Edgar Filing: CIMAREX ENERGY CO

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x Quarterly Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period ended June 30, 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 Noo

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 June 30, 2012 was 85,987,555.

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CIMAREX ENERGY CO.

Table of Contents

		Page

PART I

Item 1 — Financial Statements

	Condensed consolidated balance sheets (unaudited) as of June 30, 2012 and December 31, 2011	4

	Consolidated comprehensive statements of operations (unaudited) for the three and six months ended June 30, 2012 and 2011	5

	Condensed consolidated statements of cash flows (unaudited) for the six months ended June 30, 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		37

Item 4 — Controls and Procedures		39

PART II

Item 6 — Exhibits		40

Signatures		41

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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

	June 30,
	2012			December 31,
	(Unaudited)			2011
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	96,932		$	2,406
Receivables, net	251,575			359,409
Oil and gas well equipment and supplies	91,062			85,141
Deferred income taxes	1,193			2,723
Derivative instruments	5,745			—
Other current assets	7,205			8,216
Total current assets	453,712			457,895
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	10,697,029			9,933,517
Unproved properties and properties under development, not being amortized	647,673			607,219
	11,344,702			10,540,736
Less — accumulated depreciation, depletion and amortization	(6,638,311		)	(6,414,528		)
Net oil and gas properties	4,706,391			4,126,208
Fixed assets, net	133,463			118,215
Goodwill	691,432			691,432
Other assets, net	46,306			34,827
	$	6,031,304		$	5,428,577
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	52,170		$	79,788
Accrued liabilities	424,993			385,651
Derivative instruments	—			245
Revenue payable	133,186			150,655
Total current liabilities	610,349			616,339
Long-term debt	750,000			405,000
Deferred income taxes	1,074,633			974,932
Other liabilities	304,348			301,693
Total liabilities	2,739,330			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, 85,987,555 and 85,774,084 shares issued, respectively	860			858
Paid-in capital	1,919,777			1,908,506
Retained earnings	1,371,087			1,221,263
Accumulated other comprehensive income (loss)	250			(14		)
	3,291,974			3,130,613
	$	6,031,304		$	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						For the Six Months
	Ended June 30,						Ended June 30,
	2012			2011			2012			2011
	(In thousands, except per share data)
Revenues:
Gas sales	$	69,741		$	140,377		$	154,894		$	271,700
Oil sales	229,210			242,812			496,294			463,311
NGL sales	44,286			69,069			103,300			131,259
Gas gathering, processing and other	10,179			14,544			21,886			27,061
Gas marketing, net	(294		)	411			(216		)	478
	353,122			467,213			776,158			893,809
Costs and expenses:
Depreciation, depletion and amortization	121,237			89,847			239,499			174,873
Asset retirement obligation	2,441			2,707			5,966			4,645
Production	62,494			60,745			130,119			119,225
Transportation	15,260			16,387			30,866			29,833
Gas gathering and processing	2,864			4,630			5,425			9,181
Taxes other than income	23,483			34,495			48,643			68,092
General and administrative	12,634			10,617			26,781			25,344
Stock compensation, net	4,684			4,617			9,218			9,367
Gain on derivative instruments, net	(10,078		)	(22,477		)	(5,990		)	(4,233		)
Other operating, net	2,719			2,342			5,059			5,716
	237,738			203,910			495,586			442,043

Operating income	115,384			263,303			280,572			451,766

Other (income) and expense:
Interest expense	13,679			9,340			22,347			18,320
Capitalized interest	(9,119		)	(7,352		)	(16,923		)	(14,577		)
Loss on early extinguishment of debt	16,214			—			16,214			—
Other, net	(7,829		)	(3,018		)	(12,555		)	(3,622		)

Income before income tax	102,439			264,333			271,489			451,645
Income tax expense	38,137			97,584			101,080			166,734
Net income	$	64,302		$	166,749		$	170,409		$	284,911

Earnings per share to common stockholders:
Basic
Distributed	$	0.12		$	0.10		$	0.24		$	0.20
Undistributed	0.63			1.85			1.74			3.13
	$	0.75		$	1.95		$	1.98		$	3.33

Diluted
Distributed	$	0.12		$	0.10		$	0.24		$	0.20
Undistributed	0.62			1.84			1.73			3.11
	$	0.74		$	1.94		$	1.97		$	3.31

Comprehensive income:
Net income	$	64,302		$	166,749		$	170,409		$	284,911
Other comprehensive income:
Change in fair value of investments, net of tax	(135		)	9			264			168
Total comprehensive income	$	64,167		$	166,758		$	170,673		$	285,079

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Six Months
	Ended June 30,
	2012			2011
	(In thousands)

Cash flows from operating activities:
Net income	$	170,409		$	284,911
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	239,499			174,873
Asset retirement obligation	5,966			4,645
Deferred income taxes	101,080			168,056
Stock compensation, net	9,218			9,367
Derivative instruments, net	(5,990		)	(2,163		)
Loss on early extinguishment of debt	16,214			—
Changes in non-current assets and liabilities	5,115			4,559
Other, net	1,955			3,735
Changes in operating assets and liabilities:
Decrease in receivables, net	107,834			17,549
Increase in other current assets	(4,910		)	(9,694		)
Decrease in accounts payable and accrued liabilities	(71,458		)	(16,747		)
Net cash provided by operating activities	574,932			639,091
Cash flows from investing activities:
Oil and gas expenditures	(752,390		)	(699,301		)
Sales of oil and gas and other assets	1,681			20,646
Other expenditures	(32,305		)	(52,889		)
Net cash used by investing activities	(783,014		)	(731,544		)
Cash flows from financing activities:
Net decrease in bank debt	(55,000		)	—
Increase in other long-term debt	750,000			—
Decrease in other long-term debt	(363,595		)	—
Financing costs incurred	(12,692		)	(100		)
Dividends paid	(18,869		)	(15,415		)
Issuance of common stock and other	2,764			6,992
Net cash provided by (used in) financing activities	302,608			(8,523		)
Net change in cash and cash equivalents	94,526			(100,976		)
Cash and cash equivalents at beginning of period	2,406			114,126
Cash and cash equivalents at end of period	$	96,932		$	13,150

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY GO.

Notes to Consolidated Financial Statements

June 30, 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 “ceiling test” calculation to test our oil and gas properties for possible impairment. The primary components impacting this calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs, and depletion expense. If the net capitalized cost of our oil and gas properties subject to amortization (the “carrying value”) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.

At June 30, 2012 the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. However, a decline of 10% or more in the value of the ceiling limitation would have resulted in an impairment.

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)

June 30, 2012

(Unaudited)

	June 30, 2012		December 31, 2011
	(in thousands)
Receivables, net of allowance
Trade	$	61,109	$	58,519
Oil and gas sales	184,893		245,681
Gas gathering, processing, and marketing	5,573		7,565
Other	—		47,644
Receivables, net	$	251,575	$	359,409

Accounts payable
Trade	$	41,849	$	64,856
Gas gathering, processing, and marketing	10,321		14,932
Accounts payable	$	52,170	$	79,788

Accrued liabilities
Exploration and development	$	205,035	$	173,549
Taxes other than income	21,608		33,946
Other	198,350		178,156
Accrued liabilities	$	424,993	$	385,651

Recently Issued Accounting Standards

No significant accounting standards applicable to Cimarex have been issued during the quarter ended June 30, 2012.

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 June 30, 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

(in thousands)

Jul 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

5,745

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

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

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

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 are 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 table presents the estimated fair value of our oil contracts as of June 30, 2012 and December 31, 2011.

		June 30,		December 31,
Asset/Liability	Balance Sheet Location	2012		2011
		(in thousands)
Asset	Current assets — Derivative instruments	$	5,745	$	—
Liability	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.

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	(in thousands)
Settlements gains (losses):
Natural gas contracts	$	—	$	1,693		$	—	$	3.727
Oil contracts	—		(1,657		)	—		(1,657		)
Total settlements gains (losses)	—		36			—		2,070

Unrealized gains (losses) on fair value change:
Natural gas contracts	—		(1,149		)	—		(2,905		)
Oil contracts	10,078		23,590			5,990		5,068
Total unrealized gains (losses) on fair value change	10,078		22,441			5,990		2,163
Gain (loss) on derivative instruments, net	$	10,078	$	22,477		$	5,990	$	4,233

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,

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

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 Financial Accounting Standards Board (“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 June 30, 2012 and December 31, 2011.

June 30, 2012:	Carrying Amount			Fair Value
	(in thousands)
Financial Assets (Liabilities):
5.875% Notes due 2022	$	(750,000	)	$	(781,875	)
Derivative instruments — assets	$	5,745		$	5,745

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

Debt

The fair value of our bank debt at 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 5.875% and 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.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. At both June 30, 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 six months ended June 30, 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		156
Option exercises, net of cancellations		58
Issued and outstanding as of June 30, 2012		85,988

Dividends

In May 2012, the Board of Directors declared a cash dividend of $0.12 per share on our common stock. The dividend is payable on September 4, 2012 to stockholders of record on August 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.

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.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Restricted stock and units	$	6,729		$	6,705		$	13,550		$	13,229
Stock options	632			1,115			1,425			2,180
	7,361			7,820			14,975			15,409
Less amounts capitalized to oil and gas properties	(2,677		)	(3,203		)	(5,757		)	(6,042		)
Compensation expense	$	4,684		$	4,617		$	9,218		$	9,367

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

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

Restricted Stock and Units

In May 2012, 238,770 performance-based stock awards were granted to certain executive officers with an aggregate grant-date fair value of $12.4 million. The following tables provide information about restricted stock awards granted during the three and six months ended June 30, 2012 and 2011.

	Three Months Ended June 30, 2012			Three Months Ended June 30, 2011
	Number of Shares	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Grant-Date Fair Value
Performance-based stock awards	238,770	$	51.95	—	$	—
Service-based stock awards	37,598	$	56.17	52,453	$	109.85
Total restricted stock awards	276,368	$	52.52	52,453	$	109.85

	Six Months Ended June 30, 2012			Six Months Ended June 30, 2011
	Number of Shares	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Grant-Date Fair Value
Performance-based stock awards	238,770	$	51.95	363,758	$	73.01
Service-based stock awards	56,098	$	57.59	66,953	$	108.74
Total restricted stock awards	294,868	$	53.02	430,711	$	78.56

Performance-based awards 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 have service-based vesting schedules of five years.

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):

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Performance-based stock awards	$	4,082		$	4,079		$	7,671		$	8,070
Service-based stock awards	2,647			2,614			5,879			5,125
Restricted unit awards	—			12			—			34
	6,729			6,705			13,550			13,229
Less amounts capitalized to oil and gas properties	(2,439		)	(2,519		)	(5,169		)	(4,709		)
Restricted stock and units compensation expense	$	4,290		$	4,186		$	8,381		$	8,520

Unamortized compensation cost related to unvested restricted shares and units at June 30, 2012 was $63 million, which we expect to recognize over a weighted average period of approximately 1.9 years.

The following table provides information on restricted stock and unit activity as of June 30, 2012 and changes during the year:

	Restricted Stock		Restricted Units
Outstanding as of January 1, 2012	2,019,552		59,470
Vested	(274,309	)	—
Converted to stock	—		(632	)
Granted	294,868		—
Canceled	(37,050	)	—
Outstanding as of June 30, 2012	2,003,061		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 six months ended June 30, 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 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Stock option awards	632			1,115			1,425			2,180
Less amounts capitalized to oil and gas properties	(238		)	(684		)	(588		)	(1,333		)
Stock option compensation expense	$	394		$	431		$	837		$	847

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

As of June 30, 2012, there was $3.9 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 1.9 years.

Information about outstanding stock options is summarized below:

	Options		Weighted Average Exercise Price		Weighted Average Remaining Term	Aggregate Intrinsic Value (in thousands)
Outstanding as of January 1, 2012	1,113,334		$	37.94
Exercised	(58,071	)	$	47.60
Granted	—		$	—
Canceled	(2,650	)	$	56.74
Forfeited	(7,105	)	$	64.23
Outstanding as of June 30, 2012	1,045,508		$	37.17	3.6 Years	$	22,097
Exercisable as of June 30, 2012	817,620		$	28.05	2.8 Years	$	22,014

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

	Six Months Ended June 30,
	2012			2011
Number of options exercised	58,071			52,727
Cash received from option exercises	$	2,764		$	1,994
Tax benefit from option exercises included in paid-in-capital	$	—	(1)	$	1,161
Intrinsic value of options exercised	$	1,605		$	3,181

(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 June 30, 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	(73,418	)	$	12.76	$	32.01
Forfeited	(7,105	)	$	25.85	$	64.23
Non-vested as of June 30, 2012	227,888		$	26.72	$	69.91

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.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2012 (in thousands):

Asset retirement obligation at January 1, 2012	$	183,361
Liabilities incurred	2,235
Liability settlements and disposals	(11,456		)
Accretion expense	4,900
Revisions of estimated liabilities	13,419
Asset retirement obligation at June 30, 2012	192,459
Less current obligation	(56,480		)
Long-term asset retirement obligation	$	135,979

7. Long-Term Debt

Debt at June 30, 2012 and December 31, 2011 consisted of the following (in thousands):

	June 30, 2012		December 31, 2011
Bank debt	$	—	$	55,000
7.125% Senior Notes due 2017	—		350,000
5.875% Senior Notes due 2022	750,000		—
Total long-term debt	$	750,000	$	405,000

Bank Debt

We have a five-year senior unsecured revolving credit facility (“Credit Facility”) which matures July 14, 2016. The Credit Facility provides for a borrowing base of $2 billion. At June 30, 2012 we had aggregate commitments of $800 million from our lenders. Our aggregate commitments were subsequently raised to $1 billion in July 2012.

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.

As of June 30, 2012, we had no bank debt outstanding. We had letters of credit outstanding under the Credit Facility of $2.5 million.

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 June 30, 2012, we were in compliance with all of the financial and nonfinancial covenants.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

5.875% Notes due 2022

In April, 2012 we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May and November. The notes were sold to the public at par. The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. 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 used a portion of the net proceeds to retire our 7.125% senior notes. The remaining net proceeds were used for general corporate purposes, including repayment of $232 million outstanding under our Credit Facility.

7.125% Notes due 2017

In May, 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. 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 on or prior to April 4, 2012 received (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 were not eligible for the consent payment. Through April 18, 2012 a total of $300,163,000 of notes had been redeemed. In May 2012, the remaining notes were redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012.

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.

8. Income Taxes

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

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
Current provision (benefit)	$	—	$	(774	)	$	—	$	(1,322	)
Deferred taxes	38,137		98,358			101,080		168,056
	$	38,137	$	97,584		$	101,080	$	166,734

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 June 30, 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 2008-2011 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.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

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 rates for the six months ended June 30, 2012 and June 30, 2011 were 37.2% and 36.9%, respectively.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Cash paid during the period for:
Interest expense (including capitalized amounts)	$	12,598	$	13,746	$	14,357	$	14,808
Interest capitalized	$	9,288	$	10,929	$	10,872	$	11,783
Income taxes	$	363	$	1,500	$	374	$	1,671
Cash received for income taxes	$	48,420	$	—	$	49,236	$	25,004

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income	$	64,302		$	166,749		$	170,409		$	284,911
Less distributed earnings (dividends declared during the period)	(10,325		)	(8,567		)	(20,620		)	(17,128		)
Undistributed earnings for the period	$	53,977		$	158,182		$	149,789		$	267,783

Allocation of undistributed earnings:
Basic allocation to unrestricted common stockholders	$	52,684		$	154,452		$	146,200		$	261,469
Basic allocation to participating securities	$	1,293		$	3,730		$	3,589		$	6,314
Diluted allocation to unrestricted common stockholders	$	52,689		$	154,471		$	146,214		$	261,501
Diluted allocation to participating securities	$	1,288		$	3,711		$	3,575		$	6,282

Basic Shares Outstanding
Unrestricted outstanding common shares	83,984			83,635			83,984			83,635
Add participating securities:
Restricted stock outstanding	2,003			1,933			2,003			1,933
Restricted stock units outstanding	59			87			59			87
Total participating securities	2,062			2,020			2,062			2,020
Total Basic Shares Outstanding	86,046			85,655			86,046			85,655

Fully Diluted Shares
Unrestricted outstanding common shares	83,984			83,635			83,984			83,635
Incremental shares from assumed exercise of stock options	335			428			353			433
Fully diluted common stock	84,319			84,063			84,337			84,068
Participating securities	2,062			2,020			2,062			2,020
Total Fully Diluted Shares	86,381			86,083			86,399			86,088

Basic earnings per share
Unrestricted common stockholders:
Distributed earnings	$	0.12		$	0.10		$	0.24		$	0.20
Undistributed earnings	0.63			1.85			1.74			3.13
	$	0.75		$	1.95		$	1.98		$	3.33
Participating securities:
Distributed earnings	$	0.12		$	0.10		$	0.24		$	0.20
Undistributed earnings	0.63			1.85			1.74			3.13
	$	0.75		$	1.95		$	1.98		$	3.33
Fully diluted earnings per share
Unrestricted common stockholders:
Distributed earnings	$	0.12		$	0.10		$	0.24		$	0.20
Undistributed earnings	0.62			1.84			1.73			3.11
	$	0.74		$	1.94		$	1.97		$	3.31
Participating securities:
Distributed earnings	$	0.12		$	0.10		$	0.24		$	0.20
Undistributed earnings	0.62			1.84			1.73			3.11
	$	0.74		$	1.94		$	1.97		$	3.31

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

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

	June 30,
	2012	2011
Stock options	1,045,508	963,464
Restricted stock	2,003,061	1,933,202
Restricted units	58,838	86,470

Certain stock options considered to be anti-dilutive for the three months ended June 30, 2012 and 2011 were 249,303 and 2,832, respectively. For the six months ended June 30, 2012 and 2011, certain stock options considered to be anti-dilutive were 259,133 and 12,895, 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 six months ended June 30, 2012 (in thousands):

Outstanding at January 1, 2012	$	146,310
Accrued post-judgment interest and costs	4,512
Outstanding at June 30, 2012	$	150,822

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.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

June 30, 2012

(Unaudited)

Other

We have drilling commitments of approximately $306.6 million consisting of obligations to finish drilling and completing wells in progress at June 30, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are $21.4 million to secure the use of drilling rigs and $14.8 million to secure certain dedicated services associated with completion activities.

We have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At June 30, 2012, we had commitments of $13.9 million relating to this construction.

At June 30, 2012, we had firm sales contracts to deliver approximately 34.1 Bcf of natural gas over the next 22 months. If this gas is not delivered, our financial commitment would be approximately $81.6 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 $7.4 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 half of 2012. Subsequent to June 30, 2012, we sold various interests in oil and gas properties for $11 million. We had property acquisitions of approximately $7 million during the first half of 2012.

During the first half of 2011, we sold various interests in oil and gas properties for approximately $20.3 million and we had property acquisitions of approximately $21.2 million. Of our total acquisitions, $18 million was in our western Oklahoma Cana-Woodford shale play and $3 million was in the Permian basin.

We intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our core areas of operation.

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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 bank borrowings, sales of non-strategic assets and occasional institutional financing. 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.

Second quarter 2012 summary of financial and operating results:

· Second quarter production volumes averaged 590.1 MMcfe per day, compared to 585.7 MMcfe per day for the second quarter of 2011.

· Oil, gas and NGL sales for the second quarter of 2012 were $343.2 million, compared to $452.3 million a year earlier.

· Our average realized oil price decreased 12% to $87.81 per barrel compared to $100.12 per barrel in 2011.

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· Our average realized gas price decreased 49% to $2.42 per Mcf versus $4.75 per Mcf in 2011.

· Our average realized NGL price decreased 36% to $29.02 per barrel compared to $45.06 per barrel in 2011.

· Our second quarter cash flow provided by operating activities was $323.0 million versus $373.8 million in the prior year.

· Net income of $64.3 million ($0.74 per diluted share) declined from net income of $166.7 million ($1.94 per diluted share) in 2011.

· Total debt increased by $345 million to $750 million compared to $405 million at year-end 2011.

· We drilled 87 gross (51 net) wells during the second quarter of 2012, completing 97% as producers. In the second quarter of 2011 we drilled 95 gross (55 net) wells completing 96% as producers.

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 42% and our average realized NGL price decreased by 23%. The average price we have received for oil in 2012 has decreased by 2%. The prices we receive are determined by prevailing market conditions. Regional and worldwide economic and geopolitical activity, weather and other variable factors influence market conditions, which often result in significant volatility in commodity prices.

The following table presents our average realized commodity prices for the second quarter and first six months of 2012 versus the same periods of 2011. The realized prices do not include settlements of our commodity hedging contracts.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Gas Prices:
Average Henry Hub price ($/Mcf)	$	2.21	$	4.32	$	2.47	$	4.21
Average realized sales price ($/Mcf)	$	2.42	$	4.75	$	2.67	$	4.60
Oil Prices:
Average WTI Cushing price ($/Bbl)	$	93.49	$	102.56	$	98.21	$	98.36
Average realized sales price ($/Bbl)	$	87.81	$	100.12	$	93.63	$	95.80
NGL Prices:
Average realized sales price ($/Bbl)	$	29.02	$	45.06	$	32.94	$	42.92

On an energy equivalent basis, 53% of our aggregate 2012 production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a $5.8 million change in our gas revenues. Similarly, 47% of our production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales price would have resulted in approximately an $8.4 million change in our combined oil and NGL revenues.

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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.

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.

We use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly “ceiling test” calculation to test 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. If the net capitalized cost of our oil and gas properties subject to amortization (the “carrying value”) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.

At June 30, 2012, although the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary, the amount of the excess has declined approximately 47% since December 31, 2011. As of June 30, 2012, a decline of 10% or more in the value of the ceiling limitation would have resulted in an impairment. If negative trends continue we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

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.

For 2012, we hedged about half of our anticipated oil production. We do not have any of our gas or NGL production hedged. We have had no cash settlements on these contracts in the first six months of 2012.

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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 six months of 2011 of $2.1 million.

We had the following contracts outstanding at June 30, 2012:

Oil Contracts

Weighted
Average Price

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

Jul 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

Three Months and Six Months Ended June 30, 2012 vs. June 30, 2011

Net income for the second quarter of 2012 was $64.3 million, or $0.74 per diluted share. This compares to $166.7 million, or $1.94 per diluted share, for the second quarter of 2011. For the six months ended June 30, 2012 net income was $170.4 million, or $1.97 per diluted share, down from net income of $284.9 million, or $3.31 per diluted share, for the first six months of 2011.

Lower net income in both of the 2012 periods resulted from decreased revenues due to lower realized commodity prices, higher operating expenses and a loss on early extinguishment of debt.

These changes are discussed further in the analysis that follows.

Commodity Sales					Percent Change Between		Price/Volume Analysis
(in thousands or as indicated)	2012		2011		2012/2011		Price			Volume			Variance

For the Three Months Ended June 30,
Gas sales	$	69,741	$	140,377	-50	%	$	(67,283	)	$	(3,353	)	$	(70,636	)
Oil sales	229,210		242,812		-6	%	(32,129		)	18,527			(13,602		)
NGL sales	44,286		69,069		-36	%	(24,477		)	(306		)	(24,783		)
	$	343,237	$	452,258			$	(123,889	)	$	14,868		$	(109,021	)

For the Six Months Ended June 30,
Gas sales	$	154,894	$	271,700	-43	%	$	(111,928	)	$	(4,878	)	$	(116,806	)
Oil sales	496,294		463,311		7	%	(11,503		)	44,486			32,983
NGL sales	103,300		131,259		-21	%	(31,297		)	3,338			(27,959		)
	$	754,488	$	866,270			$	(154,728	)	$	42,946		$	(111,782	)

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	For the Three Months Ended June 30,				Percent Change Between		For the Six Months Ended June 30,				Percent Change Between
	2012		2011		2012/2011		2012		2011		2012/2011
Total gas volume — MMcf	28,877		29,551		-2	%	57,994		59,038		-2	%
Gas volume — MMcf per day	317.3		324.7				318.6		326.2
Average gas price — per Mcf	$	2.42	$	4.75	-49	%	$	2.67	$	4.60	-42	%

Total oil volume — thousand barrels	2,610		2,425		8	%	5,301		4,836		10	%
Oil volume — barrels per day	28,686		26,650				29,124		26,719
Average oil price — per barrel	$	87.81	$	100.12	-12	%	$	93.63	$	95.80	-2	%

Total NGL volume — thousand barrels	1,526		1,533		0	%	3,136		3,058		3	%
NGL volume — barrels per day	16,770		16,844				17,229		16,895
Average NGL price — per barrel	$	29.02	$	45.06	-36	%	$	32.94	$	42.92	-23	%
Total MMcfe per day	590.1		585.7		1	%	596.8		587.9		2	%

Commodity sales for the second quarter of 2012 totaled $343.2 million, compared to $452.3 million in 2011. The decrease of $109.0 million was due to lower realized sales prices, which had a negative impact of $123.9 million. The decrease from lower sales prices was partially offset by higher sales from increased oil production during the second quarter of 2012.

For the first six months of 2012 commodity sales totaled $754.5 billion. For the same period in 2011, commodity sales were $866.3 million. The $111.8 million decrease was attributable to a decrease of $154.7 million for lower realized commodity prices in 2012, partially offset by higher sales from oil and NGL production volumes compared to 2011.

Our second quarter 2012 aggregate production volumes were 590.1 MMcfe per day, up 1% from 585.7 MMcfe per day for the same period in 2011. Aggregate production volumes for the first six months of 2012 were 596.8 MMcfe per day, up 2% from 587.9 MMcfe per day for the 2011 period. Production volumes continue to increase from our Cana-Woodford shale play and Permian Basin operations as a result of our successful drilling programs. However, these increases 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. In addition, our second quarter production volumes were negatively impacted by processing plant turnarounds in the Permian Basin and Cana-Woodford ethane rejection, which together reduced our production by approximately 17-19 MMcfe per day.

In the second quarter of 2012 our gas production averaged 317.3 MMcf per day, compared to 324.7 MMcf per day in 2011. This 2% decrease resulted in $3.4 million of lower revenues for the second quarter of 2012. During the first six months of 2012 our gas production averaged 318.6 MMcf per day, or a 2% decrease from the 2011 average of 326.2 MMcf per day. The decrease in gas production for the first six months of 2012 resulted in $4.9 million of lower revenue compared to the same period of 2011.

Our oil production during the second quarter of 2012 averaged 28.7 thousand barrels per day. For the same period of 2011 our average daily oil production was 26.7 thousand barrels per day. The 8% increase in oil production for the 2012 quarter resulted in an additional $18.5 million of oil sales revenue. During the first six months of 2012 our oil production averaged 29.1 thousand barrels per day, up from 26.7 thousand barrels per day in 2011, or a 10% increase. The increased oil production contributed $44.5 million of additional revenue for the first six months of 2012 compared to the same period of 2011.

Our second quarter 2012 NGL volumes remained constant at 16.8 thousand barrels per day compared to the same amount in 2011. NGL production for the first six months of 2012 averaged 17.2 thousand barrels a day, compared to 16.9 thousand barrels a day for the same period of 2011. This 3% increase provided an additional $3.3 million of revenue in 2012.

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In the second quarter of 2012 we realized an average gas price of $2.42 per Mcf, down 49% compared to the average price of $4.75 per Mcf realized in the second quarter of 2011. The price decline accounted for $67.3 million of decreased sales revenue in the second quarter of 2012. Our average realized gas price of $2.67 per Mcf for the first six months of 2012 was 42% lower than the 2011 average realized price of $4.60. The lower realized price received in 2012 resulted in decreased sales revenues of $111.9 million in the first six months of 2012 compared to 2011.

We realized an average oil price of $87.81 per barrel for the second quarter of 2012 versus $100.12 for the same period of 2011. This 12% decrease resulted in lower oil sales revenue of $32.1 million in the 2012 quarter. For the first six months of 2012 we realized an average oil price of $93.63 per barrel, which was 2% lower than the average price of $95.80 we received for the same period in 2011. This decrease accounted for $11.5 million of lower oil sales revenue for the six months ended June 30, 2012.

Our average realized price per barrel of NGL in the second quarter of 2012 was $29.02. This price was 36% lower than the $45.06 average price received in the second quarter of 2011, and accounted for decreased NGL revenue of $24.5 million. In the first six months of 2012 the average NGL price per barrel we received was $32.94, down from $42.92 for the same period of 2011. The 23% decrease in realized NGL price resulted in lower sales of $31.3 million for the first six months of 2012.

Changes in realized commodity prices were the result of overall market conditions.

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Gas Gathering, Processing, Marketing and Other (in thousands):
Gas gathering, processing and other revenues	$	10,179		$	14,544		$	21,886		$	27,061
Gas gathering and processing costs	(2,864		)	(4,630		)	(5,425		)	(9,181		)
Gas gathering, processing and other margin	$	7,315		$	9,914		$	16,461		$	17,880

Gas marketing revenues, net of related costs	$	(294	)	$	411		$	(216	)	$	478

We sometimes transport, process and market third-party gas that is associated with our gas. In the second quarter of 2012, third-party gas gathering, processing and other contributed $7.3 million of pre-tax cash operating margin (revenues less direct cash expenses) versus $9.9 million in 2011. For the six months ended June 30, 2012 and 2011, such revenues less direct expenses totaled $16.5 million and $17.9 million, respectively. Our gas marketing margin (revenues less purchases) was a loss of $294 thousand for the second quarter of 2012, compared to $411 thousand of income in 2011. For the first six months of 2012 our gas marketing margin was a loss of $216 thousand compared to income of $478 thousand in the 2011 period. Changes in net margins from gas gathering, processing, marketing and other activities are the direct result of volumetric changes and overall market conditions.

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	For the Three Months Ended June 30,						Variance Between			For the Six Months Ended June 30,						Variance Between
	2012			2011			2012/2011			2012			2011			2012/2011
Operating costs and expenses (in thousands):
Depreciation, depletion and amortization	$	121,237		$	89,847		$	31,390		$	239,499		$	174,873		$	64,626
Asset retirement obligation	2,441			2,707			(266		)	5,966			4,645			1,321
Production	62,494			60,745			1,749			130,119			119,225			10,894
Transportation	15,260			16,387			(1,127		)	30,866			29,833			1,033
Taxes other than income	23,483			34,495			(11,012		)	48,643			68,092			(19,449		)
General and administrative	12,634			10,617			2,017			26,781			25,344			1,437
Stock compensation, net	4,684			4,617			67			9,218			9,367			(149		)
(Gain) on derivative instruments, net	(10,078		)	(22,477		)	12,399			(5,990		)	(4,233		)	(1,757		)
Other operating, net	2,719			2,342			377			5,059			5,716			(657		)
	$	234,874		$	199,280		$	35,594		$	490,161		$	432,862		$	57,299

Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased 18% to $234.9 million in the second quarter of 2012 compared to $199.3 million for the second quarter of 2011. For the first six months of 2012 operating costs were $490.2 million, or an increase of 13% over the same period of 2011. Analyses of the year over year differences are discussed below.

DD&A increased $31.4 million from $89.8 million in the second quarter of 2011 to $121.2 million in the same period of 2012. On a unit of production basis, DD&A was $2.26 per Mcfe for the second quarter of 2012 compared to $1.69 in the 2011 quarter. For the first six months of 2012 DD&A was $239.5 million, up $64.6 million compared to $174.9 million in 2011. On a unit of production basis, the six month DD&A rate for 2012 was $2.21 per Mcfe, versus $1.64 per Mcfe for the 2011 period. The increases in DD&A result primarily from increasing the cost of reserves added at a greater rate than the increase in future production. These increases account for most of the aggregate increases in total operating costs and expenses for the periods.

In the second quarter of 2012 our production costs were $62.5 million ($1.16 per Mcfe) compared to 60.7 million ($1.14 per Mcfe) in the second quarter of 2011. Production costs for the first six months of 2012 were $130.1 million ($1.20 per Mcfe), up 9% from $119.2 million ($1.12 per Mcfe) for the same period of 2011. Our production costs consist of lease operating expense and workover expense as follows (in thousands):

	For the Three Months Ended June 30,				Variance Between			For the Six Months Ended June 30,				Variance Between
	2012		2011		2012/2011			2012		2011		2012/2011

Lease operating expense	$	54,424	$	50,193	$	4,231		$	110,976	$	100,143	$	10,833
Workover expense	8,070		10,552		(2,482		)	19,143		19,082		61
	$	62,494	$	60,745	$	1,749		$	130,119	$	119,225	$	10,894

The increases in our lease operating expense for the second quarter and first six months of 2012 compared to the 2011 periods were due to higher water disposal and compressor rental costs associated with wells coming on line from our successful Permian Basin and Cana-Woodford shale drilling programs. Workover expense will vary from period to period based on the amount of maintenance and remedial activity planned and/or required during the period.

Transportation costs decreased to $15.3 million ($0.28 per Mcfe) in the second quarter of 2012 from $16.4 million ($0.31 per Mcfe) in 2011. For the first six months of 2012 transportation costs were $30.9 million ($0.28 per Mcfe) versus $29.8 million ($0.28 per Mcfe) for 2011. Generally, transportation costs will fluctuate based on increases or decreases in sales volumes, compression charges and fluctuations in the price of the fuel cost component.

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In the second quarter or 2012 taxes other than income decreased 32% from $34.5 million in 2011 to $23.5 million in 2012. For the six months ended June 30, 2012, taxes other than income were $48.6 million, down 29% compared to $68.1 million for the 2011 period. Generally, taxes other than income will vary based on increases or decreases in production volumes and changes in commodity prices. In addition, the 2012 periods 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 non-cash stock-based compensation cost as follows (in thousands):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Performance-based restricted stock awards	$	4,082		$	4,079		$	7,671		$	8,070
Service-based restricted stock awards	2,647			2,614			5,879			5,125
Restricted unit awards	—			12			—			34
Restricted stock and units	6,729			6,705			13,550			13,229
Stock option awards	632			1,115			1,425			2,180
Total stock compensation	7,361			7,820			14,975			15,409
Less amounts capitalized to oil and gas properties	(2,677		)	(3,203		)	(5,757		)	(6,042		)
Stock compensation expense, net	$	4,684		$	4,617		$	9,218		$	9,367

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.

Our net (gains) 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. 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 the net realized and unrealized (gains) and losses on our derivative instruments:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Realized (gain) on settlement of derivative instruments	$	—		$	(36	)	$	—		$	(2,070	)
Unrealized (gain) from changes to the fair value of the derivative instruments	(10,078		)	(22,441		)	(5,990		)	(2,163		)
(Gain) on derivative instruments, net	$	(10,078	)	$	(22,477	)	$	(5,990	)	$	(4,233	)

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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

	For the Three Months Ended June 30,						Variance Between			For the Six Months Ended June 30,						Variance Between
	2012			2011			2012/2011			2012			2011			2012/2011

Interest expense	$	13,679		$	9,340		$	4,339		$	22,347		$	18,320		$	4,027
Capitalized interest	(9,119		)	(7,352		)	(1,767		)	(16,923		)	(14,577		)	(2,346		)
Loss on early extinguishment of debt	16,214			—			16,214			16,214			—			16,214
Other, net	(7,829		)	(3,018		)	(4,811		)	(12,555		)	(3,622		)	(8,933		)
	$	12,945		$	(1,030	)	$	13,975		$	9,083		$	121		$	8,962

Our interest expense includes interest on outstanding borrowings, amortization of financing costs and miscellaneous interest expense. In the second quarter of 2012 we issued $750 million of 5.875% senior notes, of which proceeds was used to retire our outstanding $350 million 7.125% senior notes and outstanding bank debt of $232 million. This resulted in additional interest expense incurred in the 2012 periods compared to 2011.

In connection with the retirement of our 7.125% senior notes, we recognized a $16.2 million loss on early extinguishment of debt in the second quarter of 2012. The retirement of our 7.125% senior notes and the issuance of our 5.875% senior notes is described in more detail under “Long-Term Debt” below.

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. The increases in other, net (income) for the second quarter and first six months of 2012 compared to the same periods of 2011 are mainly due to increases in net proceeds from sales of oil and gas well equipment and supplies and income from other non-operating activities.

Income Tax Expense

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

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012		2011			2012		2011
Current provision (benefit)	$	—	$	(774	)	$	—	$	(1,322	)
Deferred taxes	38,137		98,358			101,080		168,056
	$	38,137	$	97,584		$	101,080	$	166,734

Our combined Federal and state effective income tax rate for the first six months of 2012 was 37.2% compared to 36.9% for the 2011 period. Our effective tax rates differ from the statutory rate of 35% primarily due to state income taxes and nondeductible expenses. See Note 8 to the Consolidated Financial Statements of this report for additional information regarding our income taxes.

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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. If demand remains low, prices could decline even further. Prices for oil and NGLs have fluctuated during 2012 due to supply and demand factors, seasonality and other geopolitical and economic factors. It is likely that future prices for these commodities will continue to fluctuate.

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 primarily by operating cash flow and long-term debt. 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. Our credit facility is described in more detail under “Long-Term Debt” below.

At June 30, 2012, our total debt outstanding was $750 million, which was comprised of our 5.875% Notes due in 2022. Our debt to total capitalization ratio at June 30, 2012 was 19%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is: long-term debt of $750 million divided by long-term debt of $750 million plus stockholders’ equity of $3.292 billion. Management believes that this non-GAAP measure is useful information and it is a common statistic referred to by the investment community.

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 six months of 2012 was $574.9 million, compared to $639.1 million for the same period of 2011. Most of the $64.2 million decrease resulted from lower revenues attributable to declines in commodity prices received in 2012. In addition, we had an increase in cash flow from operations attributable to a decrease in our net accounts receivable, which was partially offset by utilizing cash to reduce accounts payable and accrued liabilities.

Cash flow used in investing activities for the first six months of 2012 was $ 783.0 million, compared to $731.5 million for 2011. In 2012 we had oil and gas and other capital expenditures of $784.7 million, which were partially offset by $1.7 million of asset sales. During 2011, expenditures for oil and gas and other capital costs were $752.1 million with proceeds from asset sales of $20.6 million.

For the first six months of 2012 we had net cash flow provided by financing activities of $302.6 million versus cash flow used in financing activities of $8.5 million for the same period of 2011. The $311.1 million increase in our 2012 cash inflow was primarily due to a net increase of $318.7 million

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related to our long-term debt. In the second quarter of 2012 we issued $750 million of 5.875% senior notes. Proceeds from that offering were used to retire all of our outstanding $350 million 7.125% senior notes and bank debt, as described in more detail under “Long-Term Debt” below.

Reconciliation of Adjusted Cash Flow from Operations

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Net cash provided by operating activities	$	323,040		$	373,814		$	574,932		$	639,091
Change in operating assets and liabilities	(82,530		)	(30,451		)	(31,466		)	8,892
Adjusted cash flow from operations	$	240,510		$	343,363		$	543,466		$	647,983

Management believes that the non-GAAP measure of adjusted 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, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of cash flow from operating activities. 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 our capitalized expenditures for our oil and gas acquisition, exploration, and development activities and property sales (in thousands):

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Acquisitions:
Proved	$	240		$	9,165		$	291		$	9,165
Unproved	4,791			11,606			6,713			12,047
	5,031			20,771			7,004			21,212
Exploration and development:
Land and seismic	21,175			52,499			58,387			84,925
Exploration and development	361,743			367,486			724,242			672,061
	382,918			419,985			782,629			756,986
Sales proceeds:
Proved	(14		)	(7,129		)	(185		)	(18,483		)
Unproved	(146		)	(1,327		)	(1,088		)	(1,821		)
	(160		)	(8,456		)	(1,273		)	(20,304		)
	$	387,789		$	432,300		$	788,360		$	757,894

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 $25.6 million (3%) from $757.0 million in the first half of 2011 to $782.6 million in the first half of 2012. Of our total 2012 expenditures, 52% was for projects located in the Permian Basin, primarily in the Delaware Basin of southeast New Mexico and West Texas. Approximately 44% of our expenditures were in the Mid-Continent area; mostly in our Western Oklahoma Cana-Woodford shale play. The remaining 4% of expenditures were in the Gulf Coast and other.

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The following table reflects wells drilled by region:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Gross wells
Permian Basin	55		45		94		71
Mid-Continent	31		49		64		86
Gulf Coast / Other	1		1		2		3
	87		95		160		160
Net wells
Permian Basin	37		36		64		56
Mid-Continent	14		19		26		32
Gulf Coast / Other	—		—		1		2
	51		55		91		90

% Gross wells completed as producers	97	%	96	%	96	%	96	%

As of June 30, 2012 we had 35 net wells awaiting completion: 25 Mid-Continent and 10 Permian Basin. We also had 22 operated rigs running; 13 in the Permian Basin and 9 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 and Cana-Woodford. We expect our 2012 E&D capital expenditures to be funded from cash flow, long-term debt and occasional non-core 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 approximately $7 million of property acquisitions and no significant property sales in the first half of 2012. Subsequent to June 30, 2012, we sold various interests in oil and gas properties for $11 million. During the first half of 2011, we had property acquisitions of approximately $21.2 million of which $18 million was in our western Oklahoma Cana-Woodford shale play and $3 million was in the Permian Basin. In the first six months of 2011 we sold various non-core property interests for $20.3 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. At this time 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.

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During the first six months of 2012 our total assets increased by $603 million to $6.0 billion, up from $5.4 billion at December 31, 2011. Approximately 96% of the increase resulted from a $580 million increase in our net oil and gas properties.

At June 30, 2012, our total liabilities were $2.7 billion, up $441 million from $2.3 billion at December 31, 2011. The increase resulted primarily from a $345 million increase in long-term debt and a $100 million increase in noncurrent deferred income taxes.

Stockholders’ equity rose $161.4 million to $3.3 billion at June 30, 2012, compared to $3.1 billion at December 31, 2011. The increase is mainly due to our net income of $170.4 million, which was partially offset by dividends of $20.6 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. In May 2012, the Board of Directors declared a cash dividend of $0.12 per share on our common stock. The dividend is payable on September 4, 2012 to stockholders of record on August 15, 2012. 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.

Our working capital increased $1.8 million from a deficit of $158.4 million at year-end 2011 to a deficit of $156.6 million at June 30, 2012.

Working capital increased primarily because of the following:

· Cash and cash equivalents increased by $94.5 million due to our second quarter issuance of 5.875% Senior Notes.

· Our operations related accounts payable and accrued liabilities decreased by $37.2 million.

These working capital increases were partially offset by the following:

· Our operations related accounts receivable decreased by $60.2 million.

· We received $47.6 million of tax refunds that were outstanding at December 31, 2011, which were used to fund E&D activities.

· Accrued liabilities related to our E&D expenditures decreased by $31.5 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.

Long-term Debt

Debt at June 30, 2012 and December 31, 2011 consisted of the following (in thousands):

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	June 30, 2012		December 31, 2011
Bank debt	$	—	$	55,000
7.125% Senior Notes due 2017	—		350,000
5.875% Senior Notes due 2022	750,000		—
Total long-term debt	$	750,000	$	405,000

Bank Debt

We have a five-year senior unsecured revolving credit facility (“Credit Facility”) that matures July 14, 2016. The Credit Facility provides for a borrowing base of $2 billion. At June 30, 2012 we had $800 million of aggregate commitments from our lenders. Our aggregate commitments were subsequently increased to $1 billion in July 2012.

At June 30, 2012 we had no bank debt outstanding. We had letters of credit outstanding under the Credit Facility of $2.5 million. During the first six months of 2012 we had an average daily bank debt outstanding of $87.2 million, compared to $6.0 million for the same period of 2011. Our largest amount of bank borrowings outstanding during the first half of 2012 was $275 million in mid-March. During the first half of 2011 our largest amount of outstanding bank borrowings was $63.0 million in mid-June.

5.875% Notes due 2022

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7.125% Notes due 2017

In May, 2007, we issued $350 million of 7.125% senior unsecured notes at par which were scheduled to mature May 1, 2017. 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 on or prior to April 4, 2012 received (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 were not eligible for the consent payment. Through April 18, 2012 a total of $300,163,000 of notes were redeemed. In May 2012, the remaining notes were redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012.

In conjunction 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.

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 June 30, 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 June 30, 2012, we had contractual obligations and material commitments as follows:

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

Long-term debt(1)	$	750,000	$	—	$	—		$	—		$	750,000
Fixed-Rate interest payments(1)	443,685		47,122		88,125			88,125			220,313
Operating leases	74,579		8,197		14,384			11,831			40,167
Drilling commitments(2)	342,788		342,788		—			—			—
Gathering facilities and pipelines(3)	13,923		13,923		—			—			—
Asset retirement obligation	192,459		56,480		—		(4)	—		(4)	—		(4)
Other liabilities(5)	84,800		14,648		27,743			27,000			15,409
Firm Transportation	1,736		1,432		215			89			—

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

(2) We have drilling commitments of approximately $306.6 million consisting of obligations to finish drilling and completing wells in progress at June 30, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are $21.4 million to secure the use of drilling rigs and $14.8 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 June 30, 2012, we had commitments of $13.9 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. Nearly all the 2012 capital is directed towards oil drilling or liquids-rich gas in the Permian and Cana-Woodford. 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 six months of 2012 our realized prices averaged $2.67 per Mcf of gas, $93.63 per barrel of oil, and $32.94 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 six months of 2012 is high.

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

		2012
Production expense		$1.15 - $1.30
Transportation expense		0.28 - 0.33
DD&A and asset retirement obligation		2.25 - 2.45
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 June 30, 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 June 30, 2012:

Oil Contracts

Weighted Average Price

Fair Value
(in

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

thousands)

Jul 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

5,745

(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 $2.6 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 June 30, 2012 our only debt was our senior 5.875% notes that will mature May 1, 2022.

At June 30, 2012 we consider our interest rate exposure to be minimal because all of our long-term debt obligations were at fixed rates. 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.

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ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of June 30, 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 have concluded, as of June 30, 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 June 30, 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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SIGNATURE

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

August 2, 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)