million, which is comprised of $222 million of bank debt and $350 million of our 7.125% Notes due in 2017. Our debt to total capitalization ratio at March 31, 2012 was 15%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is: long-term debt of $572 million divided by long-term debt of $572 million plus stockholders’ equity of $3.230 billion. Management believes that this non-GAAP measure is useful information and it is a common statistic referred to by the investment community. Also, see our discussion of “Long-Term Debt” below regarding recent developments related to our debt.

We believe that our operating cash flow and other capital resources will be adequate to continue to meet our needs for our planned capital expenditures, working capital, debt servicing and dividend payments for 2012 and beyond.

Analysis of Cash Flow Changes

Cash flow provided by operating activities for the first quarter of 2012 was $251.9 million, compared to $265.3 million for the same period of 2011. Most of the $13.4 million decrease was a result of utilizing cash flow in the first quarter of 2012 to reduce accounts payable and accrued liabilities.

Cash flow used in investing activities for the first three months of 2012 was $409.9 million, compared to $322.7 million for the three months ended March 31, 2011. In 2012 we had oil and gas and other capital expenditures of $411.2 million, which were partially offset by $1.3 million of asset sales. For 2011, expenditures for oil and gas and other capital costs were $334.7 million with proceeds from asset sales of $12.0 million.

In the first quarter of 2012 we had net cash flow provided by financing activities of $160.0 million versus cash flow used in financing activities of $2.6 million for the same period of 2011. The $162.6 million increase in our 2012 net cash inflow was primarily due to net bank borrowings of $167 million during 2012.

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Reconciliation of Cash Flow from Operations

	For the Three Months Ended March 31,
	2012		2011
	(In thousands)
Net cash provided by operating activities	$	251,892	$	265,277
Change in operating assets and liabilities	51,064		39,343
Cash flow from operations	$	302,956	$	304,620

Management believes that the non-GAAP measure of cash flow from operations is useful information for investors because it is used internally and is accepted by the investment community as a means of measuring the company’s ability to fund its capital program. It is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry.

Capital Expenditures

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

	For the Three Months Ended March 31,
	2012			2011
Acquisitions:
Proved	$	51		$	—
Unproved	1,922			441
	1,973			441
Exploration and development:
Land and seismic	37,212			32,426
Exploration and development	362,499			304,575
	399,711			337,001
Sales proceeds:
Proved	(171		)	(11,354		)
Unproved	(942		)	(494		)
	(1,113		)	(11,848		)
	$	400,571		$	325,594

Capital expenditures in the table above are presented on an accrual basis. Additions to property and equipment in the Condensed Consolidated Statements of Cash Flows reflect capital expenditures on a cash basis, when payments are made.

Our exploration and development expenditures increased $62.7 million (19%) from $337.0 million in the first quarter of 2011 to $399.7 million in the first of quarter 2012. Of our total 2012 expenditures, 50% was for projects located in the Permian Basin; 45% in the Mid-Continent area; and 5% in the Gulf Coast and other.

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The following table reflects wells drilled and completed by region:

	For the Three Months Ended March 31,
	2012	2011
Gross wells
Permian Basin	39	26
Mid-Continent	33	37
Gulf Coast / Other	1	2
	73	65
Net wells
Permian Basin	27	20
Mid-Continent	12	13
Gulf Coast / Other	1	2
	40	35

% Gross wells completed as producers	95%	97%

As of March 31, 2012 we had 24 net wells awaiting completion: 18 Mid-Continent and six Permian Basin. We also had 24 operated rigs running; 14 in the Permian Basin and 10 in the Mid-Continent.

Based on current market prices and service costs, our 2012 E&D capital expenditures are presently projected to be in the range of $1.4 — 1.6 billion. We expect nearly all of our 2012 capital to be directed towards oil or liquids-rich gas drilling in the Permian Basin and our Cana-Woodford shale play in the Mid-Continent area. We expect our 2012 E&D capital expenditures to be funded from cash flow, long-term debt and property sales. The timing of capital expenditures and the receipt of cash flows do not necessarily match. Therefore, we may borrow and repay funds under our credit arrangement throughout the year.

As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions.

We had no significant acquisitions or property sales in the first quarter of 2012. In the first quarter of 2011 we sold non-core property interests for $11.8 million. We continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our core areas of operation.

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

Future cash flows and the availability of financing will be subject to a number of variables, such as our success in locating and producing new reserves, the level of production from existing wells and realized commodity prices. To meet our capital and liquidity requirements, we rely on certain resources, including cash flows from operating activities, bank borrowings, and access to capital markets. We anticipate periodically accessing our credit facility to finance our working capital needs and growth.

During the first quarter of 2012 our total assets increased by $307.9 million to $5.7 billion, up from $5.4 billion at December 31, 2011. The increase was primarily due to a $293.7 million increase in our net oil and gas properties.

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At March 31, 2012, our total liabilities increased to $2.5 billion, up $208.0 million from $2.3 billion at December 31, 2011. The increase is primarily made up of an increase in long-term debt of $167.0 million and an increase of $66.3 million in noncurrent deferred income taxes, offset by a $28.6 million decrease in net current liabilities. The decrease in net current liabilities was a result of net decreases in operations related accounts payable and accrued liabilities.

Stockholders’ equity rose $99.8 million to $3.2 billion at the end of the first quarter of 2012 compared to $3.1 billion at December 31, 2011. The increase is mainly due to our net income of $106.1 million, which was partially offset by dividends of $10.3 million.

Dividends

On February 22, 2012 the Board of Directors increased our regular cash dividend on our common stock from $0.10 to $0.12 per common share. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Working Capital Analysis

Our working capital balance fluctuates primarily as a result of our exploration and development activities, our realized commodity prices and our production operating activities. Working capital is also impacted by our current tax provisions, accrued G&A and changes in the fair value of our outstanding derivative instruments.

In the first quarter of 2012 our working capital increased $35.8 million from a deficit of $158.4 million at year-end 2011 to a deficit of $122.6 million at March 31, 2012.

Working capital increased primarily because of the following:

• Our operations related accounts payable and accrued liabilities decreased by $33.2 million

• Our operations related accounts receivable increased by $2.9 million.

• Cash and cash equivalents increased by $2 million.

These working capital increases were partially offset by the following:

• The net fair value of our derivative instruments liability increased by $4.1 million.

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. Our collection of receivables during the period presented has been timely. Historically, losses associated with uncollectible receivables have not been significant.

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Long-Term Debt

Debt at March 31, 2012 and December 31, 2011 consisted of the following (in thousands):

	March 31, 2012		December 31, 2011
Bank debt	$	222,000	$	55,000
7.125% Senior Notes due 2017	350,000		350,000
Total long-term debt	$	572,000	$	405,000

Bank Debt

During the first quarter of 2012 we had an average daily bank debt outstanding of $164.4 million, compared to $44.4 thousand for the same period of 2011. Our largest amount of bank borrowings outstanding during the first quarter of 2012 was $275 million, occurring in mid-March. During the first quarter of 2011 our largest amount of outstanding borrowings was $2 million in late March.

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7.125% Notes due 2017

Off Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of March 31, 2012, the material off —balance sheet arrangements that we have entered into included operating lease agreements, all of which are customary in the oil and gas industry.

Contractual Obligations and Material Commitments

At March 31, 2012, we had contractual obligations and material commitments as follows:

	Payments Due by Period
	Total		Less than 1 Year		1-3 Years			4-5 Years			More than 5 Years
	(In thousands)
Contractual obligations:

Long-term debt(1)	$	572,000	$	—	$	—		$	222,000		$	350,000
Fixed-Rate interest payments(1)	137,156		24,938		49,875			49,875			12,468
Operating leases	75,161		6,646		15,061			11,863			41,591
Drilling commitments(2)	324,496		324,496		—			—			—
Gas facilities and pipelines(3)	9,850		9,850		—			—			—
Asset retirement obligation	182,460		42,911		—		(4)	—		(4)	—		(4)
Derivative instruments	4,333		4,333		—			—			—
Other liabilities(5)	51,619		12,643		24,035			18			14,923
Firm transportation	2,204		1,873		215			116			—

(1) These amounts do not include interest on the $222 million of bank debt outstanding at March 31, 2012. These amounts have not been adjusted to reflect the subsequent redemption of our 7.125% notes and issuance of new notes. See item 3: Interest Rate Risk for more information regarding fixed and variable rate debt.

(2) We have drilling commitments of approximately $268.6 million consisting of obligations to complete drilling wells in progress at March 31, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are $34.4 million to secure the use of drilling rigs and $21.5 million to secure certain dedicated services associated with completion activities.

(3) We have projects in Oklahoma, New Mexico and Texas where we are constructing gathering facilities and pipelines. At March 31, 2012, we had commitments of $9.9 million relating to this construction.

(4) We have not included the long term asset retirement obligations because we are not able to precisely 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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We have various other delivery commitments in the normal course of business, which are individually and in the aggregate not material.

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, amounts available under our existing bank credit facility, proceeds from our recent debt offering and occasional sales of non-strategic assets will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration, development and other capital expenditures.

2012 Outlook

Our 2012 exploration and development capital investment is presently expected to be in the range of $1.4-1.6 billion. We have a large inventory of drilling opportunities, limited lease expirations and few service commitments. Actual amounts invested will depend on our calculated rate of return which is significantly influenced by commodity prices.

As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service cost and drilling success. Operationally we have the flexibility to adjust our capital expenditures based upon market conditions.

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.

Production for 2012 is projected to be in the range of 612 to 632 MMcfe per day, or a 3 — 7% growth over 2011. 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 2011, our realized prices averaged $4.42 per Mcf of gas, $93.00 per barrel of oil, and $42.31 per barrel of NGL. For the first three months of 2012 our realized prices averaged $2.92 per Mcf of gas, $99.28 per barrel of oil, and $36.66 per barrel of NGL. Commodity prices can be very volatile and the possibility of full year realized 2012 prices varying from prices received in the first three months of 2012 is high.

Certain expenses for 2012 on a per Mcfe basis are currently estimated as follows:

		2012
Production expense		$1.15 - $1.35
Transportation expense		0.28 - 0.33
DD&A and asset retirement obligation		2.10 - 2.30
General and administrative		0.25 - 0.30
Production taxes (% of oil and gas revenue)		6.5% - 7.0%

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We consider accounting policies related to oil and gas reserves, full cost accounting, goodwill, derivatives, contingencies and asset retirement obligations to be critical policies and estimates. These critical policies and estimates are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K.

Recent Accounting Developments

No significant accounting standards applicable to Cimarex have been issued during the quarter ended March 31, 2012.

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. 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.

We periodically hedge a portion of our price risk associated with our future oil and gas production.

The following table details the contracts we have in place as of March 31, 2012:

Oil Contracts

Weighted Average Price

Fair Value

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

(000’s)

Apr 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

(4,333

)

(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the contracts listed above, a hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2012 of $3.9 million.

In spite of the recent turmoil in the financial markets, counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Second, our derivative contracts are held with “investment grade” counterparties that are a part of our credit facility. See Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.

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Interest Rate Risk

At March 31, 2012, our debt was comprised of the following (in thousands):

	Fixed Rate Debt			Variable Rate Debt
Bank debt	$	—		$	222,000
7.125% Notes due 2017	350,000			—

Total long-term debt	$		350,000	$	222,000

As of March 31, 2012, the amounts outstanding under our five-year senior unsecured revolving credit facility bears interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. Our senior unsecured notes bear interest at a fixed rate of 7.125% and will mature on May 1, 2017. Subsequent to March 31, 2012 these notes will be redeemed with proceeds from the issuance of $750 million of 5.875% notes that will mature May 1, 2022.

We consider our interest rate exposure to be minimal because approximately 61% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the interest rate of our variable rate debt would increase our annual interest expense by $2.2 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 3 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding debt.

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 March 31, 2012 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

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have concluded, as of March 31, 2012, 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 March 31, 2012, 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 Thomas E. Jorden, 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 Thomas E. Jorden, 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.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

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SIGNATURES

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

May 3, 2012

	CIMAREX ENERGY CO.


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


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