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 March 31, 2013

Commission file number 001-31446

CIMAREX ENERGY CO.

(Exact name of registrant as specified in its charter)

Incorporated in the
state of Delaware

Employer Identification

No. 45-0466694

1700 Lincoln Street, Suite 1800, Denver, Colorado 80203

(Address of principal executive offices including ZIP code)

(303) 295-3995

(Registrant’s telephone number)

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

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

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

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

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

The number of shares of Cimarex Energy Co. common stock outstanding as of March 31, 2013 was 86,449,746.

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CIMAREX ENERGY CO.

Table of Contents

		Page
PART I

Item 1 — Financial Statements

Condensed consolidated balance sheets (unaudited) as of March 31, 2013 and December 31, 2012		4

Consolidated statements of income and comprehensive income (unaudited) for the three months ended March 31, 2013 and 2012		5

Condensed consolidated statements of cash flows (unaudited) for the three months ended March 31, 2013 and 2012		6

Notes to consolidated financial statements (unaudited)		7

Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

Item 3 — Qualitative and Quantitative Disclosures About Market Risk		34

Item 4 — Controls and Procedures		35

PART II

Item 6 — Exhibits		37

Signatures		38

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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 working interest percentage

Net Production—Gross production multiplied by net revenue interest

NGL or NGLs—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

WTI—West Texas Intermediate

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

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

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

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

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PART I

ITEM 1 - Financial Statements

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

	March 31,
	2013			December 31,
	(Unaudited)			2012
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	18,532		$	69,538
Receivables, net	333,550			302,974
Oil and gas well equipment and supplies	73,035			81,029
Deferred income taxes	12,122			8,477
Derivative instruments	288			—
Prepaid expenses	6,431			7,420
Other current assets	539			699
Total current assets	444,497			470,137
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	11,733,247			11,258,748
Unproved properties and properties under development, not being amortized	579,927			645,078
	12,313,174			11,903,826
Less — accumulated depreciation, depletion and amortization	(7,027,421		)	(6,899,057		)
Net oil and gas properties	5,285,753			5,004,769
Fixed assets, net	164,727			152,605
Goodwill	620,232			620,232
Other assets, net	54,740			57,409
	$	6,569,949		$	6,305,152
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	83,274		$	103,653
Accrued liabilities	411,789			392,909
Derivative instruments	2,617			—
Revenue payable	147,945			149,300
Total current liabilities	645,625			645,862
Long-term debt	870,000			750,000
Deferred income taxes	1,178,221			1,121,353
Other liabilities	321,510			313,201
Total liabilities	3,015,356			2,830,416
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, 86,449,746 and 86,595,976 shares issued, respectively	864			866
Paid-in capital	1,941,443			1,939,628
Retained earnings	1,611,732			1,533,768
Accumulated other comprehensive income	554			474
	3,554,593			3,474,736
	$	6,569,949		$	6,305,152

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Consolidated Statements of Income and Comprehensive Income

(Unaudited)

	For the Three Months
	Ended March 31,
	2013			2012
	(In thousands, except per share data)
Revenues:
Gas sales	$	101,121		$	85,153
Oil sales	257,532			267,084
NGL sales	56,875			59,014
Gas gathering, processing and other	10,727			11,707
Gas marketing, net	101			78
	426,356			423,036
Costs and expenses:
Depreciation, depletion and amortization	136,438			118,262
Asset retirement obligation	2,399			3,525
Production	69,386			67,625
Transportation	18,634			13,316
Gas gathering and processing	6,156			4,851
Taxes other than income	25,128			25,160
General and administrative	15,577			14,147
Stock compensation	3,605			4,534
Loss on derivative instruments, net	1,603			4,088
Other operating, net	2,932			2,340
	281,858			257,848

Operating income	144,498			165,188

Other (income) and expense:
Interest expense	13,206			8,668
Capitalized interest	(9,195		)	(7,804		)
Other, net	(2,616		)	(4,726		)

Income before income tax	143,103			169,050
Income tax expense	53,176			62,943
Net income	$	89,927		$	106,107

Earnings per share to common stockholders:
Basic
Distributed	$	0.14		$	0.12
Undistributed	0.90			1.12
	$	1.04		$	1.24

Diluted
Distributed	$	0.14		$	0.12
Undistributed	0.90			1.11
	$	1.04		$	1.23

Comprehensive income:
Net income	$	89,927		$	106,107
Other comprehensive income:
Change in fair value of investments, net of tax	80			399
Total comprehensive income	$	90,007		$	106,506

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Three Months
	Ended March 31,
	2013			2012
	(In thousands)

Cash flows from operating activities:
Net income	$	89,927		$	106,107
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	136,438			118,262
Asset retirement obligation	2,399			3,525
Deferred income taxes	53,176			62,943
Stock compensation	3,605			4,534
Derivative instruments, net	2,329			4,088
Changes in non-current assets and liabilities	3,374			2,239
Other, net	1,173			1,258
Changes in operating assets and liabilities:
Increase in receivables, net	(30,576		)	(2,144		)
Decrease in other current assets	9,143			69
Decrease in accounts payable and accrued liabilities	(23,910		)	(48,989		)
Net cash provided by operating activities	247,078			251,892
Cash flows from investing activities:
Oil and gas expenditures	(390,669		)	(400,963		)
Sales of oil and gas and other assets	975			1,322
Other expenditures	(19,523		)	(10,300		)
Net cash used by investing activities	(409,217		)	(409,941		)
Cash flows from financing activities:
Net increase in bank debt	120,000			167,000
Dividends paid	(10,356		)	(8,576		)
Issuance of common stock and other	1,489			1,625
Net cash provided by financing activities	111,133			160,049
Net change in cash and cash equivalents	(51,006		)	2,000
Cash and cash equivalents at beginning of period	69,538			2,406
Cash and cash equivalents at end of period	$	18,532		$	4,406

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements

March 31, 2013

(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 2012 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 2013 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 March 31, 2013, 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, we experienced a lower ceiling limitation since December 31, 2012 resulting primarily from decreases in the 12-month average trailing prices for oil and NGLs, which have reduced proved reserve values. If pricing conditions do not improve, or if there is a negative impact on one or more of the other components of the calculation, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.

Use of Estimates

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

Accounts Receivable, Accounts Payable, and Accrued Liabilities

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

(in thousands)	March 31, 2013		December 31, 2012

Receivables, net of allowance
Trade	$	64,534	$	55,528
Oil and gas sales	257,219		239,106
Gas gathering, processing, and marketing	11,373		7,901
Other	424		439
Receivables, net	$	333,550	$	302,974

Accounts payable
Trade	$	62,190	$	88,168
Gas gathering, processing, and marketing	21,084		15,485
Accounts payable	$	83,274	$	103,653

Accrued liabilities
Exploration and development	$	170,181	$	155,002
Taxes other than income	19,542		29,179
Other	222,066		208,728
Accrued liabilities	$	411,789	$	392,909

Recently Issued Accounting Standards

No significant accounting standards applicable to Cimarex have been issued during the quarter ended March 31, 2013.

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.

The following table summarizes our outstanding oil contracts as of March 31, 2013. We have elected not to account for these derivatives as cash flow hedges.

					Weighted Average Price						Fair Value
Period	Type	Volume/Day		Index(1)	Floor		Ceiling		Swap		(in thousands)
Apr 13 – Dec 13	Collars	6,000	Bbls	WTI	$	85.00	$	102.31	—		$	(1,273	)
Apr 13 – Dec 13	Swaps	6,000	Bbls	WTI	—		—		$	96.13	$	(1,056	)

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

Subsequent to March 31, 2013, we entered into the following gas hedges:

					Weighted Average Price
Period	Type	Volume/Day		Index(1)	Floor		Ceiling
May 13 – Jun 13	Collars	30,000	MMBtu	PEPL	$	3.50	$	4.50
Jul 13 – Dec 14	Collars	80,000	MMBtu	PEPL	$	3.51	$	4.57

(1) PEPL refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. For a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price. We are required to make a payment to the counterparty if the settlement price for the settlement period is greater than the swap price.

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.

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 March 31,
(in thousands)	2013			2012
Realized gain (loss) on settlement of derivative instruments	$	726		$	—
Unrealized gain (loss) from changes to the fair value of the derivative instruments	(2,329		)	(4,088		)
Gain (loss) on derivative instruments, net	$	(1,603	)	$	(4,088	)

Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms.

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

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. The estimated fair values of our oil contracts as of March 31, 2013 was an asset of $288 thousand, located in Current assets — derivative instruments, and a liability of $2.6 million, located in Current liabilities — derivative instruments. All of our derivative contracts entered into prior to January 1, 2013 were settled as of December 31, 2012. Our derivatives are presented on a gross basis.

Because we elect 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.

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)

March 31, 2013

(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

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). 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 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The following tables provide fair value measurement information for certain assets and liabilities as of March 31, 2013 and December 31, 2012:

March 31, 2013: (in thousands)	Carrying Amount			Fair Value
Financial Assets (Liabilities):
Bank debt	$	(120,000	)	$	(120,000	)
5.875% Notes due 2022	$	(750,000	)	$	(806,250	)
Derivative instruments — assets	$	288		$	288
Derivative instruments — liabilities	$	(2,617	)	$	(2,617	)

December 31, 2012: (in thousands)	Carrying Amount			Fair Value
Financial (Liabilities):
5.875% Notes due 2022	$	(750,000	)	$	(825,750	)

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 (Level 1)

The fair value of our bank debt at March 31, 2013 was estimated to approximate the carrying amount because the floating interest rate paid on such debt was set for periods of three months or less.

The fair value for our 5.875% 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)

March 31, 2013

(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.

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.

We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At March 31, 2013 and December 31, 2012, the allowance for doubtful accounts was $6.5 million.

4. Capital Stock

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At March 31, 2013 there were no shares of preferred stock outstanding. A summary of our common stock activity for the three months ended March 31, 2013 follows:

(in thousands)
Issued and outstanding as of December 31, 2012	86,596
Restricted shares issued under compensation plans, net of reacquired stock and cancellations	(183	)
Option exercises, net of cancellations	37
Issued and outstanding as of March 31, 2013	86,450

Dividends

In February 2013, the Board of Directors increased our quarterly dividend to $0.14 per share from $0.12 per share. The dividend is payable on June 3, 2013 to stockholders of record on May 15, 2013. 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, and our previous plan was terminated. Outstanding awards under the previous plan were not impacted. The 2011 Plan provides for grants of stock options, restricted stock, restricted stock units, performance stock and performance stock units. A total of 5.3 million shares of common stock may be issued under the 2011 Plan.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

We have recognized non-cash stock-based compensation cost as follows:

	Three Months Ended March 31,
(in thousands)	2013			2012
Restricted stock and units	$	5,906		$	6,821
Stock options	708			793
	6,614			7,614
Less amounts capitalized to oil and gas properties	(3,009		)	(3,080		)
Compensation expense	$	3,605		$	4,534

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

Restricted Stock and Units

No restricted stock awards were granted during the three months ended March 31, 2013. During the first quarter of 2012, we granted 18,500 service-based stock awards at a weighted average grant-date fair value of $60.49.

From time to time performance-based awards are granted to eligible executives and are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. Service-based stock awards granted to other eligible employees and non-employee directors have vesting schedules of three to five years.

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:

	Three Months Ended March 31,
(in thousands)	2013			2012
Performance-based stock awards	$	2,685		$	3,589
Service-based stock awards	3,221			3,232
	5,906			6,821
Less amounts capitalized to oil and gas properties	(2,784		)	(2,730		)
Restricted stock compensation expense	$	3,122		$	4,091

Unrecognized compensation cost related to unvested restricted shares at March 31, 2013 was $47.6 million, which we expect to recognize over a weighted average period of approximately 2.3 years. The restricted units were fully expensed in 2011.

The following table provides information on restricted stock and unit activity as of March 31, 2013 and changes during the year:

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

	Restricted Stock		Restricted Units
Outstanding as of January 1, 2013	1,838,736		33,838
Vested	(202,320	)	—
Converted to stock	—		(25,000	)
Canceled	(106,680	)	—
Outstanding as of March 31, 2013	1,529,736		8,838
Vested included in outstanding	N/A		8,838

Stock Options

Options granted under our 2011 and previous plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years. The plans provide that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. No options were granted during the first quarters of 2013 and 2012.

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:

	Three Months Ended March 31,
(in thousands)	2013			2012
Stock option awards	$	708		$	793
Less amounts capitalized to oil and gas properties	(225		)	(350		)
Stock option compensation expense	$	483		$	443

As of March 31, 2013, there was $4.1 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 1.8 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, 2013	687,459		$	54.51
Exercised	(36,829	)	$	40.47
Cancelled	(666	)	$	86.01
Forfeited	(3,668	)	$	75.13
Outstanding as of March 31, 2013	646,296		$	55.16	5.6 Years	$	14,108
Exercisable as of March 31, 2013	332,902		$	50.22	5.4 Years	$	8,763

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

The following table provides information regarding the options exercised:

	Three Months Ended March 31,
(dollars in thousands)	2013		2012
Number of options exercised	36,829		42,075
Cash received from option exercises	$	1,490	$	2,117
Intrinsic value of options exercised	$	1,162	$	1,261

The following summary reflects the status of non-vested stock options as of March 31, 2013 and changes during the year:

	Options		Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price
Non-vested as of January 1, 2013	317,062		$	23.22	$	60.58
Forfeited	(3,668	)	$	29.84	$	75.13
Non-vested as of March 31, 2013	313,394		$	23.14	$	60.41

6. Asset Retirement Obligations

We recognize the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the abandoning of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the three months ended March 31, 2013:

(in thousands)
Asset retirement obligation at January 1, 2013	$	185,138
Liabilities incurred	1,090
Liability settlements and disposals	(8,691		)
Accretion expense	2,096
Revisions of estimated liabilities	300
Asset retirement obligation at March 31, 2013	179,933
Less current obligation	(40,133		)
Long-term asset retirement obligation	$	139,800

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

7. Long-Term Debt

Debt at March 31, 2013 and December 31, 2012 consisted of the following:

(in thousands)	March 31, 2013		December 31, 2012
Bank debt	$	120,000	$	—
5.875% Senior Notes due 2022	750,000		750,000
Total long-term debt	$	870,000	$	750,000

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 with aggregate commitments of $1 billion from our lenders. The borrowing base was increased to $2.250 billion in April 2013.

The borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular annual redetermination date is on April 15, 2014.

As of March 31, 2013, we had $120 million of bank debt outstanding at a weighted average interest rate of 1.96%. We also had letters of credit outstanding under the Credit Facility of $2.5 million, leaving an unused borrowing availability of $877.5 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 March 31, 2013, we were in compliance with all of the financial and nonfinancial covenants.

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.

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 (Tender Offer)

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

to purchase all of the outstanding 7.125% senior notes. The Tender Offer was completed in the second quarter of 2012.

8. Income Taxes

The components of our provision for income taxes are as follows:

	Three Months Ended March 31,
(in thousands)	2013		2012
Current provision (benefit)	$	—	$	—
Deferred taxes	53,176		62,943
	$	53,176	$	62,943

At December 31, 2012, the company had a U.S. net tax operating carryforward of approximately $480.7 million, which would expire between 2031 and 2032. We believe that the carryforward will be utilized before it expires. We also had an alternative minimum tax credit carryforward of approximately $4.4 million.

At March 31, 2013, 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 2009-2011 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 to examination for the 2005-2011 tax years.

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and nondeductible expenses. The effective income tax rate for each of the three months ending March 31, 2013 and 2012 was 37.2%.

9. Supplemental Disclosure of Cash Flow Information:

	Three Months Ended March 31,
(in thousands)	2013		2012
Cash paid during the period for:
Interest expense (including capitalized amounts)	$	1,018	$	1,759
Interest capitalized	709		1,584
Income taxes	55		11
Cash received for income taxes	15		816

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

10. Earnings per Share

The calculations of basic and diluted net earnings per common share under the two-class method are presented below:

	Three Months Ended March 31,
(in thousands, except per share data)	2013			2012
Basic:
Net income	$	89,927		$	106,107
Participating securities’ share in earnings	(1,385		)	(2,055		)
Net income applicable to common shareholders	$	88,542		$	104,052

Diluted:
Net income	$	89,927		$	106,107
Participating securities’ share in earnings	(1,383		)	(2,046		)
Net income applicable to common shareholders	$	88,544		$	104,061

Shares:
Basic shares outstanding	84,920			83,937
Incremental shares from assumed exercise of stock options	96			370
Fully diluted common stock	85,016			84,307
Excluded (1)	156			167

Earnings per share to common shareholders:
Basic	$	1.04		$	1.24
Diluted	$	1.04		$	1.23

(1) Inclusion of certain outstanding stock options would have an anti-dilutive effect.

11. Commitments and Contingencies

Commitments

We have drilling commitments of $203.9 million. Most of these consist of obligations to finish drilling and completing wells in progress at March 31, 2013.

In New Mexico and Texas, we are constructing gathering facilities and pipelines. At March 31, 2013, we had commitments of $2.5 million relating to these construction projects.

At March 31, 2013, we had firm sales contracts to deliver approximately 27.4 Bcf of natural gas over the next 13 months. If this gas is not delivered, our financial commitment would be approximately $104.2 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 $7.2 million.

We have various commitments for office space and equipment under operating lease arrangements totaling $125.4 million for the next 5 years and beyond.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

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

Litigation

In the normal course of business, we have various litigation 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, we believe the resolution of them, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.

Hitch Enterprises, Inc. et al. v. Cimarex Energy Co. et al.

On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch Enterprises, Inc., et al. v. Cimarex Energy Co., et al. (Hitch) litigation matter for $16.4 million. Hitch was filed as a statewide royalty putative class action in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a mediation, which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. The Court has entered an order preliminarily approving the parties’ settlement. The deadline for putative class members to opt out of the settlement class was February 15, 2013, and less than ½% of the class members opted out. The Court will issue final judgment after July 1, 2013. In the fourth quarter of 2012, we accrued $16.4 million for this matter.

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

In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al. v. Helmerich & Payne, Inc. (H&P) case. This lawsuit originally was filed in 1998 and addressed H&P’s conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage and other related issues. 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, including this lawsuit. In 2008 we recorded a litigation expense of $119.6 million for this lawsuit. We have accrued additional post-judgment interest and costs during the appeal of the District Court’s judgment.

On August 18, 2011, the Oklahoma Court of Appeals reversed and remanded the $112.7 million disgorgement of profits award, holding 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 District Court’s judgment, including damages of $6.845 million. On February 13, 2012 the Oklahoma Supreme Court granted Cimarex’s Petition for Certiorari, which requested a review of the affirmed portion of the judgment. We are awaiting a ruling from the Oklahoma Supreme Court, 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 noncurrent accrued liability for this lawsuit for the three months ended March 31, 2013:

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

March 31, 2013

(Unaudited)

(in thousands)
Outstanding at January 1, 2013	$	155,374
Accrued post-judgment interest and costs	2,336
Outstanding at March 31, 2013	$	157,710

12. Property Sales and Acquisitions

There were no significant property sales and acquisitions during the first quarters of 2013 and 2012.

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

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

OVERVIEW

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

Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our shareholders through a diversified drilling portfolio. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development. We occasionally consider property acquisitions and mergers to enhance our competitive position.

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. We seek geologic and geographic diversification by operating in multiple basins. In recent years, we have shifted our capital expenditures to oil and liquids-rich gas projects because of strong oil prices relative to gas prices.

Our operations are currently focused in two main areas: the Mid-Continent region and the Permian Basin. The Mid-Continent region consists of Oklahoma, the Texas Panhandle, 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.

Growth is generally funded with cash flow provided by operating activities together with bank borrowings, sale of non-strategic assets and occasional public financing. Conservative use of leverage and maintaining a strong balance sheet have long been a part of our financial strategy. We have a long track record of profitable growth.

Our revenue, profitability and future growth are highly dependent on the commodity prices we receive. Prices impact 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. An extended decline in oil and/or 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 impact reported results of operations and the amount of reported assets, liabilities, equity and proved reserves.

First quarter 2013 summary operating and financial results:

· Production volumes averaged 661.1 MMcfe per day, up 10% from 603.5 MMcfe per day for first quarter 2012.

· Production volumes increased by 11% for oil, 21% for NGL and 3% for gas, compared to the first quarter of 2012.

· Oil, gas and NGL sales were $415.5 million, compared to $411.3 million a year earlier.

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· Our average realized gas price increased 16% to $3.38 per Mcf versus $2.92 per Mcf in the first quarter of 2012.

· Our average realized oil price decreased 13% to $86.31 per barrel compared to $99.28 per barrel in the first quarter of 2012.

· Our average realized NGL price decreased 20% to $29.31 per barrel compared to $36.66 per barrel in the first quarter of 2012.

· Cash flow from operating activities was $247.1 million down slightly from $251.9 million in the prior year.

· Net income of $89.9 million ($1.04 per diluted share) declined from net income of $106.1 million ($1.23 per diluted share) in the first quarter of 2012.

· Total debt increased by $120 million to $870 million compared to $750 million at year-end 2012.

· We drilled and completed 87 gross (47 net) wells, completing 100% as producers, compared to 73 gross (40 net) wells, completing 95% as producers in the first quarter of 2012.

Revenues

Most of our revenues are derived from sales of oil, gas and NGL production. While revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our results of operations. 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. Realized prices do not include settlements of our commodity hedging contracts.

	Three Months Ended March 31,
	2013		2012
Gas Prices:
Average Henry Hub price ($/Mcf)	$	3.34	$	2.72
Average realized sales price ($/Mcf)	$	3.38	$	2.92

Oil Prices:
Average WTI Cushing price ($/Bbl)	$	94.38	$	102.93
Average realized sales price ($/Bbl)	$	86.31	$	99.28

NGL Prices:
Average realized sales price ($/Bbl)	$	29.31	$	36.66

On an energy equivalent basis, 50% of our first quarter 2013 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a $3.0 million change in our gas revenues. Similarly, 50% of our production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales price would have resulted in a $4.9 million change in our combined oil and NGL revenues.

See RESULTS OF OPERATIONS below for a discussion of the impact changes in realized prices had on our 2013 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 2012, we owned interests in 13,127 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. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The costs of replacing production also impact our DD&A rate. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and reclassifications of properties from unproved to proved 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 expensed. The ceiling limitation is equal to the sum of (a) the present value discounted at 10% of estimated future net cash flows from proved reserves, (b) the cost of properties not being amortized, (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (d) all related tax effects.

General and administrative (G&A) 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. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting.

See RESULTS OF OPERATIONS below for a discussion of changes in production and other operating expenses.

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Derivative Instruments/Hedging

We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in oil and/or gas 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, we hedged about half of our anticipated oil production. We did not hedge any of our gas or NGL production. All of the oil contracts expired during 2012 without any cash settlements. As of December 31, 2012, we did not have any hedges in place.

In the first quarter of 2013, we hedged about a third of our anticipated 2013 oil production. We did not hedge any of our gas or NGL production. Net cash settlements on the oil contracts in the first quarter of 2013 totaled $726 thousand.

At March 31, 2013 we had the following oil contracts outstanding:

					Weighted Average Price
Period	Type	Volume/Day		Index(1)	Floor		Ceiling		Swap
Apr 13 – Dec 13	Collars	6,000	Bbls	WTI	$	85.00	$	102.31	—
Apr 13 – Dec 13	Swaps	6,000	Bbls	WTI	—		—		$	96.13

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

Subsequent to March 31, 2013, we entered into the following gas hedges:

					Weighted Average Price
Period	Type	Volume/Day		Index(1)	Floor		Ceiling
May 13 – Jun 13	Collars	30,000	MMBtu	PEPL	$	3.50	$	4.50
Jul 13 – Dec 14	Collars	80,000	MMBtu	PEPL	$	3.51	$	4.57

(1) PEPL refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC.

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.

Since 2009, we have chosen not to apply hedge accounting treatment to our derivative contracts. Therefore, settlements on our derivative contracts do not impact our realized commodity prices. 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 the discussion of our net gain/loss on hedging activities below, in RESULTS OF OPERATIONS. Also, see Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

RESULTS OF OPERATIONS

Quarter ended March 31, 2013 vs. March 31, 2012

Net income for the first quarter of 2013 was $89.9 million, or $1.04 per diluted share. This compares to $106.1 million, or $1.23 per diluted share, for the same period in 2012. Increased revenue from higher sales volumes was mostly offset by lower realized commodity prices. Increased DD&A and transportation expense were the primary factors for the decrease in 2013 net income. These changes are discussed further in the analysis that follows.

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Commodity Sales	For the Three Months Ended March 31,				Percent Change Between	Price / Volume Change
(in thousands or as indicated)	2013		2012		2013/2012	Price			Volume		Total
Gas sales	$	101,121	$	85,153	19%	$	13,778		$	2,190	$	15,968
Oil sales	257,532		267,084		-4%	(38,702		)	29,150		(9,552		)
NGL Sales	56,875		59,014		-4%	(14,266		)	12,127		(2,139		)
Total sales	$	415,528	$	411,251	1%	$	(39,190	)	$	43,467	$	4,277

Total gas volume—MMcf	29,952		29,117		3%
Gas volume—MMcf per day	332.8		320.0
Average gas price—per Mcf	$	3.38	$	2.92	16%
Total oil volume—thousand barrels	2,984		2,690		11%
Oil volume—barrels per day	33,154		29,562
Average oil price—per barrel	$	86.31	$	99.28	-13%
Total NGL volume—thousand barrels	1,941		1,610		21%
NGL volume—barrels per day	21,562		17,687
Average NGL price—per barrel	$	29.31	$	36.66	-20%
Total equivalent production volumes — MMcfe per day	661.1		603.5		10%

Commodity sales of $415.5 million for the first quarter of 2013 were relatively flat, compared to $411.3 million in 2012. In 2013, our increased revenue from higher production volumes was largely offset by lower realized sales prices for oil and NGLs.

In 2013, our aggregate production volumes were 661.1 MMcfe per day, up 10% from 603.5 MMcfe per day in 2012. The period-over-period increase in production was a result of our successful Permian Basin and Cana-Woodford shale drilling programs.

Our 2013 gas production averaged 332.8 MMcf per day, up from 320.0 MMcf per day in 2012. This increase resulted in $2.2 million of higher revenue.

Oil production for 2013 averaged 33,154 barrels per day, compared to 29,562 barrels per day in 2012. The increase in oil production resulted in $29.2 million of additional revenue.

The average daily NGL production in 2013 was 21,562 barrels per day, up from 17,687 barrels per day in 2012. The increase in NGL volume added $12.1 million of revenue.

Our average realized gas price for 2013 increased to $3.38 per Mcf, from $2.92 per Mcf in 2012. The 16% increase in our realized gas price contributed $13.8 million in higher revenue in 2013.

Realized oil prices in 2013 averaged $86.31 per barrel, a decrease of 13% compared to the average price received in 2012 of $99.28. This decrease resulted in lower revenue of $38.7 million in 2013.

The average NGL price we received in 2013 was $29.31 per barrel, down from $36.66 per barrel in 2012. The decrease in 2013 sales due to the 20% decrease in realized NGL prices totaled $14.3 million.

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

We sometimes transport, process and market third-party gas that is associated with our gas. The table below reflects our pre-tax operating margin (revenues less direct expenses) for third-party gas gathering and processing as well as the marketing margin (revenues less purchases) for marketing third-party gas.

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	For the Three Months Ended March 31,
	2013			2012
Gas Gathering, Processing, and Marketing (in thousands):
Gas gathering, processing and other revenues	$	10,727		$	11,707
Gas gathering and processing costs	(6,156		)	(4,851		)
Gas gathering, processing and other margin	$	4,571		$	6,856

Gas marketing revenues, net of related costs	$	101		$	78

Changes in net margins from gas gathering, processing, marketing and other activities result from volumetric changes and overall market conditions.

In the first quarter of 2013, our total operating costs and expenses (not including gas gathering, processing and marketing costs, or income tax expense) were $275.7 million compared to $253.0 million in 2012. Analyses of the quarter-over-quarter differences are discussed below.

	For the Three Months Ended March 31,				Variance Between			Per Mcfe
	2013		2012		2013/2012			2013		2012
Operating costs and expenses (in thousands):
Depreciation, depletion and amortization (DD&A)	$	136,438	$	118,262	$	18,176		$	2.29	$	2.15
Asset retirement obligation	2,399		3,525		(1,126		)	$	0.04	$	0.06
Production	69,386		67,625		1,761			$	1.17	$	1.23
Transportation	18,634		13,316		5,318			$	0.31	$	0.24
Taxes other than income	25,128		25,160		(32		)	$	0.42	$	0.46
General and administrative	15,577		14,147		1,430			$	0.26	$	0.26
Stock compensation	3,605		4,534		(929		)	$	0.06	$	0.08
Loss on derivative instruments, net	1,603		4,088		(2,485		)	N/A		N/A
Other operating, net	2,932		2,340		592			N/A		N/A
	$	275,702	$	252,997	$	22,705

Our first quarter 2013 DD&A expense was $18.2 million (15%) higher than it was for the same period of 2012. This accounted for 80% of the overall increase in operating costs and expenses for 2013. On a per Mcfe basis, 2013 DD&A increased by $0.14, or 7%. The higher DD&A rate is primarily the result of increasing the cost of reserves added at a greater rate than the increase in future production.

Production costs consist of lease operating expense and workover expense as follows:

	For the Three Months Ended March 31,				Variance Between			Per Mcfe
(in thousands)	2013		2012		2013/2012			2013		2012
Lease operating expense	$	53,146	$	56,552	$	(3,406	)	$	0.89	$	1.03
Workover expense	16,240		11,073		5,167			0.28		0.20
	$	69,386	$	67,625	$	1,761		$	1.17	$	1.23

Lease operating expense in 2013 decreased by 6% compared to 2012. Increases in costs due to new well activity were more than offset by decreases associated with property sales and divestitures, which occurred subsequent to the first quarter of 2012. The lower rate per Mcfe in 2013 is primarily a function of increased production volumes and efficiencies of horizontal well operations.

Our workover expense was 47% higher in 2013 than it was in 2012. Workover costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.

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Transportation costs increased 40% to $18.6 million for 2013, compared to $13.3 million in 2012. About 80% of the increase is due to increased production from our Permian Basin and Cana-Woodford shale drilling programs. In addition, we have experienced increased transportation rates in our Mid-Continent region. Transportation costs will fluctuate regionally, based on increases or decreases in sales volumes, compression charges and fluctuation in the price of the fuel cost component.

Taxes other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based severance taxes, which are our largest component of these taxes, will fluctuate with increases and decreases in commodity prices.

General and administrative (G&A) costs were as follows:

	For the Three Months Ended March 31,				Variance Between
(in thousands)	2013		2012		2013/2012
G&A capitalized to oil and gas properties	$	18,679	$	18,335	$	344
G&A expense	15,577		14,147		1,430
	$	34,256	$	32,482	$	1,774
G&A expense per Mcfe	$	0.26	$	0.26	$	—

Stock compensation expense consists of non-cash 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 March 31,						Variance Between
	2013			2012			2013/2012
Performance-based restricted stock awards	$	2,685		$	3,589		$	(904	)
Service-based restricted stock awards	3,221			3,232			(11		)
Restricted stock	5,906			6,821			(915		)
Stock option awards	708			793			(85		)
Total stock compensation	6,614			7,614			(1,000		)
Less amounts capitalized to oil and gas properties	(3,009		)	(3,080		)	71
Stock compensation	$	3,605		$	4,534		$	(929	)

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.

Net gain or loss on derivative instruments includes both realized gains and losses on settlements of derivative contracts and unrealized gains and losses stemming from changes in the fair value of outstanding derivative instruments. We have not elected hedge accounting treatment for derivative contracts. Therefore, we recognize all realized settlements and unrealized changes in fair value in operating costs and expenses.

The following table reflects our net realized and unrealized (gains) and losses on derivative instruments:

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	For the Three Months Ended March 31,					Variance Between
(in thousands)	2013			2012		2013/2012
Realized (gain) on settlement of derivative instruments	$	(726	)	$	—	$	(726	)
Unrealized loss from changes to the fair value of the derivative instruments	2,329			4,088		$	(1,759	)
Loss on derivative instruments, net	$	1,603		$	4,088	$	(2,485	)

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 consists of costs related to various legal matters, most of which pertain to litigation, contract settlements and title and royalty issues. See Note 11 to the Consolidated Financial Statements for further information regarding litigation matters.

Other (income) and expense

	For the Three Months Ended March 31,						Variance Between
(in thousands)	2013			2012			2013/2012
Interest expense	$	13,206		$	8,668		$	4,538
Capitalized interest	(9,195		)	(7,804		)	(1,391		)
Other, net	(2,616		)	(4,726		)	2,110
	$	1,395		$	(3,862	)	$	5,257

Interest expense includes interest on debt and amortization of financing costs. Our 2013 interest expense increased by 52% compared to 2012. The increase was due to having an additional $400 million of outstanding senior notes in 2013.

We capitalize interest on non-producing leasehold costs, the costs of drilling and completing wells and constructing qualified assets. The 18% increase in capitalized interest for 2013 was a result of higher costs on which interest was calculated.

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, as well as miscellaneous asset sales and interest income. Most of the decrease in other, net was a result of lower income from sales of oil and gas well equipment and supplies.

Income tax expense

The components of our provision for income taxes were as follows:

	For the Three Months Ended March 31,
(in thousands)	2013			2012
Current taxes	$	—		$	—
Deferred taxes	53,176			62,943
	$	53,176		$	62,943
Combined Federal and state effective income tax rate	37.2		%	37.2		%

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Our effective tax rates will differ from the statutory rate of 35% primarily due to state income taxes and nondeductible expenses. See Note 8 to the Consolidated Financial Statements for further information regarding our income taxes.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our liquidity is highly dependent on the commodity price we receive for the oil, gas and NGLs we produce. Because commodity prices are market driven and are very volatile, we cannot predict future commodity prices. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth.

In the first quarter of 2013 our average realized price for natural gas was $3.38 per Mcf, an increase of 16% over the realized price for the same period of 2012. The average realized prices for oil and NGLs in the first quarter of 2013 decreased 13% and 20%, respectively, compared to 2012. Future prices for these commodities will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors.

We deal with volatility in commodity prices by maintaining flexibility in our capital investment program. In addition, we periodically hedge a portion of our oil and/or gas production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment. Based on current commodity prices, our 2013 exploration and development (E&D) capital expenditures are expected to be approximately $1.5 billion. Nearly all the capital is directed towards oil and liquids-rich gas opportunities in the Permian Basin and Cana-Woodford shale play. Actual amounts invested will depend on our calculated rates of return.

Our E&D expenditures have generally been funded by cash flow provided by operating activities (operating cash flow). During 2012, E&D expenditures of $1.6 billion were largely funded by operating cash flow and the sale of $306 million of non-strategic assets. We expect our 2013 E&D capital expenditures to be funded by operating cash flow and long-term debt. We have hedged a portion of our 2013 production to protect our operating cash flow for reinvestment.

We consider acquisition opportunities that play to our strengths and have drilling upside, however, the timing and size of acquisitions is unpredictable.

At March 31, 2013, our total debt outstanding was $870 million, which was comprised of $120 million of bank debt and $750 million of our 5.875% senior notes. Debt to total capitalization at March 31, 2013 was 20%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is: long-term debt of $870 million divided by long-term debt of $870 million plus stockholders’ equity of $3.555 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 meet our needs for our planned capital expenditures, working capital, debt servicing and dividend payments for 2013 and beyond.

Analysis of Cash Flow Changes

Cash flow provided by operating activities for the first quarter of 2013 was $247.1 million, down $4.8 million from $251.9 million for the same period in 2012. In 2013, increased revenues were more than offset by increased operating expenses.

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In the first quarter of 2013, our cash flow used in investing activities of $409.2 million was comparable to the $409.9 million used in investing activities in the 2012 period. In 2013 we had oil and gas and other capital expenditures of $410.2 million, which were partially offset by $1.0 million of asset sales. For the same period of 2012, expenditures for oil and gas and other capital costs were $411.2 million, and proceeds from asset sales were $1.3 million.

Net cash flow provided by financing activities was $111.1 million in the first quarter of 2013. In the same period of 2012, net cash flow provided by financing activities was $160 million. The $48.9 million decrease from 2012 to 2013 was primarily due to lower net bank borrowings during 2013.

Reconciliation of Adjusted Cash Flow from Operations

	For the Three Months Ended March 31,
(in thousands)	2013		2012
Net cash provided by operating activities	$	247,078	$	251,892
Change in operating assets and liabilities	45,343		51,064
Adjusted cash flow from operations	$	292,421	$	302,956

Management believes that the non-GAAP measure of adjusted cash flow from operations is useful information for investors. It is accepted by the investment community as a means of measuring the company’s ability to fund its capital program without reflecting 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 capitalized expenditures for our oil and gas acquisition, exploration, and development activities and property sales:

	For the Three Months Ended March 31,
(in thousands)	2013			2012
Acquisitions:
Proved	$	—		$	51
Unproved	250			1,922
	250			1,973
Exploration and development:
Land and seismic	31,310			37,212
Exploration and development	377,297			365,359
	408,607			402,571
Sales proceeds:
Proved	(818		)	(171		)
Unproved	(81		)	(942		)
	(899		)	(1,113		)
	$	407,958		$	403,431

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.

In the first quarter of 2013, our exploration and development expenditures of $408.6 million were relatively flat, compared to $402.6 million for the same period of 2012. Approximately 64% of our 2013 expenditures was for Permian Basin projects, primarily located in the Delaware Basin of both Texas

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and southeast New Mexico, which targeted the Bone Spring and Wolfcamp formations. Most of the remainder of our expenditures was in the Cana-Woodford shale play.

The following table reflects wells drilled and completed by region:

	For the Three Months Ended March 31,
	2013		2012
Gross wells
Permian Basin	35		39
Mid-Continent	52		33
Gulf Coast / Other	—		1
	87		73
Net wells
Permian Basin	27		27
Mid-Continent	20		12
Gulf Coast / Other	—		1
	47		40

% Gross wells completed as producers	100	%	95	%

As of March 31, 2013, we had 28 net wells awaiting completion: 15 Mid-Continent and 13 Permian Basin. We also had 17 operated rigs running: 13 in the Permian Basin and 4 in the Mid-Continent.

Full year 2013 E&D capital expenditures are expected to be approximately $1.5 billion, most of which will be directed towards drilling oil and liquids-rich gas wells in the Permian Basin and Cana-Woodford shale play. We expect our 2013 E&D capital expenditures to be funded from cash flow and long-term debt. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which has and will cause us to borrow and repay funds under our credit arrangement throughout the year.

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 a diversified portfolio that gives us the flexibility to adjust our capital expenditures based upon market conditions.

We had no significant acquisitions or property sales in the first quarters of 2013 and 2012. We will continue to evaluate potential 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. 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 are subject to a number of variables including success in finding and producing new reserves, 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 periodically use our credit facility to finance our working capital needs.

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During the first quarter of 2013, our total assets increased by $264.8 million to $6.6 billion, up from $6.3 billion at December 31, 2012. The increase was primarily due to a $281 million increase in our net oil and gas properties.

At March 31, 2013, our total liabilities increased to $3 billion, up $184.9 million from $2.8 billion at December 31, 2012. The increase resulted primarily from a net increase in long-term debt of $120.0 million and an increase in noncurrent deferred income taxes of $56.9 million.

At the end of the first quarter of 2013 our Stockholders’ equity totaled $3.6 billion, up $79.9 million from $3.5 billion at December 31, 2012. The increase resulted from net income of $89.9 million less dividends declared of $12.0 million.

Dividends

A quarterly cash dividend has been paid to shareholders since the first quarter of 2006. On February 26, 2013 the Board of Directors increased the cash dividend on our common stock from $0.12 to $0.14 per common share. Future dividend payments will depend on the company’s level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Working Capital Analysis

Our working capital fluctuates primarily as a result of our exploration and development activities, realized commodity prices and our operating activities. Working capital is also impacted by income tax receivables or payables, property sales, accrued G&A and changes in inventory balances.

Working capital decreased $25.4 million from a deficit of $175.7 million at year-end 2012 to a deficit of $201.1 million at March 31, 2013.

The decrease in working capital resulted primarily from the following:

· Cash and cash equivalents decreased by $51.0 million.

· Accrued liabilities related to our E&D expenditures increased by $15.2 million.

· Oil and gas well equipment and supplies decreased by $8.0 million.

Working capital decreases were partially offset by:

· An increase in operations related accounts receivable of $30.6 million.

· An $18.0 million decrease in accounts payable and accrued liabilities related to non-E&D expenditures.

Accounts receivable are a major component of working capital and include a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies and other end-users. The collection of receivables during the periods presented has been timely. Historically, losses associated with uncollectible receivables have not been significant.

Long-Term Debt

Debt at March 31, 2013 and December 31, 2012 consisted of the following:

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(in thousands)	March 31, 2013		December 31, 2012
Bank debt	$	120,000	$	—
5.875% Senior Notes due 2022	750,000		750,000
Total long-term debt	$	870,000	$	750,000

Bank Debt

We have a five-year senior unsecured revolving credit facility (Credit Facility), which matures July 14, 2016. At March 31, 2013, the Credit Facility provided for a borrowing base of $2 billion with aggregate commitments of $1 billion from our lenders.

Under our Credit Facility, the borrowing base is determined at the discretion of the lenders based on the value of our proved reserves. In April 2013, as part of their regular annual review, the lenders increased our borrowing base to $2.250 billion. Our aggregate commitments remain unchanged at $1 billion.

As of March 31, 2013, we had $120 million of bank debt outstanding at a weighted average interest rate of 1.96%. We also had letters of credit outstanding of $2.5 million, leaving an unused borrowing availability of $877.5 million. During the first quarter of 2013, we had average daily bank debt outstanding of $51.8 million, compared to $164.4 million for the same period in 2012. Our highest amount of bank borrowings outstanding during the first quarter of 2013 was $178 million occurring in mid-March. During the first quarter of 2012, the highest amount of outstanding bank borrowings was $275 million also occurring in mid-March.

At our 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 has a number of financial and non-financial covenants of which we were in compliance with at March 31, 2013. See Note 7 to the Consolidated Financial Statements for further information.

5.875% Notes due 2022

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 (Tender Offer) to purchase all of the outstanding 7.125% senior notes. The Tender Offer was completed in the second quarter of 2012.

Off Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of March 31, 2013, our material off—balance sheet arrangements included operating lease agreements, which are customary in the oil and gas industry.

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Contractual Obligations and Material Commitments

At March 31, 2013, we had contractual obligations and material commitments as follows:

	Payments Due by Period
Contractual obligations: (in thousands)	Total		1 Year or Less		2-3 Years			4-5 Years			More than 5 Years

Long-term debt(1)	$	870,000	$	—	$	—		$	120,000		$	750,000
Fixed-Rate interest payments(1)	418,594		44,063		88,125			88,125			198,281
Operating leases	125,407		9,044		18,623			19,295			78,445
Drilling commitments(2)	203,919		203,919		—			—			—
Gathering facilities and pipelines(3)	2,530		2,530		—			—			—
Asset retirement obligation	179,933		40,133		—		(4)	—		(4)	—		(4)
Other liabilities(5)	62,264		15,366		30,385			—			16,513
Firm Transportation	1,169		679		481			9			—

(1)	These amounts do not include interest on the $120 million of bank debt outstanding at March 31, 2013. See Item 3: Interest Rate Risk for more information regarding fixed and variable rate debt.
(2)	Most of our drilling commitments consist of obligations to finish drilling and completing wells in progress at March 31, 2013.
(3)	We have projects in New Mexico and Texas where we are constructing gathering facilities and pipelines. At March 31, 2013, we had commitments of $2.5 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.

At March 31, 2013, we had firm sales contracts to deliver approximately 27.4 Bcf of natural gas over the next 13 months. In total, our financial exposure would be approximately $104.2 million should we not deliver this gas. Our exposure will fluctuate with price volatility and actual volumes delivered. However, we believe Cimarex has no financial exposure from these contracts based on our current proved reserves and production levels. In the normal course of business we have various other delivery commitments which are not material individually or in the aggregate. 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 estimated net cash generated from operations and amounts available under our existing Credit Facility will be adequate to meet future liquidity needs.

2013 Outlook

Our 2013 E&D capital investment is presently expected to be approximately $1.5 billion. Nearly all of this capital will be used for drilling oil and liquids-rich gas wells in the Permian Basin and Cana-Woodford shale play. We have a large inventory of drilling opportunities, limited lease expirations and few service commitments. We regularly review our capital expenditures and may adjust our investments based on changes in commodity prices, service costs and drilling success. Actual amounts invested will depend on our calculated rates of return which are significantly influenced by commodity prices.

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 2013 is projected to be in the range of 675 to 705 MMcfe per day, or 8 — 13% growth over 2012. 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 all of 2012, realized prices averaged

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$89.25 per barrel of oil, $2.88 per Mcf of gas and $30.66 per barrel of NGL. For the first three months of 2013 our realized prices averaged $86.31 per barrel of oil, $3.38 per Mcf of gas, and $29.31 per barrel of NGL. Commodity prices can be volatile and the possibility of 2013 realized prices varying from those received in 2012 are high.

Certain expenses for 2013 on a per Mcfe basis are currently estimated as follows:

	2013
Production expense	$ 1.10	-	$ 1.22
Transportation expense	0.27	-	0.32
DD&A and asset retirement obligation	2.40	-	2.55
General and administrative	0.22	-	0.28
Production taxes (% of oil and gas revenue)	6.0%	-	6.5%

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Recent Accounting Developments

No significant accounting standards applicable to Cimarex have been issued during the quarter ended March 31, 2013.

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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, gas and NGL 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, gas and NGLs 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 oil contracts we have in place as of March 31, 2013:

				Weighted Average Price						Fair Value
Period	Type	Volume/Day	Index(1)	Floor		Ceiling		Swap		(in thousands)
Apr 13 – Dec 13	Collars	6,000 Bbls	WTI	$	85.00	$	102.31	—		$	(1,273	)
Apr 13 – Dec 13	Swaps	6,000 Bbls	WTI	—		—		$	96.13	$	(1,056	)

(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 2013 of $3.3 million.

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Subsequent to March 31, 2013, we entered into gas collars. See Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.

Counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily because we have mitigated our exposure to any single counterparty by contracting with numerous counterparties and because our derivative contracts are held with “investment grade” counterparties that are also part of our credit facility.

Interest Rate Risk

At March 31, 2013, our debt was comprised of the following:

(in thousands)	Fixed Rate Debt		Variable Rate Debt
Bank debt	$	—	$	120,000
5.875% Notes due 2022	750,000		—
Total long-term debt	$	750,000	$	120,000

As of March 31, 2013, the amounts outstanding under our five-year senior unsecured revolving credit facility bears interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. Our senior unsecured notes bear interest at a fixed rate of 5.875% and will mature on May 1, 2022.

We consider our interest rate exposure to be minimal because approximately 86% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the interest rate of our variable rate debt would increase our annual interest expense by $1.2 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 3 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding debt.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our management, with the participation of our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of March 31, 2013 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

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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 March 31, 2013, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended March 31, 2013, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II

ITEM 6 — EXHIBITS

31.1	Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

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

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

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SIGNATURES

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

May 7, 2013

	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)