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 September 30, 2012

Commission File No. 001-31446

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(303) 295-3995

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x 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		Smaller reporting company o
(Do not check if a smaller reporting company)

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

The number of shares of Cimarex Energy Co. common stock outstanding as of September 30, 2012 was 86,540,753.

Table of Contents

CIMAREX ENERGY CO.

Table of Contents

		Page

PART I

Item 1 — Financial Statements

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

	Consolidated statements of income and comprehensive income (unaudited) for the three and nine months ended September 30, 2012 and 2011	5

	Condensed consolidated statements of cash flows (unaudited) for the nine months ended September 30, 2012 and 2011	6

	Notes to consolidated financial statements (unaudited)	7

Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3 — Qualitative and Quantitative Disclosures about Market Risk		39

Item 4 — Controls and Procedures		41

PART II

Item 6 — Exhibits		42

Signatures		43

Table of Contents

GLOSSARY

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

Bbls—Barrels (of oil or natural gas liquids)

Bcf—Billion cubic feet

Bcfe—Billion cubic feet equivalent

Btu—British thermal unit

MBbls—Thousand barrels

Mcf—Thousand cubic feet (of natural gas)

Mcfe—Thousand cubic feet equivalent

MMBbls—Million barrels

MMBtu—Million British Thermal Units

MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

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

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

NGL—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

WTI—West Texas Intermediate

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

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

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

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

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PART I

ITEM 1 - Financial Statements

CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

	September 30,
	2012			December 31,
	(Unaudited)			2011
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	5,411		$	2,406
Receivables, net	335,011			359,409
Oil and gas well equipment and supplies	77,879			85,141
Deferred income taxes	2,126			2,723
Derivative instruments	416			—
Other current assets	6,715			8,216
Total current assets	427,558			457,895
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	11,116,783			9,933,517
Unproved properties and properties under development, not being amortized	661,626			607,219
	11,778,409			10,540,736
Less — accumulated depreciation, depletion and amortization	(6,767,943		)	(6,414,528		)
Net oil and gas properties	5,010,466			4,126,208
Fixed assets, net	134,776			118,215
Goodwill	691,432			691,432
Other assets, net	49,023			34,827
	$	6,313,255		$	5,428,577
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	64,988		$	79,788
Accrued liabilities	434,966			385,651
Derivative instruments	—			245
Revenue payable	151,798			150,655
Total current liabilities	651,752			616,339
Long-term debt	830,000			405,000
Deferred income taxes	1,128,642			974,932
Other liabilities	324,914			301,693
Total liabilities	2,935,308			2,297,964
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued	—			—
Common stock, $0.01 par value, 200,000,000 shares authorized, 86,540,753 and 85,774,084 shares issued, respectively	865			858
Paid-in capital	1,931,583			1,908,506
Retained earnings	1,445,011			1,221,263
Accumulated other comprehensive income (loss)	488			(14		)
	3,377,947			3,130,613
	$	6,313,255		$	5,428,577

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						For the Nine Months
	Ended September 30,						Ended September 30,
	2012			2011			2012			2011
	(In thousands, except per share data)
Revenues:
Gas sales	$	83,208		$	138,631		$	238,102		$	410,331
Oil sales	263,315			211,928			759,609			675,239
NGL sales	50,860			69,169			154,160			200,428
Gas gathering, processing and other	10,054			13,762			31,940			40,823
Gas marketing, net	(525		)	319			(741		)	797
	406,912			433,809			1,183,070			1,327,618
Costs and expenses:
Depreciation, depletion and amortization	135,987			104,681			375,486			279,554
Asset retirement obligation	3,512			3,578			9,478			8,223
Production	62,699			62,333			192,818			181,558
Transportation	14,481			13,754			40,966			41,559
Gas gathering and processing	5,496			6,263			15,302			17,472
Taxes other than income	24,095			30,533			72,738			98,625
General and administrative	14,742			9,390			41,523			34,734
Stock compensation, net	8,301			4,595			17,519			13,962
(Gain) loss on derivative instruments, net	5,329			(7,120		)	(661		)	(11,353		)
Other operating, net	2,236			2,379			7,295			8,095
	276,878			230,386			772,464			672,429

Operating income	130,034			203,423			410,606			655,189

Other (income) and expense:
Interest expense	13,223			9,279			35,570			27,599
Capitalized interest	(9,231		)	(7,253		)	(26,154		)	(21,830		)
Loss on early extinguishment of debt	—			—			16,214			—
Other, net	(6,159		)	(3,604		)	(18,714		)	(7,226		)

Income before income tax	132,201			205,001			403,690			656,646
Income tax expense	47,939			76,849			149,019			243,583
Net income	$	84,262		$	128,152		$	254,671		$	413,063

Earnings per share to common stockholders:
Basic
Distributed	$	0.12		$	0.10		$	0.36		$	0.30
Undistributed	0.85			1.39			2.58			4.51
	$	0.97		$	1.49		$	2.94		$	4.81

Diluted
Distributed	$	0.12		$	0.10		$	0.36		$	0.30
Undistributed	0.85			1.39			2.57			4.49
	$	0.97		$	1.49		$	2.93		$	4.79

Comprehensive income:
Net income	$	84,262		$	128,152		$	254,671		$	413,063
Other comprehensive income:
Change in fair value of investments, net of tax	238			(585		)	502			(417		)
Total comprehensive income	$	84,500		$	127,567		$	255,173		$	412,646

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	For the Nine Months
	Ended September 30,
	2012			2011
	(In thousands)

Cash flows from operating activities:
Net income	$	254,671		$	413,063
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	375,486			279,554
Asset retirement obligation	9,478			8,223
Deferred income taxes	150,648			288,986
Stock compensation, net	17,519			13,962
Derivative instruments, net	(661		)	(7,536		)
Loss on early extinguishment of debt	16,214			—
Changes in non-current assets and liabilities	7,930			3,719
Other, net	3,354			4,816
Changes in operating assets and liabilities:
(Increase) decrease in receivables, net	24,398			(32,229		)
Decrease in other current assets	8,763			30,736
Decrease in accounts payable and accrued liabilities	(31,652		)	(31,771		)
Net cash provided by operating activities	836,148			971,523
Cash flows from investing activities:
Oil and gas expenditures	(1,181,742		)	(1,152,676		)
Sales of oil and gas assets	12,167			104,163
Sales of other assets	550			111,837
Other expenditures	(42,913		)	(70,050		)
Net cash used by investing activities	(1,211,938		)	(1,006,726		)
Cash flows from financing activities:
Net increase in bank debt	25,000			—
Increase in other long-term debt	750,000			—
Decrease in other long-term debt	(363,595		)	—
Financing costs incurred	(13,821		)	(7,348		)
Dividends paid	(29,199		)	(23,998		)
Issuance of common stock and other	10,410			9,583
Net cash provided by (used in) financing activities	378,795			(21,763		)
Net change in cash and cash equivalents	3,005			(56,966		)
Cash and cash equivalents at beginning of period	2,406			114,126
Cash and cash equivalents at end of period	$	5,411		$	57,160

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY GO.

Notes to Consolidated Financial Statements

September 30, 2012

(Unaudited)

1. Basis of Presentation

The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in annual reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our 2011 Annual Report on Form 10-K.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods shown. Certain amounts in prior years’ financial statements have been reclassified to conform to the 2012 financial statement presentation. We have evaluated subsequent events through the date of this filing.

Oil and Gas Properties

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

If negative trends in pricing continue we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

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 allowance for doubtful accounts, 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 (in thousands).

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

	September 30, 2012		December 31, 2011
Receivables, net of allowance
Trade	$	77,617	$	58,519
Oil and gas sales	251,304		245,681
Gas gathering, processing, and marketing	5,543		7,565
Other	547		47,644
Receivables, net	$	335,011	$	359,409

Accounts payable
Trade	$	53,159	$	64,856
Gas gathering, processing, and marketing	11,829		14,932
Accounts payable	$	64,988	$	79,788

Accrued liabilities
Exploration and development	$	201,592	$	173,549
Taxes other than income	30,280		33,946
Other	203,094		178,156
Accrued liabilities	$	434,966	$	385,651

Recently Issued Accounting Standards

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

2. Derivative Instruments/Hedging

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

The following table summarizes our outstanding oil contracts as of September 30, 2012. We have not hedged any of our 2012 gas or NGL production. We have no hedges in place beyond December 2012. We have elected not to account for these derivatives as cash flow hedges.

Oil Contracts

Weighted Average Price

Fair Value

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

(in thousands)

Oct 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

416

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

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.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

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

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

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. The following table presents the estimated fair value of our oil contracts as of September 30, 2012 and December 31, 2011 (in thousands).

Asset/Liability	Balance Sheet Location	September 30, 2012		December 31, 2011
Asset	Current assets — Derivative instruments	$	416	$	—
Liability	Current liabilities — Derivative instruments	$	—	$	245

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Settlements gains (losses):
Natural gas contracts	$	—		$	1,865		$	—	$	5,591
Oil contracts	—			(118		)	—		(1,774		)
Total settlements gains (losses)	—			1,747			—		3,817

Unrealized gains (losses) on fair value change:
Natural gas contracts	—			(316		)	—		(3,221		)
Oil contracts	(5,329		)	5,689			661		10,757
Total unrealized gains (losses) on fair value change	(5,329		)	5,373			661		7,536
Gain (loss) on derivative instruments, net	$	(5,329	)	$	7,120		$	661	$	11,353

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

3. Fair Value Measurements

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

The following tables provide fair value measurement information for certain assets and liabilities as of September 30, 2012 and December 31, 2011 (in thousands).

September 30, 2012:	Carrying Amount			Fair Value

Financial Assets (Liabilities):
Bank debt	$	(80,000	)	$	(80,000	)
5.875% Notes due 2022	$	(750,000	)	$	(793,125	)
Derivative instruments	$	416		$	416

December 31, 2011:	Carrying Amount			Fair Value

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

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

Debt

The fair value of our bank debt at September 30, 2012 and December 31, 2011 was estimated to approximate the carrying amount because the floating rate interest paid on such debt was set for periods of three months or less.

The fair value for our 5.875% and 7.125% fixed rate notes was based on their last traded value before period end.

Derivative Instruments (Level 2)

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

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

nature of these assets and liabilities. At both September 30, 2012 and December 31, 2011, the aggregate allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $6.4 million.

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.

4. Capital Stock

A summary of our common stock activity for the nine months ended September 30, 2012 follows (in thousands):

Issued and outstanding as of December 31, 2011		85,774
Restricted shares issued under compensation plans, net of reacquired stock and cancellations		262
Option exercises, net of cancellations		505
Issued and outstanding as of September 30, 2012		86,541

Dividends

In September 2012, the Board of Directors declared a cash dividend of $0.12 per share on our common stock. The dividend is payable on December 3, 2012 to stockholders of record on November 15, 2012. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

5. Stock-based Compensation

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Restricted stock and units	$	10,769		$	7,013		$	24,319		$	20,242
Stock options	692			551			2,117			2,731
	11,461			7,564			26,436			22,973
Less amounts capitalized to oil and gas properties	(3,160		)	(2,969		)	(8,917		)	(9,011		)
Compensation expense	$	8,301		$	4,595		$	17,519		$	13,962

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

Restricted Stock and Units

The following tables provide information about restricted stock awards granted during the three and nine months ended September 30, 2012 and 2011.

	Three Months Ended September 30, 2012			Three Months Ended September 30, 2011
	Number of Shares	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Grant-Date Fair Value
Performance-based stock awards	24,000	$	48.24	—	$	—
Service-based stock awards	238,100	$	53.19	204,100	$	85.32
Total restricted stock awards	262,100	$	52.73	204,100	$	85.32

	Nine Months Ended September 30, 2012			Nine Months Ended September 30, 2011
	Number of Shares	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Grant-Date Fair Value
Performance-based stock awards	262,770	$	43.22	363,758	$	73.01
Service-based stock awards	294,198	$	54.03	271,053	$	91.11
Total restricted stock awards	556,968	$	48.93	634,811	$	80.74

Performance-based awards are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. The material terms of performance goals applicable to these awards were approved by stockholders in May 2010. The other restricted shares granted in 2012 have service-based vesting schedules of three to five years.

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

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

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Performance-based stock awards	$	7,719		$	4,116		$	15,390		$	12,185
Service-based stock awards	3,050			2,897			8,929			8,023
Restricted unit awards	—			—			—			34
	10,769			7,013			24,319			20,242
Less amounts capitalized to oil and gas properties	(2,912		)	(2,696		)	(8,081		)	(7,405		)
Restricted stock and units compensation expense	$	7,857		$	4,317		$	16,238		$	12,837

The 2012 compensation cost for the performance-based awards includes $3.9 million of accelerated compensation expense related to the death of our Chairman, F.H. Merelli.

Unamortized compensation cost related to unvested restricted shares at September 30, 2012 was $63 million, which we expect to recognize over a weighted average period of approximately 2.3 years.

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

	Restricted Stock		Restricted Units
Outstanding as of January 1, 2012	2,019,552		59,470
Vested	(582,172	)	—
Converted to stock	—		(10,632	)
Granted	556,968		—
Canceled	(134,813	)	—
Outstanding as of September 30, 2012	1,859,535		48,838
Vested included in outstanding	N/A		48,838

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

Stock Options

The following tables provide information about stock options granted in 2012 and 2011:

	Three Months Ended September 30, 2012					Three Months Ended September 30, 2011
	Options	Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price		Options	Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price
Granted to certain executive officers	—	$	—	$	—	90,000	$	19.17	$	55.96
Granted to other employees	152,800	$	20.55	$	51.92	91,300	$	34.20	$	86.01
	152,800					181,300

	Nine Months Ended September 30, 2012					Nine Months Ended September 30, 2011
	Options	Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price		Options	Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price
Granted to certain executive officers	—	$	—	$	—	90,000	$	19.17	$	55.96
Granted to other employees	152,800	$	20.55	$	51.92	91,300	$	34.20	$	86.01
	152,800					181,300

Options granted under our 2011 and 2002 plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years. The plans provide that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant.

Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Stock option awards	$	692		$	551		$	2,117		$	2,731
Less amounts capitalized to oil and gas properties	(248		)	(273		)	(836		)	(1,606		)
Stock option compensation expense	$	444		$	278		$	1,281		$	1,125

As of September 30, 2012, there was $5.6 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost pro rata over a weighted-average period of approximately 2.2 years.

Information about outstanding stock options is summarized below:

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

	Options		Weighted Average Exercise Price		Weighted Average Remaining Term	Aggregate Intrinsic Value (in thousands)
Outstanding as of January 1, 2012	1,113,334		$	37.94
Exercised	(505,057	)	$	20.61
Granted	152,800		$	51.92
Canceled	(2,650	)	$	56.74
Forfeited	(13,106	)	$	61.19
Outstanding as of September 30, 2012	745,321		$	52.07	5.8 Years	$	8,074
Exercisable as of September 30, 2012	418,198		$	45.64	5.3 Years	$	6,759

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

	Nine Months Ended September 30,
	2012			2011
Number of options exercised	505,057			65,325
Cash received from option exercises	$	10,410		$	2,602
Tax benefit from option exercises included in paid-in-capital	$	76	(1)	$	1,298
Intrinsic value of options exercised	$	20,232		$	3,558

(1) No tax benefit is recorded until the benefit reduces current taxes payable. The amount shown relates to a prior period adjustment.

The following summary reflects the status of non-vested stock options as of September 30, 2012 and changes during the year:

	Options		Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price
Non-vested as of January 1, 2012	308,411		$	23.37	$	60.75
Granted	152,800		$	20.55	$	51.92
Vested	(120,982	)	$	20.38	$	50.83
Forfeited	(13,106	)	$	24.47	$	61.19
Non-vested as of September 30, 2012	327,123		$	23.12	$	60.28

6. Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability, which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool.

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

Asset retirement obligation at January 1, 2012	$	183,361
Liabilities incurred	17,079
Liability settlements and disposals	(15,689		)
Accretion expense	7,600
Revisions of estimated liabilities	14,490
Asset retirement obligation at September 30, 2012	206,841
Less current obligation	(52,579		)
Long-term asset retirement obligation	$	154,262

7. Long-Term Debt

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

	September 30, 2012		December 31, 2011
Bank debt	$	80,000	$	55,000
7.125% Senior Notes due 2017	—		350,000
5.875% Senior Notes due 2022	750,000		—
Total long-term debt	$	830,000	$	405,000

Bank Debt

We have a five-year senior unsecured revolving credit facility (“Credit Facility”) which matures July 14, 2016. The Credit Facility provides for a borrowing base of $2 billion with aggregate commitments of $1 billion (increased from $800 million in July 2012) from our lenders.

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, 2013.

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

The Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to: incur additional indebtedness, pay dividends, repurchase our common stock, or sell assets. As of September 30, 2012, 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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

governed by an indenture containing certain covenants, events of default and other restrictive provisions. We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and thereafter.

Net proceeds from the offering approximated $737 million, after deducting underwriting discounts, commissions and estimated expenses of the offering. We used a portion of the net proceeds to retire our 7.125% senior notes. The remaining net proceeds were used for general corporate purposes, including repayment of $232 million outstanding under our Credit Facility.

7.125% Notes due 2017

In May, 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. On March 22, 2012 we commenced a cash tender offer (the “Tender Offer”) to purchase all of the outstanding 7.125% senior notes.

Under the terms of the Tender Offer, holders who tendered their notes on or prior to April 4, 2012 received (i) $1,035.63 per $1,000.00 in principal amount of notes tendered plus (ii) a consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. Through April 18, 2012, a total of $300,163,000 of notes had been redeemed. In May 2012, the remaining notes were redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012.

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

8. Income Taxes

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Current benefit	$	(1,629	)	$	(44,081	)	$	(1,629	)	$	(45,403	)
Deferred taxes	49,568			120,930			150,648			288,986
	$	47,939		$	76,849		$	149,019		$	243,583

At December 31, 2011, the company had a U.S. net tax operating carryforward of approximately $86.9 million which would expire in 2031. We believe that the carryforward will be utilized before it expires. We also had an alternative minimum tax credit carryforward of approximately $2.9 million.

At September 30, 2012, we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 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 for tax years 2005-2011 for examination.

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and nondeductible expenses. The effective income tax rates for the nine months ended September 30, 2012 and September 30, 2011 were 36.9% and 37.1%, respectively.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Cash paid during the period for:
Interest expense (including capitalized amounts)	$	1,017	$	1,345	$	15,374	$	16,153
Interest capitalized	$	432	$	994	$	11,304	$	12,777
Income taxes	$	—	$	—	$	375	$	1,671
Cash received for income taxes	$	57	$	89	$	49,293	$	25,094

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

10. Earnings per Share

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net income	$	84,262		$	128,152		$	254,671		$	413,063
Less distributed earnings (dividends declared during the period)	(10,391		)	(8,581		)	(31,011		)	(25,709		)
Undistributed earnings for the period	$	73,871		$	119,571		$	223,660		$	387,354

Allocation of undistributed earnings:
Basic allocation to unrestricted common stockholders	$	72,243		$	116,686		$	218,731		$	378,009
Basic allocation to participating securities	$	1,628		$	2,885		$	4,929		$	9,345
Diluted allocation to unrestricted common stockholders	$	72,249		$	116,699		$	218,750		$	378,054
Diluted allocation to participating securities	$	1,622		$	2,872		$	4,910		$	9,300

Basic Shares Outstanding
Unrestricted outstanding common shares	84,681			83,736			84,681			83,736
Add participating securities:
Restricted stock outstanding	1,859			2,006			1,859			2,006
Restricted stock units outstanding	49			64			49			64
Total participating securities	1,908			2,070			1,908			2,070
Total Basic Shares Outstanding	86,589			85,806			86,589			85,806

Fully Diluted Shares
Unrestricted outstanding common shares	84,681			83,736			84,681			83,736
Incremental shares from assumed exercise of stock options	316			379			340			415
Fully diluted common stock	84,997			84,115			85,021			84,151
Participating securities	1,908			2,070			1,908			2,070
Total Fully Diluted Shares	86,905			86,185			86,929			86,221

Basic earnings per share
Unrestricted common stockholders:
Distributed earnings	$	0.12		$	0.10		$	0.36		$	0.30
Undistributed earnings	0.85			1.39			2.58			4.51
	$	0.97		$	1.49		$	2.94		$	4.81
Participating securities:
Distributed earnings	$	0.12		$	0.10		$	0.36		$	0.30
Undistributed earnings	0.85			1.39			2.58			4.51
	$	0.97		$	1.49		$	2.94		$	4.81
Fully diluted earnings per share
Unrestricted common stockholders:
Distributed earnings	$	0.12		$	0.10		$	0.36		$	0.30
Undistributed earnings	0.85			1.39			2.57			4.49
	$	0.97		$	1.49		$	2.93		$	4.79
Participating securities:
Distributed earnings	$	0.12		$	0.10		$	0.36		$	0.30
Undistributed earnings	0.85			1.39			2.57			4.49
	$	0.97		$	1.49		$	2.93		$	4.79

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

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

	September 30,
	2012	2011
Stock options	745,321	1,126,670
Restricted stock	1,859,535	2,005,702
Restricted units	48,838	64,470

Certain stock options considered to be anti-dilutive for the three months ended September 30, 2012 and 2011 were 399,855 and 264,767, respectively. For the nine months ended September 30, 2012 and 2011, certain stock options considered to be anti-dilutive were 408,266 and 203,676, respectively.

11. Commitments and Contingencies

Litigation

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

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

On August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On 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 accrued liability for this lawsuit for the nine months ended September 30, 2012 (in thousands):

Outstanding at January 1, 2012	$	146,310
Accrued post-judgment interest and costs	6,788
Outstanding at September 30, 2012	$	153,098

Other litigation

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2012

(Unaudited)

Other

We have drilling commitments of approximately $261.4 million consisting of obligations to finish drilling and completing wells in progress at September 30, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are $12.1 million to secure the use of drilling rigs and $8.4 million to secure certain dedicated services associated with completion activities.

We have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At September 30, 2012, we had commitments of $4 million relating to this construction.

At September 30, 2012, we had firm sales contracts to deliver approximately 37.9 Bcf of natural gas over the next 19 months. If this gas is not delivered, our financial commitment would be approximately $67.3 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current reserves and production levels.

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

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

12. Property Sales and Acquisitions

We sold various interests in oil and gas properties for $12.2 million during the first nine months of 2012 and we had property acquisitions of $11.3 million. Subsequent to September 30, 2012, we had a property acquisition of $21 million located in Culberson County, Texas.

During the first nine months of 2011, we sold all of our interests in assets located in Sublette County, Wyoming for $195.5 million (after purchase price adjustments). The assets sold principally consisted of a gas processing plant under construction and related assets ($111.4 million) and 210 Bcf of proved undeveloped gas reserves ($84.1 million). Also during this period, we sold various interests in other oil and gas properties for $20.6 million and we had property acquisitions of approximately $42 million. Of our total acquisitions, $39 million was in our western Oklahoma Cana-Woodford shale play and $3 million was in the Permian basin.

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

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

OVERVIEW

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

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

To supplement our growth and to provide for new drilling opportunities, we also consider property acquisitions and mergers that allow us to enhance our competitive position in existing core areas or to add new areas. In order to achieve a consistent rate of growth and mitigate risk we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We intend to deal with volatility in the current commodity price environment by maintaining flexibility in our planned capital investment program.

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

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

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

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

Third quarter 2012 summary of financial and operating results:

· Third quarter production volumes averaged 635.1 MMcfe per day, compared to 592.0 MMcfe per day for the third quarter of 2011.

· Oil, gas and NGL sales for the third quarter of 2012 were $397.4 million, compared to $419.7 million a year earlier.

· Our average realized oil price of $88.18 per barrel was relatively flat compared to $87.64 per barrel in 2011.

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· Our average realized gas price decreased 39% to $2.79 per Mcf versus $4.57 per Mcf in 2011.

· Our average realized NGL price decreased 34% to $28.55 per barrel compared to $43.11 per barrel in 2011.

· Our third quarter cash flow provided by operating activities was $261.2 million versus $332.4 million in the prior year.

· Net income of $84.3 million ($0.97 per diluted share) declined from net income of $128.2 million ($1.49 per diluted share) in 2011.

· Total debt increased by $425 million to $830 million compared to $405 million at year-end 2011.

· We drilled 93 gross (47 net) wells during the third quarter of 2012, completing 99% as producers. In the third quarter of 2011 we drilled 82 gross (48 net) wells completing 94% as producers.

Revenues

Our revenues are derived from the sale of our oil, gas and NGL production and do not include the effects of the settlements of our commodity hedging contracts. While our revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our results of operations. Compared to 2011, our 2012 average realized gas price decreased by 41% and our average realized NGL price decreased by 27%. The average price we have received for oil in 2012 has decreased by 2%. The prices we receive are determined by prevailing market conditions. Regional and worldwide economic and geopolitical activity, weather and other variable factors influence market conditions, which often result in significant volatility in commodity prices.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Gas Prices:
Average Henry Hub price ($/Mcf)	$	2.80	$	4.20	$	2.58	$	4.21
Average realized sales price ($/Mcf)	$	2.79	$	4.57	$	2.71	$	4.59
Oil Prices:
Average WTI Cushing price ($/Bbl)	$	92.22	$	89.76	$	96.21	$	95.49
Average realized sales price ($/Bbl)	$	88.18	$	87.64	$	91.67	$	93.08
NGL Prices:
Average realized sales price ($/Bbl)	$	28.55	$	43.11	$	31.35	$	42.99

On an energy equivalent basis, 53% of our aggregate 2012 production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in an $8.8 million change in our gas revenues. Similarly, 47% of our production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales price would have resulted in a $13.2 million change in our combined oil and NGL revenues.

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Production and other operating expenses

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

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

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

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

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

At September 30, 2012 the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. However, the amount of the excess has declined approximately 80% since December 31, 2011. As of September 30, 2012, a decline of 4% or more in the value of the ceiling limitation would have resulted in an impairment. If negative trends continue we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

General and administrative (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. While we expect these costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth. Our G&A expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting.

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

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

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

Hedging

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

For 2012, we hedged about half of our anticipated oil production. We do not have any of our gas or NGL production hedged. We have had no cash settlements on these contracts in the first nine months of 2012. We have no hedges in place for 2013.

We entered into oil and gas contracts relative to our 2011 production which approximated 40 to 45% of our anticipated 2011 oil production and 5 to 6% of projected gas production. Those contracts had net cash settlements in the first nine months of 2011 of $3.8 million.

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

Oil Contracts

Weighted
Average Price

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

Oct 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

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

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

RESULTS OF OPERATIONS

Three Months and Nine Months Ended September 30, 2012 vs. September 30, 2011

Net income for the third quarter of 2012 was $84.3 million, or $0.97 per diluted share. This compares to $128.2 million, or $1.49 per diluted share, for the third quarter of 2011. Lower net income in the third quarter of 2012 resulted primarily from decreased revenues due to lower realized commodity prices, which were partially offset by increased production volumes. Higher operating expenses in 2012 also contributed to the lower net income.

For the nine months ended September 30, 2012, net income was $254.7 million, or $2.93 per diluted share, down from net income of $413.1 million, or $4.79 per diluted share, for the first nine months of 2011. In the 2012 period we had decreased revenues due to lower realized commodity prices,

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which were partially offset by higher production volumes. In 2012 higher operating expenses and a loss on early extinguishment of debt were also factors in the decrease in net income.

These changes are discussed further in the analysis that follows.

					Percent
					Change
Commodity Sales					Between	Price/Volume Analysis
(in thousands or as indicated)	2012		2011		2012/2011	Price			Volume			Variance
For the Three Months Ended September 30,
Gas sales	$	83,208	$	138,631	-40%	$	(53,099	)	$	(2,324	)	$	(55,423	)
Oil sales	263,315		211,928		-24%	1,612			49,775			51,387
NGL sales	50,860		69,169		-26%	(25,931		)	7,622			(18,309		)
	$	397,383	$	419,728		$	(77,418	)	$	55,073		$	(22,345	)

For the Nine Months Ended September 30,
Gas sales	$	238,102	$	410,331	-42%	$	(165,111	)	$	(7,118	)	$	(172,229	)
Oil sales	759,609		675,239		12%	(11,685		)	96,055			84,370
NGL sales	154,160		200,428		-23%	(57,234		)	10,966			(46,268		)
	$	1,151,871	$	1,285,998		$	(234,030	)	$	99,903		$	(134,127	)

	For the Three Months Ended September 30,				Percent Change Between	For the Nine Months Ended September 30,				Percent Change Between
	2012		2011		2012/2011	2012		2011		2012/2011
Total gas volume — MMcf	29,831		30,329		-2%	87,825		89,367		-2%
Gas volume — MMcf per day	324.2		329.7			320.5		327.4
Average gas price — per Mcf	$	2.79	$	4.57	-39%	$	2.71	$	4.59	-41%

Total oil volume — thousand barrels	2,986		2,418		23%	8,287		7,254		14%
Oil volume — barrels per day	32,456		26,284			30,243		26,572
Average oil price — per barrel	$	88.18	$	87.64	1%	$	91.67	$	93.08	-2%

Total NGL volume — thousand barrels	1,781		1,604		11%	4,917		4,662		5%
NGL volume — barrels per day	19,360		17,438			17,944		17,078
Average NGL price — per barrel	$	28.55	$	43.11	-34%	$	31.35	$	42.99	-27%

Total MMcfe per day	635.1		592.0		7%	609.6		589.3		3%

Commodity sales for the third quarter of 2012 totaled $397.4 million, compared to $419.7 million in 2011. The decrease of $22.3 million was due to lower realized sales prices for gas and NGL, which had a negative impact of $77.4 million. The decrease from lower sales prices was partially offset by higher sales from increased oil and NGL production during the third quarter of 2012.

For the first nine months of 2012 commodity sales totaled $1.152 billion. For the same period in 2011, commodity sales were $1.286 billion. The $134.1 million decrease was attributable to a decrease of $234 million for lower realized commodity prices in 2012, which were partially offset by higher sales from oil and NGL production volumes compared to 2011.

Our third quarter 2012 aggregate production volumes were 635.1 MMcfe per day, up 7% from 592.0 MMcfe per day for the same period in 2011. Aggregate production volumes for the first nine months of 2012 were 609.6 MMcfe per day, up 3% from 589.3 MMcfe per day for the 2011 period. Production volumes continue to increase from our Cana-Woodford shale play and Permian Basin operations as a result of our successful drilling programs. However, these increases have been partially offset by decreased Gulf Coast production. The lower output from the Gulf Coast results from natural declines in wells we drilled in previous years.

In the third quarter of 2012 our gas production averaged 324.2 MMcf per day, compared to 329.7 MMcf per day in 2011. This 2% decrease resulted in $2.3 million of lower gas revenue for the third quarter of 2012. During the first nine months of 2012 our gas production averaged 320.5 MMcf per

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day, a 2% decrease from the 2011 average of 327.4 MMcf per day. The decrease in gas production for the first nine months of 2012 resulted in $7.1 million of lower gas revenue compared to the same period of 2011.

Our oil production during the third quarter of 2012 averaged 32.5 thousand barrels per day. For the same period of 2011 our average daily oil production was 26.3 thousand barrels per day. The 23% increase in oil production for the 2012 quarter resulted in an additional $49.8 million of oil sales revenue. During the first nine months of 2012 our oil production averaged 30.2 thousand barrels per day, up from 26.6 thousand barrels per day in 2011, or a 14% increase. The increased oil production contributed $96.1 million of additional revenue for the first nine months of 2012 compared to the same period of 2011.

Our third quarter 2012 NGL volumes increased to 19.4 thousand barrels per day compared to 17.4 thousand barrels per day in 2011, or an increase of 11%. The increase resulted in $7.6 million of additional revenue in the 2012 period. NGL volumes for the first nine months of 2012 averaged 17.9 thousand barrels a day, up from 17.1 thousand barrels a day for the same period of 2011. This 5% increase provided an additional $11 million of revenue in 2012.

The year over year increases in our oil and NGL production volumes reflect our focus on oil drilling or liquids-rich gas in the Permian and Cana-Woodford basins.

In the third quarter of 2012 our average realized gas price of $2.79 per Mcf, was down 39% compared to the average price of $4.57 per Mcf realized in the third quarter of 2011. The price decline accounted for $53.1 million of decreased sales revenue in the third quarter of 2012. Our average realized gas price of $2.71 per Mcf for the first nine months of 2012 was 41% lower than the 2011 average realized price of $4.59. The lower realized price received in 2012 resulted in decreased gas revenues of $165.1 million in the first nine months of 2012 compared to 2011.

We realized an average oil price of $88.18 per barrel for the third quarter of 2012 versus $87.64 for the same period of 2011. This 1% increase resulted in higher oil sales revenue of $1.6 million in the 2012 quarter. For the first nine months of 2012 we realized an average oil price of $91.67 per barrel, which was 2% lower than the average price of $93.08 we received for the same period in 2011. This decrease accounted for $11.7 million of lower sales revenue for the nine months ended September 30, 2012.

Our average realized price per barrel of NGL in the third quarter of 2012 was $28.55. This price was 34% lower than the $43.11 average price received in the third quarter of 2011, and accounted for decreased NGL revenue of $25.9 million. In the first nine months of 2012 the average NGL price per barrel we received was $31.35, down from $42.99 for the same period of 2011. The 27% decrease in realized NGL price resulted in lower sales of $57.2 million for the first nine months of 2012.

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

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Gas Gathering, Processing, Marketing and Other	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands):	2012			2011			2012			2011
Gas gathering, processing and other revenues	$	10,054		$	13,762		$	31,940		$	40,823
Gas gathering and processing costs	(5,496		)	(6,263		)	(15,302		)	(17,472		)
Gas gathering, processing and other margin	$	4,558		$	7,499		$	16,638		$	23,351

Gas marketing revenues, net of related costs	$	(525	)	$	319		$	(741	)	$	797

We sometimes transport, process and market third-party gas that is associated with our gas. In the third quarter of 2012, third-party gas gathering, processing and other contributed $4.6 million of pre-tax operating margin (revenues less direct expenses) versus $7.5 million in 2011. Our gas marketing margin (revenues less purchases) was a loss of $525 thousand for the third quarter of 2012, compared to $319 thousand of income in 2011.

For the nine months ended September 30, 2012 and 2011, the operating margin for the third party gas gathering, processing and other was $16.6 million and $23.4 million, respectively. For the first nine months of 2012 our gas marketing margin was a loss of $741 thousand compared to income of $797 thousand in the 2011 period.

The lower net margins between 2012 and 2011 from gas gathering, processing, marketing and other activities are primarily the result of lower volumes and prices associated with third party gas.

Operating costs and expenses	For the Three Months Ended September 30,					Variance Between			For the Nine Months Ended September 30,						Variance Between
(in thousands):	2012		2011			2012/2011			2012			2011			2012/2011
Depreciation, depletion and amortization	$	135,987	$	104,681		$	31,306		$	375,486		$	279,554		$	95,932
Asset retirement obligation	3,512		3,578			(66		)	9,478			8,223			1,255
Production	62,699		62,333			366			192,818			181,558			11,260
Transportation	14,481		13,754			727			40,966			41,559			(593		)
Taxes other than income	24,095		30,533			(6,438		)	72,738			98,625			(25,887		)
General and administrative	14,742		9,390			5,352			41,523			34,734			6,789
Stock compensation, net	8,301		4,595			3,706			17,519			13,962			3,557
(Gain)/loss on derivative instruments, net	5,329		(7,120		)	12,449			(661		)	(11,353		)	10,692
Other operating, net	2,236		2,379			(143		)	7,295			8,095			(800		)
	$	271,382	$	224,123		$	47,259		$	757,162		$	654,957		$	102,205

Total operating costs and expenses (not including gas gathering, marketing and processing costs, or income tax expense) increased 21% to $271.4 million in the third quarter of 2012 compared to $224.1 million for the third quarter of 2011. For the first nine months of 2012 operating costs were $757.2 million, or an increase of 16% over the same period of 2011. Analyses of the year over year differences are discussed below.

DD&A increased $31.3 million from $104.7 million in the third quarter of 2011 to $136.0 million in the same period of 2012. On a unit of production basis, DD&A was $2.33 per Mcfe for the third quarter of 2012 compared to $1.92 in the 2011 quarter. For the first nine months of 2012, DD&A was $375.5 million, up $95.9 million compared to $279.6 million in 2011. On a unit of production basis, the nine month DD&A rate for 2012 was $2.25 per Mcfe, versus $1.74 per Mcfe for the 2011 period. The 2012 period increases in DD&A result primarily from increasing the cost of reserves added at a greater rate than the increase in future production. These increases account for most of the aggregate increases in total operating costs and expenses for the periods.

In the third quarter of 2012 our production costs were $62.7 million ($1.07 per Mcfe) compared to $62.3 million ($1.15 per Mcfe) in the third quarter of 2011. Production costs for the first nine months of 2012 were $192.8 million ($1.15 per Mcfe), up 6% from $181.6 million ($1.13 per Mcfe) for the same

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period of 2011. Our production costs consist of lease operating expense and workover expense as follows (in thousands):

	For the Three Months Ended September 30,				Variance Between			For the Nine Months Ended September 30,				Variance Between
	2012		2011		2012/2011			2012		2011		2012/2011

Lease operating expense	$	52,100	$	51,245	$	855		$	163,076	$	151,388	$	11,688
Workover expense	10,599		11,088		(489		)	29,742		30,170		(428		)
	$	62,699	$	62,333	$	366		$	192,818	$	181,558	$	11,260

Our third quarter 2012 lease operating expense of $52.1 million was relatively flat compared to $51.2 million for the same period of 2011. On a unit of production basis, lease operating expense in the third quarter of 2012 declined to $0.89 per Mcfe, down 5.3%, compared to $0.94 per Mcfe for the third quarter of 2011.

Lease operating expense of $163.1 million for the first nine months of 2012 increased $11.7 million (7.7%) compared to $151.4 million for 2011. The increase was due to higher water disposal, compressor rental and well servicing costs associated with wells coming on line from our successful Permian Basin and Cana-Woodford shale drilling programs. Lease operating expense was $0.98 per Mcfe for the first nine months of 2012, up 4.3% compared to $0.94 for the 2011 period.

Workover expense will vary from period to period based on the amount of maintenance and remedial activity planned and/or required during the period.

Transportation costs increased to $14.5 million ($0.25 per Mcfe) in the third quarter of 2012 from $13.8 million ($0.25 per Mcfe) in 2011. For the first nine months of 2012 transportation costs were $41.0 million ($0.25 per Mcfe) versus $41.6 million ($0.26 per Mcfe) for 2011. Generally, transportation costs will fluctuate based on increases or decreases in sales volumes, compression charges and fluctuations in the price of the fuel cost component.

In the third quarter of 2012, taxes other than income decreased 21% from $30.5 million in 2011 to $24.1 million in 2012. As a percentage of revenue, taxes other than income were 6.1% and 7.3% for the third quarters of 2012 and 2011, respectively. For the nine months ended September 30, 2012, taxes other than income were $72.7 million (6.3% of revenue) compared to $98.6 million (7.7% of revenue) for the 2011 period. Generally, taxes other than income will vary based on increases or decreases in production volumes and changes in commodity prices. In addition, the 2012 periods benefited from certain horizontal drilling and deep well tax credits.

General and administrative costs were as follows (in thousands):

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
G&A expense	$	14,742	$	9,390	$	41,523	$	34,734
G&A capitalized to oil & gas properties	$	16,880	$	10,483	$	50,831	$	41,143

Our G&A expense for the third quarter of 2012 increased by $5.4 million (57%) compared to the third quarter of 2011. For the nine months ended September 30, 2012, G&A expense increased by $6.8 million (20%) compared to the same period of 2011. The increases in the 2012 periods include $3.6 million of death benefits paid to the estate of our Chairman of the Company, F.H. Merelli, as per his employment contract. The 2012 periods were also impacted by higher compensation costs.

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Stock compensation expense, net consists of noncash charges resulting from the issuance of restricted stock, restricted stock units and stock option awards net of amounts capitalized. The 2012 costs for the performance-based awards include $3.9 million of accelerated compensation expense related to the death of our Chairman, F.H. Merelli. We have recognized non-cash stock-based compensation cost as follows (in thousands):

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
Performance-based restricted stock awards	$	7,719		$	4,116		$	15,390		$	12,185
Service-based restricted stock awards	3,050			2,897			8,929			8,023
Restricted unit awards	—			—			—			34
Restricted stock and units	10,769			7,013			24,319			20,242
Stock option awards	692			551			2,117			2,731
Total stock compensation	11,461			7,564			26,436			22,973
Less amounts capitalized to oil and gas properties	(3,160		)	(2,969		)	(8,917		)	(9,011		)
Stock compensation expense, net	$	8,301		$	4,595		$	17,519		$	13,962

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

Our net (gain) or loss on derivative instruments includes both realized gains and losses on settlements of our derivative contracts and unrealized gains and losses stemming from changes in the fair value of our outstanding derivative instruments. We did not elect to use hedge accounting treatment for our derivative contracts. Therefore we recognize net gains and losses in our operating costs and expenses.

We estimate the fair value of our outstanding instruments based on published forward commodity price curves as of the date of the estimate, using an option pricing model which takes into account market volatility, market prices and contract terms. The fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk. The fair value of instruments in a liability position includes a measure of our own nonperformance risk.

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

	For the Three Months Ended September 30,					For the Nine months Ended September 30,
	2012		2011			2012			2011
Realized (gain) on settlement of derivative instruments	$	—	$	(1,747	)	$	—		$	(3,817	)
Unrealized (gain) loss from changes to the fair value of the derivative instruments	5,329		(5,373		)	(661		)	(7,536		)
(Gain) loss on derivative instruments, net	$	5,329	$	(7,120	)	$	(661	)	$	(11,353	)

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 and Item 3 of this report for additional information regarding our derivative instruments.

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

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Other (income) and expense

	For the Three Months Ended September 30,						Variance Between			For the Nine Months Ended September 30,						Variance Between
	2012			2011			2012/2011			2012			2011			2012/2011

Interest expense	$	13,223		$	9,279		$	3,944		$	35,570		$	27,599		$	7,971
Capitalized interest	(9,231		)	(7,253		)	(1,978		)	(26,154		)	(21,830		)	(4,324		)
Loss on early extinguishment of debt	—			—			—			16,214			—			16,214
Other, net	(6,159		)	(3,604		)	(2,555		)	(18,714		)	(7,226		)	(11,488		)
	$	(2,167	)	$	(1,578	)	$	(589	)	$	6,916		$	(1,457	)	$	8,373

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

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

Components of other, net consist of miscellaneous income and expense items that will vary from period to period, including gain or loss on the sale or value of oil and gas well equipment, income and expense associated with other non-operating activities, miscellaneous asset sales and interest income. The increases in other, net (income) for the third quarter and first nine months of 2012 compared to the same periods of 2011 are mainly due to increases in net proceeds from sales of oil and gas well equipment and supplies and income from other non-operating activities.

Income Tax Expense

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
Current benefit	$	(1,629	)	$	(44,081	)	$	(1,629	)	$	(45,403	)
Deferred taxes	49,568			120,930			150,648			288,986
	$	47,939		$	76,849		$	149,019		$	243,583
Combined Federal and state effective income tax rate	36.3		%	37.5		%	36.9		%	37.1		%

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

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Prices for natural gas have continued to decline since year-end 2011, primarily as a result of an oversupply of natural gas and an exceptionally mild winter. If demand remains low, prices could decline even further. Prices for oil and NGLs have fluctuated during 2012 due to supply and demand factors, seasonality and other geopolitical and economic factors. It is likely that future prices for these commodities will continue to fluctuate.

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

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

At September 30, 2012, our total debt outstanding was $830 million, which was comprised of $80 million of bank debt and $750 million of our 5.875% Notes due in 2022. Our debt to total capitalization ratio at September 30, 2012 was 20%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is: long-term debt of $830 million divided by long-term debt of $830 million plus stockholders’ equity of $3.378 billion. Management believes that this non-GAAP measure is useful information and it is a common statistic referred to by the investment community.

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

Analysis of Cash Flow Changes

Cash flow provided by operating activities for the first nine months of 2012 was $836.1 million, down $135.4 million, compared to $971.5 million for the same period of 2011. Most of the decrease resulted from lower revenue of $234 million attributable to declines in commodity prices received in 2012, which were partially offset by increased revenue of $99.9 million from higher production volumes in 2012.

Cash flow used in investing activities for the first nine months of 2012 was $1.212 billion, or an increase of $205 million compared to $1.007 billion for 2011. Changes in the cash flow used in investing activities are generally the result of changes in our exploration and development programs, acquisitions, and other asset expenditures net of proceeds received from asset sales. Our 2012 oil and gas expenditures were relatively flat compared to 2011. The 2012 increase in cash used in investing activities was a result of receiving $203 million less proceeds from asset sales compared to proceeds received in 2011. See the discussion below for further information regarding our capital expenditures and property sales.

For the first nine months of 2012 we had net cash flow provided by financing activities of $378.8 million versus cash flow used in financing activities of $21.8 million for the same period of 2011. The $400.6 million increase in our 2012 cash inflow was primarily due to a net increase of $411.4 million related to our long-term debt. In the second quarter of 2012 we issued $750 million of 5.875% Senior Notes. Proceeds from that offering were used to retire all of our outstanding $350 million 7.125% Senior Notes and bank debt, as described in more detail under “Long-Term Debt” below.

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Reconciliation of Adjusted Cash Flow from Operations

	For the Nine Months Ended September 30,
	2012			2011
	(in thousands)
Net cash provided by operating activities	$	836,148		$	971,523
Change in operating assets and liabilities	(1,509		)	33,264
Adjusted cash flow from operations	$	834,639		$	1,004,787

Management believes that the non-GAAP measure of adjusted cash flow from operations is useful information for investors because it is used internally and is accepted by the investment community as a means of measuring the company’s ability to fund its capital program, without fluctuations caused by changes in current assets and liabilities, which are included in the GAAP measure of cash flow from operating activities. It is also used by professional research analysts in providing investment recommendations pertaining to companies in the oil and gas exploration and production industry.

Capital Expenditures

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

	For the Three Months Ended September , 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
Acquisitions:
Proved	$	—		$	12,439		$	—		$	21,604
Unproved	4,636			8,380			11,349			20,427
	4,636			20,819			11,349			42,031
Exploration and development:
Land and seismic	28,226			61,907			86,613			146,832
Exploration and development	389,989			360,733			1,120,740			1,032,794
	418,215			422,640			1,207,353			1,179,626
Sales proceeds:
Proved	(10,894		)	(83,709		)	(11,079		)	(102,192		)
Unproved	—			(150		)	(1,088		)	(1,971		)
	(10,894		)	(83,859		)	(12,167		)	(104,163		)
	$	411,957		$	359,600		$	1,206,535		$	1,117,494

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

Our exploration and development expenditures increased $27.0 million (2%) from $1.180 billion in the first nine months of 2011 to $1.207 billion in the same period of 2012. Of our total 2012 expenditures, 52% were for projects located in the Permian Basin, primarily in the Delaware Basin of southeast New Mexico and West Texas. Approximately 44% of our expenditures were in the Mid-Continent area, mostly in our western Oklahoma Cana-Woodford shale play. The remaining 4% of expenditures were in the Gulf Coast and other areas.

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The following table reflects wells drilled by region:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
Gross wells
Permian Basin	37		35		131		106
Mid-Continent	55		42		119		128
Gulf Coast / Other	1		5		3		8
	93		82		253		242
Net wells
Permian Basin	24		23		88		79
Mid-Continent	23		20		49		52
Gulf Coast / Other	—		5		1		7
	47		48		138		138

% Gross wells completed as producers	99	%	94	%	97	%	95	%

As of September 30, 2012 we had 39 net wells awaiting completion: 28 Mid-Continent and 11 Permian Basin. We also had 20 operated rigs running; 13 in the Permian Basin and 7 in the Mid-Continent.

Based on current market prices and service costs, our full year 2012 E&D capital expenditures are expected to be approximately $1.6 billion. Nearly all of our 2012 capital expenditures have been, and will continue to be, directed towards oil or liquids-rich gas drilling in the Permian Basin and Cana-Woodford shale. Our 2012 E&D capital expenditures continue to be funded from cash flow, long-term debt and occasional non-core property sales. The timing of capital expenditures and the receipt of cash flows do not necessarily match. Therefore, we borrow and repay funds under our credit arrangement throughout the year.

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

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

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

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Financial Condition

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

During the first nine months of 2012 our total assets increased by $885 million to $6.3 billion, up from $5.4 billion at December 31, 2011. Nearly all of the increase resulted from the $884 million increase in our net oil and gas properties.

At September 30, 2012, our total liabilities were $2.9 billion, up $637 million from $2.3 billion at December 31, 2011. The increase resulted primarily from a net increase in long-term debt of $425 million and a $154 million increase in noncurrent deferred income taxes.

Stockholders’ equity rose $247 million to $3.3 billion at September 30, 2012, compared to $3.1 billion at December 31, 2011. The increase is mainly due to our net income of $254.7 million, which was partially offset by dividends of $30.9 million.

Dividends

On February 22, 2012, the Board of Directors increased our regular cash dividend on our common stock from $0.10 to $0.12 per common share. In September 2012, the Board of Directors declared a cash dividend of $0.12 per share on our common stock. The dividend is payable on December 3, 2012, to stockholders of record on November 15, 2012. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Working Capital Analysis

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

Our working capital decreased $65.8 million from a deficit of $158.4 million at year-end 2011 to a deficit of $224.2 million at September 30, 2012.

Working capital decreased primarily because of the following:

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

· Accrued liabilities related to our E&D expenditures increased by $28.0 million.

· Accrued interest expense increased $17.5 million due to our second quarter issuance of 5.875% Senior Notes.

These working capital decreases were offset by the following:

· Cash and cash equivalents increased by $3.0 million.

· Our operations related accounts receivable increased by $22.7 million.

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

Long-term Debt

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

	September 30, 2012		December 31, 2011
Bank debt	$	80,000	$	55,000
7.125% Senior Notes due 2017	—		350,000
5.875% Senior Notes due 2022	750,000		—
Total long-term debt	$	830,000	$	405,000

Bank Debt

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

The borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. The next regular annual redetermination date is on April 15, 2013.

As of September 30, 2012, we had $80 million of bank debt outstanding at a weighted average interest rate of 2.1%. We also had letters of credit outstanding under the Credit Facility of $2.5 million leaving an unused borrowing availability of $917.5 million. During the first nine months of 2012 we had an average daily bank debt outstanding of $73.3 million, compared to $12.3 million for the same period of 2011. Our largest amount of bank borrowings outstanding during the first nine months of 2012 was $275 million in mid-March. During the first nine months of 2011 our largest amount of outstanding bank borrowings was $149 million in mid-July.

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.

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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 which were scheduled to mature May 1, 2017. On March 22, 2012 we commenced a cash tender offer (the “Tender Offer”) to purchase all of the outstanding 7.125% senior notes.

Under the terms of the Tender Offer, holders who tendered their notes on or prior to April 4, 2012 received (i) $1,035.63 per $1,000.00 in principal amount of notes tendered plus (ii) a consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. Through April 18, 2012 a total of $300,163,000 of notes were redeemed. In May 2012, the remaining notes were redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012.

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

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2012, the material off-balance sheet arrangements that we have entered into included operating lease agreements, all of which are customary in the oil and gas industry.

Contractual Obligations and Material Commitments

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

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

Long-term debt(1)	$	830,000	$	—	$	—		$	80,000		$	750,000
Fixed-Rate interest payments(1)	443,685		47,122		88,125			88,125			220,313
Operating leases	73,136		8,962		13,645			11,626			38,903
Drilling commitments(2)	281,941		281,941		—			—			—
Gathering facilities and pipelines(3)	4,010		4,010		—			—			—
Asset retirement obligation	206,841		52,579		—		(4)	—		(4)	—		(4)
Other liabilities(5)	84,131		14,844		27,413			27,000			14,874
Firm Transportation	1,269		992		214			63			—

(1)	These amounts do not include interest on the $80 million of bank debt outstanding at September 30, 2012. The weighted average interest rate at September 30, 2012 was approximately 2.1%. See item 3: Interest Rate Risk for more information regarding fixed and variable rate debt.
(2)	We have drilling commitments of approximately $261.4 million consisting of obligations to finish drilling and completing wells in progress at September 30, 2012. We also have various commitments for drilling rigs as well as certain service

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	contracts. The total minimum expenditure commitments under these agreements are $12.1 million to secure the use of drilling rigs and $8.4 million to secure certain dedicated services associated with completion activities.
(3)	We have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At September 30, 2012, we had commitments of $4 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.

We have various other delivery commitments in the normal course of business, 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 the estimated net cash generated from operations, amounts available under our existing bank Credit Facility and occasional sales of non-strategic assets will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operations and planned exploration, development and other capital expenditures.

2012 Outlook

Our 2012 exploration and development capital investment is presently expected to be approximately $1.6 billion. Nearly all the 2012 capital is directed towards oil drilling or liquids-rich gas in the Permian Basin and Cana-Woodford shale. Actual amounts invested will depend on our calculated rate of return which is significantly influenced by commodity prices.

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

Though there are a variety of factors that could curtail, delay or even cancel some of our planned operations, we believe our projected program is likely to occur. The majority of projects are in hand, drilling rigs are being scheduled, and the historical results of our drilling efforts warrant pursuit of the projects.

Production for 2012 is projected to be in the range of 620 to 626 MMcfe per day, or a 5 to 6% growth over 2011. Revenues from production will be dependent not only on the level of oil and gas actually produced, but also the prices that will be realized. During 2011, our realized prices averaged $4.42 per Mcf of gas, $93.00 per barrel of oil, and $42.31 per barrel of NGL. For the first nine months of 2012 our realized prices averaged $2.71 per Mcf of gas, $91.67 per barrel of oil, and $31.35 per barrel of NGL. Commodity prices can be very volatile and the possibility of full year realized 2012 prices varying from prices received in the first nine months of 2012 is high.

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

	2012
Production expense	$ 1.11	- $1.16
Transportation expense	0.25	- 0.30
DD&A and asset retirement obligation	2.35	- 2.45
General and administrative	0.25	- 0.30
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 September 30, 2012.

ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

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

Price Fluctuations

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

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

The following table details the contracts we have in place as of September 30, 2012:

Oil Contracts

Weighted Average Price

Fair Value

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

(in thousands)

Oct 12 - Dec 12

Collar

14,000 Bbls

WTI

80.00

119.35

416

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

While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the contracts listed above, a hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2012 of $1.3 million.

Counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Second, our derivative

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contracts are held with “investment grade” counterparties that are a part of our credit facility. See Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.

Interest Rate Risk

At September 30, 2012, our debt was comprised of the following (in thousands):

	Fixed Rate Debt		Variable Rate Debt
Bank debt	$	—	$	80,000
5.875% Notes due 2022	750,000		—
Total long-term debt	$	750,000	$	80,000

As of September 30, 2012, the amounts outstanding under our five-year senior unsecured revolving credit facility bears interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. Our senior unsecured notes bear interest at a fixed rate of 5.875% and will mature on May 1, 2022.

We consider our interest rate exposure to be minimal because approximately 90% 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 $800,000. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 3 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding debt.

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ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)) as of September 30, 2012, and concluded that the disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is also based upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of September 30, 2012, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended September 30, 2012, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II

ITEM 6 — EXHIBITS

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

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

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

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

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

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SIGNATURE

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

November 2, 2012


	CIMAREX ENERGY CO.


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


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