Cimarex Energy (CIMXP) 10-K 23 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	CIMAREX ENERGY CO
Entity Central Index Key	1,168,054
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 10.2
Entity Common Stock, Shares Outstanding		94,819,854
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 779,382	$ 405,862
Accounts receivable:
Trade, net of allowance	81,888	134,443
Oil and gas sales, net of allowance	136,537	259,220
Gas gathering, processing, and marketing, net of allowance	6,935	18,009
Other	38	436
Oil and gas well equipment and supplies	54,579	89,780
Deferred income taxes		13,475
Derivative instruments	10,745
Prepaid expenses	7,036	9,356
Other current assets	790	1,223
Total current assets	1,077,930	931,804
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	15,546,948	14,402,064
Unproved properties and properties under development, not being amortized	440,166	759,149
Gross oil and gas properties	15,987,114	15,161,213
Less - accumulated depreciation, depletion, amortization and impairment	(12,710,968)	(8,257,502)
Net oil and gas properties	3,276,146	6,903,711
Fixed assets, less accumulated depreciation of $207,173 and $175,453	230,009	211,031
Goodwill	620,232	620,232
Derivative instruments	501
Other assets, net	38,468	41,691
Total assets	5,243,286	8,708,469
Accounts payable:
Trade	53,384	102,276
Gas gathering, processing, and marketing	13,431	35,775
Accrued liabilities:
Exploration and development	56,721	200,929
Taxes other than income	17,545	26,950
Other	173,242	219,505
Revenue payable	95,744	190,892
Total current liabilities	410,067	776,327
Long-term debt:
Principal	1,500,000	1,500,000
Less - unamortized debt issuance costs	(14,380)	(16,824)
Long-term debt, net	1,485,620	1,483,176
Deferred income taxes	352,705	1,754,706
Asset retirement obligation	153,857	159,792
Other liabilities	43,359	33,836
Total liabilities	2,445,608	4,207,837
Stockholders' equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 94,820,570 and 87,592,535 shares issued, respectively	948	876
Paid-in capital	2,762,976	1,997,080
Retained earnings	33,313	2,501,574
Accumulated other comprehensive income	441	1,102
Total stockholders' equity	2,797,678	4,500,632
Total liabilities and stockholders' equity	$ 5,243,286	$ 8,708,469

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidated Balance Sheets
Fixed assets, accumulated depreciation (in dollars)	$ 207,173	$ 175,453
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	94,820,570	87,592,535

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil sales	$ 809,664	$ 1,308,958	$ 1,250,212
Gas sales	428,227	687,930	471,045
NGL sales	179,647	375,941	231,248
Gas gathering and other	34,688	49,602	45,441
Gas marketing, net of related costs of $144,673, $256,836 and $187,772 respectively	393	1,745	105
Total revenues	1,452,619	2,424,176	1,998,051
Costs and expenses:
Impairment of oil and gas properties	3,716,883
Depreciation, depletion and amortization	778,923	806,021	615,874
Asset retirement obligation	9,121	10,082	7,989
Production	299,374	342,304	286,742
Transportation, processing and other operating	182,362	195,414	93,580
Gas gathering and other	38,138	35,113	25,876
Taxes other than income	84,764	128,793	112,732
General and administrative	74,688	81,160	77,466
Stock compensation	19,559	15,001	14,279
(Gain) loss on derivative instruments, net	(11,246)	(3,762)	209
Other operating (income) expense, net	856	116	(132,334)
Total costs and expenses	5,193,422	1,610,242	1,102,413
Operating income (loss)	(3,740,803)	813,934	895,638
Other (income) and expense:
Interest expense	85,746	72,865	54,973
Capitalized interest	(30,589)	(35,925)	(31,517)
Other, net	(13,576)	(28,907)	(21,518)
Income (loss) before income tax	(3,782,384)	805,901	893,700
Income tax expense (benefit)	(1,373,436)	298,697	329,011
Net income (loss)	$ (2,408,948)	$ 507,204	$ 564,689
Basic
Distributed (in dollars per share)	$ 0.64	$ 0.64	$ 0.56
Undistributed (in dollars per share)	(26.56)	5.15	5.92
Total basic (in dollars per share)	(25.92)	5.79	6.48
Diluted
Distributed (in dollars per share)	0.64	0.64	0.56
Undistributed (in dollars per share)	(26.56)	5.14	5.91
Total diluted (in dollars per share)	$ (25.92)	$ 5.78	$ 6.47
Comprehensive income (loss):
Net income (loss)	$ (2,408,948)	$ 507,204	$ 564,689
Other comprehensive income (loss):
Change in fair value of investments, net of tax	(661)	(87)	715
Total comprehensive income (loss)	$ (2,409,609)	$ 507,117	$ 565,404

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statements of Operations and Comprehensive Income (Loss)
Gas marketing, related costs	$ 144,673	$ 256,836	$ 187,772

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (2,408,948)	$ 507,204	$ 564,689
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments and other valuation losses	3,716,883
Depreciation, depletion and amortization	778,923	806,021	615,874
Asset retirement obligation	9,121	10,082	7,989
Deferred income taxes	(1,388,146)	298,293	329,700
Stock compensation	19,559	15,001	14,279
(Gain) loss on derivative instruments	(11,246)	(3,762)	209
Settlements on derivative instruments		7,641	(4,088)
Changes in non-current assets and liabilities	23,230	(2,440)	(141,215)
Other, net	4,206	(3,828)	751
Changes in operating assets and liabilities:
Receivables, net	186,699	(35,133)	(64,780)
Other current assets	37,954	(25,428)	14,234
Accounts payable and other current liabilities	(276,735)	45,714	(13,294)
Net cash provided by operating activities	691,500	1,619,365	1,324,348
Cash flows from investing activities:
Oil and gas expenditures	(979,044)	(2,108,250)	(1,572,288)
Sales of oil and gas assets	39,853	449,981	61,503
Sales of other assets	1,178	8,413	31,661
Other capital expenditures	(70,592)	(90,611)	(51,913)
Net cash used by investing activities	(1,008,605)	(1,740,467)	(1,531,037)
Cash flows from financing activities:
Net bank debt borrowings		(174,000)	174,000
Proceeds from other long-term debt		750,000
Proceeds from sale of common stock	752,100
Financing and underwriting fees	(24,633)	(11,616)	(100)
Dividends paid	(58,281)	(53,849)	(46,712)
Proceeds from exercise of stock options and other	21,439	11,898	14,494
Net cash provided by financing activities	690,625	522,433	141,682
Net change in cash and cash equivalents	373,520	401,331	(65,007)
Cash and cash equivalents at beginning of period	405,862	4,531	69,538
Cash and cash equivalents at end of period	$ 779,382	$ 405,862	$ 4,531

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
Balance at Dec. 31, 2012	$ 866	$ 1,939,628	$ 1,533,768	$ 474	$ 3,474,736
Balance, shares at Dec. 31, 2012	86,596,000
Increase (Decrease) in Stockholders' Equity
Dividends			(48,423)		(48,423)
Net income (loss)			564,689		564,689
Unrealized change in fair value of investments, net of tax				715	715
Issuance of restricted stock awards	$ 6	(6)
Issuance of service-based restricted stock awards, shares	579,000
Common stock reacquired and retired	$ (1)	(10,100)			(10,101)
Common stock reacquired and retired, shares	(153,000)
Restricted stock forfeited and retired	$ (2)	2
Restricted stock forfeited and retired, shares	(171,000)
Exercise of stock options	$ 3	14,491			14,494
Exercise of stock options, shares	276,000
Vesting of restricted stock units, shares	25,000
Stock-based compensation		26,098			26,098
Balance at Dec. 31, 2013	$ 872	1,970,113	2,050,034	1,189	4,022,208
Balance, shares at Dec. 31, 2013	87,152,000
Increase (Decrease) in Stockholders' Equity
Dividends			(55,664)		(55,664)
Net income (loss)			507,204		507,204
Unrealized change in fair value of investments, net of tax				(87)	(87)
Issuance of restricted stock awards	$ 4	(4)
Issuance of service-based restricted stock awards, shares	487,000
Common stock reacquired and retired	$ (1)	(13,559)			(13,560)
Common stock reacquired and retired, shares	(123,000)
Restricted stock forfeited and retired	$ (1)	1
Restricted stock forfeited and retired, shares	(135,000)
Exercise of stock options	$ 2	11,896			11,898
Exercise of stock options, shares	211,000
Stock-based compensation		28,633			28,633
Balance at Dec. 31, 2014	$ 876	1,997,080	2,501,574	1,102	4,500,632
Balance, shares at Dec. 31, 2014	87,592,000
Increase (Decrease) in Stockholders' Equity
Dividends			(59,313)		(59,313)
Net income (loss)			(2,408,948)		(2,408,948)
Unrealized change in fair value of investments, net of tax				(661)	(661)
Issuance of common stock	$ 69	729,468			729,537
Issuance of common stock, shares	6,900,000
Issuance of restricted stock awards	$ 5	(5)
Issuance of service-based restricted stock awards, shares	471,000
Common stock reacquired and retired	$ (2)	(21,238)			(21,240)
Common stock reacquired and retired, shares	(194,000)
Restricted stock forfeited and retired	$ (1)	1
Restricted stock forfeited and retired, shares	(90,000)
Exercise of stock options	$ 1	8,450			8,451
Exercise of stock options, shares	142,000
Stock-based compensation		36,232			36,232
Stock-based compensation tax benefit		12,988			12,988
Balance at Dec. 31, 2015	$ 948	$ 2,762,976	$ 33,313	$ 441	$ 2,797,678
Balance, shares at Dec. 31, 2015	94,821,000

BASIS OF PRESENTATION

BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2015
Basis of Presentation
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	1. BASI S OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma and New Mexico. Basis of presentation Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation. Segment Information We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed. Use of estimates The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. 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. The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. Estimates and judgments are also required in determining allowance for doubtful accounts, impairments of undeveloped properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements and commitments and contingencies. We analyze our estimates, including those related to oil, gas and NGL revenues, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. Cash and Cash Equivalents Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. Cash equivalents are stated at cost, which approximates market value. Oil and Gas Well Equipment and Supplies The Financial Accounting Standards Board (FASB) issued new guidance (ASU 2015-11) to simplify the measurement of inventory effective for interim and annual periods beginning in 2017 with early adoption permitted. Under current guidance, inventory is carried at the lower of cost or market, where market can be replacement cost or a net realizable value. Under the new guidance, inventory is to be carried at the lower of cost or net realizable value, where net realizable value is a defined estimated selling price. We adopted this standard as of December 31, 2015. An analysis of our oil and gas well equipment and supplies was performed and no impairment was required. However, the industry-wide decline in drilling operations has put downward pressure on the price of oil and gas well equipment and supplies. Further declines in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity. Oil and Gas Properties We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Companies that follow the full cost accounting method are required to make quarterly ceiling test calculations. This test ensures that total capitalized costs for oil and gas properties (net of accumulated DD&A and deferred income taxes) do not exceed 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. We currently do not have any unproven properties that are being amortized. Estimated future net cash flows are determined by commodity prices and proved reserve quantities. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for the prior 12 months. If net capitalized costs subject to amortization exceed this limit, the excess is charged to expense. At December 31, 2015, the carrying value of our oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation and we recognized an impairment of $965.3 m illion ( $613.4 million, net of tax). We also recognized impairments in the first three quarters of 2015. Full year impairments totaled $ 3.7 billion ($ 2.4 billion, net of tax). These impairments resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the future net cash flows from proved reserves. If pricing conditions stay at current levels or decline further, or if there is a negative impact on one or more of the other components of the calculation, we will incur full cost ceiling impairments in future quarters. The ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and gas properties is not reversible at a later date. Depletion of proved oil and gas properties is computed on the units- of-production method, whereby capitalized costs, including future development costs and asset retirement obligations, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities, commodity prices and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred. Fixed assets, net Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years. Goodwill Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. We have one reporting unit for which we first assess qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold ) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculated fair value by charging the impairment to expense. We evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our qualitative assessment at December 31, 201 5 , goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become less favorable. Revenue Recognition Oil, Gas and NGL Sales Revenue is recorded from the sales of oil, gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. There is a ready market for our products and sales occur soon after production. Under certain contracts, when NGLs are extracted from the gas stream, processors receive 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. Increasing NGL production combined with the impact of recent changes to these contracts has resulted in processing costs becoming more significant. Accordingly, we have changed our policy to record these processing costs with operating costs as allowed under EITF 00-10. 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 in 2014 was that total revenue was $ 51.4 million higher with an offsetting increase in total transportation, processing and other operating 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. Marketing Sales We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statements of operations and comprehensive income (loss) . Gas Imbalances We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. A liability is established in situations where there are insufficient proved reserves available to make-up an overproduced imbalance. Imbalances have not been significant in the periods presented. General and Administrative Expenses General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting. Derivatives Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 4 for additional information regarding our derivative instruments. Income Taxes In November 2015, the FASB issued a new standard (ASU 2015-17) regarding the balance sheet classification of deferred taxes for interim and annual periods beginning in 2017, with early adoption permitted on a prospective or retrospective basis. Under current guidance, entities that present a classified balance sheet must show both current and noncurrent amounts for deferred tax assets and liabilities. The new standard requires entities to classify all deferred tax assets and liabilities as noncurrent. We have elected to adopt this standard on a prospective basis as of December 31, 2015. Prior periods have not been retrospectively adjusted. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. We routinely assess the realizability of the deferred tax assets. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. We regularly assess and, if required, establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding our income taxes. Contingencies A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us. See Note 1 0 for additional information regarding our contingencies. 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 current portions of the asset retirement obligations are recorded in “accrued liabilities, other” in the accompanying consolidated balance sheets and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note 8 for additional information regarding our asset retirement obligations. Stock-based Compensation We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions) and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 6 for additional information regarding our stock-based compensation. Earnings (loss) per Share We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and therefore should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share based payment awards, consisting of restricted stock and units , qualify as participating securities. See Note 7 for additional information regarding our earnings per share. Recently Issued Accounting Standards The FASB issued ASU 2015-03, Interest-Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs in April 2015 and ASU 2015-15, Interest-Imputation of Interest-Presentation and Subsequent Measurement of Debt Issuance Costs associated with Line-of-Credit Arrangements in August 2015. These ASUs simplify the presentation of debt issuance costs by requiring such costs (except for those related to revolving credit facilities) to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability rather than as an asset. These ASUs are effective for annual and interim periods beginning in 2016. Early adoption is permitted. We adopted these ASUs at December 31, 2015. Accordingly, prior periods have been adjusted retrospectively to conform to this guidance (see Note 3). In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016. 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 Recognition , and most industry-specific guidance throughout the Industry Topics of the Codification . Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. We do not intend to adopt the standard early. We have not determined which transition method we will use and are continuing to evaluate the potential impact of this guidance. At this time we do not expect that the adoption of this standard will have a material effect on our financial position or results of operation and related disclosures. Subsequent Events The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing .

CAPITAL STOCK

CAPITAL STOCK	12 Months Ended
	Dec. 31, 2015
Capital Stock
Capital Stock	2 . CAPITAL STOCK Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 201 5 , there were no shares of preferred stock outstanding. See our Consolidated Statements of Stockholders’ Equity for detailed capital stock activity. In May 2015, we completed an underwritten public offering of 6,900,000 shares of common stock, which included 900,000 shares of common stock issued pursuant to an overallotment option to purchase additional shares granted to the underwriters. The stock was sold to the public at $109.00 per share, with a par value of $0.01 , and we received net proceeds of approximately $730 million from the sale of these shares of common stock, after deducting underwriting fees. Dividends A cash dividend has been paid to stockholders in every quarter since the first quarter of 2006. In February 2016, the quarterly dividend was decreased to $0.08 per share from $0.16 per share. Future dividend payments will depend on our level of earnings, financial requirements and other factors considered relevant by the Board of Directors. 2015 2014 2013 Dividend declared (in millions) $ $ $ Dividend per share $ $ $

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
Long-Term Debt
Long-Term Debt	3 . LONG-TERM DEBT A summary of our debt is as follows: December 31, 2015 December 31, 2014 Unamortized Debt Unamortized Debt (in thousands) Principal Issuance Costs Principal Issuance Costs 5.875% Senior Notes, due May 1, 2022 $ $ $ $ 4.375% Senior Notes, due June 1, 2024 Total long-term debt $ $ $ $ All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. In 2015, the FASB issued new guidance to simplify the presentation of debt issuance costs by requiring such costs (except for those related to revolving credit facilities) to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability (ASU 2015-03 and 2015-15). Historically, we have treated these costs as deferred assets and included them in Other assets, net in our balance sheet. We adopted the new guidance at December 31, 2015, and have applied it on a retrospective basis. The following table reflects the reclassification of $16.8 million of debt issuance costs from an asset to a direct deduction of the related debt liability for the balance sheet line items affected by the retrospective application of the change in accounting principle. December 31, 2014 After As Previously (in thousands) Adoption Reported Other assets, net $ $ Long-term debt $ $ Bank Debt In October 2015, we entered into a new senior unsecured revolving credit facility (Credit Facility) which matures October 16, 2020. The Credit Facility has aggregate commitments of $1.0 billion, with an option to increase aggregate commitments to $1.25 billion at any time. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of December 31, 201 5 , there were no borrowings outstanding under the Credit Facility. W e had letters of credit outstanding under the Credit Facility of $2.5 million, leaving an unu sed borrowing availability of $997.5 million. At our option, borrowings under the new facility may bear interest at either (a) LIBOR plus 1.125 – 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 – 1.0% , based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.125 – 0.35% , based on the credit rating for our senior unsecured long-term debt. The Credit Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65% . As of December 31, 201 5 , we were in compliance with all of the financial and non-financial covenants. ASU 2015-15 specifically exempts entities with revolving credit facilities from presenting associated debt issuance costs as a direct deduction from the carrying amount of the related liability. At December 31, 2015 and 2014, we had $5.7 million and $6.5 million, respectively, of unamortized debt issuance costs associated with our Credit Facility which were recorded as deferred assets and included in Other assets, net in our balance sheet. The costs are being amortized to interest expense ratably over the life of the Credit Facility. Senior Notes In June 2014, we issued $750 million of 4.375% senior notes due 2024 and received net proceeds of $740.9 million, after deducting offering discounts and costs. The net proceeds were used to pay outstanding bank debt and for general corporate purposes. The effective interest rate on the notes , including the debt issuance cost, is 4.50% . In April 2012, we issued $750 million of 5.875% senior notes due 2022 and received net proceeds of $737.0 million, after deducting underwriting discounts and offering costs. We used a portion of the net proceeds to retire our 7.125% senior notes and the remaining proceeds were used to pay outstanding bank debt and for general corporate purposes. The effective interest rate on the notes, including the debt issuance cost, is 6.04% . Each of our outstanding senior notes is governed by an indenture containing certain covenants, events of default and other restrictive provisions with which we were in compliance as of December 31, 2015 . Interest on each of the senior notes is payable semi-annually.

DERIVATIVE INSTRUMENTS_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING	12 Months Ended
	Dec. 31, 2015
Derivative Instruments/Hedging
Derivative Instruments/Hedging	4 . DERIVATIVE INSTR UMENTS/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. 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. The following tables summarize our derivative contracts as of December 31, 2015: First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Three-Way Collars: 2016: WTI (1) Volume (Bbls) Wtd Avg Price - Lower Floor $ $ $ $ $ Wtd Avg Price - Upper Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ (1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2016: PEPL (1) Volume (MMBtu) Wtd Avg Price - Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ Perm EP (1) Volume (MMBtu) Wtd Avg Price - Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ 2017: Perm EP (1) Volume (MMBtu) — — Wtd Avg Price - Floor $ $ $ — $ — $ Wtd Avg Price - Ceiling $ $ $ — $ — $ (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. A three-way collar is a combination of three options: lower floor (sold put), upper floor (bought put) and ceiling (sold call). If the published index price is below the lower floor, we receive the difference between the two floors. If the index price is between the two floors, we receive the difference between the upper floor and the index price. If the index price is between the upper floor and the ceiling, we do not receive or pay any amounts. If the index price is above the ceiling, we pay the excess over the ceiling price. 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 the ceiling price. Subsequent to December 31, 2015, we entered into the following gas hedges: First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2016: PEPL Volume (MMBtu) — Wtd Avg Price - Floor $ — $ $ $ $ Wtd Avg Price - Ceiling $ — $ $ $ $ Perm EP Volume (MMBtu) — Wtd Avg Price - Floor $ — $ $ $ $ Wtd Avg Price - Ceiling $ — $ $ $ $ 2017: PEPL Volume (MMBtu) — — Wtd Avg Price - Floor $ $ $ — $ — $ Wtd Avg Price - Ceiling $ $ $ — $ — $ Perm EP Volume (MMBtu) — — Wtd Avg Price - Floor $ $ $ — $ — $ Wtd Avg Price - Ceiling $ $ $ — $ — $ 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 presents the net ( gains ) and losses from settlements and changes in fair value of our derivative contracts, and the ( gains ) losses only from settlements during the periods shown below. (in thousands) 2015 2014 2013 (Gain) loss on derivative instruments, net $ $ $ Settlement (gains) losses $ — $ $ Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and 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 December 31, 201 5 , as well as the potential effect of netting arrangements on contracts with the same counterparty. We did not have any outstanding contracts as of December 31, 2014. December 31, 2015: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ $ — Natural gas contracts Current assets — Derivative instruments — Natural gas contracts Non-current assets — Derivative instruments — Total gross amounts presented in accompanying balance sheet — Less: gross amounts not offset in the accompanying balance sheet — — Net amount: $ $ — We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which ha ve 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.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements
Fair Value Measurements	5. FAIR VALUE ME ASUREMENTS 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. The following table provides fair value measurement information for certain assets and liabilities as of December 31, 2015 and 2014. December 31, 2015 December 31, 2014 Carrying Fair Carrying Fair (in thousands) Amount Value Amount Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ $ $ $ 4.375% Notes due 2024 $ $ $ $ Derivative instruments — assets $ $ $ — $ — 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 for our 4.375% and 5.875% fixed rate notes was based on their last traded value before year end. Derivative Instruments (Level 2) The fair value of our derivative instruments was estimated using option pricing models. These models use certain variables including forward price and volatility curves and the strike prices for the instruments. The fair value estimates are adjusted relative to non-performance risk as appropriate. Please see Note 4 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. Included in “accrued liabilities, other” at December 31, 2015 and 2014, respectively, are: 1) liabilities of approximately $ 23.1 million and $42.0 million representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts; 2) accrued payroll related general and administrative expenses of $ 21.5 million and $44.2 million; and 3) accrued operating expenses of $60.4 million and $67.5 million. Our accounts receivable are primarily from either purchasers of our gas, oil and NGL production (customers) or from exploration and production companies which own interests in properties we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, because our customers and joint working interest owners may be similarly affected by changes in industry conditions. We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit or prepayments when deemed necessary. 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 not be collected and the amount of the reserve may be reasonably estimated. At December 31, 2015, the allowance for doubtful accounts totaled $ 1.8 million. At December 31, 2014, the allowance for doubtful accounts was $1.5 million. Major Customers Our major customers during 2015 were Sunoco Logistics Partners L.P. (Sunoco) and Enterprise Products Partners L.P. (Enterprise). Sunoco and Enterprise accounted for 21% and 17% , respectively, of our consolidated revenues in 2015. During 2014, Enterprise and Sunoco each accounted for 19% of our consolidated revenues. Oneok Partners, L.P. accounted for 10% of our 2014 consolidated revenues. Sunoco is a significant purchaser of our oil in Southeast New Mexico and Canadian County, Oklahoma. Enterprise is a significant oil purchaser in Oklahoma and West Texas. If either of these entities were to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay. If both parties were to discontinue purchasing our product, we believe there would be challenges initially, but ample markets to handle the disruption.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
STOCK-BASED COMPENSATION and OTHER COMPENSATION
Stock-based compensation and other compensation	6 . STOCK-BASED and OT HER COMPENSATION We have recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. Years Ended December 31, (in thousands) 2015 2014 2013 Restricted stock awards Performance stock awards $ $ $ Service-based stock awards Stock option awards Less amounts capitalized to oil and gas properties Compensation expense $ $ $ The increase in 2015 stock compensation is primarily related to performance awards granted in December 2014, a portion of which were amortized during 2015. Equity Incentive Plan Our 2014 Equity Incentive Plan (the 2014 Plan) was approved by stockholders in May 2014 and our previous plan was terminated at that time. Outstanding awards under the previous plan were not impacted. A total of 6.6 million shares of common stock may be issued under the 2014 Plan, including shares available from the previous plan. 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. Restricted Stock The following table provides information about restricted stock awards granted during the last three years. Years Ended December 31, 2015 2014 2013 Weighted Weighted Weighted Average Average Average Number Grant-Date Number Grant-Date Number Grant-Date of Shares Fair Value of Shares Fair Value of Shares Fair Value Performance stock awards $ $ $ Service-based stock awards $ $ $ Total restricted stock awards $ $ $ Performance awards were 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 provides information on restricted stock activity during the year. Performance Service-based (subject to market conditions) Weighted Weighted Average Average Grant-Date Grant-Date Awards Fair Value Awards Fair Value Outstanding beginning of period $ $ Vested $ $ Granted $ $ Canceled $ $ Outstanding end of period $ $ The total fair value of restricted stock that vested was $ 52.2 million in 201 5 , $ 34.1 million in 201 4 , and $ 25.7 million in 201 3 . Unrecognized compensation cost related to unvested restricted shares at December 31, 201 5 was $ 85.8 million. We expect to recognize that cost over a weighted average period of 2.2 years. Restricted Units As of December 31, 201 5 and 201 4 , we had 8,838 restricted units outstanding . These 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. 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 (NYSE) 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 NYSE 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. The following summarizes the options granted and related information, and the assumptions used to determine the fair value of those options. Years Ended December 31, 2015 2014 2013 Options granted Weighted average grant-date fair value $ $ $ Weighted average exercise price $ $ $ Total Fair Value (in thousands) $ $ $ Expected years until exercise Expected stock volatility % % % Dividend yield % % % Risk-free interest rate % % % 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, 2015 $ Exercised $ Granted $ Canceled $ Forfeited $ Outstanding as of December 31, 2015 $ Years $ Exercisable as of December 31, 2015 $ Years $ The following table provides information regarding options exercised and the grant-date fair value of options vested. Years Ended December 31, (in thousands) 2015 2014 2013 Number of options exercised Cash received from option exercises $ $ $ Tax benefit from option exercises included in paid-in-capital (1) $ $ — $ — Intrinsic value of options exercised $ $ $ Grant-date fair value of options vested $ $ $ (1) No tax benefit is recorded until the benefit reduces current taxes payable. However, in 2015 we recognized tax benefit on prior period option exercises. The following summary reflects the status of non-vested stock options as of December 31, 201 5 and changes during the year. Weighted Weighted Average Average Grant-Date Exercise Options Fair Value Price Non-vested as of January 1, 2015 $ $ Vested $ $ Granted $ $ Forfeited $ $ Non-vested as of December 31, 2015 $ $ As of December 31, 201 5 , there was $ 3.9 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost on a pro rata basis over a weighted average period of 1.8 years. Other Compensation We maintain and sponsor a contributory 401(k) plan for our employees. Annual matching costs related to the plan were $ 6.4 million for 2015. During 2014 and 2013, such costs were $11.0 million and $9.0 million, respectively.

EARNINGS (LOSS) PER SHARE

EARNINGS (LOSS) PER SHARE	12 Months Ended
	Dec. 31, 2015
Earnings (loss) per Share
Earnings (loss) per Share	7 . EARNINGS (LOSS) P ER SHARE The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below. Years Ended December 31, (in thousands, except per share data) 2015 2014 2013 Basic: Net income (loss) $ $ $ Participating securities’ share in earnings (1) — Net income (loss) applicable to common stockholders $ $ $ Diluted: Net income (loss) $ $ $ Participating securities’ share in earnings (1) — Net income (loss) applicable to common stockholders $ $ $ Shares: Basic shares outstanding Dilutive effect of stock options — Fully diluted common stock Excluded (2) Earnings (loss) per share to common stockholders (3): Basic $ $ $ Diluted $ $ $ (1) Participating securities are not included in undistributed earnings when a loss exists. (2) Inclusion of certain shares would have an anti-dilutive effect. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations
Asset Retirement Obligations	8 . ASSET RETIREM ENT OBLIGATIONS The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 201 5 and 201 4 . (in thousands) 2015 2014 Asset retirement obligation at January 1, $ $ Liabilities incurred Liability settlements and disposals Accretion expense Revisions of estimated liabilities Asset retirement obligation at December 31, Less current obligation Long-term asset retirement obligation $ $ The year-over-year decline in liabilities incurred resulted from lower drilling and acquisition activity in 2015. D uring 201 5 , the liability settl ements and disposals included $13.3 million related to properties that were sold. During 201 4 , the liability settl ements and disposals included $11.2 million related to properties that were sold. Also during 2014 we recognized revisions of estimated liabilities totaling $25.4 million , which were due to changes in abandonment cost and timing estimates.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
Income Taxes
Income Taxes	9 . INCOME TAXES Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. Federal income tax rate, primarily due to the effect of state income taxes , non-deductible expenses and revisions . The components of the provision for income taxes are as follows: Years Ended December 31, (in thousands) 2015 2014 2013 Current Taxes: Federal (benefit) $ $ — $ State (benefit) Deferred taxes: Federal (benefit) State (benefit) $ $ $ Reconciliations of the income tax expense (benefit) calculated at the federal statutory rate of 35% to the total income tax expense are as follows: Years Ended December 31, (in thousands) 2015 2014 2013 Provision at statutory rate $ $ $ Effect of state taxes Revision of previous balances — — Other permanent differences Income tax expense (benefit) $ $ $ The components of Cimarex’s net deferred tax liabilities are as follows: December 31, (in thousands) 2015 2014 Long-term: Assets: Stock compensation and other accrued amounts $ $ Net operating loss carryforward, net of valuation allowance Credit carryforward Liabilities: Property, plant and equipment Net, long-term deferred tax liability Current: Assets: Other accrued amounts — — Net deferred tax liabilities $ $ At December 31, 2015 , we had a U.S. net tax operating loss carryforward of approximately $ 907.5 million, which would expire in years 2031 through 203 5 . We believe that the carryforward will be utilized before it expires. We recorded an increase to the net operating loss carryforward at December 31, 2015, for certain state losses. The net increase in the state net operating loss valuation allowance during the year was $51.0 million. The total valuation allowance on state net operating losses at December 31, 2015, was $70.1 million because it is not more likely than not that these additional state net operating losses will be utilized before they expire. The amount of the U.S. net tax operating loss carryforward that will be recorded to equity when utilized to reduce taxes payable is $ 77.2 million. We also had an alternative minimum tax credit carryforward of approximately $ 6.0 million. At December 31, 201 5 and 201 4 , 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 201 2 through 201 4 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 tax years 201 1 through 201 4 .

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies
Commitments and Contingencies	1 0 . COMMITMENTS AN D CONTINGENCIES Lease Commitments We have various commitments for office space and equipment under operating lease arrangements. Rent expense for the operating leases totaled $ 13.2 million in 2015 . Rent expense was $14.3 million and $13.2 million for 201 4 and 201 3, respectively. Shown below are future minimum cash payments required under these leases as of December 31, 201 5 . (in thousands) Operating Leases 2016 $ 2017 2018 2019 2020 Later years Total future minimum lease payments $ Other Commitments We have commitments of $ 201.7 million to finish drilling and completing wells in progress at December 31, 2015. We also have various commitments for drilling rigs. The total minimum expenditure commitments under these agreements are $21.6 million. At December 31, 2015, we had firm sales contracts to deliver approximately 56 Bcf of natural gas over the next three years . If this gas is not delivered, our financial commitment would be approximately $ 116.7 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 . In connection with gas gathering and processing agreements, we have volume commitments over the next ten years. If no gas is delivered, the maximum amount that would be payable under these commitments would be approximately $20 3 . 0 million. 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 minimum volume delivery commitments in connection with agreements to reimburse connection costs to various pipelines. The maximum amount that would be payable if no gas is delivered would be approximately $12.4 million. Of this total, we have accrued a liability of $9.7 million . Due to reduced drilling activity in 2015 and projected for 2016, we may have additional liabilities associated with these delivery commitments in the future . We have other various transportation , delivery and facilities commitments in the normal course of business, which approximate $3 6.3 million. We currently anticipate meeting these obligations. All of the noted commitments were routine and 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, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals. H.B. Krug, et al. versus H&P In 2008, we recorded litigation expense of $119.6 million for the H.B. Krug, et al. v. Helmerich & Payne, Inc. (H&P) lawsuit, and began accruing additional post-judgment interest and costs for this case. Over the years, the lawsuit has been disputed until December 13, 2013 when the Oklahoma Supreme Court reversed the Tulsa County District Court’s original judgment of $119.6 million and affirmed an alternative jury verdict for $3.65 million. It also remanded the case back to the trial court for consideration of potential prejudgment interest, attorney’s fees and cost awards. Accordingly, on December 31, 2013 we reduced the previously recognized litigation expense, which included related interest and costs, and the associated long-term liability by $142.8 million. On April 1, 2014, Cimarex paid the Plaintiffs $15.8 million in satisfaction of the $3.65 million damages award, the post-judgment interest award and the payment in lieu of bond, all of which are now final and not appealable. On June 24, 2014, the trial court ruled the Plaintiffs were not entitled to prejudgment interest but were entitled to attorney’s fees and costs, the amount of which will be determined at a subsequent hearing. On November 3, 2015, the Oklahoma Supreme Court affirmed the trial court’s denial of prejudgment interest. The only remaining issue is the amount of Plaintiffs’ award of attorney’s fees, which is subject to future trial and appellate court proceedings and, therefore, cannot be determined or estimated at this time .

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	1 1 . RELATED PARTY TRA NSACTIONS Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $ 7.9 million were incurred by Cimarex related to such services for 201 5 . During 201 4 and 201 3 , such costs were $ 18.4 million and $17.0 million, respectively. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P. Lisa Stewart joined our Board of Directors in October, 2015. Ms. Stewart is Chairman and Chief Investment Officer of Sheridan Production Partners, a privately-owned oil and gas operating company she founded in 2007. During 2015, Cimarex paid certain affiliates of Sheridan Production Partners oil and gas revenues of $224.2 thousand and received $81.5 thousand for joint interest billings. In addition, Cimarex paid the Sheridan affiliates joint interest billings of $10.4 thousand and received $4.1 thousand of oil and gas revenues. Jerry Box , a director of Cimarex whose term expired May 2015, was the non-executive Chairman of the Board of Newpark through May 2014. Certain subsidiaries of Newpark Resources, Inc. provided various drilling services to Cimarex. Costs of such services were $ 0.6 million through May 2014. During 2013, such costs were $3.5 million.

PROPERTY SALES AND ACQUISITIONS

PROPERTY SALES AND ACQUISITIONS	12 Months Ended
	Dec. 31, 2015
Property Acquisitions and Sales
Property Acquisitions and Sales	12 . PROPERTY SALES AN D ACQUISITIONS The following sales and acquisitions were made in the ordinary course of business. All amounts are net of customary purchase price adjustments. There were no significant sales and acquisitions in 2015. We sold interests in various non-co re oil and gas properties for $446.1 million during 2014. Most of the proceeds were related to sales of producing gas wells in southwestern Kansas and undeveloped acreage in Reagan County, Texas. During 2014, we made p roperty acquisitions totaling $249.7 million, most of which were in our Cana-Woodford shale play in Western Oklahoma. In 2013, we sold interests in non-core oil and gas assets for $61.5 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. Total property acquisitions during 2013 were $37.1 million, mostly for undeveloped acreage in Reeves County, Texas.

SUPPLEMENTAL DISCLOSURE OF CASH

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2015
Supplemental Disclosure of Cash Flow Information:
Supplemental Disclosure of Cash Flow Information:	13. SUPPLEMENTAL DISC LOSURE OF CASH FLOW INFORMATION Years Ended December 31, (in thousands) 2015 2014 2013 Cash paid during the period for: Interest expense (including capitalized amounts) $ $ $ Interest capitalized $ $ $ Income taxes $ $ $ Cash received for income taxes $ $ $

BASIS OF PRESENTATION (Policies

BASIS OF PRESENTATION (Policies)	12 Months Ended
	Dec. 31, 2015
Basis of Presentation
Basis of presentation	Basis of presentation Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation.
Segment Information	Segment Information We have determined that our business is comprised of only one segment because our gathering, processing and marketing activities are ancillary to our production operations and are not separately managed.
Use of Estimates	Use of estimates The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. 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. The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. Estimates and judgments are also required in determining allowance for doubtful accounts, impairments of undeveloped properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements and commitments and contingencies. We analyze our estimates, including those related to oil, gas and NGL revenues, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. Cash equivalents are stated at cost, which approximates market value.
Oil and Gas Properties	Oil and Gas Well Equipment and Supplies The Financial Accounting Standards Board (FASB) issued new guidance (ASU 2015-11) to simplify the measurement of inventory effective for interim and annual periods beginning in 2017 with early adoption permitted. Under current guidance, inventory is carried at the lower of cost or market, where market can be replacement cost or a net realizable value. Under the new guidance, inventory is to be carried at the lower of cost or net realizable value, where net realizable value is a defined estimated selling price. We adopted this standard as of December 31, 2015. An analysis of our oil and gas well equipment and supplies was performed and no impairment was required. However, the industry-wide decline in drilling operations has put downward pressure on the price of oil and gas well equipment and supplies. Further declines in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity. Oil and Gas Properties We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Companies that follow the full cost accounting method are required to make quarterly ceiling test calculations. This test ensures that total capitalized costs for oil and gas properties (net of accumulated DD&A and deferred income taxes) do not exceed 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. We currently do not have any unproven properties that are being amortized. Estimated future net cash flows are determined by commodity prices and proved reserve quantities. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for the prior 12 months. If net capitalized costs subject to amortization exceed this limit, the excess is charged to expense. At December 31, 2015, the carrying value of our oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation and we recognized an impairment of $965.3 m illion ( $613.4 million, net of tax). We also recognized impairments in the first three quarters of 2015. Full year impairments totaled $ 3.7 billion ($ 2.4 billion, net of tax). These impairments resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the future net cash flows from proved reserves. If pricing conditions stay at current levels or decline further, or if there is a negative impact on one or more of the other components of the calculation, we will incur full cost ceiling impairments in future quarters. The ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and stockholders’ equity. Any recorded impairment of oil and gas properties is not reversible at a later date. Depletion of proved oil and gas properties is computed on the units- of-production method, whereby capitalized costs, including future development costs and asset retirement obligations, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities, commodity prices and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes. The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred.
Fixed assets, net	Fixed assets, net Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years.
Goodwill	Goodwill Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. We have one reporting unit for which we first assess qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold ) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculated fair value by charging the impairment to expense. We evaluate our goodwill for impairment in the fourth quarter of each year or whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our qualitative assessment at December 31, 201 5 , goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become less favorable.
Revenue Recognition	Revenue Recognition Oil, Gas and NGL Sales Revenue is recorded from the sales of oil, gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. There is a ready market for our products and sales occur soon after production. Under certain contracts, when NGLs are extracted from the gas stream, processors receive 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. Increasing NGL production combined with the impact of recent changes to these contracts has resulted in processing costs becoming more significant. Accordingly, we have changed our policy to record these processing costs with operating costs as allowed under EITF 00-10. 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 in 2014 was that total revenue was $ 51.4 million higher with an offsetting increase in total transportation, processing and other operating 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. Marketing Sales We market and sell natural gas for working interest owners under short term sales and supply agreements and earn a fee for such services. Revenues are recognized as gas is delivered and are reflected net of gas purchases on the consolidated statements of operations and comprehensive income (loss) . Gas Imbalances We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas reserves are adjusted to the extent there are sufficient quantities of natural gas to make up an imbalance. A liability is established in situations where there are insufficient proved reserves available to make-up an overproduced imbalance. Imbalances have not been significant in the periods presented.
General and Administrative Expenses	General and Administrative Expenses General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting.
Derivatives	Derivatives Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 4 for additional information regarding our derivative instruments.
Income Taxes	Income Taxes In November 2015, the FASB issued a new standard (ASU 2015-17) regarding the balance sheet classification of deferred taxes for interim and annual periods beginning in 2017, with early adoption permitted on a prospective or retrospective basis. Under current guidance, entities that present a classified balance sheet must show both current and noncurrent amounts for deferred tax assets and liabilities. The new standard requires entities to classify all deferred tax assets and liabilities as noncurrent. We have elected to adopt this standard on a prospective basis as of December 31, 2015. Prior periods have not been retrospectively adjusted. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. We routinely assess the realizability of the deferred tax assets. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. We regularly assess and, if required, establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding our income taxes.
Contingencies	Contingencies A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental and other contingencies and periodically determine when we should record losses for these items based on information available to us. See Note 1 0 for additional information regarding our contingencies.
Asset Retirement Obligations	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 current portions of the asset retirement obligations are recorded in “accrued liabilities, other” in the accompanying consolidated balance sheets and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note 8 for additional information regarding our asset retirement obligations.
Stock-based Compensation	Stock-based Compensation We recognize compensation related to all stock-based awards, including stock options, in the financial statements based on their estimated grant-date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions) and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 6 for additional information regarding our stock-based compensation.
Earnings (loss) per Share	Earnings (loss) per Share We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and therefore should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share based payment awards, consisting of restricted stock and units , qualify as participating securities. See Note 7 for additional information regarding our earnings per share.
Recently Issued Accounting Standards	Recently Issued Accounting Standards The FASB issued ASU 2015-03, Interest-Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs in April 2015 and ASU 2015-15, Interest-Imputation of Interest-Presentation and Subsequent Measurement of Debt Issuance Costs associated with Line-of-Credit Arrangements in August 2015. These ASUs simplify the presentation of debt issuance costs by requiring such costs (except for those related to revolving credit facilities) to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability rather than as an asset. These ASUs are effective for annual and interim periods beginning in 2016. Early adoption is permitted. We adopted these ASUs at December 31, 2015. Accordingly, prior periods have been adjusted retrospectively to conform to this guidance (see Note 3). In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016. 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 Recognition , and most industry-specific guidance throughout the Industry Topics of the Codification . Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. We do not intend to adopt the standard early. We have not determined which transition method we will use and are continuing to evaluate the potential impact of this guidance. At this time we do not expect that the adoption of this standard will have a material effect on our financial position or results of operation and related disclosures.
Subsequent Events	Subsequent Events The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing .

CAPITAL STOCK (Tables)

CAPITAL STOCK (Tables)	12 Months Ended
	Dec. 31, 2015
Capital Stock
Schedule of dividends declared	2015 2014 2013 Dividend declared (in millions) $ $ $ Dividend per share $ $ $

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
Long-Term Debt
Summary of debt	December 31, 2015 December 31, 2014 Unamortized Debt Unamortized Debt (in thousands) Principal Issuance Costs Principal Issuance Costs 5.875% Senior Notes, due May 1, 2022 $ $ $ $ 4.375% Senior Notes, due June 1, 2024 Total long-term debt $ $ $ $
Schedule of debt issuance cost reclassification	December 31, 2014 After As Previously (in thousands) Adoption Reported Other assets, net $ $ Long-term debt $ $

DERIVATIVE INSTRUMENTS_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments/Hedging
Outstanding hedging contracts relative to future production	First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Three-Way Collars: 2016: WTI (1) Volume (Bbls) Wtd Avg Price - Lower Floor $ $ $ $ $ Wtd Avg Price - Upper Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ (1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2016: PEPL (1) Volume (MMBtu) Wtd Avg Price - Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ Perm EP (1) Volume (MMBtu) Wtd Avg Price - Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ 2017: Perm EP (1) Volume (MMBtu) — — Wtd Avg Price - Floor $ $ $ — $ — $ Wtd Avg Price - Ceiling $ $ $ — $ — $ (1) (2) 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. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2016: PEPL Volume (MMBtu) — Wtd Avg Price - Floor $ — $ $ $ $ Wtd Avg Price - Ceiling $ — $ $ $ $ Perm EP Volume (MMBtu) — Wtd Avg Price - Floor $ — $ $ $ $ Wtd Avg Price - Ceiling $ — $ $ $ $ 2017: PEPL Volume (MMBtu) — — Wtd Avg Price - Floor $ $ $ — $ — $ Wtd Avg Price - Ceiling $ $ $ — $ — $ Perm EP Volume (MMBtu) — — Wtd Avg Price - Floor $ $ $ — $ — $ Wtd Avg Price - Ceiling $ $ $ — $ — $
Net (gains) and losses from settlements and changes in fair value of derivative contracts	(in thousands) 2015 2014 2013 (Gain) loss on derivative instruments, net $ $ $ Settlement (gains) losses $ — $ $
Schedule of amounts and classifications of entity's derivative assets and liabilities as well as the potential effect of netting arrangements on contracts with the same counterparty	December 31, 2015: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ $ — Natural gas contracts Current assets — Derivative instruments — Natural gas contracts Non-current assets — Derivative instruments — Total gross amounts presented in accompanying balance sheet — Less: gross amounts not offset in the accompanying balance sheet — — Net amount: $ $ —

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements
Fair value measurement information for certain assets and liabilities	December 31, 2015 December 31, 2014 Carrying Fair Carrying Fair (in thousands) Amount Value Amount Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ $ $ $ 4.375% Notes due 2024 $ $ $ $ Derivative instruments — assets $ $ $ — $ —

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2015
Options, Restricted Stock and Unit Awards
Recognition of non-cash stock-based compensation cost	Years Ended December 31, (in thousands) 2015 2014 2013 Restricted stock awards Performance stock awards $ $ $ Service-based stock awards Stock option awards Less amounts capitalized to oil and gas properties Compensation expense $ $ $
Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Restricted stock rollforward	Performance Service-based (subject to market conditions) Weighted Weighted Average Average Grant-Date Grant-Date Awards Fair Value Awards Fair Value Outstanding beginning of period $ $ Vested $ $ Granted $ $ Canceled $ $ Outstanding end of period $ $
Restricted Stock and Units [Member]
Options, Restricted Stock and Unit Awards
Summary of restricted stock awards granted	Years Ended December 31, 2015 2014 2013 Weighted Weighted Weighted Average Average Average Number Grant-Date Number Grant-Date Number Grant-Date of Shares Fair Value of Shares Fair Value of Shares Fair Value Performance stock awards $ $ $ Service-based stock awards $ $ $ Total restricted stock awards $ $ $
Employee Stock Option [Member]
Options, Restricted Stock and Unit Awards
Outstanding stock options rollforward	. Weighted Weighted Aggregate Average Average Intrinsic Exercise Remaining Value Options Price Term (in thousands) Outstanding as of January 1, 2015 $ Exercised $ Granted $ Canceled $ Forfeited $ Outstanding as of December 31, 2015 $ Years $ Exercisable as of December 31, 2015 $ Years $
Summary of information regarding options exercised and grant-date fair value of options vested	Years Ended December 31, (in thousands) 2015 2014 2013 Number of options exercised Cash received from option exercises $ $ $ Tax benefit from option exercises included in paid-in-capital (1) $ $ — $ — Intrinsic value of options exercised $ $ $ Grant-date fair value of options vested $ $ $ (1) No tax benefit is recorded until the benefit reduces current taxes payable. However, in 2015 we recognized tax benefit on prior period option exercises.
Non-vested stock options rollforward	Weighted Weighted Average Average Grant-Date Exercise Options Fair Value Price Non-vested as of January 1, 2015 $ $ Vested $ $ Granted $ $ Forfeited $ $ Non-vested as of December 31, 2015 $ $
Summary of options granted, weighted average grant-date fair value, total fair value of the options and assumptions used to determine fair market value of those options	Years Ended December 31, 2015 2014 2013 Options granted Weighted average grant-date fair value $ $ $ Weighted average exercise price $ $ $ Total Fair Value (in thousands) $ $ $ Expected years until exercise Expected stock volatility % % % Dividend yield % % % Risk-free interest rate % % %

EARNINGS (LOSS) PER SHARE (Tabl

EARNINGS (LOSS) PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings (loss) per Share
Calculations of basic and diluted net earnings (loss) per common share under the two-class method	Years Ended December 31, (in thousands, except per share data) 2015 2014 2013 Basic: Net income (loss) $ $ $ Participating securities’ share in earnings (1) — Net income (loss) applicable to common stockholders $ $ $ Diluted: Net income (loss) $ $ $ Participating securities’ share in earnings (1) — Net income (loss) applicable to common stockholders $ $ $ Shares: Basic shares outstanding Dilutive effect of stock options — Fully diluted common stock Excluded (2) Earnings (loss) per share to common stockholders (3): Basic $ $ $ Diluted $ $ $ (1) Participating securities are not included in undistributed earnings when a loss exists. (2) Inclusion of certain shares would have an anti-dilutive effect. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations
Change in the carrying amount of the asset retirement obligation	(in thousands) 2015 2014 Asset retirement obligation at January 1, $ $ Liabilities incurred Liability settlements and disposals Accretion expense Revisions of estimated liabilities Asset retirement obligation at December 31, Less current obligation Long-term asset retirement obligation $ $

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes
Components of the provision for income taxes	Years Ended December 31, (in thousands) 2015 2014 2013 Current Taxes: Federal (benefit) $ $ — $ State (benefit) Deferred taxes: Federal (benefit) State (benefit) $ $ $
Reconciliations of income tax (benefit) expense calculated at federal statutory rate of 35% to the total income tax (benefit) expense	Years Ended December 31, (in thousands) 2015 2014 2013 Provision at statutory rate $ $ $ Effect of state taxes Revision of previous balances — — Other permanent differences Income tax expense (benefit) $ $ $
Components of net deferred tax liabilities	December 31, (in thousands) 2015 2014 Long-term: Assets: Stock compensation and other accrued amounts $ $ Net operating loss carryforward, net of valuation allowance Credit carryforward Liabilities: Property, plant and equipment Net, long-term deferred tax liability Current: Assets: Other accrued amounts — — Net deferred tax liabilities $ $

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies
Schedule of future minimum payments required under leases	(in thousands) Operating Leases 2016 $ 2017 2018 2019 2020 Later years Total future minimum lease payments $

SUPPLEMENTAL DISCLOSURE OF CA31

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Disclosure of Cash Flow Information:
Supplemental Disclosure of Cash Flow Information	Years Ended December 31, (in thousands) 2015 2014 2013 Cash paid during the period for: Interest expense (including capitalized amounts) $ $ $ Interest capitalized $ $ $ Income taxes $ $ $ Cash received for income taxes $ $ $

BASIS OF PRESENTATION (Details)

BASIS OF PRESENTATION (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)segment
Number of reportable segments | segment		1
Oil and Gas Properties
Discount rate for calculating present value of estimated future net revenues from proved reserves (as a percent)		10.00%
Impairment of oil and gas properties, after tax	$ 613,400,000	$ 2,400,000,000
Results of Operations, Impairment of Oil and Gas Properties	$ 965,300,000	$ 3,716,883,000
Oil, Gas and NGL Sales
Residue gas and NGLs, portion reflected in prices (as a percent)		100.00%
Increase in total revenue and processing costs		$ 51,400,000
Goodwill
Goodwill impairment		$ 0
Maximum [Member]
Fixed assets, net
Fixed assets expected lives		30 years
Minimum [Member]
Fixed assets, net
Fixed assets expected lives		3 years

CAPITAL STOCK (Details)

CAPITAL STOCK (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended			12 Months Ended
	Feb. 29, 2016	May. 31, 2015	Feb. 28, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capital Stock [Line Items]
Common stock, shares authorized				200,000,000	200,000,000
Preferred stock, shares authorized				15,000,000	15,000,000
Preferred stock outstanding (in shares)				0
Issuance of common stock		6,900,000
Price per share sold		$ 109
Common stock, par value (in dollars per share)		$ 0.01		$ 0.01	$ 0.01
Proceeds from sale of common stock, net of underwriting fees		$ 730,000
Dividends
Cash dividend declared (in dollars per share)	$ 0.08		$ 0.16
Dividend payable
Dividend declared				$ 59,313	$ 55,664	$ 48,423
Dividend per share				$ 0.64	$ 0.64	$ 0.56
Additional Shares Issued [Member]
Capital Stock [Line Items]
Issuance of common stock		900,000

LONG-TERM DEBT - Summary (Detai

LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2014	Apr. 30, 2012
Debt Instrument
Principal	$ 1,500,000	$ 1,500,000
Unamortized Debt Issuance Costs	14,380	16,824
Notes 5.875 Percent [Member]
Debt Instrument
Principal	750,000	750,000
Unamortized Debt Issuance Costs	$ 6,978	$ 8,343
Interest rate (as a percent)	5.875%	5.875%		5.875%
Notes 4.375 Percent [Member]
Debt Instrument
Principal	$ 750,000	$ 750,000
Unamortized Debt Issuance Costs	$ 7,402	$ 8,481
Interest rate (as a percent)	4.375%	4.375%	4.375%

LONG-TERM DEBT - Schedule of de

LONG-TERM DEBT - Schedule of debt issuance cost reclassification (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other assets, net	$ 38,468	$ 41,691
Long-term debt	$ 1,485,620	1,483,176
Scenario, Previously Reported [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other assets, net		58,515
Long-term debt		$ 1,500,000

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Jun. 30, 2014	Apr. 30, 2012	Dec. 31, 2015	Oct. 31, 2015	Dec. 31, 2014
Debt Instrument
Unamortized debt issuance costs			$ 14,380		$ 16,824
Long-term debt			1,485,620		1,483,176
Revolving Credit Facility [Member]
Debt Instrument
Unamortized debt issuance costs			5,700		6,500
Credit facility amount				$ 1,000,000
Credit facility, increase amount option				$ 1,250,000
Borrowings outstanding			$ 0
Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument
Commitment fee percentage			0.125%
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument
Commitment fee percentage			0.35%
Debt-to-Capital ratio			65.00%
Line of Credit [Member]
Debt Instrument
Letters of credit outstanding under the credit facility			$ 2,500
Unused borrowing availability			997,500
Notes 7.125 Percent [Member]
Debt Instrument
Interest rate (as a percent)		7.125%
Notes 5.875 Percent [Member]
Debt Instrument
Unamortized debt issuance costs			$ 6,978		$ 8,343
Issuance of senior unsecured notes		$ 737,000
Effective rate		6.04%
Interest rate (as a percent)		5.875%	5.875%		5.875%
Long-term debt		$ 750,000
Notes 4.375 Percent [Member]
Debt Instrument
Unamortized debt issuance costs			$ 7,402		$ 8,481
Issuance of senior unsecured notes	$ 740,900
Effective rate	4.50%
Interest rate (as a percent)	4.375%		4.375%		4.375%
Long-term debt	$ 750,000
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument
Interest rate margin (as a percent)			1.125%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument
Interest rate margin (as a percent)			2.00%
Base Rate [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument
Interest rate margin (as a percent)			0.125%
Base Rate [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument
Interest rate margin (as a percent)			1.00%

DERIVATIVE INSTRUMENTS_HEDGIN37

DERIVATIVE INSTRUMENTS/HEDGING (Details)	Feb. 23, 2016MMBTU / D$ / MMBTU	Dec. 31, 2015MMBTU / D$ / bbl$ / MMBTU
Derivative Contract Oil Three-Way Collars WTI Index [Member] | 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		1,098,000
Weighted Average Price
Ceiling, weighted average price (in dollars per unit) | $ / bbl		60
Derivative Contract Oil Three-Way Collars WTI Index [Member] | First Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		273,000
Weighted Average Price
Ceiling, weighted average price (in dollars per unit) | $ / bbl		60
Derivative Contract Oil Three-Way Collars WTI Index [Member] | Second Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		273,000
Weighted Average Price
Ceiling, weighted average price (in dollars per unit) | $ / bbl		60
Derivative Contract Oil Three-Way Collars WTI Index [Member] | Third Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		276,000
Weighted Average Price
Ceiling, weighted average price (in dollars per unit) | $ / bbl		60
Derivative Contract Oil Three-Way Collars WTI Index [Member] | Fourth Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		276,000
Weighted Average Price
Ceiling, weighted average price (in dollars per unit) | $ / bbl		60
Derivative Contract Gas Collar PEPL Index [Member] | 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		3,660,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.70
Ceiling, weighted average price (in dollars per unit)		2.85
Derivative Contract Gas Collar PEPL Index [Member] | First Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		910,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.70
Ceiling, weighted average price (in dollars per unit)		2.85
Derivative Contract Gas Collar PEPL Index [Member] | Second Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		910,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.70
Ceiling, weighted average price (in dollars per unit)		2.85
Derivative Contract Gas Collar PEPL Index [Member] | Third Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		920,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.70
Ceiling, weighted average price (in dollars per unit)		2.85
Derivative Contract Gas Collar PEPL Index [Member] | Fourth Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		920,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.70
Ceiling, weighted average price (in dollars per unit)		2.85
Derivative Contract Gas Collar PEPL Index [Member] | Subsequent Event [Member] | 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,500,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.13
Ceiling, weighted average price (in dollars per unit)	2.70
Derivative Contract Gas Collar PEPL Index [Member] | Subsequent Event [Member] | Second Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,820,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.13
Ceiling, weighted average price (in dollars per unit)	2.70
Derivative Contract Gas Collar PEPL Index [Member] | Subsequent Event [Member] | Third Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.13
Ceiling, weighted average price (in dollars per unit)	2.70
Derivative Contract Gas Collar PEPL Index [Member] | Subsequent Event [Member] | Fourth Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.13
Ceiling, weighted average price (in dollars per unit)	2.70
Derivative Contract Gas Collar PEPL Index [Member] | Subsequent Event [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	3,620,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.13
Ceiling, weighted average price (in dollars per unit)	2.70
Derivative Contract Gas Collar PEPL Index [Member] | Subsequent Event [Member] | First Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,800,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.13
Ceiling, weighted average price (in dollars per unit)	2.70
Derivative Contract Gas Collar PEPL Index [Member] | Subsequent Event [Member] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,820,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.13
Ceiling, weighted average price (in dollars per unit)	2.70
Derivative Contract Gas Collar Perm EP [Member] | 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		4,870,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.09
Derivative Contract Gas Collar Perm EP [Member] | First Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		1,820,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.12
Derivative Contract Gas Collar Perm EP [Member] | Second Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		1,210,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.09
Derivative Contract Gas Collar Perm EP [Member] | Third Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		920,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.06
Derivative Contract Gas Collar Perm EP [Member] | Fourth Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		920,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.06
Derivative Contract Gas Collar Perm EP [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		1,810,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.36
Derivative Contract Gas Collar Perm EP [Member] | First Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		900,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.36
Derivative Contract Gas Collar Perm EP [Member] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D		910,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)		2.75
Ceiling, weighted average price (in dollars per unit)		3.36
Derivative Contract Gas Collar Perm EP [Member] | Subsequent Event [Member] | 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,500,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.25
Ceiling, weighted average price (in dollars per unit)	2.77
Derivative Contract Gas Collar Perm EP [Member] | Subsequent Event [Member] | Second Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,820,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.25
Ceiling, weighted average price (in dollars per unit)	2.77
Derivative Contract Gas Collar Perm EP [Member] | Subsequent Event [Member] | Third Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.25
Ceiling, weighted average price (in dollars per unit)	2.77
Derivative Contract Gas Collar Perm EP [Member] | Subsequent Event [Member] | Fourth Quarter - 2016 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.25
Ceiling, weighted average price (in dollars per unit)	2.77
Derivative Contract Gas Collar Perm EP [Member] | Subsequent Event [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	3,620,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.25
Ceiling, weighted average price (in dollars per unit)	2.77
Derivative Contract Gas Collar Perm EP [Member] | Subsequent Event [Member] | First Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,800,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.25
Ceiling, weighted average price (in dollars per unit)	2.77
Derivative Contract Gas Collar Perm EP [Member] | Subsequent Event [Member] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,820,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.25
Ceiling, weighted average price (in dollars per unit)	2.77
Minimum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		40
Minimum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | First Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		40
Minimum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | Second Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		40
Minimum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | Third Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		40
Minimum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | Fourth Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		40
Maximum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		50
Maximum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | First Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		50
Maximum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | Second Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		50
Maximum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | Third Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		50
Maximum [Member] | Derivative Contract Oil Three-Way Collars WTI Index [Member] | Fourth Quarter - 2016 [Member]
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl		50

DERIVATIVE INSTRUMENTS_HEDGIN38

DERIVATIVE INSTRUMENTS/HEDGING (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
(Gain) loss on derivative instruments, net
(Gain) loss on derivative instruments, net	$ (11,246)	$ (3,762)	$ 209
(Gains) losses from settlement of derivative instruments:
Settlement (gains) losses		$ (7,641)	$ 4,088

DERIVATIVE INSTRUMENTS_HEDGIN39

DERIVATIVE INSTRUMENTS/HEDGING - Derivative assets and liabilities (Details) $ in Thousands	Dec. 31, 2015USD ($)
Asset
Total gross amounts presented in accompanying balance sheet	$ 10,745
Not Designated as Hedging Instrument [Member]
Asset
Total gross amounts presented in accompanying balance sheet	11,246
Net amount:	11,246
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	6,774
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	3,971
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Noncurrent Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	$ 501

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2014	Apr. 30, 2012
Financial Assets (Liabilities):
Derivative instruments	$ 10,745
Notes 5.875 Percent [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	5.875%	5.875%		5.875%
Notes 5.875 Percent [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	5.875%
Notes 4.375 Percent [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	4.375%	4.375%	4.375%
Notes 4.375 Percent [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	4.375%
Reported Value Measurement [Member]
Financial Assets (Liabilities):
Derivative instruments	$ 11,246
Reported Value Measurement [Member] | Notes 5.875 Percent [Member]
Financial Assets (Liabilities):
Long-term debt	(743,022)	$ (741,657)
Reported Value Measurement [Member] | Notes 4.375 Percent [Member]
Financial Assets (Liabilities):
Long-term debt	(742,598)	(741,519)
Estimate of Fair Value Measurement [Member]
Financial Assets (Liabilities):
Derivative instruments	11,246
Estimate of Fair Value Measurement [Member] | Notes 5.875 Percent [Member]
Financial Assets (Liabilities):
Long-term debt	(723,750)	(776,250)
Estimate of Fair Value Measurement [Member] | Notes 4.375 Percent [Member]
Financial Assets (Liabilities):
Long-term debt	$ (683,318)	$ (720,000)

FAIR VALUE MEASUREMENTS - Other

FAIR VALUE MEASUREMENTS - Other instruments (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Financial Instruments
Liabilities representing checks issued but not yet presented for payment	$ 23.1	$ 42
Accrued payroll related general and administrative expenses	21.5	44.2
Accrued operating expenses	60.4	67.5
Allowance for Trade Receivables [Member]
Other Financial Instruments
Aggregate allowance for doubtful accounts	$ 1.8	$ 1.5

FAIR VALUE MEASUREMENTS - Conce

FAIR VALUE MEASUREMENTS - Concentration (Details) - Sales Revenue, Goods, Net [Member]	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Enterprise Products
Concentration Risk
Percentage of sales to revenue, major customers (as a percent)	17.00%	19.00%
Sunoco Logistics
Concentration Risk
Percentage of sales to revenue, major customers (as a percent)	21.00%	19.00%
Oneok
Concentration Risk
Percentage of sales to revenue, major customers (as a percent)		10.00%

STOCK-BASED and OTHER COMPENSAT

STOCK-BASED and OTHER COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Options, Restricted Stock and Unit Awards
Compensation expense before capitalized cost	$ 36,341	$ 28,805	$ 26,268
Less amounts capitalized to oil and gas properties	(16,782)	(13,804)	(11,989)
Compensation expense	$ 19,559	15,001	14,279
Maximum number of shares of common stock that may be issued under the Stock Incentive Plan	6,600,000
Restricted Stock and Units [Member]
Options, Restricted Stock and Unit Awards
Compensation expense before capitalized cost	$ 33,538	$ 25,748	$ 23,123
Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Restricted stock granted (in shares)	471,119	486,843	579,236
Restricted stock granted, weighted average grant-date fair value (in dollars per share)	$ 99.29	$ 101.95	$ 75.39
Performance Based Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation expense before capitalized cost	$ 18,991	$ 12,141	$ 11,105
Restricted stock granted (in shares)	263,939	316,441	298,000
Restricted stock granted, weighted average grant-date fair value (in dollars per share)	$ 87.12	$ 83.22	$ 77.75
Vesting period	3 years
Performance Based Restricted Stock [Member] | Maximum [Member]
Options, Restricted Stock and Unit Awards
Award vesting percentage	100.00%
Performance Based Restricted Stock [Member] | Minimum [Member]
Options, Restricted Stock and Unit Awards
Award vesting percentage	50.00%
Service Based Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation expense before capitalized cost	$ 14,547	$ 13,607	$ 12,018
Restricted stock granted (in shares)	207,180	170,402	281,236
Restricted stock granted, weighted average grant-date fair value (in dollars per share)	$ 114.80	$ 136.72	$ 72.89
Service Based Restricted Stock [Member] | Maximum [Member]
Options, Restricted Stock and Unit Awards
Vesting period	5 years
Service Based Restricted Stock [Member] | Minimum [Member]
Options, Restricted Stock and Unit Awards
Vesting period	3 years
Employee Stock Option [Member]
Options, Restricted Stock and Unit Awards
Compensation expense before capitalized cost	$ 2,803	$ 3,057	$ 3,145
Employee Stock Option [Member] | Maximum [Member]
Options, Restricted Stock and Unit Awards
Vesting period	5 years
Employee Stock Option [Member] | Minimum [Member]
Options, Restricted Stock and Unit Awards
Vesting period	3 years

STOCK-BASED and OTHER COMPENS44

STOCK-BASED and OTHER COMPENSATION - RSA and RSU activity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock [Member]
Restricted stock and unit activity
Granted (in shares)	471,119	486,843	579,236
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Granted	$ 99.29	$ 101.95	$ 75.39
Fair value of resticted stock vested	$ 52.2	$ 34.1	$ 25.7
Performance Based Restricted Stock [Member]
Restricted stock and unit activity
Outstanding at the beginning of the period (in shares)	877,211
Vested (in shares)	(284,675)
Granted (in shares)	263,939	316,441	298,000
Canceled (in shares)	(26,667)
Outstanding at the end of the period (in shares)	829,808	877,211
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Outstanding beginning of period	$ 69.38
Vested	47.29
Granted	87.12	$ 83.22	$ 77.75
Canceled	81.98
Outstanding end of period	$ 82.99	$ 69.38
Service Based Restricted Stock [Member]
Restricted stock and unit activity
Outstanding at the beginning of the period (in shares)	1,036,417
Vested (in shares)	(181,665)
Granted (in shares)	207,180	170,402	281,236
Canceled (in shares)	(63,750)
Outstanding at the end of the period (in shares)	998,182	1,036,417
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Outstanding beginning of period	$ 82.69
Vested	72.16
Granted	114.80	$ 136.72	$ 72.89
Canceled	81.19
Outstanding end of period	$ 91.37	$ 82.69
Restricted Stock Units (RSUs) [Member]
Restricted stock and unit activity
Outstanding at the beginning of the period (in shares)	8,838
Outstanding at the end of the period (in shares)	8,838	8,838

STOCK-BASED and OTHER COMPENS45

STOCK-BASED and OTHER COMPENSATION - Options, assumptions (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock and Units [Member]
Options, Restricted Stock and Unit Awards
Unrecognized compensation costs related to unvested awards (in dollars)	$ 85,800
Expected period to recognize unamortized compensation costs related to unvested awards	2 years 2 months 12 days
Restricted Stock Units (RSUs) [Member]
Options, Restricted Stock and Unit Awards
Share Based Compensation Arrangement by Share Based Payment Award, Equity Instruments Other than Options, Outstanding, Number	8,838	8,838
Employee Stock Option [Member]
Options, Restricted Stock and Unit Awards
Unrecognized compensation costs related to unvested awards (in dollars)	$ 3,900
Expected period to recognize unamortized compensation costs related to unvested awards	1 year 9 months 18 days
Outstanding Stock Options
Outstanding balance at beginning of period (in shares)	384,082
Granted (in shares)	69,000	82,500	144,400
Exercised (in shares)	(141,517)	(211,258)	(276,069)
Canceled (in shares)	(666)
Forfeited (in shares)	(11,670)
Outstanding balance at end of period (in shares)	299,229	384,082
Exercisable at end of period (in shares)	142,188
Weighted Average Exercise Price
Outstanding balance at beginning of period (in dollars per share)	$ 78.19
Granted (in dollars per share)	115.28	$ 139.02	$ 72.25
Exercised (in dollars per share)	59.73
Canceled (in dollars per share)	139.02
Forfeited (in dollars per share)	118.77
Outstanding at end of period (in dollars per share)	93.76	$ 78.19
Exercisable at end of period (in dollars per share)	$ 74.07
Weighted Average Remaining Term
Weighted Average Remaining Term, Outstanding at end of period	4 years 10 months 24 days
Weighted Average Remaining Term, Exercisable at end of period	3 years 10 months 24 days
Aggregate Intrinsic Value
Aggregate Intrinsic Value Outstanding at end of period (in dollars)	$ 4,095
Aggregate Intrinsic Value Exercisable at the end of the period (in dollars)	$ 3,398
Grant-Date Fair value
Number of options exercised (in shares)	141,517	211,258	276,069
Cash received from option exercises	$ 8,451	$ 11,898	$ 14,494
Tax benefit from option exercises included in paid-in-capital	4,442
Intrinsic value of stock options exercised	7,467	15,384	10,109
Grant date fair value of options vested	$ 2,734	$ 4,419	$ 2,521
Granted (in dollars per share)	$ 37.56	$ 41.69	$ 21.64
Non-vested Stock Options
Non-vested at the beginning of the period (in shares)	205,156
Granted (in shares)	69,000	82,500	144,400
Vested (in shares)	(105,445)
Forfeited (in shares)	(11,670)
Non-vested at the end of the period (in shares)	157,041	205,156
Weighted Average Grant Date Fair Value - Non-Vested Stock Options
Non-vested as of January (in dollars per share)	$ 29.35
Granted (in dollars per share)	37.56	$ 41.69	$ 21.64
Vested (in dollars per share)	25.93
Forfeited (in dollars per share)	35.89
Non-vested as of December (in dollars per share)	34.77	29.35
Weighted Average Exercise Price - Non-Vested Stock Options
Non-vested at the beginning of the period (in dollars per share)	94.76
Granted (in dollars per share)	115.28
Vested (in dollars per share)	80.49
Forfeited (in dollars per share)	118.77
Non-vested at the end of the period (in dollars per share)	$ 111.58	$ 94.76
Assumptions used to determine the fair market value of options
Granted (in shares)	69,000	82,500	144,400
Weighted average grant-date fair value	$ 37.56	$ 41.69	$ 21.64
Weighted average exercise price	$ 115.28	$ 139.02	$ 72.25
Total fair value of options granted	$ 2,592	$ 3,439	$ 3,125
Expected years until exercise	5 years	4 years	4 years
Expected stock volatility (as a percent)	36.60%	36.70%	38.60%
Dividend yield (as a percent)	0.60%	0.50%	0.80%
Risk-free interest rate (as a percent)	1.60%	1.80%	1.40%
Maximum [Member] | Employee Stock Option [Member]
Grant-Date Fair value
Vesting period	5 years
Term of options from grant to expiration	10 years
Minimum [Member] | Employee Stock Option [Member]
Grant-Date Fair value
Vesting period	3 years
Term of options from grant to expiration	7 years

STOCK-BASED and OTHER COMPENS46

STOCK-BASED and OTHER COMPENSATION - 401(k) Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
STOCK-BASED COMPENSATION and OTHER COMPENSATION
Annual costs related to the plan	$ 6.4	$ 11	$ 9

EARNINGS (LOSS) PER SHARE (Deta

EARNINGS (LOSS) PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Basic:
Net income (loss)	$ (2,408,948)	$ 507,204	$ 564,689
Participating securities' share in earnings (in dollars)		(9,906)	(11,091)
Net income (loss) applicable to common stockholders	(2,408,948)	497,298	553,598
Diluted:
Net income (loss)	(2,408,948)	507,204	564,689
Participating securities' share in earnings (in dollars)		(9,891)	(11,076)
Net income (loss) applicable to common stockholders	$ (2,408,948)	$ 497,313	$ 553,613
Shares:
Basic shares outstanding	92,992	85,679	85,288
Dilutive effect of stock options		131	121
Fully diluted common stock (in shares)	92,992	85,810	85,409
Excluded antidilutive securities (in shares)	2,136	94	251
Earnings per share to common shareholders
Basic (in dollars per share)	$ (25.92)	$ 5.79	$ 6.48
Diluted (in dollars per share)	$ (25.92)	$ 5.78	$ 6.47

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations
Balance at beginning of year	$ 173,008	$ 154,026
Liabilities incurred	4,114	13,015
Liability settlements and disposals	(25,061)	(27,036)
Accretion expense	7,682	7,583
Revisions of estimated liabilities	4,362	25,420
Balance at end of year	173,008	154,026	$ 164,105	$ 173,008
Less current obligation			10,248	13,216
Long-term asset retirement obligation			$ 153,857	$ 159,792
Liability settlements and disposals related to properties that were sold	$ 13,300	$ 11,200

INCOME TAXES - Components of th

INCOME TAXES - Components of the Provision for income taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Taxes:
Federal (benefit)	$ 14,417		$ (381)
State (benefit)	293	$ 404	(308)
Current taxes (benefit)	14,710	404	(689)
Deferred Taxes:
Federal	(1,294,194)	282,729	315,165
State	(93,952)	15,564	14,535
Deferred income taxes	(1,388,146)	298,293	329,700
Total income tax expense (benefits)	$ (1,373,436)	$ 298,697	$ 329,011

INCOME TAXES - Reconciliations

INCOME TAXES - Reconciliations of the income tax (benefit) expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliations of the income tax (benefit) expense
Provision at statutory rate	$ (1,323,834)	$ 282,066	$ 312,795
Effect of state taxes	(60,634)	15,826	14,226
Revision of previous balances	5,997
Other permanent differences	5,035	805	1,990
Total income tax expense (benefits)	$ (1,373,436)	$ 298,697	$ 329,011

INCOME TAXES - Components of ne

INCOME TAXES - Components of net deferred tax liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-term Assets:
Stock compensation and other accrued amounts	$ 32,084	$ 26,527
Net operating loss carryforward, net of valuation allowance	305,506	218,584
Credit carryforward	6,016	4,068
Net deferred tax assets, long-term	343,606	249,179
Long-term Liabilities:
Property, plant and equipment	(696,311)	(2,003,885)
Net, long-term deferred tax liability	(352,705)	(1,754,706)
Current Assets:
Other accrued amounts		13,475
Net deferred tax assets, current, total		13,475
Net deferred tax liabilities	$ (352,705)	$ (1,741,231)

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
U.S. net tax operating loss carryforward	$ 907.5
U.S. net tax operating loss carryforward recorded to equity when utilized to reduce taxes payable	77.2
Alternative minimum tax credit carryforward	6
Unrecognized tax benefits that would impact the entity's effective rate	0	$ 0
Provisions for interest or penalties related to uncertain tax positions	$ 0	$ 0
U.S. statutory rate (as a percent)	35.00%	35.00%	35.00%
State [Member]
Operating Loss Carryforwards [Line Items]
Valuation allowance against net operating losses	$ 51
Total valuation allowance on net operating losses	$ 70.1

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Minimum lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies
Rental expense	$ 13,200	$ 14,300	$ 13,200
Future minimum payments under leases
2,016	9,248
2,017	9,625
2,018	9,119
2,019	9,196
2,020	9,349
Later years	50,173
Total future minimum lease payments	$ 96,710

COMMITMENTS AND CONTINGENCIES54

COMMITMENTS AND CONTINGENCIES - Other Commitments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Drilling Commitments [Member]
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 201.7
Commitments to Secure Use of Drilling Rigs [Member]
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 21.6

COMMITMENTS AND CONTINGENCIES55

COMMITMENTS AND CONTINGENCIES - Other Commitments - Delivery, operating leases (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MMcf
Natural Gas Sales Contracts [Member]
Delivery Commitments
Volume of gas deliverable (in Bcf) | MMcf	56,000
Delivery term	3 years
Financial commitment upon nondelivery	$ 116.7
Gas Gathering And Processing Agreements [Member]
Delivery Commitments
Delivery term	10 years
Financial commitment upon nondelivery	$ 203
Minimum Volume Agreement [Member]
Delivery Commitments
Financial commitment upon nondelivery	12.4
Accrued liabilities	9.7
Other Transportation, Delivery And Facilities Commitments [Member]
Delivery Commitments
Other commitments	$ 36.3

COMMITMENTS AND CONTINGENCIES56

COMMITMENTS AND CONTINGENCIES - Litigation (Details) - Helmerich and Payne Case [Member] - USD ($) $ in Thousands	Apr. 01, 2014	Dec. 31, 2013	Dec. 13, 2013	Dec. 31, 2008
Loss Contingencies
Accrued litigation expense				$ 119,600
Reversal of initial award to plaintiff, disgorgement			$ 119,600
Loss Contingency, Damages Awarded, Value			$ 3,650
Reduction in previously recognized litigation expense and associated long-term liability		$ 142,800
Payments to plaintiff	$ 15,800

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	5 Months Ended	12 Months Ended
	May. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Sheridan Production Parnters [Member]
Related Party Transactions
Revenues from related party		$ 4.1
Payments to related party		10.4
Certain Affiliates Of Sheridan Production Partners [Member]
Related Party Transactions
Payments to related party		224.2
Payments from related parties for joint interest billings		81.5
Helmerich and Payne, Inc [Member]
Related Party Transactions
Contract drilling services costs		$ 7.9	$ 18.4	$ 17
Subsidiary of Newpark Resources, Inc [Member]
Related Party Transactions
Contract drilling services costs	$ 0.6			$ 3.5

PROPERTY SALES AND ACQUISITIO58

PROPERTY SALES AND ACQUISITIONS (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property Sales
Acquisition of interest in oil and gas properties			$ 249,700	$ 37,100
Sales of other assets		$ 1,178	8,413	31,661
Triple Crown Gas Gathering and Processing System [Member]
Property Sales
Sales of other assets	$ 31,000
Interest sold in property (as a percent)	50.00%
Non Core Oil and Gas Properties [Member]
Property Sales
Sale of interests in oil and gas properties			$ 446,100	$ 61,500

SUPPLEMENTAL DISCLOSURE OF CA59

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash paid during the period for:
Interest expense (including capitalized amounts)	$ 80,785	$ 66,167	$ 50,754
Interest capitalized	28,819	32,623	29,098
Income taxes	558	354	205
Cash received for income taxes	$ 1,503	$ 460	$ 966