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, 2013

Commission File No. 001-31446

CIMAREX ENERGY CO.

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(303) 295-3995

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

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

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

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

Large accelerated filer x

Accelerated filer o

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

Smaller reporting company o

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

The number of shares of Cimarex Energy Co. common stock outstanding as of September 30, 2013 was 86,838,423.

Table of Contents

CIMAREX ENERGY CO.

Table of Contents

		Page
PART I — FINANCIAL INFORMATION

Item 1 —	Financial Statements

	Condensed consolidated balance sheets (unaudited) as of September 30, 2013 and December 31, 2012	4

	Consolidated statements of income and comprehensive income (unaudited) for the three and nine months ended September 30, 2013 and 2012	5

	Condensed consolidated statements of cash flows (unaudited) for the nine months ended September 30, 2013 and 2012	6

	Notes to consolidated financial statements (unaudited)	7

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

Item 3 —	Quantitative and Qualitative Disclosures about Market Risk	37

Item 4 —	Controls and Procedures	39

PART II — OTHER INFORMATION

Item 6 —	Exhibits	40

Signatures		41

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GLOSSARY

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

Bbls—Barrels (of oil or natural gas liquids)

Bcf—Billion cubic feet

Bcfe—Billion cubic feet equivalent

Btu—British thermal unit

MBbls—Thousand barrels

Mcf—Thousand cubic feet (of natural gas)

Mcfe—Thousand cubic feet equivalent

MMBbls—Million barrels

MMBtu—Million British Thermal Units

MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

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

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

NGL or NGLs—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

WTI—West Texas Intermediate

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

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS

Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. These forward-looking statements include, among others, statements concerning our outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil, gas, and NGLs 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 or areas due to mechanical, transportation, 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 economic, 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,
	2013			December 31,
	(Unaudited)			2012
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	4,531		$	69,538
Restricted cash	818			—
Receivables, net	391,105			302,974
Oil and gas well equipment and supplies	69,517			81,029
Deferred income taxes	13,902			8,477
Derivative instruments	7,168			—
Prepaid expenses	5,750			7,420
Other current assets	4,082			699
Total current assets	496,873			470,137
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	12,466,073			11,258,748
Unproved properties and properties under development, not being amortized	597,526			645,078
	13,063,599			11,903,826
Less — accumulated depreciation, depletion and amortization	(7,318,137		)	(6,899,057		)
Net oil and gas properties	5,745,462			5,004,769
Fixed assets, net	137,455			152,605
Goodwill	620,232			620,232
Derivative instruments	2,717			—
Other assets, net	51,625			57,409
	$	7,054,364		$	6,305,152
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	111,082		$	103,653
Accrued liabilities	403,413			392,909
Derivative instruments	4,320			—
Revenue payable	187,065			149,300
Total current liabilities	705,880			645,862
Long-term debt	900,000			750,000
Deferred income taxes	1,338,623			1,121,353
Other liabilities	293,576			313,201
Total liabilities	3,238,079			2,830,416
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued	—			—
Common stock, $0.01 par value, 200,000,000 shares authorized, 86,838,423 and 86,595,976 shares issued, respectively	868			866
Paid-in capital	1,959,160			1,939,628
Retained earnings	1,855,382			1,533,768
Accumulated other comprehensive income	875			474
	3,816,285			3,474,736
	$	7,054,364		$	6,305,152

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY CO.

Consolidated Statements of Income and Comprehensive Income

(Unaudited)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2013			2012			2013			2012
	(In thousands, except per share data)
Revenues:
Gas sales	$	118,824		$	83,208		$	346,492		$	238,102
Oil sales	371,881			263,315			933,879			759,609
NGL sales	58,922			50,860			168,106			154,160
Gas gathering, processing and other	11,380			10,054			32,951			31,940
Gas marketing, net	329			(525		)	21			(741		)
	561,336			406,912			1,481,449			1,183,070
Costs and expenses:
Depreciation, depletion and amortization	159,182			135,987			442,851			375,486
Asset retirement obligation	1,797			3,512			7,080			9,478
Production	76,166			62,699			214,985			192,818
Transportation and other operating	25,838			14,481			66,494			40,966
Gas gathering and processing	6,970			5,496			18,310			15,302
Taxes other than income	31,104			24,095			84,039			72,738
General and administrative	19,003			14,742			57,416			41,523
Stock compensation	3,347			8,301			10,459			17,519
(Gain) loss on derivative instruments, net	10,824			5,329			(1,233		)	(661		)
Other operating, net	2,507			2,236			7,804			7,295
	336,738			276,878			908,205			772,464

Operating income	224,598			130,034			573,244			410,606

Other (income) and expense:
Interest expense	13,954			13,223			41,272			35,570
Capitalized interest	(7,286		)	(9,231		)	(23,868		)	(26,154		)
Loss on early extinguishment of debt	—			—			—			16,214
Other, net	(2,263		)	(6,159		)	(13,637		)	(18,714		)

Income before income tax	220,193			132,201			569,477			403,690
Income tax expense	81,823			47,939			211,615			149,019
Net income	$	138,370		$	84,262		$	357,862		$	254,671

Earnings per share to common stockholders:
Basic
Distributed	$	0.14		$	0.12		$	0.42		$	0.36
Undistributed	1.45			0.85			3.70			2.58
	$	1.59		$	0.97		$	4.12		$	2.94

Diluted
Distributed	$	0.14		$	0.12		$	0.42		$	0.36
Undistributed	1.45			0.85			3.70			2.57
	$	1.59		$	0.97		$	4.12		$	2.93

Comprehensive income:
Net income	$	138,370		$	84,262		$	357,862		$	254,671
Other comprehensive income:
Change in fair value of investments, net of tax	302			238			401			502
Total comprehensive income	$	138,672		$	84,500		$	358,263		$	255,173

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,
	2013			2012
	(In thousands)

Cash flows from operating activities:
Net income	$	357,862		$	254,671
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	442,851			375,486
Asset retirement obligation	7,080			9,478
Deferred income taxes	211,615			150,648
Stock compensation	10,459			17,519
Gain on derivative instruments	(1,233		)	(661		)
Settlements on derivative instruments	(4,332		)	—
Loss on early extinguishment of debt	—			16,214
Changes in non-current assets and liabilities	9,102			7,930
Other, net	(685		)	3,354
Changes in operating assets and liabilities:
Receivables, net	(88,131		)	24,398
Other current assets	9,799			8,763
Accounts payable and accrued liabilities	(13,639		)	(31,652		)
Net cash provided by operating activities	940,748			836,148
Cash flows from investing activities:
Oil and gas expenditures	(1,165,555		)	(1,181,742		)
Sales of oil and gas assets	37,707			12,167
Sales of other assets	31,252			550
Other expenditures	(34,657		)	(42,913		)
Net cash used by investing activities	(1,131,253		)	(1,211,938		)
Cash flows from financing activities:
Net bank debt borrowings	150,000			25,000
Proceeds from other long-term debt	—			750,000
Other long-term debt payments	—			(363,595		)
Financing costs incurred	(100		)	(13,821		)
Dividends paid	(34,570		)	(29,199		)
Issuance of common stock and other	10,168			10,410
Net cash provided by financing activities	125,498			378,795
Net change in cash and cash equivalents	(65,007		)	3,005
Cash and cash equivalents at beginning of period	69,538			2,406
Cash and cash equivalents at end of period	$	4,531		$	5,411

See accompanying notes to consolidated financial statements.

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CIMAREX ENERGY GO.

Notes to Consolidated Financial Statements

September 30, 2013

(Unaudited)

1. Basis of Presentation

The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex”, “we”, or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (SEC). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in annual reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our 2012 Annual Report on Form 10-K.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods and as of the dates 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.

Restricted Cash

At December 31, 2012, we had restricted cash of $811 thousand included in our non-current other assets which consisted of monies from third parties that were being held by Cimarex, as operator of a property in Oklahoma, until the ownership disputes among the third parties could be resolved. As of September 30, 2013, the ownership disputes have been resolved and we have transferred the restricted cash and the related liability from non-current to current.

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, depletion expense, and tax effects. 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, 2013, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. Our ceiling limitation has improved since December 31, 2012. However, a decline of 5% in the value of the ceiling limitation would have resulted in an impairment. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.

Use of Estimates

The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved oil and gas reserves, the use of these oil and gas reserves in calculating depletion, depreciation, and amortization (DD&A), 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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

allowance for bad debt, impairments of undeveloped properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements, and commitments and contingencies.

Accounts Receivable, Accounts Payable, and Accrued Liabilities

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

(in thousands)	September 30, 2013		December 31, 2012
Receivables, net of allowance
Trade	$	87,069	$	55,528
Oil and gas sales	289,673		239,106
Gas gathering, processing, and marketing	14,363		7,901
Other	—		439
Receivables, net	$	391,105	$	302,974

Accounts payable
Trade	$	84,152	$	88,168
Gas gathering, processing, and marketing	26,930		15,485
Accounts payable	$	111,082	$	103,653

Accrued liabilities
Exploration and development	$	173,066	$	155,002
Taxes other than income	29,022		29,179
Other	201,325		208,728
Accrued liabilities	$	403,413	$	392,909

Recently Issued Accounting Standards

No significant accounting standards applicable to Cimarex have been issued during the quarter ended September 30, 2013.

2. Derivative Instruments/Hedging

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

The following tables summarize our outstanding hedging contracts as of September 30, 2013:

Oil Contracts

				Weighted Average Price						Fair Value
Period	Type	Volume/Day	Index(1)	Floor		Ceiling		Swap		(in thousands)
Oct 13 – Dec 13	Collars	6,000 Bbls	WTI	$	85.00	$	102.31	N/A		$	(1,311	)
Oct 13 – Dec 13	Swaps	6,000 Bbls	WTI	N/A		N/A		$	96.13	$	(2,987	)
Jan 14 – Dec 14	Collars	6,000 Bbls	WTI	$	85.00	$	105.68	N/A		$	1,477

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

Gas Contracts

Weighted Average
Price

Fair Value

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

(in thousands)

Oct 13 – Dec 14

Collars

80,000 MMBtu

PEPL

3.51

4.57

8,386

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

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

Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.

We have elected not to account for our derivatives as cash flow hedges. Therefore, we recognize settlements and changes in the assets or liabilities relating to our open derivative contracts in earnings. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Gain (loss) on derivative instruments, net
Natural gas contracts	$	376		$	—		$	9,575		$	—
Oil contracts	(11,200		)	(5,329		)	(8,342		)	661
Gain (loss) on derivative instruments, net	$	(10,824	)	$	(5,329	)	$	1,233		$	661

Gains (losses) from settlement of derivative instruments:
Natural gas contracts	$	1,189		$	—		$	1,189		$	—
Oil contracts	(7,286		)	—			(5,521		)	—
Settlement gains (losses)	$	(6,097	)	$	—		$	(4,332	)	$	—

Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs. We estimate the fair value with 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 non-performance risk. These credit risks are based on current published credit default swap rates.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

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.

Our derivative instruments are subject to enforceable master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our policy is to not offset asset and liability positions in our accompanying balance sheets.

The following table presents the amounts and classifications of our derivative assets and liabilities as of September 30, 2013, as well as the potential effect of netting arrangements on contracts with the same counterparty. At December 31, 2012, we had no outstanding derivative contracts.

September 30, 2013: (in thousands)	Balance Sheet Location	Asset			Liability
Oil contracts	Current assets — Derivative instruments	$	303		$	—
Natural gas contracts	Current assets — Derivative instruments	$	6,865		$	—
Oil contracts	Non-current assets — Derivative instruments	$	1,196		$	—
Natural gas contracts	Non-current assets — Derivative instruments	$	1,521		$	—
Oil contracts	Current liabilities — Derivative instruments	$	—		$	4,320
Total gross amounts presented in accompanying balance sheet		$	9,885		$	4,320
Less: gross amounts not offset in the accompanying balance sheet		$	(3,995	)	$	(3,995	)
Net amount:		$	5,890		$	325

We are exposed to financial risks associated with our derivative contracts from non-performance 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.

3. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Financial Accounting Standards Board (FASB) has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The following tables provide fair value measurement information for certain assets and liabilities as of September 30, 2013 and December 31, 2012:

September 30, 2013: (in thousands)	Carrying Amount			Fair Value
Financial Assets (Liabilities):
Bank debt	$	(150,000	)	$	(150,000	)
5.875% Notes due 2022	$	(750,000	)	$	(765,000	)
Derivative instruments — assets	$	9,885		$	9,885
Derivative instruments — liabilities	$	(4,320	)	$	(4,320	)

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

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

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

Debt (Level 1)

The fair value of our bank debt at September 30, 2013 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% 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 non-performance for both our counterparties and our liability positions. Please see Note 2 for further information on the fair value of our derivative instruments.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.

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

We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At September 30, 2013 and December 31, 2012, the allowance for doubtful accounts was $6.0 and $6.5 million, respectively.

4. Capital Stock

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At September 30, 2013, there were no shares of preferred stock outstanding. A summary of our common stock activity for the nine months ended September 30, 2013 follows:

(in thousands)
Issued and outstanding as of December 31, 2012		86,596
Restricted shares issued under compensation plans, net of reacquired stock and cancellations		41
Option exercises, net of cancellations		201
Issued and outstanding as of September 30, 2013		86,838

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

Dividends

In September 2013, the Board of Directors declared a cash dividend of $0.14 per share. The dividend is payable on December 2, 2013 to stockholders of record on November 15, 2013. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

5. Stock-based Compensation

Our 2011 Equity Incentive Plan (the 2011 Plan) was approved by stockholders in May 2011 and our previous plan was terminated at that time. Outstanding awards under the previous plan were not impacted. The 2011 Plan provides for grants of stock options, restricted stock, restricted stock units, performance stock and performance stock units. A total of 5.3 million shares of common stock may be issued under the 2011 Plan.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Restricted stock	$	5,329		$	10,769		$	17,252		$	24,319
Stock options	940			692			2,355			2,117
	6,269			11,461			19,607			26,436
Less amounts capitalized to oil and gas properties	(2,922		)	(3,160		)	(9,148		)	(8,917		)
Compensation expense	$	3,347		$	8,301		$	10,459		$	17,519

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

Restricted Stock and Units

The following tables provide information about restricted stock awards granted during the three and nine months ended September 30, 2013 and 2012.

	Three Months Ended September 30, 2013			Three Months Ended September 30, 2012
	Number of Shares	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Grant-Date Fair Value
Performance-based stock awards	26,000	$	56.85	24,000	$	48.24
Service-based stock awards	228,200	$	72.83	238,100	$	53.19
Total restricted stock awards	254,200	$	71.20	262,100	$	52.73

	Nine Months Ended September 30, 2013			Nine Months Ended September 30, 2012
	Number of Shares	Weighted Average Grant-Date Fair Value		Number of Shares	Weighted Average Grant-Date Fair Value
Performance-based stock awards	26,000	$	56.85	262,770	$	43.22
Service-based stock awards	277,236	$	72.49	294,198	$	54.03
Total restricted stock awards	303,236	$	71.15	556,968	$	48.93

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

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

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

The following table reflects the non-cash compensation cost related to our restricted stock:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Performance-based stock awards	$	2,710		$	7,719		$	7,963		$	15,390
Service-based stock awards	2,619			3,050			9,289			8,929
	5,329			10,769			17,252			24,319
Less amounts capitalized to oil and gas properties	(2,491		)	(2,912		)	(8,229		)	(8,081		)
Restricted stock compensation expense	$	2,838		$	7,857		$	9,023		$	16,238

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

Unrecognized compensation cost related to unvested restricted shares at September 30, 2013 was $52.7 million, which we expect to recognize over a weighted average period of approximately 2.5 years.

The following table provides information on restricted stock and unit activity as of September 30, 2013 and changes during the year. A restricted unit held by an employee represents a right to an unrestricted share of common stock upon completion of defined vesting and holding periods. A restricted unit held by a non-employee director represents an election to defer payment of director fees until the time specified by the director in his deferred compensation agreement. The remaining outstanding restricted units shown below represent restricted units held by a non-employee director who has elected to defer payment of common stock represented by the units until termination of his service on the Board of Directors.

	Restricted Stock		Restricted Units
Outstanding as of January 1, 2013	1,838,736		33,838
Vested	(383,175	)	N/A
Converted to stock	N/A		(25,000	)
Granted	303,236		—
Canceled	(133,530	)	—
Outstanding as of September 30, 2013	1,625,267		8,838
Vested included in outstanding	N/A		8,838

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

Stock Options

The following table provides information about stock options granted in 2013 and 2012:

	Three and Nine Months Ended September 30, 2013		Three and Nine Months Ended September 30, 2012

Options	144,400		152,800
Weighted average grant-date fair value	$	21.64	$	20.55
Weighted average exercise price	$	72.25	$	51.92

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

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Stock option awards	$	940		$	692		$	2,355		$	2,117
Less amounts capitalized to oil and gas properties	(431		)	(248		)	(919		)	(836		)
Stock option compensation expense	$	509		$	444		$	1,436		$	1,281

As of September 30, 2013, there was $5.1 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost pro rata over a weighted-average period of approximately 2.0 years.

Information about outstanding stock options is summarized below:

	Options		Weighted Average Exercise Price		Weighted Average Remaining Term	Aggregate Intrinsic Value (in thousands)
Outstanding as of January 1, 2013	687,459		$	54.51
Granted	144,400		$	72.25
Exercised	(201,295	)	$	50.51
Canceled	(2,663	)	$	86.00
Forfeited	(15,443	)	$	65.51
Outstanding as of September 30, 2013	612,458		$	59.59	5.6 Years	$	21,721
Exercisable as of September 30, 2013	262,776		$	53.98	5.1 Years	$	10,796

The following table provides information regarding the options exercised and the grant-date fair value of options vested:

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

	Nine Months Ended September 30,
(dollars in thousands)	2013		2012
Number of options exercised	201,295		505,057
Cash received from option exercises	$	10,168	$	10,410
Intrinsic value of options exercised	$	6,811	$	20,232
Grant-date fair value of options vested	$	2,521	$	2,466

The following summary reflects the status of non-vested stock options as of September 30, 2013 and changes during the year:

	Options		Weighted Average Grant-Date Fair Value		Weighted Average Exercise Price
Non-vested as of January 1, 2013	317,062		$	23.22	$	60.58
Granted	144,400		$	21.64	$	72.25
Vested	(96,337	)	$	26.17	$	65.54
Forfeited	(15,443	)	$	25.96	$	65.51
Non-vested as of September 30, 2013	349,682		$	21.63	$	63.82

6. Asset Retirement Obligations

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

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, 2013:

(in thousands)
Asset retirement obligation at January 1, 2013	$	185,138
Liabilities incurred	4,272
Liability settlements and disposals	(41,540		)
Accretion expense	5,987
Revisions of estimated liabilities	2,502
Asset retirement obligation at September 30, 2013	156,359
Less current obligation	(49,435		)
Long-term asset retirement obligation	$	106,924

7. Long-Term Debt

Debt at September 30, 2013 and December 31, 2012 consisted of the following:

(in thousands)	September 30, 2013		December 31, 2012
Bank debt	$	150,000	$	—
5.875% Senior Notes due 2022	750,000		750,000
Total long-term debt	$	900,000	$	750,000

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

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 $2.25 billion with aggregate commitments of $1 billion from our lenders. The borrowing base under the Credit Facility is determined at the discretion of the lenders based on the value of our proved reserves. The next regular annual redetermination date is scheduled for April 15, 2014.

As of September 30, 2013, we had $150 million of bank debt outstanding at a weighted average interest rate of 2.28%. We also had letters of credit outstanding under the Credit Facility of $2.5 million, leaving an unused borrowing availability of $847.5 million.

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

The Credit Facility 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 non-cash 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, 2013, we were in compliance with all of the financial and non-financial covenants.

5.875% Notes due 2022

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

7.125% Notes due 2017

In May 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. On March 22, 2012, we commenced a cash tender offer (Tender Offer) to purchase all of the outstanding 7.125% senior notes. The Tender Offer was completed in the second quarter of 2012. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

8. Income Taxes

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2013		2012			2013		2012
Current benefit	$	—	$	(1,629	)	$	—	$	(1,629	)
Deferred taxes	81,823		49,568			211,615		150,648
	$	81,823	$	47,939		$	211,615	$	149,019

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

At September 30, 2013, we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2009-2012 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities, which remain open to examination for the 2008-2012 tax years.

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and non-deductible expenses. The effective income tax rates for the nine months ended September 30, 2013 and September 30, 2012 were 37.2% and 36.9%, respectively.

9. Supplemental Disclosure of Cash Flow Information:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2013		2012		2013		2012
Cash paid during the period for:
Interest expense (including capitalized amounts)	$	1,932	$	1,017	$	27,158	$	15,374
Interest capitalized	$	394	$	432	$	15,706	$	11,304
Income taxes	$	—	$	—	$	205	$	375
Cash received for income taxes	$	213	$	57	$	450	$	49,293

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

10. Earnings per Share

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

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2013			2012			2013			2012

Basic:
Net income	$	138,370		$	84,262		$	357,862		$	254,671
Participating securities’ share in earnings	(2,375		)	(1,628		)	(6,049		)	(4,929		)
Net income applicable to common shareholders	$	135,995		$	82,634		$	351,813		$	249,742

Diluted:
Net income	$	138,370		$	84,262		$	357,862		$	254,671
Participating securities’ share in earnings	(2,371		)	(1,622		)	(6,041		)	(4,910		)
Net income applicable to common shareholders	$	135,999		$	82,640		$	351,821		$	249,761

Shares:
Basic shares outstanding	85,213			84,681			85,213			84,681
Incremental shares from assumed exercise of stock options	134			316			117			340
Fully diluted common stock	85,347			84,997			85,330			85,021
Excluded (1)	232			400			254			408

Earnings per share to common shareholders: (2)
Basic	$	1.59		$	0.97		$	4.12		$	2.94
Diluted	$	1.59		$	0.97		$	4.12		$	2.93

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

(2) Earnings per share are based on actual figures rather than the rounded figures presented.

11. Commitments and Contingencies

Commitments

We have commitments of $176.9 million to finish drilling and completing wells in progress at September 30, 2013.

In New Mexico and Texas, we are constructing gathering facilities and pipelines. At September 30, 2013, we had commitments of $4.1 million relating to these construction projects.

At September 30, 2013, we had firm sales contracts to deliver approximately 25 Bcf of natural gas over the next 11 months. If this gas is not delivered, our financial commitment would be approximately $82.8 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 proved reserves and production levels.

We have other various transportation and delivery commitments in the normal course of business, which approximate $3.5 million over the next four years.

We have various commitments for office space and equipment under operating lease arrangements totaling $130.7 million for the next five years and beyond.

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

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

Litigation

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

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

On December 11, 2012, Cimarex entered into a preliminary resolution of the Hitch Enterprises, Inc., et al. v. Cimarex Energy Co., et al. (Hitch) litigation matter for $16.4 million. Hitch is a statewide royalty class action pending in the Federal District Court in Oklahoma City, Oklahoma. The settlement was reached at a mediation, which occurred after the parties began to exchange information, including damage analyses, on November 16, 2012. On July 2, 2013, the Court entered a judgment approving the parties’ settlement. The judgment became final and unappealable on August 2, 2013. Cimarex distributed the settlement proceeds pursuant to the Court’s order in September 2013 and the administration of the settlement is ongoing. In the fourth quarter of 2012, we accrued $16.4 million for this matter.

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

On August 18, 2011, the Oklahoma Court of Appeals reversed and remanded the $112.7 million disgorgement of profits award, holding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other respects, the Court of Appeals affirmed the District Court’s judgment, including damages of $6.845 million. On February 13, 2012, the Oklahoma Supreme Court granted Cimarex’s Petition for Certiorari, which requested a review of the affirmed portion of the judgment. We are awaiting a ruling from the Oklahoma Supreme Court, and the final outcome cannot be determined at this time. If the District Court’s original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then-determined amount of post-judgment interest and costs would become payable.

The following table reflects the change in the non-current accrued liability for this lawsuit for the nine months ended September 30, 2013:

(in thousands)
Outstanding at January 1, 2013	$	155,374
Accrued post-judgment interest and costs	7,070
Outstanding at September 30, 2013	$	162,444

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CIMAREX ENERGY CO.

Notes to Consolidated Financial Statements (Continued)

September 30, 2013

(Unaudited)

12. Property Sales and Acquisitions

We sold interests in various oil and gas properties for $37.7 million during the first nine months of 2013. There were $12.2 million of oil and gas property sales during the first nine months of 2012. During the second quarter of 2013, we also sold a 50% interest in our Culberson County, Texas Triple Crown gas gathering and processing system for approximately $31 million.

During the first nine months of 2013 and 2012, we had property acquisitions of $6.2 million and $11.3 million, respectively.

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

OVERVIEW

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

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

In order to achieve a consistent rate of growth and mitigate risk, we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects. We seek geologic and geographic diversification by operating in multiple basins. In recent years, we have shifted our capital expenditures to oil and liquids-rich gas projects because of strong oil prices relative to gas prices.

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

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

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

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

Third quarter 2013 summary of operating and financial results:

· Net income increased 64% to $138.4 million, or $1.59 per diluted share.

· Oil, gas and NGL sales for the third quarter of 2013 were $549.6 million, 38% higher than a year earlier.

· Our overall production volumes increased 13% to a record 716.8 MMcfe per day.

· Oil production grew 21%, to a record 39,292 barrels per day.

· NGL volumes increased by 16% and gas volumes were up 7%.

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· Year-to-date cash flow provided by operating activities was $940.7 million versus $836.1 million for the same period of 2012.

· Year-to-date exploration and development expenditures totaled $1.187 billion.

· Total debt at September 30, 2013 was $900 million, up $150 million from year-end 2012.

Revenues

Most of our revenues are derived from the sales of oil, gas and NGL production. While revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our results of operations. Prices we receive are determined by prevailing market conditions. Regional and worldwide economic and geopolitical activity, weather and other variable factors influence market conditions, which often result in significant volatility in commodity prices.

The following table presents our average realized commodity prices. Realized prices do not include settlements of our commodity hedging contracts, which are financial instruments.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Oil Prices:
Average WTI Cushing price ($/Bbl)	$	105.81	$	92.22	$	98.14	$	96.21
Average realized sales price ($/Bbl)	$	102.88	$	88.18	$	93.81	$	91.67

Gas Prices:
Average Henry Hub price ($/Mcf)	$	3.58	$	2.80	$	3.67	$	2.58
Average realized sales price ($/Mcf)	$	3.72	$	2.79	$	3.73	$	2.71

NGL Prices:
Average realized sales price ($/Bbl)	$	28.63	$	28.55	$	28.57	$	31.35

On an energy equivalent basis, 51% of our aggregate 2013 production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales price would have resulted in a $15.8 million change in our combined oil and NGL revenues. Similarly, 49% of our production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a $9.3 million change in our gas revenues.

See RESULTS OF OPERATIONS below for a discussion of the impact changes in realized prices had on our 2013 revenues.

Production and other operating expenses

Costs associated with producing oil and gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production and some are a function of the number of wells we own. At the end of 2012, we owned interests in 13,127 gross wells.

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

Transportation and other operating costs include expenditures to prepare and move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which

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is net of these 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 estimated proved reserves for that well which in turn depend upon the assumed price for future sales of production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our DD&A rate. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and reclassifications of properties from unproved to proved will impact depletion expense.

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

General and administrative (G&A) expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices and not directly associated with exploration, development or production activities. Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting.

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

Derivative Instruments/Hedging

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

For 2012, we hedged about half of our anticipated oil production. We did not hedge any of our gas or NGL production. All of the oil contracts expired during 2012 without any cash settlements and we did not have any hedges in place at year-end.

In the first nine months of 2013, we hedged approximately 32% of our anticipated 2013 oil production, and 23% of our anticipated gas production. We have also hedged a portion of our 2014 oil

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and gas production. For contracts that have settled through September 30, 2013, we have paid net cash settlements of $5.5 million on oil contracts and received $1.2 million of cash settlements on our gas contracts.

The following tables summarize our outstanding contracts as of September 30, 2013:

Oil Contracts

Weighted Average Price

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

Swap

Oct 13 – Dec 13

Collars

6,000 Bbls

WTI

85.00

102.31

N/A

Oct 13 – Dec 13

Swaps

6,000 Bbls

WTI

N/A

96.13

Jan 14 – Dec 14

Collars

6,000 Bbls

WTI

85.00

105.68

N/A

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

Gas Contacts

Weighted Average
Price

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

Oct 13 – Dec 14

Collars

80,000 MMBtu

PEPL

3.51

4.57

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

Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.

Since 2009, we have chosen not to apply hedge accounting treatment to our derivative contracts. As a result, any settlements on the contracts are shown as a component of operating costs and expenses as either a net gain or loss on derivative instruments. See the discussion of our net gain/loss on hedging activities below, in RESULTS OF OPERATIONS. Also, see Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

RESULTS OF OPERATIONS

Third Quarter and Nine Months Ended September 30, 2013 vs. September 30, 2012

Net income for the third quarter of 2013 was $138.4 million ($1.59 per diluted share), up 64% from $84.3 million ($0.97 per diluted share) for the same period of 2012. For the first nine months of 2013, net income of $357.9 million ($4.12 per diluted share) was 41% higher than net income of $254.7 million ($2.93 per diluted share) for 2012. The increases in net income for the 2013 periods were primarily a result of higher revenues from increased production volumes and higher realized commodity prices, which were partially offset by higher operating expenses. In addition, the first nine months of 2012 included a loss on early extinguishment of debt. These changes are discussed further in the analysis that follows.

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Commodity Sales					Percent Change Between		Price/Volume Change
(in thousands or as indicated)	2013		2012		2013/2012		Price			Volume		Total
For the Three Months Ended September 30,
Oil sales	$	371,881	$	263,315	41	%	$	53,141		$	55,425	$	108,566
Gas sales	118,824		83,208		43	%	29,674			5,942		35,616
NGL sales	58,922		50,860		16	%	165			7,897		8,062
	$	549,627	$	397,383			$	82,980		$	69,264	$	152,244

For the Nine Months Ended September 30,
Oil sales	$	933,879	$	759,609	23	%	$	21,304		$	152,966	$	174,270
Gas sales	346,492		238,102		46	%	94,772			13,618		108,390
NGL sales	168,106		154,160		9	%	(16,355		)	30,301		13,946
	$	1,448,477	$	1,151,871			$	99,721		$	196,885	$	296,606

	For the Three Months Ended September 30,				Percent Change Between		For the Nine Months Ended September 30,				Percent Change Between
	2013		2012		2013/2012		2013		2012		2013/2012
Total oil volume — thousand barrels	3,615		2,986		21	%	9,955		8,287		20	%
Oil volume — barrels per day	39,292		32,456		21	%	36,464		30,243		21	%
Average oil price — per barrel	$	102.88	$	88.18	17	%	$	93.81	$	91.67	2	%

Total gas volume — MMcf	31,908		29,831		7	%	92,914		87,825		6	%
Gas volume — MMcf per day	346.8		324.2		7	%	340.3		320.5		6	%
Average gas price — per Mcf	$	3.72	$	2.79	33	%	$	3.73	$	2.71	38	%

Total NGL volume — thousand barrels	2,058		1,781		16	%	5,883		4,917		20	%
NGL volume — barrels per day	22,373		19,360		16	%	21,550		17,944		20	%
Average NGL price — per barrel	$	28.63	$	28.55	—		$	28.57	$	31.35	-9	%
Total equivalent production volumes — MMcfe per day	716.8		635.1		13	%	688.4		609.6		13	%

Third quarter 2013 commodity sales of $549.6 million were 38% higher than year-earlier sales of $397.4 million. Most of the $152.2 million increase in sales resulted from higher oil production and prices.

For the first nine months of 2013, commodity sales totaled $1.448 billion, up 26% from $1.152 billion for the same period of 2012. The $296.6 million increase was attributable to increases in production volumes for each of the commodities and higher realized sales prices for oil and gas.

Our third-quarter 2013 aggregate average production volumes reached a record 716.8 MMcfe per day, up 13% from 635.1 MMcfe per day for the same period in 2012. Average production volumes for the first nine months of 2013 were 688.4 MMcfe per day, up 13% from 609.6 MMcfe per day for the comparable 2012 period. The period-over-period increases in production were a result of our drilling programs in the Permian Basin and western Oklahoma.

Oil production during the third quarter of 2013 grew 21% to a record 39,292 barrels per day, compared to 32,456 barrels per day in 2012. This increase resulted in an additional $55.4 million of oil sales revenue. During the first nine months of 2013, our oil production averaged 36,464 barrels per day, up from 30,243 barrels per day in the 2012 period. The 21% increase contributed $153.0 million of additional revenue for the first nine months of 2013.

Third-quarter 2013 gas production averaged 346.8 MMcf per day, compared to 324.2 MMcf per day in the second quarter of 2012. This 7% increase resulted in an additional $5.9 million of gas revenue for the third quarter of 2013. During the first nine months of 2013 our gas production averaged 340.3 MMcf per day, up 6% from the first nine months of 2012 average of 320.5 MMcf per day.

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Increased gas production contributed additional revenue of $13.6 million for the first nine months of 2013.

NGL production volumes in the third quarter of 2013 increased 16% to 22,373 barrels per day compared to 19,360 barrels per day in the 2012 period, which resulted in additional revenue of $7.9 million. During the first nine months of 2013, NGL production averaged 21,550 barrels per day, compared to 17,944 barrels per day in the 2012 period. The 20% increase in production provided an additional $30.3 million of revenue in 2013.

Our average realized oil price of $102.88 per barrel received in the third quarter of 2013 was 17% higher than the 2012 average price of $88.18. The increase in price contributed an additional $53.1 million in revenue. In the first nine months of 2013, our average realized oil price was $93.81 per barrel, which was 2% higher than the average price of $91.67 for the same period of 2012. The increase in price accounted for $21.3 million of higher oil revenue during the first nine months of 2013.

In the third quarter of 2013, we realized an average gas price of $3.72 per Mcf, up from $2.79 per Mcf in the third quarter of 2012, or an increase of 33%, which contributed $29.7 million of additional gas revenue. Our average realized gas price of $3.73 per Mcf for the first nine months of 2013 was 38% higher than an average realized price of $2.71 for the same period of 2012. The higher price received in 2013 resulted in increased gas revenues of $94.8 million.

The average NGL price we received in the third quarter of 2013 of $28.63 per barrel was flat compared to $28.55 per barrel in the third quarter of 2012. In the first nine months of 2013, we received an average NGL price of $28.57 per barrel, which was 9% lower than the 2012 average price of $31.35 and resulted in $16.4 million of lower NGL revenue in 2013.

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

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
Gas Gathering, Processing, Marketing and Other (in thousands):
Gas gathering, processing and other revenues	$	11,380		$	10,054		$	32,951		$	31,940
Gas gathering and processing costs	(6,970		)	(5,496		)	(18,310		)	(15,302		)
Gas gathering, processing and other margin	$	4,410		$	4,558		$	14,641		$	16,638

Gas marketing revenues, net of related costs	$	329		$	(525	)	$	21		$	(741	)

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

In the third quarter of 2013, our total operating costs and expenses (not including gas gathering, processing and marketing costs, or income tax expense) were $329.8 million, up 22% compared to $271.4 million in the third quarter of 2012. For the first nine months of 2013, operating costs were $889.9 million, or an increase of 18% over the same period of 2012. Analyses of the year-over-year differences are discussed below.

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	For the Three Months Ended September 30,				Variance Between			Per Mcfe
	2013		2012		2013/2012			2013		2012
Operating costs and expenses (in thousands):
Depreciation, depletion and amortization	$	159,182	$	135,987	$	23,195		$	2.41	$	2.33
Asset retirement obligation	1,797		3,512		(1,715		)	$	0.03	$	0.06
Production	76,166		62,699		13,467			$	1.16	$	1.07
Transportation and other operating	25,838		14,481		11,357			$	0.39	$	0.25
Taxes other than income	31,104		24,095		7,009			$	0.47	$	0.41
General and administrative	19,003		14,742		4,261			$	0.29	$	0.25
Stock compensation	3,347		8,301		(4,954		)	$	0.05	$	0.14
(Gain) loss on derivative instruments, net	10,824		5,329		5,495			N/A		N/A
Other operating, net	2,507		2,236		271			N/A		N/A
	$	329,768	$	271,382	$	58,386

	For the Nine Months Ended September 30,						Variance Between			Per Mcfe
	2013			2012			2013/2012			2013		2012
Operating costs and expenses (in thousands):
Depreciation, depletion and amortization	$	442,851		$	375,486		$	67,365		$	2.36	$	2.25
Asset retirement obligation	7,080			9,478			(2,398		)	$	0.04	$	0.06
Production	214,985			192,818			22,167			$	1.15	$	1.15
Transportation and other operating	66,494			40,966			25,528			$	0.35	$	0.25
Taxes other than income	84,039			72,738			11,301			$	0.45	$	0.44
General and administrative	57,416			41,523			15,893			$	0.31	$	0.25
Stock compensation	10,459			17,519			(7,060		)	$	0.06	$	0.11
(Gain) loss on derivative instruments, net	(1,233		)	(661		)	(572		)	N/A		N/A
Other operating, net	7,804			7,295			509			N/A		N/A
	$	889,895		$	757,162		$	132,733

Our third quarter 2013 DD&A expense of $159.2 million was 17% higher than during the same period of 2012 and accounted for 40% of the total quarter-over-quarter increase in costs and expenses. On a unit of production basis, third-quarter 2013 DD&A increased by $0.08 to $2.41 per Mcfe. For the first nine months of 2013, DD&A was $442.9 million, up 18% compared to the same period of 2012. This increase was 51% of the aggregate year-over-year variance. DD&A per Mcfe for the first nine months of 2013 increased by $0.11 to $2.36 per Mcfe. About two-thirds of the increases in DD&A in the 2013 periods were attributable to our higher production volumes. The rest of the increase was a result of a higher DD&A rate. Our DD&A rate has increased because the per unit cost of adding new proved reserves has exceeded the net remaining book basis of proved reserves added in prior years.

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

	For the Three Months Ended September 30,				Variance Between		Per Mcfe
(in thousands)	2013		2012		2013/2012		2013		2012
Lease operating expense	$	60,364	$	52,100	$	8,264	$	0.92	$	0.89
Workover expense	15,802		10,599		5,203		0.24		0.18
	$	76,166	$	62,699	$	13,467	$	1.16	$	1.07

	For the Nine Months Ended September 30,				Variance Between		Per Mcfe
(in thousands)	2013		2012		2013/2012		2013		2012
Lease operating expense	$	166,995	$	163,076	$	3,919	$	0.89	$	0.98
Workover expense	47,990		29,742		18,248		0.26		0.17
	$	214,985	$	192,818	$	22,167	$	1.15	$	1.15

Our third quarter 2013 lease operating expense (LOE) of $60.4 million increased 16% from $52.1 million during the same period of 2012. In 2013, increased costs due to new well activity were

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partially offset by decreased costs related to property divestitures which occurred subsequent to the third quarter of 2012.

LOE for the first nine months of 2013 increased by 2% to $167.0 million compared to $163.1 million in 2012. In 2013, increased costs due to new well activity were largely offset by decreased costs from property divestitures and decreased salt water disposal costs.

Our workover expenses for the third quarter and first nine months of 2013 were considerably higher than costs incurred for the same periods of 2012. Workover costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.

In general, transportation and other operating costs vary by product type and area. Increases or decreases in sales volumes, compression charges and fuel costs also have an impact. As we have grown our oil and NGL production in the Permian Basin and western Oklahoma, we have experienced an increase in these costs. In the third quarter of 2013, transportation and other operating costs increased 78% to $25.8 million compared to $14.5 million for the third quarter of 2012. For the first nine months of 2013, transportation and other operating costs were $66.5 million, up 62% from $41.0 million for the same period of 2012.

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

General and administrative costs were as follows:

	For the Three Months Ended September 30,				Variance Between		For the Nine Months Ended September 30,				Variance Between
(in thousands)	2013		2012		2013/2012		2013		2012		2013/2012
G&A capitalized to oil & gas properties	$	19,836	$	16,880	$	2,956	$	57,530	$	50,831	$	6,699
G&A expense	19,003		14,742		4,261		57,416		41,523		15,893
	$	38,839	$	31,622	$	7,217	$	114,946	$	92,354	$	22,592
G&A expense per Mcfe	$	0.29	$	0.25			$	0.31	$	0.25

G&A costs of $38.8 million for the third quarter of 2013 were 23% higher than costs for the third quarter of 2012. The increase was mainly attributable to higher salaries and benefits due to more employees in 2013. In addition, we had increased rent related to new office facilities.

For the first nine months of the year G&A costs of $114.9 million were 24% higher than G&A for the same period of 2012. In 2013 we experienced increased costs for salaries and benefits, and increased rent related to new office facilities. In addition, 2013 expenditures include $7 million for university endowments established in honor of our former Chairman F.H. Merelli and $1 million of contributions for tornado relief in Oklahoma.

Stock compensation expense consists of non-cash charges resulting from the issuance of restricted stock and stock option awards, net of amounts capitalized. We have recognized non-cash stock-based compensation cost as follows:

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	For the Three Months Ended September 30,						Variance Between			For the Nine Months Ended September 30,						Variance Between
(in thousands)	2013			2012			2013/2012			2013			2012			2013/2012
Performance-based restricted stock awards	$	2,710		$	7,719		$	(5,009	)	$	7,963		$	15,390		$	(7,427	)
Service-based restricted stock awards	2,619			3,050			(431		)	9,289			8,929			360
Restricted stock	5,329			10,769			(5,440		)	17,252			24,319			(7,067		)
Stock option awards	940			692			248			2,355			2,117			238
Total stock compensation	6,269			11,461			(5,192		)	19,607			26,436			(6,829		)
Less amounts capitalized to oil & gas properties	(2,922		)	(3,160		)	238			(9,148		)	(8,917		)	(231		)
Stock compensation	$	3,347		$	8,301		$	(4,954	)	$	10,459		$	17,519		$	(7,060	)

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

We have not elected hedge accounting treatment for our derivative instruments. Therefore, we recognize settlements and changes in the assets or liabilities relating to our open derivative contracts in earnings. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. See Note 2 to the Consolidated Financial Statements for further details regarding our derivative instruments.

The following table summarizes the net (gains) and losses from settlements and changes in fair value of our derivative contracts.

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2013			2012		2013			2012
(Gain) loss on derivative instruments, net
Natural gas contracts	$	(376	)	$	––	$	(9,575	)	$	––
Oil contracts	11,200			5,329		8,342			(661		)
(Gain) loss on derivative instruments, net	$	10,824		$	5,329	$	(1,233	)	$	(661	)

Settlement (gains) losses:
Natural gas contracts	$	(1,189	)	$	––	$	(1,189	)	$	––
Oil contracts	7,286			––		5,521			––
Settlement (gains) losses	$	6,097		$	––	$	4,332		$	––

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

Other (income) and expense

	For the Three Months Ended September 30,						Variance Between		For the Nine Months Ended September 30,						Variance Between
(in thousands)	2013			2012			2013/2012		2013			2012			2013/2012

Interest expense	$	13,954		$	13,223		$	731	$	41,272		$	35,570		$	5,702
Capitalized interest	(7,286		)	(9,231		)	1,945		(23,868		)	(26,154		)	2,286
Loss on early extinguishment of debt	––			––			—		—			16,214			(16,214		)
Other, net	(2,263		)	(6,159		)	3,896		(13,637		)	(18,714		)	5,077
	$	4,405		$	(2,167	)	$	6,572	$	3,767		$	6,916		$	(3,149	)

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Interest expense includes interest on debt and amortization of financing costs. Our third quarter 2013 interest expense increased 6% compared to that of the third quarter of 2012. The increase resulted from having higher outstanding bank debt in the third quarter of 2013. Interest expense for the first nine months of 2013 was 16% higher than the same period of 2012. Most of the increase relates to our 5.875% senior notes being outstanding for all of 2013, whereas they were only outstanding for five months during the first nine months of 2012. See Long-term Debt below for further information regarding our senior notes.

We capitalize interest on non-producing leasehold costs, the costs of drilling and completing wells and constructing qualified assets. Period over period costs will fluctuate based on the current rate of interest and the amount of costs on which interest is calculated.

In connection with the retirement of our 7.125% senior notes during the second quarter of 2012, we recognized a $16.2 million loss on early extinguishment of debt. See Long-term Debt below for additional information regarding our senior notes.

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 63% decrease in other, net (income) for the third quarter of 2013 versus 2012 is mainly due to lower income from non-operating activities. The 27% decrease in other, net (income) for the first nine months of 2013 compared to the same period of 2012 results from lower income from non-operating activity and lower gains on sales of oil and gas well equipment which were partially offset by net gains on the sale of certain assets.

Income Tax Expense

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Current benefit	$	—		$	(1,629	)	$	—		$	(1,629	)
Deferred taxes	81,823			49,568			211,615			150,648
	$	81,823		$	47,939		$	211,615		$	149,019
Combined Federal and state effective income tax rate	37.2		%	36.3		%	37.2		%	36.9		%

Our combined Federal and state effective tax rates differ from the statutory rate of 35% primarily due to state income taxes and non-deductible 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 prices we receive for the oil, gas and NGLs we produce. Commodity prices are market driven and may be volatile. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth.

During the first nine months of 2013, our average realized price for natural gas was $3.73 per Mcf, an increase of 38% over the realized price for the same period of 2012. During the first nine months of 2013 our average realized price per barrel of oil was $93.81, an increase of 2% compared to the 2012

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period. Our realized price for NGLs during 2013 has averaged $28.57 per barrel, which was 9% lower than the average realized price for the same period of 2012. Future prices for these commodities will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors.

We deal with volatility in commodity prices by maintaining flexibility in our capital investment program. In addition, we periodically hedge a portion of our oil and/or gas production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment. Our 2013 exploration and development (E&D) capital expenditures are currently expected to be approximately $1.6 billion. Nearly all the capital is directed towards oil and liquids-rich gas opportunities in the Permian Basin and Cana-Woodford shale play.

We expect our 2013 E&D capital expenditures to be funded primarily by cash flow provided by operating activities. Modest increases in our long-term debt and occasional property sales often supplement funding of any capital expenditures. During 2013, we have drawn $150 million on our credit facility and have $847.5 million of undrawn capacity.

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

At September 30, 2013, our total debt outstanding was $900 million, which was comprised of $150 million of bank debt and $750 million of our 5.875% senior notes. Debt to total capitalization at September 30, 2013 was 19%. The reconciliation of debt to total capitalization, which is a non-GAAP measure, is: long-term debt of $900 million divided by long-term debt of $900 million plus stockholders’ equity of $3.816 billion. Management believes that this non-GAAP measure is useful information and it is a common statistic referred to by the investment community.

We believe that our operating cash flow and other capital resources will be adequate to meet our needs for our planned capital expenditures, working capital, debt servicing and dividend payments for 2013 and beyond.

Analysis of Cash Flow Changes

Cash flow provided by operating activities of $940.7 million for the first nine months of 2013 increased by $104.6 million (13%), compared to $836.1 million for the same period of 2012. Increased revenues in 2013 from higher production volumes and increased realized oil and gas prices were partially offset by higher operating expenses and an increase in the amount of outstanding accounts receivable.

Net cash flow used by investing activities for the first nine months of 2013 declined 7% to $1.1 billion, compared to $1.2 billion for 2012. In 2013, we had oil and gas and other capital expenditures of $1.2 billion, which were partially offset by $69.0 million of asset sales. For the same period of 2012, expenditures for oil and gas and other capital costs were also $1.2 billion and proceeds from asset sales were $12.7 million.

During the first nine months of 2013, net cash flow provided by financing activities was $125.5 million. For the same period of 2012, net cash flow provided by financing activities was $378.8 million. The $253.3 million decrease from 2012 to 2013 resulted mainly from our long-term debt activity. During the first nine months of 2013, net borrowings under our credit facility provided $150 million of cash flow. In 2012, we issued $750 million of 5.875% senior notes and used $363.6 million of the proceeds to retire our outstanding 7.125% senior notes. Net proceeds from the debt offering together with $25 million of net bank debt borrowings provided $411.4 million of cash flow for the 2012 period.

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Reconciliation of Adjusted Cash Flow from Operations

	For the Nine Months Ended September 30,
(in thousands)	2013		2012
Net cash provided by operating activities	$	940,748	$	836,148
Change in operating assets and liabilities	91,971		(1,509		)
Adjusted cash flow from operations	$	1,032,719	$	834,639

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

Capital Expenditures

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

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Acquisitions:
Proved *	$	(246	)	$	––		$	677		$	—
Unproved	1,816			4,636			5,481			11,349
	1,570			4,636			6,158			11,349
Exploration and development:
Land and seismic	59,035			28,226			127,064			86,613
Exploration and development	328,655			389,989			1,059,546			1,120,740
	387,690			418,215			1,186,610			1,207,353
Sales proceeds:
Proved *	1,212			(10,894		)	(36,667		)	(11,079		)
Unproved	—			––			(1,041		)	(1,088		)
	1,212			(10,894		)	(37,708		)	(12,167		)
	$	390,472		$	411,957		$	1,155,060		$	1,206,535

* The negative amount in the third-quarter 2013 proved acquisitions and the positive amount in the third-quarter 2013 proved sales proceeds reflect net purchase price adjustments related to second-quarter 2013 activity.

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

Our exploration and development expenditures of $1.187 billion during the first nine months of 2013 were slightly lower than the $1.207 billion of expenditures during the 2012 period. Approximately 65% of our 2013 expenditures were for Permian Basin projects, located in the Delaware Basin of Texas and southeast New Mexico, mainly targeting the Bone-Spring and Wolfcamp formations. Most of the rest of our expenditures were in our Cana-Woodford shale play.

The following table reflects wells drilled by region:

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	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Gross wells
Permian Basin	42		37		132		131
Mid-Continent	67		55		154		119
Gulf Coast / Other	3		1		5		3
	112		93		291		253
Net wells
Permian Basin	28		24		87		88
Mid-Continent	21		23		56		49
Gulf Coast / Other	3		—		4		1
	52		47		147		138
% Gross wells completed as producers	99	%	99	%	99	%	97	%

As of September 30, 2013, we had 22 net wells awaiting completion: 12 Mid-Continent and 10 Permian Basin. We also had 16 operated rigs running: 13 in the Permian Basin, 2 in the Mid-Continent and 1 in the Gulf Coast.

We regularly review our exploration and development capital expenditures and will adjust our activity based on changes in commodity prices, service costs and drilling success. We have a diversified portfolio that gives us the flexibility to adjust our capital expenditures based upon market conditions.

In the first nine months of 2013 and 2012, we had property acquisitions of $6.2 million and $11.3 million, respectively.

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

Financial Condition

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

During the first nine months of 2013 our total assets increased by $749.2 million to $7.1 billion, up from $6.3 billion at December 31, 2012. The increase resulted mostly from the $740.7 million increase in our net oil and gas properties.

At September 30, 2013, our total liabilities were $3.2 billion, up $407.7 million from $2.8 billion at December 31, 2012. The increase is primarily attributable to a net increase in long-term debt of $150.0 million, an increase in non-current deferred income taxes of $217.3 million, and an increase in current liabilities of $60.0 million.

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Our stockholders’ equity totaled $3.8 billion at September 30, 2013, up $341.5 million from $3.5 billion at December 31, 2012. The increase resulted mainly from net income of $357.9 million less dividends of $36.4 million.

Dividends

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

Working Capital Analysis

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

Our working capital decreased $33.3 million (19%) from a deficit of $175.7 million at year-end 2012 to a deficit of $209.0 million at September 30, 2013.

Working capital decreased primarily because of the following:

· Cash and cash equivalents decreased by $65.0 million

· Accrued liabilities related to our E&D expenditures increased by $18.1 million.

· Net accounts payable and accrued liabilities related to non-E&D expenditures increased by $37.6 million.

These working capital decreases were partially offset by an increase in operations related accounts receivable of $88.6 million.

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

Long-term Debt

Debt at September 30, 2013 and December 31, 2012 consisted of the following:

(in thousands)	September 30, 2013		December 31, 2012
Bank debt	$	150,000	$	—
5.875% Senior Notes due 2022	750,000		750,000
Total long-term debt	$	900,000	$	750,000

Bank Debt

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at the discretion of the lenders based on the value of our proved reserves. The next regular annual redetermination date is scheduled for April 15, 2014.

As of September 30, 2013, we had $150 million of bank debt outstanding at a weighted average interest rate of 2.28%. We also had letters of credit outstanding of $2.5 million, leaving an unused borrowing availability of $847.5 million. During the first nine months of 2013, we had average daily bank debt outstanding of $147.4 million, compared to $73.3 million for the same period in 2012. Our highest amount of bank borrowings outstanding during the first nine months of 2013 was $285 million, occurring in mid-September. During the first nine months of 2012, the highest amount of outstanding bank borrowings was $275 million, occurring in mid-March.

The Credit Facility has a number of financial and non-financial covenants of which we were in compliance with at September 30, 2013. See Note 7 to the Consolidated Financial Statements for further information.

5.875% Notes due 2022

7.125% Notes due 2017

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

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2013, our material off-balance sheet arrangements included operating lease agreements, which are customary in the oil and gas industry and are included in the table below.

Contractual Obligations and Material Commitments

At September 30, 2013, we had contractual obligations and material commitments as follows:

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

Long-term debt(1)	$	900,000	$	—	$	150,000		$	—		$	750,000
Fixed-Rate interest payments(1)	396,563		44,063		88,125			88,125			176,250
Operating leases	130,681		8,680		21,348			20,794			79,859
Drilling commitments(2)	176,922		176,922		––			—			—
Gathering facilities and pipelines(3)	4,089		4,089		—			—			—
Asset retirement obligation (4)	156,359		49,435		––		(4)	—		(4)	—		(4)
Other liabilities(5)	69,022		19,909		31,568			961			16,584
Firm Transportation	808		600		208			—			—

(1) These amounts do not include interest on the $150 million of bank debt outstanding at September 30, 2013. See Item 3: Interest Rate Risk for more information regarding fixed and variable rate debt.

(2) Our drilling commitments consist of obligations to finish drilling and completing wells in progress at September 30, 2013.

(3) We have projects in New Mexico and Texas where we are constructing gathering facilities and pipelines. At September 30, 2013, we had commitments of $4.1 million relating to this construction.

(4) We have not included the long-term asset retirement obligations because we are not able to precisely predict the timing of these amounts.

(5) Other liabilities include the fair value of our liabilities associated with our benefit obligations and other miscellaneous commitments.

At September 30, 2013, we had firm sales contracts to deliver approximately 25 Bcf of natural gas over the next 11 months. In total, our financial exposure would be approximately $82.8 million should we not deliver this gas. Our exposure will fluctuate with price volatility and actual volumes delivered. However, we believe Cimarex has no financial exposure from these contracts based on our current proved reserves and production levels.

In the normal course of business we have various delivery commitments which are not material individually or in the aggregate. All of the noted commitments were routine and were made in the normal course of our business.

Based on current commodity prices and anticipated levels of production, we believe that estimated net cash generated from operations and amounts available under our existing Credit Facility will be adequate to meet future liquidity needs.

2013 Outlook

Our 2013 E&D capital investment is presently expected to be approximately $1.55 to $1.6 billion. Nearly all of this capital will be used for drilling oil and liquids-rich gas wells in the Permian Basin and Cana-Woodford shale play.

Production for 2013 is projected to be in the range of 695-700 MMcfe per day, or 11-12% growth over 2012. Fourth-quarter 2013 volumes are expected to average 714-734 MMcfe per day.

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

		2013
Production expense		$1.11 - $1.16
Transportation and other operating		0.40 - 0.45
DD&A and asset retirement obligation		2.35 - 2.45
General and administrative		0.28 - 0.32
Production taxes (% of oil and gas revenue)		5.8% - 6.2%

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We consider accounting policies related to oil and gas reserves, full cost accounting, goodwill, 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, 2013.

ITEM 3. QUANTITATIVE AND QUALITATIVE 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 enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production.

The following tables detail the financial derivative contracts we have in place as of September 30, 2013.

Oil Contracts

				Weighted Average Price						Fair Value
Period	Type	Volume/Day	Index(1)	Floor		Ceiling		Swap		(in thousands)
Oct 13 – Dec 13	Collars	6,000 Bbls	WTI	$	85.00	$	102.31	N/A		$	(1,311	)
Oct 13 – Dec 13	Swaps	6,000 Bbls	WTI	N/A		N/A		$	96.13	$	(2,987	)
Jan 14 – Dec 14	Collars	6,000 Bbls	WTI	$	85.00	$	105.68	N/A		$	1,477

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

Gas Contracts

Weighted Average
Price

Fair Value

Period

Type

Volume/Day

Index(1)

Floor

Ceiling

(in thousands)

Oct 13 – Dec 14

Collars

80,000 MMBtu

PEPL

3.51

4.57

8,386

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

While these contracts limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. For the oil contracts listed above, a hypothetical $1.00 change in the price below or above the contracted price applied to the notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2013 of $3.3 million. For the gas contracts listed above, a hypothetical $0.10 change in the price below or above the contracted price applied to the

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notional amounts would cause a change in our gain (loss) on mark-to-market derivatives in 2013 of $3.7 million.

Counterparty credit risk did not have a significant effect on our cash flow calculations and commodity derivative valuations. This is primarily because we have mitigated our exposure to any single counterparty by contracting with numerous counterparties and because our derivative contracts are held with “investment grade” counterparties that are 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, 2013, our debt was comprised of the following:

(in thousands)	Fixed Rate Debt		Variable Rate Debt
Bank debt	$	—	$	150,000
5.875% Notes due 2022	750,000		—
Total long-term debt	$	750,000	$	150,000

As of September 30, 2013, the amounts outstanding under our five-year senior unsecured revolving credit facility bears interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio. Our senior unsecured notes bear interest at a fixed rate of 5.875% and will mature on May 1, 2022.

We consider our interest rate exposure to be minimal because approximately 83% of our long-term debt obligations were at fixed rates. An increase of 100 basis points in the interest rate of our variable rate debt would increase our annual interest expense by $1.5 million. This sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. See Note 3 and Note 7 to the Consolidated Financial Statements in this report for additional information regarding debt.

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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 13(a) and 15(d)-15(e) as of September 30, 2013 and concluded that the disclosure controls and procedures are effective in providing reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system reflects 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, 2013, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal controls over financial reporting or in other factors that occurred during the fiscal quarter ended September 30, 2013 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II

ITEM 6 — EXHIBITS

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

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

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

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

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB XBRL Taxonomy Extension Label Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

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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 6, 2013


	CIMAREX ENERGY CO.


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


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