UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

(Mark One)

 

 

For the Quarterly Period ended June 30, 2014

 

Commission File No. 001-31446

 

CIMAREX ENERGY CO.

 

1700 Lincoln Street, Suite 1800

Denver, Colorado 80203-4518

(303) 295-3995

 

 

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   ☒   No   ☐

 

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   ☒   No   ☐

 

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  ☒	Accelerated filer  ☐	Non-accelerated filer  ☐ (Do not check if a smaller reporting company)	Smaller reporting company  ☐

 

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

 

The number of shares of Cimarex Energy Co. common stock outstanding as of June 30, 2014 was 87,021,935 .

 

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CIMAREX ENERGY CO.

 

Table of Contents

 

 

 

 

 

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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

MMBbl /MMBbl s —Million barrels

MMBtu —Million British Thermal Units

MMcf —Million cubic feet

MMcf/d —Million cubic feet per day

MMcfe —Million cubic feet equivalent

MMcfe/d —Million cubic feet equivalent per day

Net Acres —Gross acreage multiplied by working interest percentage

Net Production —Gross production multiplied by net revenue interest

NGL or NGLs —Natural gas liquids

Tcf —Trillion cubic feet

Tcfe —Trillion cubic feet equivalent

 

E nergy equivalent is determined using the ratio of o ne barrel of crude oil , condensate or NGL to 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 f rom 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

 

		June 30,					December 31,
		2014					2013
		(Unaudited)
		(in thousands, except share data)
Assets
Current assets:
Cash and cash equivalents		$		128,555					$	4,531
Receivables, net				449,456						367,754
Oil and gas well equipment and supplies				85,278						66,772
Deferred income taxes				13,725						16,854
Derivative instruments				—						4,268
Prepaid expenses				7,906						7,867
Other current assets				1,432						1,093
Total current assets				686,352						469,139
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties				13,801,249						12,863,961
Unproved properties and properties under development, not being amortized				886,361						585,361
				14,687,610						13,449,322
Less — accumulated depreciation, depletion and amortization				(7,838,007)						(7,483,685)
Net oil and gas properties				6,849,603						5,965,637
Fixed assets, net				182,521						146,918
Goodwill				620,232						620,232
Other assets, net				60,299						51,209
		$		8,399,007					$	7,253,135
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$		126,259					$	116,110
Accrued liabilities				468,952						412,495
Derivative instruments				8,506						389
Revenue payable				197,473						154,173
Total current liabilities				801,190						683,167
Long-term debt				1,500,000						924,000
Deferred income taxes				1,626,206						1,459,841
Other liabilities				184,980						163,919
Total liabilities				4,112,376						3,230,927
Commitments and contingencies
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, 87,021,935 and 87,152,197 shares issued, respectively				870						872
Paid-in capital				1,975,159						1,970,113
Retained earnings				2,309,429						2,050,034
Accumulated other comprehensive income				1,173						1,189
				4,286,631						4,022,208
		$		8,399,007					$	7,253,135

 See accompanying notes to consolidated financial statements.

 

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Table of Contents

CIMAREX ENERGY CO.

Consolidated Statements of Income and Comprehensive Income

(Unaudited)

 

		For the Three Months						For the Six Months
		Ended June 30,						Ended June 30,
		2014			2013			2014			2013
		(in thousands, except per share data)
Revenues:
Gas sales		$	172,503		$	126,547		$	342,600		$	227,668
Oil sales			354,882			304,466			679,953			561,998
NGL sales			95,470			52,309			185,427			109,184
Gas gathering and other			14,284			10,844			26,748			21,571
Gas marketing, net			(470)			(409)			1,157			(308)
			636,669			493,757			1,235,885			920,113
Costs and expenses:
Depreciation, depletion and amortization			194,989			147,231			368,920			283,669
Asset retirement obligation			3,650			2,884			6,868			5,283
Production			86,085			69,433			161,226			138,819
Transportation, processing, and other operating			46,478			22,022			90,726			40,656
Gas gathering and other			10,041			5,184			18,825			11,340
Taxes other than income			32,323			27,807			65,944			52,935
General and administrative			16,571			22,836			37,283			38,413
Stock compensation			3,548			3,507			7,272			7,112
(Gain) loss on derivative instruments, net			2,454			(13,660)			18,189			(12,057)
Other operating, net			112			2,365			215			5,297
			396,251			289,609			775,468			571,467
Operating income			240,418			204,148			460,417			348,646
Other (income) and expense:
Interest expense			16,724			14,112			30,766			27,318
Capitalized interest			(8,575)			(7,387)			(15,865)			(16,582)
Other, net			(4,129)			(8,758)			(11,084)			(11,374)
Income before income tax			236,398			206,181			456,600			349,284
Income tax expense			87,758			76,616			169,503			129,792
Net income		$	148,640		$	129,565		$	287,097		$	219,492
Earnings per share to common stockholders:
Basic
Distributed		$	0.16		$	0.14		$	0.32		$	0.28
Undistributed			1.55			1.36			2.98			2.26
		$	1.71		$	1.50		$	3.30		$	2.54
Diluted
Distributed		$	0.16		$	0.14		$	0.32		$	0.28
Undistributed			1.54			1.35			2.97			2.25
		$	1.70		$	1.49		$	3.29		$	2.53
Comprehensive income:
Net income		$	148,640		$	129,565		$	287,097		$	219,492
Other comprehensive income:
Change in fair value of investments, net of tax			(56)			19			(16)			99
Total comprehensive income		$	148,584		$	129,584		$	287,081		$	219,591

See accompanying notes to consolidated financial statements.

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Table of Contents

CIMAREX ENERGY CO.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

		For the Six Months
		Ended June 30,
		2014			2013
		(in thousands)
Cash flows from operating activities:
Net income		$	287,097		$	219,492
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			368,920			283,669
Asset retirement obligation			6,868			5,283
Deferred income taxes			169,503			129,792
Stock compensation			7,272			7,112
(Gain) loss on derivative instruments			18,189			(12,057)
Settlements on derivative instruments			(5,804)			1,765
Changes in non-current assets and liabilities			(2,436)			5,790
Other, net			2,395			(2,116)
Changes in operating assets and liabilities:
Receivables, net			(81,702)			(55,060)
Other current assets			(19,182)			14,840
Accounts payable and accrued liabilities			18,649			(28,724)
Net cash provided by operating activities			769,769			569,786
Cash flows from investing activities:
Oil and gas expenditures			(1,138,539)			(776,138)
Sales of oil and gas assets			1,123			14,407
Sales of other assets			251			31,157
Other expenditures			(51,401)			(25,475)
Net cash used by investing activities			(1,188,566)			(756,049)
Cash flows from financing activities:
Net bank debt borrowings			(174,000)			142,000
Proceeds from other long-term debt			750,000			—
Financing costs incurred			(11,218)			—
Dividends paid			(26,022)			(22,448)
Issuance of common stock and other			4,061			1,705
Net cash provided by financing activities			542,821			121,257
Net change in cash and cash equivalents			124,024			(65,006)
Cash and cash equivalents at beginning of period			4,531			69,538
Cash and cash equivalents at end of period		$	128,555		$	4,532

 

See accompanying notes to consolidated financial statements.

 

 

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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 2013 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.  We have evaluated subsequent events through the date of this filing.

 

Oil and Gas Properties

 

We use the full cost method of accounting for our oil and gas operations.  Accounting rules require us to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment.  The primary components impacting this calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs, 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 June 30, 2014, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.   However, a decline of 9% 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.

 

Oil, Gas and NGL sales

 

Oil, gas and NGL sales are based on the sales method by which revenue is recognized on actual volumes sold to purchasers.  There is a ready market for our products and sales occur soon after production.  The determination to record and separately disclose NGL volumes is based on the location at which both title contractually transfers from Cimarex to a buyer and the associated volumes can be physically quantified.  For those NGL volumes that we have recorded and disclosed separately, contractual title of the volumes has passed from Cimarex to a buyer at a point where the NGL volumes have been physically separated from the production stream.  Should title contractually transfer before NGL volumes can be physically separated and quantified (typically at the wellhead), we do not report separate NGL volumes and the value of the NGLs are included in the reported value of the disclosed gas volumes.

 

Under certain contracts, when NGLs are extracted from the gas stream, processors receive as compensation a portion of the sales value from both the residue gas and the NGLs as a processing fee and remit the contractual proceeds to us.  Prior to 2014,  revenue was recognized net of these processing fees for residue gas and NGLs sold under these contracts as allowed under EITF 00-10 Accounting for Shipping and Handling Fees and Costs.   Beginning in 2014, we believe that with the increase in NGL production and the impact of recent changes to these contracts, these processing costs will become more significant in the future.  Accordingly, we have changed our policy to record these processing costs with operating costs as allowed under EITF 00-10.  As a result, beginning in 2014, our realized prices for sales under these contracts reflect the value of 100% of the residue gas and NGLs yielded by processing, rather than the value associated with the contractual proceeds we received.  The related processing fees now are included in “transportation, processing and other” operating costs.  The effect of this change

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in the current quarter and six months ended was that total revenue was $12.2 million and $24.1 million, respectively, higher with an offsetting increase in total transportation, processing and other costs.  There was no impact on operating income.  Financial statements for periods prior to 2014 have not been reclassified to reflect this change in accounting treatment as it was impracticable to do so.

 

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 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:

 

 

		June 30,			December 31,
(in thousands)		2014			2013
Receivables, net of allowance
Trade		$	95,201		$	83,070
Oil and gas sales			333,614			265,050
Gas gathering, processing, and marketing			20,452			19,102
Other			189			532
Receivables, net		$	449,456		$	367,754
Accounts payable
Trade		$	84,567		$	80,918
Gas gathering, processing, and marketing			41,692			35,192
Accounts payable		$	126,259		$	116,110
Accrued liabilities
Exploration and development		$	251,663		$	173,298
Taxes other than income			27,134			27,509
Other			190,155			211,688
Accrued liabilities		$	468,952		$	412,495

 

 

Recently Issued Accounting Standards

 

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606).  The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue

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Recognition ,   and most industry-specific guidance throughout the Industry Topics of the Codification .  We must comply with this ASU beginning in fiscal year 2017 and early adoption is not permitted.  Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach.    We are currently evaluating the impact of the provisions of Topic 606 and the effects of adoption cannot be determined at this time.

 

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 June 30, 2014:

 

Oil Contracts

 

 

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(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)
Jul 14 – Dec 14		Collars		80,000 MMBtu		PEPL		$	3.51		$	4.57		$	(969)
Jul 14 – Dec 14		Collars		60,000 MMBtu		Perm EP		$	3.62		$	4.50		$	(1,563)

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(1)  PEPL refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC.  Perm EP refers   to El Paso Natural Gas Company, Permian Basin 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 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. 

 

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.

 

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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						Six Months Ended
		June 30,						June 30,
(in thousands)		2014			2013			2014						2013
Gain (loss) on derivative instruments, net:
Natural gas contracts		$	2,062		$	9,199		$		(9,820)				$		9,199
Oil contracts			(4,516)			4,461				(8,369)						2,858
Gain (loss) on derivative instruments, net		$	(2,454)		$	13,660		$		(18,189)				$		12,057
Gains (losses) from settlement of derivative instruments:
Natural gas contracts		$	(37)		$	—		$		(4,824)				$		—
Oil contracts			(980)			1,039				(980)						1,765
Settlement gains (losses)		$	(1,017)		$	1,039		$		(5,804)				$		1,765

 

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.

 

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.

 

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The following table presents the amounts and classifications of our derivative assets and liabilities as of June 30, 2014 and December 31, 2013, as well as the potential effect of netting arrangements on contracts with the same counterparty.

 

 

 

 

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.  Because some of the member banks have discontinued hedging activities, in the future we may hedge with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

 

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 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.

 

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The following tables provide fair value measurement information for certain assets and liabilities as of June 30, 2014 and December 31, 2013:

 

 

 

June 30, 2014:		Carrying			Fair
(in thousands)		Amount			Value
Financial Assets (Liabilities):
5.875% Notes due 2022		$	(750,000)		$	(832,500)
4.375% Notes due 2024		$	(750,000)		$	(765,938)
Derivative instruments — liabilities		$	(8,506)		$	(8,506)
December 31, 2013:		Carrying			Fair
(in thousands)		Amount			Value
Financial Assets (Liabilities):
Bank debt		$	(174,000)		$	(174,000)
5.875% Notes due 2022		$	(750,000)		$	(799,988)
Derivative instruments — assets		$	4,268		$	4,268
Derivative instruments — liabilities		$	(389)		$	(389)

 

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 December 31, 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 4.375% and 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, 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 it is probable that a receivable will

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not be collected and the amount of the reserve may be reasonably estimated.  At June 30, 2014 and December 31, 2013, the allowance for doubtful accounts was $3.2 million and $6.0 million , respectively.

 

4. Capital Stock

 

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock.  At June 30, 2014, there were no shares of preferred stock outstanding.  A summary of our common stock activity for the six months ended June 30, 2014 follows:

 

 

(in thousands)
Issued and outstanding as of December 31, 2013		87,152
Issuance of restricted stock awards		14
Common stock reacquired and retired		(117)
Restricted stock forfeited and retired		(101)
Option exercises, net of cancellations		74
Issued and outstanding as of June 30, 2014		87,022

 

Dividends

 

In May 2014, the Board of Directors declared a cash dividend of $0.16 per share.  The dividend is payable on September 2, 2014 to stockholders of record on August 15, 2014.  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

 

In May 2014, our 2014 Equity Incentive Plan (the 2014 Plan) was approved by stockholders and our previous plan was terminated at that time.  Outstanding awards under the previous plan were not impacted.  The primary purposes of the 2014 Plan are to increase the number of shares available in connection with awards, provide flexibility in the types of available awards and design of awards, modify certain individual award limits and revise the performance measures for qualified performance-based awards.  The 2014 Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, dividend equivalents and other stock-based awards.  A total of 6.6  million shares of common stock may be issued under the 2014 Plan, including shares available from the previous plan.

 

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

 

 

		Three Months Ended						Six Months Ended
		June 30,						June 30,
(in thousands)		2014			2013			2014			2013
Restricted stock		$	5,979		$	6,017		$	12,430		$	11,923
Stock options			782			707			1,555			1,415
			6,761			6,724			13,985			13,338
Less amounts capitalized to oil and gas properties			(3,213)			(3,217)			(6,713)			(6,226)
Compensation expense		$	3,548		$	3,507		$	7,272		$	7,112

 

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

 

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Restricted Stock and Units

 

During the six months ended June 30, 2014 and 2013, we granted 13,652 and 49,036 service-based stock awards at a weighted average grant-date fair value of $127.30 and $70.92 , respectively. 

 

From time to time performance 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 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						Six Months Ended
		June 30,						June 30,
(in thousands)		2014			2013			2014			2013
Performance stock awards		$	2,867		$	2,568		$	5,814		$	5,253
Service-based stock awards			3,112			3,449			6,616			6,670
			5,979			6,017			12,430			11,923
Less amounts capitalized to oil and gas properties			(2,891)			(2,954)			(6,071)			(5,738)
Restricted stock compensation expense		$	3,088		$	3,063		$	6,359		$	6,185

 

Unrecognized compensation cost related to unvested restricted shares at June 30, 2014 was $55.6  million, which we expect to recognize over a weighted average period of approximately 2.3  years.

 

The following table provides information on restricted stock and unit activity as of June 30, 2014 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.

 

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		Restricted		Restricted
		Stock		Units
Outstanding as of January 1, 2014		1,863,834		8,838
Vested		(287,047)		N/A
Converted to stock		N/A		—
Granted		13,652		—
Canceled		(100,568)		—
Outstanding as of June 30, 2014		1,489,871		8,838
Vested included in outstanding		N/A		8,838

 

Stock Options

 

Options that have been granted under the 2014 plan and previous plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years.  The exercise price for an option under the 2014 plan is the closing price of our common stock as reported by the New York Stock Exchange on the date of grant. The previous plans provided that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant.  No options were granted during the first six months of 2014 and 2013.

 

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						Six Months Ended
		June 30,						June 30,
(in thousands)		2014			2013			2014			2013
Stock option awards		$	782		$	707		$	1,555		$	1,415
Less amounts capitalized to oil and gas properties			(322)			(263)			(642)			(488)
Stock option compensation expense		$	460		$	444		$	913		$	927

 

As of June 30, 2014, there was $2.7 million of unrecognized compensation cost related to non-vested stock options.  We expect to recognize that cost pro rata over a weighted-average period of approximately 1.2  years.

 

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Information about outstanding stock options is summarized below:

 

 

				Weighted			Weighted			Aggregate
				Average			Average			Intrinsic
				Exercise			Remaining			Value
		Options		Price			Term			(in thousands)
Outstanding as of January 1, 2014		531,016		$	59.78
Exercised		(73,935)		$	54.92
Forfeited		(7,670)		$	63.42
Outstanding as of June 30, 2014		449,411		$	60.52		4.9	Years		$	36,989
Exercisable as of June 30, 2014		114,067		$	50.82		4.0	Years		$	10,495

 

The following table provides information regarding the options exercised:

 

		Six months ended
		June 30,
(dollars in thousands)		2014			2013
Number of options exercised			73,935			43,156
Cash received from option exercises		$	4,061		$	1,705
Intrinsic value of options exercised		$	4,632		$	1,407

 

The following table provides information on non-vested stock option activity as of June 30, 2014 and changes during the year:

 

				Weighted			Weighted
				Average			Average
				Grant-Date			Exercise
		Options		Fair Value			Price
Non-vested as of January 1, 2014		343,014		$	21.64		$	63.81
Forfeited		(7,670)		$	21.94		$	63.42
Non-vested as of June 30, 2014		335,344		$	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 plugging and 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.

 

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The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2014:

 

(in thousands)
Asset retirement obligation at January 1, 2014		$	154,026
Liabilities incurred			7,905
Liability settlements and disposals			(7,302)
Accretion expense			3,756
Revisions of estimated liabilities			8,210
Asset retirement obligation at June 30, 2014			166,595
Less current obligation			(15,176)
Long-term asset retirement obligation		$	151,419

 

 

 

 

 

7. Long-Term Debt

 

Debt at June 30, 2014 and December 31, 2013 consisted of the following:

 

 

		June 30,			December 31,
(in thousands)		2014			2013
Bank debt		$	—		$	174,000
5.875% Senior Notes due 2022			750,000			750,000
4.375% Senior Notes due 2024			750,000			—
Total long-term debt		$	1,500,000		$	924,000

 

Bank Debt

 

In May 2014, we amended our senior unsecured revolving credit facility (Credit Facility) to extend the maturity date two years to July 14, 2018 and lowered the margins applicable to loans and commitments.  The amendment also raised our borrowing base from $2.25 billion to $2.5 billion until the next regular annual redetermination date scheduled for April 15, 2015.  The borrowing base under the Credit Facility is determined at the discretion of the lenders based on the value of our proved reserves.  Our aggregate commitments remained unchanged at $1 billion. 

 

As of June 30, 2014, we had letters of credit outstanding under the Credit Facility of $2.5  million, leaving an unused borrowing availability of $997.5  million.

 

At our option, borrowings under the Credit Facility, as amended in May 2014, may bear interest at either (a)  LIBOR plus 1.5-2.25% , 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 0.5-1.25% , 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 .  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 .  Other covenants could limit our ability to incur additional indebtedness, pay

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dividends, repurchase our common stock, or sell assets.  As of June 30, 2014, 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.

 

 4 .375% Notes due 2024

 

In June 2014, we issued $750 million of 4.375% senior notes due June 1, 2024, with interest payable semiannually in June and December.  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. At any time prior to March 1, 2024, we may redeem all or a part of the notes at a defined make-whole redemption price calculated at the time of redemption.  At any time on or after March 1, 2024, we may redeem all or part of the notes at a price equal to 100% of the principal amount.

 

8. Income Taxes

 

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

 

 

		Three months ended						Six months ended
		June 30,						June 30,
(in thousands)		2014			2013			2014			2013
Current benefit		$	—		$	—		$	—		$	—
Deferred taxes			87,758			76,616			169,503			129,792
		$	87,758		$	76,616		$	169,503		$	129,792

 

At December 31, 2013 , we had a U.S. net tax operating loss carryforward of approximately $605.4  million, which would expire in tax years 2031 through 2033.  We believe that the carryforward will be utilized before it expires.  The amount of U.S. net tax operating loss carryforward that will be recorded to equity when utilized to reduce taxes payable is $56.4 million.  We also had an alternative minimum tax credit carryforward of approximately $4.1  million.

 

At June 30, 2014 , we had no unrecognized tax benefits that would impact our effective tax 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 2009-2012 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 three and six months ended June 30, 2014 and June 30 ,   2013 were 37.1% and 37.2% , respectively.

 

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9. Supplemental Disclosure of Cash Flow Information

 

		Three months ended						Six months ended
		June 30,						June 30,
(in thousands)		2014			2013			2014			2013
Cash paid during the period for:
Interest expense (including capitalized amounts)		$	24,195		$	24,208		$	26,290		$	25,226
Interest capitalized		$	12,469		$	14,603		$	13,557		$	15,312
Income taxes		$	353		$	150		$	354		$	205
Cash received for income taxes		$	133		$	222		$	342		$	237

 

 

 

 

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						Six months ended
		June 30,						June 30,
(in thousands, except per share data)		2014			2013			2014			2013
Basic:
Net income		$	148,640		$	129,565		$	287,097		$	219,492
Participating securities’ share in earnings			(2,320)			(2,131)			(4,464)			(3,543)
Net income applicable to common stockholders		$	146,320		$	127,434		$	282,633		$	215,949
Diluted:
Net income		$	148,640		$	129,565		$	287,097		$	219,492
Participating securities’ share in earnings			(2,316)			(2,128)			(4,457)			(3,539)
Net income applicable to common stockholders		$	146,324		$	127,437		$	282,640		$	215,953
Shares:
Basic shares outstanding			85,532			84,942			85,532			84,942
Incremental shares from assumed exercise of stock options			157			112			147			101
Fully diluted common stock			85,689			85,054			85,679			85,043
Excluded (1)			—			100			1			156
Earnings per share to common stockholders (2):
Basic		$	1.71		$	1.50		$	3.30		$	2.54
Diluted		$	1.70		$	1.49		$	3.29		$	2.53

 

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(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 .

 

 

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11. Commitments and Contingencies

 

Commitments

 

We have commitments of $192.0  million to finish drilling and completing wells in progress at June 30, 2014.  We also have various commitments for drilling rigs.  The total minimum expenditure commitments under these agreements are $53.6   million.

 

In New Mexico and Texas, we are constructing gathering facilities and pipelines.  At June 30, 2014, we had commitments of $6.6  million relating to these construction projects.

 

At June 30, 2014, we had firm sales contracts to deliver approximately 34.7  Bcf of natural gas over the next 12  months.  If this gas is not delivered, our financial commitment would be approximately $146.4  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 from which we can fulfill these obligations.

 

We have other various transportation and delivery commitments in the normal course of business, which approximate $2  million over the next four years.

 

We have various commitments for office space and equipment under operating lease arrangements totaling $131.7  million for the next five years and beyond.

 

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

 

Litigation

 

In the ordinary 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. 

 

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 of H&P, Cimarex assumed the assets and liabilities of H&P’s exploration and production business, including this lawsuit.  For 2008, we recorded a litigation expense of $119.6  million plus additional post-judgment interest and costs after the trial court entered a final judgment for these amounts. 

 

On December 10, 2013, the Oklahoma Supreme Court reversed the trial court’s original judgment of $119.6 million and affirmed an alternative jury verdict for $3.65 million.  In light of the Oklahoma Supreme Court’s ruling, on December 31, 2013, we reduced previously recognized litigation expense and the associated long-term liability by $142.8 million.

 

On March 14, 2014, after denying the Plaintiffs’ Petition for Rehearing, the Oklahoma Supreme Court remanded the matter back to the trial court.  On March 31, 2014, the trial court entered a final judgment for damages, post-judgment interest and a payment in lieu of bond. The following day Cimarex paid the Plaintiffs $15.8 million in satisfaction of these awards, which now are final and not appealable.

 

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On June 24, 2014, the trial court ruled that the Plaintiffs were not entitled to prejudgment interest but were entitled to an award of attorney’s fees and costs.  At a subsequent hearing the trial court will determine the amount of the attorney’s fees and costs owed to Plaintiffs.  The outcome of these remaining issues cannot be determined at this time and will be subject to an appeal.  Our current assessments and estimates likely will change in the future as a result of subsequent legal proceedings both in the trial court and on appeal.

 

 

 

12. Property Acquisitions and Sales

The following acquisitions and sales were made in the ordinary course of business.

During the first half of 2014, we had property acquisitions of $259  million, primarily in the Cana-Woodford shale play in Western Oklahoma. In order to acquire and sell oil and gas properties in a tax efficient manner, we periodically enter into like-kind exchange tax deferred transactions. Certain of these property acquisitions were structured to qualify as the first step of a reverse like-kind exchange.  We utilized an exchange accommodation titleholder, a type of variable interest entity, for which we are the primary beneficiary.  Accordingly, we have consolidated the oil and gas assets and reserves attributable to these properties.  During the same period of 2013, we had property acquisitions of $4.6 million.

There were no significant property sales during the first half of 2014.  Subsequent to June 30, 2014, we sold interests in Kansas non-core oil and gas properties for net proceeds of approximately $136 million.  In the first half of 2013, we sold interests in non-core oil and gas properties for $38.9 million. 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.