Cimarex Energy (CIMXP) 10-K 24 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
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, 2016
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			$ 11.1
Entity Common Stock, Shares Outstanding		95,121,492
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 652,876	$ 779,382
Accounts receivable:
Trade, net of allowance	42,287	81,888
Oil and gas sales, net of allowance	217,395	136,537
Gas gathering, processing, and marketing, net of allowance	14,888	6,935
Other	27	38
Oil and gas well equipment and supplies	33,342	54,579
Derivative instruments		10,745
Prepaid expenses	7,335	7,036
Other current assets	1,154	790
Total current assets	969,304	1,077,930
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	16,225,495	15,546,948
Unproved properties and properties under development, not being amortized	478,277	440,166
Gross oil and gas properties	16,703,772	15,987,114
Less - accumulated depreciation, depletion, amortization and impairment	(13,849,701)	(12,710,968)
Net oil and gas properties	2,854,071	3,276,146
Fixed assets, less accumulated depreciation of $246,901 and $207,173	205,465	230,009
Goodwill	620,232	620,232
Derivative instruments		501
Other assets, net	32,621	38,468
Total assets	4,681,693	5,243,286
Accounts payable:
Trade	49,163	53,384
Gas gathering, processing, and marketing	25,323	13,431
Accrued liabilities:
Exploration and development	82,320	56,721
Taxes other than income	18,766	17,545
Other	177,695	173,242
Derivative instruments	49,370
Revenue payable	119,715	95,744
Total current liabilities	522,352	410,067
Long-term debt:
Principal	1,500,000	1,500,000
Less - unamortized debt issuance costs	(12,061)	(14,380)
Long-term debt, net	1,487,939	1,485,620
Deferred income taxes	126,894	352,705
Asset retirement obligation	140,770	153,857
Derivative instruments	2,570
Other liabilities	41,104	43,359
Total liabilities	2,321,629	2,445,608
Stockholders' equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 95,123,525 and 94,820,570 shares issued, respectively	951	948
Paid-in capital	2,763,452	2,762,976
Retained earnings (Accumulated deficit)	(405,284)	33,313
Accumulated other comprehensive income	945	441
Total stockholders' equity	2,360,064	2,797,678
Total liabilities and stockholders' equity	$ 4,681,693	$ 5,243,286

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	May 31, 2015
Condensed Consolidated Balance Sheets
Fixed assets, accumulated depreciation (in dollars)	$ 246,901	$ 207,173
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	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	95,123,525	94,820,570

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil sales	$ 632,934	$ 809,664	$ 1,308,958
Gas sales	388,786	428,227	687,930
NGL sales	199,498	179,647	375,941
Gas gathering and other	36,033	34,688	49,602
Gas marketing, net of related costs of $122,655, $144,673 and $256,836 respectively	94	393	1,745
Total revenues	1,257,345	1,452,619	2,424,176
Costs and expenses:
Impairment of oil and gas properties	719,142	3,716,883
Depreciation, depletion and amortization	465,936	778,923	806,021
Asset retirement obligation	7,828	9,121	10,082
Production	232,002	299,374	342,304
Transportation, processing and other operating	190,725	182,362	195,414
Gas gathering and other	31,785	38,138	35,113
Taxes other than income	61,946	84,764	128,793
General and administrative	73,901	74,688	81,160
Stock compensation	24,523	19,559	15,001
(Gain) loss on derivative instruments, net	55,749	(11,246)	(3,762)
Other operating, net	755	856	116
Total costs and expenses	1,864,292	5,193,422	1,610,242
Operating income (loss)	(606,947)	(3,740,803)	813,934
Other (income) and expense:
Interest expense	83,272	85,746	72,865
Capitalized interest	(21,248)	(30,589)	(35,925)
Other, net	(10,707)	(13,576)	(28,907)
Income (loss) before income tax	(658,264)	(3,782,384)	805,901
Income tax expense (benefit)	(227,215)	(1,373,436)	298,697
Net income (loss)	$ (431,049)	$ (2,408,948)	$ 507,204
Basic
Distributed (in dollars per share)	$ 0.32	$ 0.64	$ 0.64
Undistributed (in dollars per share)	(4.94)	(26.56)	5.15
Total basic (in dollars per share)	(4.62)	(25.92)	5.79
Diluted
Distributed (in dollars per share)	0.32	0.64	0.64
Undistributed (in dollars per share)	(4.94)	(26.56)	5.14
Total diluted (in dollars per share)	$ (4.62)	$ (25.92)	$ 5.78
Comprehensive income (loss):
Net income (loss)	$ (431,049)	$ (2,408,948)	$ 507,204
Other comprehensive income (loss):
Change in fair value of investments, net of tax	504	(661)	(87)
Total comprehensive income (loss)	$ (430,545)	$ (2,409,609)	$ 507,117

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated Statements of Operations and Comprehensive Income (Loss)
Gas marketing, related costs	$ 122,655	$ 144,673	$ 256,836

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (431,049)	$ (2,408,948)	$ 507,204
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments and other valuation losses	719,142	3,716,883
Depreciation, depletion and amortization	465,936	778,923	806,021
Asset retirement obligation	7,828	9,121	10,082
Deferred income taxes	(226,100)	(1,388,146)	298,293
Stock compensation	24,523	19,559	15,001
(Gain) loss on derivative instruments	55,749	(11,246)	(3,762)
Settlements on derivative instruments	7,437		7,641
Changes in non-current assets and liabilities	3,867	23,230	(2,440)
Other, net	1,805	4,206	(3,828)
Changes in operating assets and liabilities:
Receivables, net	(49,340)	186,699	(35,133)
Other current assets	20,880	37,954	(25,428)
Accounts payable and other current liabilities	(1,453)	(276,735)	45,714
Net cash provided by operating activities	599,225	691,500	1,619,365
Cash flows from investing activities:
Oil and gas expenditures	(699,558)	(979,044)	(2,108,250)
Sales of oil and gas assets	21,487	39,853	449,981
Sales of other assets	7,889	1,178	8,413
Other capital expenditures	(22,228)	(70,592)	(90,611)
Net cash used by investing activities	(692,410)	(1,008,605)	(1,740,467)
Cash flows from financing activities:
Net bank debt borrowings			(174,000)
Proceeds from other long-term debt			750,000
Proceeds from sale of common stock		752,100
Financing and underwriting fees	(101)	(24,633)	(11,616)
Dividends paid	(38,024)	(58,281)	(53,849)
Proceeds from exercise of stock options and other	4,804	21,439	11,898
Net cash (used) provided by financing activities	(33,321)	690,625	522,433
Net change in cash and cash equivalents	(126,506)	373,520	401,331
Cash and cash equivalents at beginning of period	779,382	405,862	4,531
Cash and cash equivalents at end of period	$ 652,876	$ 779,382	$ 405,862

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, 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
Increase (Decrease) in Stockholders' Equity
Dividends			(7,548)		(7,548)
Dividends in Excess of Retained Earnings		(22,803)			(22,803)
Net income (loss)			(431,049)		(431,049)
Unrealized change in fair value of investments, net of tax				504	504
Issuance of restricted stock awards	$ 5	(5)
Issuance of service-based restricted stock awards, shares	479,000
Common stock reacquired and retired	$ (3)	(26,622)			(26,625)
Common stock reacquired and retired, shares	(208,000)
Restricted stock forfeited and retired, shares	(32,000)
Exercise of stock options	$ 1	4,803			4,804
Exercise of stock options, shares	64,000
Stock-based compensation		45,103			45,103
Balance at Dec. 31, 2016	$ 951	$ 2,763,452	$ (405,284)	$ 945	$ 2,360,064
Balance, shares at Dec. 31, 2016	95,124,000

BASIS OF PRESENTATION AND SUMMA

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	1. BASI 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 the allowance for doubtful accounts, impairments of unproved 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 We carry our inventory at the lower of cost or net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. We performed an analysis of our oil and gas well equipment and supplies as of December 31, 2016, 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. 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. Expenditures for maintenance and repairs are charged to production expense in the period incurred. 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 exceed this limit, the excess is charged to expense. At December 31, 2016, the carrying value of our oil and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, we did not recognize an impairment. However, a decline of 11% or more in the value of the ceiling limitation would have resulted in an impairment. We did recognize impairments in the first three quarters of 2016 totaling $719.1 million ($456.9 million, net of tax). For the year ended December 31, 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 decline, 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 other components of our balance sheet. 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 costs, 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. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors. 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 and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our qualitative assessment at December 31, 2016, 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. 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 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 classify all deferred tax assets and liabilities as noncurrent. 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 determine when we should record losses for these items based on information available to us. See Note 10 for additional information regarding our contingencies. Asset Retirement Obligations We recognize the present value of 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 cost related to all stock-based awards 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 In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 intend to adopt this standard on January 1, 2018, utilizing a modified retrospective approach. Management does not believe the effect of adoption will be material to our financial statements because we follow the sales method of accounting for our oil, gas and NGL production, which is generally consistent with the revenue recognition provisions of the new standard. However, we anticipate the new standard will result in more robust footnote disclosures. We cannot currently determine the extent of the new footnote disclosures as further clarification is needed for certain practices common to the industry. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current GAAP, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases. Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of assets and liabilities on the balance sheet. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. Upon transition, lessees will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. While we are in the process of evaluating the potential impact of adopting this guidance, the primary effect will be to record assets and obligations for contracts currently recognized as operating leases. We do not intend to adopt the standard early. In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The standard contains various amendments, and specifies whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. We will adopt ASU 2016-09 effective January 1, 2017. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures will be adopted using a modified retrospective method. In accordance with this method, we expect to record a cumulative-effect adjustment on that date relating to those amendments, representing a decrease to beginning Deferred income taxes of approximately $33 million, a reduction to beginning Accumulated deficit of approximately $31 million and an increase to beginning Paid-in capital of approximately $2 million. The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards will be adopted using a retrospective method. In accordance with this method, we estimate that Net cash provided by operating activities would have increased and Net cash (used) provided by financing activities would have decreased by approximately $27 million, $34 million and $14 million, for the years ended December 31, 2016, 2015 and 2014, respectively. In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)—Simplifying the Test for Goodwill Impairment . This ASU eliminates step two from the goodwill impairment test. Under current guidance, if the fair value of the reporting unit is less than its carrying amount (step 1 of the goodwill impairment test), entities must complete step two to determine the impairment amount, if any. Under step two, the impairment amount is determined by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination, and comparing it to the carrying amount of the goodwill. Under this ASU, the impairment amount is the amount by which the carrying amount of the reporting unit exceeds the reporting unit’s fair value, with the amount of impairment not to exceed the carrying amount of the goodwill. This ASU retains the option to qualitatively assess whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount in order to determine if it is necessary to initiate step 1. This ASU is effective for annual or any interim goodwill impairment tests in the fiscal years beginning after December 15, 2019, with early adoption permitted for testing dates after January 1, 2017. The implementation of this ASU will affect the amount of goodwill impairment we record, if any. We adopted this ASU on January 1, 2017, and will apply its provisions in future periods if we determine our goodwill has been impaired. 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, 2016
Capital Stock
CAPITAL STOCK	2. CAPITAL Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 2016, 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. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by the Board of Directors. Years Ended December 31, 2016 2015 2014 Dividends declared from Retained earnings (in millions) $ $ $ Dividends declared from Paid-in capital (in millions) $ $ — $ — Dividends per share $ $ $

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2016
Long-term debt
LONG-TERM DEBT	3. LONG-TERM A summary of our debt is as follows: December 31, 2016 December 31, 2015 Unamortized Debt Long-term Unamortized Debt Long-term (in thousands) Principal Issuance Costs Debt, net Principal Issuance Costs Debt, net 5.875% Senior Notes $ $ $ $ $ $ 4.375% Senior Notes Total long-term debt $ $ $ $ $ $ At December 31, 2016 and 2015, we had no bank debt outstanding. 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. 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, 2016, we had $2.5 million in letters of credit outstanding under the Credit Facility, leaving an unused borrowing availability of $997.5 million. At our option, borrowings under the Credit 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, 2016, we were in compliance with all of the financial and non-financial covenants. At December 31, 2016 and 2015, we had $4.5 million and $5.7 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 sheets. 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 costs, 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 costs, is 6.04%. These senior notes are callable by us beginning May 1, 2017 at a price of 102.938% of face value declining to 100% of face value on May 1, 2020 and thereafter. 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, 2016. Interest on each of the senior notes is payable semi-annually.

DERIVATIVE INSTRUMENTS_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING	12 Months Ended
	Dec. 31, 2016
Derivative instruments/hedging
DERIVATIVE INSTRUMENTS/HEDGING	4. DERIVATIVE INSTR 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. We may hedge up to 50% of our oil and natural gas production on a forward five quarter basis. The following tables summarize our derivative contracts as of December 31, 2016: First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) Wtd Avg Price - Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ 2018: WTI (1) Volume (Bbls) — — — Wtd Avg Price - Floor $ $ — $ — $ — $ Wtd Avg Price - Ceiling $ $ — $ — $ — $ (1) WTI refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: 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 $ $ $ $ $ 2018: PEPL (1) Volume (MMBtu) — — — Wtd Avg Price - Floor $ $ — $ — $ — $ Wtd Avg Price - Ceiling $ $ — $ — $ — $ Perm EP (1) Volume (MMBtu) 1,800,000 — — — Wtd Avg Price - Floor $ $ — $ — $ — $ Wtd Avg Price - Ceiling $ $ — $ — $ — $ (1) PEPL refers to the Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC. Perm EP refers to the El Paso Natural Gas Company, Permian Basin Index as quoted in Platt’s Inside FERC. Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price. We have elected not to account for our derivatives as cash flow hedges. Therefore, we recognize settlements and changes in the fair value of 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 from cash settlements during the periods shown below. Years Ended December 31, (in thousands) 2016 2015 2014 (Gain) loss on derivative instruments, net: Natural gas contracts $ $ $ Oil contracts (Gain) loss on derivative instruments, net $ $ $ Settlement (gains) losses: Natural gas contracts $ $ — $ Oil contracts — 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, 2016 and 2015, as well as the potential effect of netting arrangements on contracts with the same counterparty. December 31, 2016: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current liabilities — Derivative instruments $ — $ Natural gas contracts Current liabilities — Derivative instruments — Oil contracts Non-current liabilities — Derivative instruments — Natural gas contracts Non-current liabilities — Derivative instruments — Total gross amounts presented in accompanying balance sheet — Less: gross amounts not offset in the accompanying balance sheet — — Net amount: $ — $ 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 have 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, 2016
Fair Value Measurements
FAIR VALUE MEASUREMENTS	5. FAIR VALUE ME 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, 2016 and 2015. December 31, 2016 December 31, 2015 Book Fair Book Fair (in thousands) Value Value Value Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ $ $ $ 4.375% Notes due 2024 $ $ $ $ Derivative instruments — assets $ — $ — $ $ Derivative instruments — liabilities $ $ $ — $ — Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above. Debt (Level 1) The fair value of our 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. 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, 2016 and 2015, respectively, are 1) liabilities of approximately $19.3 million and $23.1 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts; 2) accrued payroll related costs of $43.5 million and $21.5 million; and 3) accrued operating expenses of $53.9 million and $60.4 million. Our accounts receivable are primarily from either purchasers of our oil, gas, 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, 2016 and 2015, the allowance for doubtful accounts totaled $1.6 million and $1.8 million, respectively. Major Customers Our major customer during 2016 was Sunoco Logistics Partners L.P. (Sunoco), which accounted for 20% of our consolidated revenues. Sunoco and Enterprise Products Partners L.P. (Enterprise) were our major customers in 2015, accounting for 21% and 17%, respectively, of our consolidated revenues that year. During 2014, Sunoco and Enterprise each accounted for 19% of our consolidated revenues and Oneok Partners, L.P. accounted for 10% of our consolidated revenues. If Sunoco was 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 multiple significant customers were to discontinue purchasing our product, we believe there would be challenges initially, but ample markets to handle the disruption.

STOCK-BASED AND OTHER COMPENSAT

STOCK-BASED AND OTHER COMPENSATION	12 Months Ended
	Dec. 31, 2016
Stock based and other compensation
STOCK-BASED AND OTHER COMPENSATION	6. STOCK-BASED AND OT 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) 2016 2015 2014 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 2016 stock compensation is primarily related to performance awards granted in December 2015, a portion of which were amortized during 2016, forfeiture rate adjustments on the service-based stock awards, and the acceleration of expense on a portion of service-based awards for employees who participated in a voluntary early retirement incentive program. 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, 2016 2015 2014 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 Number of Grant-Date Number of Grant-Date Shares Fair Value Shares Fair Value Outstanding as of January 1, 2016 $ $ Vested $ $ Granted $ $ Canceled $ $ Outstanding as of December 31, 2016 $ $ The total fair value of restricted stock that vested was $67.9 million in 2016, $52.2 million in 2015, and $34.1 million in 2014. Unrecognized compensation cost related to unvested restricted stock at December 31, 2016 was $96.0 million. We expect to recognize that cost over a weighted average period of 2.8 years. Restricted Units As of December 31, 2016 and 2015, 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, 2016 2015 2014 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, 2016 $ Exercised $ Granted $ Canceled $ Forfeited $ Outstanding as of December 31, 2016 $ Years $ Exercisable as of December 31, 2016 $ Years $ The following table provides information regarding options exercised and the grant-date fair value of options vested. Years Ended December 31, (in thousands) 2016 2015 2014 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, 2016 and changes during the year. Weighted Weighted Average Average Grant-Date Exercise Options Fair Value Price Non-vested as of January 1, 2016 $ $ Vested $ $ Granted $ $ Forfeited $ $ Non-vested as of December 31, 2016 $ $ As of December 31, 2016, there was $3.6 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 2.0 years. Other Compensation We maintain and sponsor a contributory 401(k) plan for our employees. Annual matching costs related to the plan were $6.7 million, $6.4 million, and $11.0 million for 2016, 2015, and 2014, respectively.

EARNINGS (LOSS) PER SHARE

EARNINGS (LOSS) PER SHARE	12 Months Ended
	Dec. 31, 2016
Earnings (Loss) per Share
EARNINGS (LOSS) PER SHARE	7. EARNINGS (LOSS) P 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) 2016 2015 2014 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 is based on actual figures rather than the rounded figures presented.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligations
ASSET RETIREMENT OBLIGATIONS	8. ASSET RETIREM The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 2016 and 2015. (in thousands) 2016 2015 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 $ $ During 2016 and 2015, the liability settlements and disposals included $14.9 million and $13.3 million, respectively, related to properties that were sold.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2016
Income Taxes
INCOME TAXES	9. INCOME The components of the provision for income taxes are as follows: Years Ended December 31, (in thousands) 2016 2015 2014 Current taxes: Federal expense $ — $ $ — State (benefit) expense Deferred taxes: Federal (benefit) expense State (benefit) expense $ $ $ 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. Reconciliations of the income tax expense (benefit) calculated at the federal statutory rate of 35% to the total income tax expense (benefit) are as follows: Years Ended December 31, (in thousands) 2016 2015 2014 Provision at statutory rate $ $ $ Effect of state taxes Revision of previous balances — Other permanent differences Change in valuation allowance — — Income tax expense (benefit) $ $ $ The components of net deferred tax liabilities are as follows: December 31, (in thousands) 2016 2015 Assets: Stock compensation and other accrued amounts $ $ Net operating loss carryforward, net of valuation allowance Credit carryforward Liabilities: Property, plant and equipment Net deferred tax liabilities $ $ At December 31, 2016, we had a U.S. net tax operating loss carryforward of approximately $1,182.4 million, which would expire in years 2031 through 2036. We believe that the carryforward will be utilized before it expires. We recorded a $10.4 million increase to the net operating loss carryforward at December 31, 2016, for certain state losses and a corresponding increase in the state net operating loss valuation allowance of $11.9 million. The net decrease in the state net operating losses after reduction for the valuation allowance was $1.5 million. The total valuation allowance on state net operating losses at December 31, 2016, was $82.0 million because it is not more likely than not that these additional state net operating losses will be utilized before they expire. Approximately $90.9 million of the U.S. net tax operating loss carryforward is attributable to deductions taken for employee stock awards on the Company’s tax returns in excess of amounts expensed through the Company’s income statement. We also had an alternative minimum tax credit carryforward of approximately $6.0 million. At December 31, 2016 and 2015, 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 2013 through 2015 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 2012 through 2015.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies
COMMITMENTS AND CONTINGENCIES	10. COMMITMENTS AN Lease Commitments We have various commitments for office space and equipment under operating lease arrangements. Rent expense for the operating leases totaled $12.9 million in 2016. Rent expense was $13.2 million and $14.3 million for 2015 and 2014, respectively. Shown below are future minimum cash payments required under these leases as of December 31, 2016. Operating (in thousands) Leases 2017 $ 2018 2019 2020 2021 Later years Total future minimum lease payments $ Other Commitments We have commitments of $157.5 million to finish drilling and completing wells in progress at December 31, 2016. At December 31, 2016, we had firm sales contracts to deliver approximately 46.4 Bcf of natural gas over the next twenty-two months. If this gas is not delivered, our financial commitment would be approximately $164.8 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these obligations. In connection with gas gathering and processing agreements, we have volume commitments over the next ten years. At December 31, 2016, if no gas is delivered, the maximum amount that would be payable under these commitments would be approximately $220.0 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. At December 31, 2016, the maximum amount that would be payable if no gas is delivered would be approximately $7.9 million. Of this total, we have accrued a liability of $2.1 million. We may have additional liabilities associated with these delivery commitments in the future depending on our production levels and drilling results. We have other various transportation, delivery, and facilities commitments in the normal course of business, which approximate $35.7 million at December 31, 2016. We currently anticipate meeting these obligations. All of the noted commitments were made in the normal course of our business. Litigation In the normal course of business, we have various litigation matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, 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. v. Helmerich & Payne, Inc. In 2008, we recorded litigation expense of $119.6 million for the H.B. Krug, et al. v. Helmerich & Payne, Inc. trial court verdict, and began accruing additional post-judgment interest and costs for this case. On December 13, 2013, the Oklahoma Supreme Court reversed the trial court’s $119.6 million verdict and affirmed an alternative jury verdict for $3.65 million. The Supreme Court 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 at this time.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2016
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	11. RELATED PARTY TRA Helmerich & Payne, Inc. (H&P) provides contract drilling services to Cimarex. Drilling costs of approximately $18.3 million were incurred by Cimarex related to such services for 2016. During 2015 and 2014, such costs were $7.9 million and $18.4 million, respectively. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P. Lisa Stewart, who joined Cimarex’s Board of Directors in October 2015, is Chairman, President, Chief Executive Officer, and Chief Investment Officer of Sheridan Production Partners (Sheridan). During 2016, Cimarex paid certain affiliates of Sheridan oil and gas revenues of $177.6 thousand and joint interest billings of $5.2 thousand and received oil and gas revenues of $0.4 thousand and joint interest billings of $73.1 thousand from Sheridan affiliates. During 2015, Cimarex paid certain affiliates of Sheridan oil and gas revenues of $224.2 thousand and joint interest billings of $10.4 thousand and received oil and gas revenues of $4.1 thousand and joint interest billings of $81.5 thousand from Sheridan affiliates. Jerry Box, a director of Cimarex whose term expired May 2015, was the non-executive Chairman of the Board of Directors of Newpark Resources, Inc. (Newpark) through May 2014. Certain subsidiaries of Newpark provided various drilling services to Cimarex. Costs of such services were $589.2 thousand through May 2014.

PROPERTY SALES AND ACQUISITIONS

PROPERTY SALES AND ACQUISITIONS	12 Months Ended
	Dec. 31, 2016
Property Acquisitions and Sales
PROPERTY SALES AND ACQUISITIONS	12. PROPERTY SALES AN 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 2016 or 2015. We sold interests in various non-core 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 property acquisitions totaling $249.7 million, most of which were in our Cana area in Western Oklahoma.

SUPPLEMENTAL DISCLOSURE OF CASH

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION	12 Months Ended
	Dec. 31, 2016
Supplemental Disclosure of Cash Flow Information:
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION	13. SUPPLEMENTAL DISC Years Ended December 31, (in thousands) 2016 2015 2014 Cash paid during the period for: Interest expense (including capitalized amounts) $ $ $ Interest capitalized $ $ $ Income taxes $ $ $ Cash received for income tax refunds $ $ $

BASIS OF PRESENTATION AND SUM21

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 the allowance for doubtful accounts, impairments of unproved 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 We carry our inventory at the lower of cost or net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. We performed an analysis of our oil and gas well equipment and supplies as of December 31, 2016, 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. 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. Expenditures for maintenance and repairs are charged to production expense in the period incurred. 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 exceed this limit, the excess is charged to expense. At December 31, 2016, the carrying value of our oil and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, we did not recognize an impairment. However, a decline of 11% or more in the value of the ceiling limitation would have resulted in an impairment. We did recognize impairments in the first three quarters of 2016 totaling $719.1 million ($456.9 million, net of tax). For the year ended December 31, 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 decline, 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 other components of our balance sheet. 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 costs, 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. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors.
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 and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our qualitative assessment at December 31, 2016, 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. 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 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 classify all deferred tax assets and liabilities as noncurrent. 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 determine when we should record losses for these items based on information available to us. See Note 10 for additional information regarding our contingencies.
Asset Retirement Obligations	Asset Retirement Obligations We recognize the present value of 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 cost related to all stock-based awards 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 In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 intend to adopt this standard on January 1, 2018, utilizing a modified retrospective approach. Management does not believe the effect of adoption will be material to our financial statements because we follow the sales method of accounting for our oil, gas and NGL production, which is generally consistent with the revenue recognition provisions of the new standard. However, we anticipate the new standard will result in more robust footnote disclosures. We cannot currently determine the extent of the new footnote disclosures as further clarification is needed for certain practices common to the industry. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current GAAP, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases. Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified asset in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of assets and liabilities on the balance sheet. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. Upon transition, lessees will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. While we are in the process of evaluating the potential impact of adopting this guidance, the primary effect will be to record assets and obligations for contracts currently recognized as operating leases. We do not intend to adopt the standard early. In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The standard contains various amendments, and specifies whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. We will adopt ASU 2016-09 effective January 1, 2017. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures will be adopted using a modified retrospective method. In accordance with this method, we expect to record a cumulative-effect adjustment on that date relating to those amendments, representing a decrease to beginning Deferred income taxes of approximately $33 million, a reduction to beginning Accumulated deficit of approximately $31 million and an increase to beginning Paid-in capital of approximately $2 million. The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards will be adopted using a retrospective method. In accordance with this method, we estimate that Net cash provided by operating activities would have increased and Net cash (used) provided by financing activities would have decreased by approximately $27 million, $34 million and $14 million, for the years ended December 31, 2016, 2015 and 2014, respectively. In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)—Simplifying the Test for Goodwill Impairment . This ASU eliminates step two from the goodwill impairment test. Under current guidance, if the fair value of the reporting unit is less than its carrying amount (step 1 of the goodwill impairment test), entities must complete step two to determine the impairment amount, if any. Under step two, the impairment amount is determined by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination, and comparing it to the carrying amount of the goodwill. Under this ASU, the impairment amount is the amount by which the carrying amount of the reporting unit exceeds the reporting unit’s fair value, with the amount of impairment not to exceed the carrying amount of the goodwill. This ASU retains the option to qualitatively assess whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount in order to determine if it is necessary to initiate step 1. This ASU is effective for annual or any interim goodwill impairment tests in the fiscal years beginning after December 15, 2019, with early adoption permitted for testing dates after January 1, 2017. The implementation of this ASU will affect the amount of goodwill impairment we record, if any. We adopted this ASU on January 1, 2017, and will apply its provisions in future periods if we determine our goodwill has been impaired.
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, 2016
Capital Stock
Schedule of dividends declared	Years Ended December 31, 2016 2015 2014 Dividends declared from Retained earnings (in millions) $ $ $ Dividends declared from Paid-in capital (in millions) $ $ — $ — Dividends per share $ $ $

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2016
Long-term debt
Summary of debt	December 31, 2016 December 31, 2015 Unamortized Debt Long-term Unamortized Debt Long-term (in thousands) Principal Issuance Costs Debt, net Principal Issuance Costs Debt, net 5.875% Senior Notes $ $ $ $ $ $ 4.375% Senior Notes Total long-term debt $ $ $ $ $ $

DERIVATIVE INSTRUMENTS_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative instruments/hedging
Outstanding hedging contracts relative to future production	First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) Wtd Avg Price - Floor $ $ $ $ $ Wtd Avg Price - Ceiling $ $ $ $ $ 2018: WTI (1) Volume (Bbls) — — — Wtd Avg Price - Floor $ $ — $ — $ — $ Wtd Avg Price - Ceiling $ $ — $ — $ — $ (1) WTI refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: 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 $ $ $ $ $ 2018: PEPL (1) Volume (MMBtu) — — — Wtd Avg Price - Floor $ $ — $ — $ — $ Wtd Avg Price - Ceiling $ $ — $ — $ — $ Perm EP (1) Volume (MMBtu) 1,800,000 — — — Wtd Avg Price - Floor $ $ — $ — $ — $ Wtd Avg Price - Ceiling $ $ — $ — $ — $ (1) PEPL refers to the Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC. Perm EP refers to the El Paso Natural Gas Company, Permian Basin Index as quoted in Platt’s Inside FERC.
Net (gains) and losses from settlements and changes of derivative contracts	Years Ended December 31, (in thousands) 2016 2015 2014 (Gain) loss on derivative instruments, net: Natural gas contracts $ $ $ Oil contracts (Gain) loss on derivative instruments, net $ $ $ Settlement (gains) losses: Natural gas contracts $ $ — $ Oil contracts — 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, 2016: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current liabilities — Derivative instruments $ — $ Natural gas contracts Current liabilities — Derivative instruments — Oil contracts Non-current liabilities — Derivative instruments — Natural gas contracts Non-current liabilities — Derivative instruments — Total gross amounts presented in accompanying balance sheet — Less: gross amounts not offset in the accompanying balance sheet — — Net amount: $ — $ 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, 2016
Fair Value Measurements
Fair value measurement information for certain assets and liabilities	December 31, 2016 December 31, 2015 Book Fair Book Fair (in thousands) Value Value Value Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ $ $ $ 4.375% Notes due 2024 $ $ $ $ Derivative instruments — assets $ — $ — $ $ Derivative instruments — liabilities $ $ $ — $ —

STOCK-BASED AND OTHER COMPENS26

STOCK-BASED AND OTHER COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2016
Options, Restricted Stock and Unit Awards
Recognition of non-cash stock-based compensation cost	Years Ended December 31, (in thousands) 2016 2015 2014 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 Number of Grant-Date Number of Grant-Date Shares Fair Value Shares Fair Value Outstanding as of January 1, 2016 $ $ Vested $ $ Granted $ $ Canceled $ $ Outstanding as of December 31, 2016 $ $
Restricted Stock and Units [Member]
Options, Restricted Stock and Unit Awards
Summary of restricted stock awards granted	Years Ended December 31, 2016 2015 2014 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, 2016 $ Exercised $ Granted $ Canceled $ Forfeited $ Outstanding as of December 31, 2016 $ Years $ Exercisable as of December 31, 2016 $ Years $
Summary of information regarding options exercised and grant-date fair value of options vested	Years Ended December 31, (in thousands) 2016 2015 2014 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, 2016 $ $ Vested $ $ Granted $ $ Forfeited $ $ Non-vested as of December 31, 2016 $ $
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, 2016 2015 2014 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 % % %

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligations
Change in the carrying amount of the asset retirement obligation	(in thousands) 2016 2015 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, 2016
Income Taxes
Components of the provision for income taxes	Years Ended December 31, (in thousands) 2016 2015 2014 Current taxes: Federal expense $ — $ $ — State (benefit) expense Deferred taxes: Federal (benefit) expense State (benefit) expense $ $ $
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) 2016 2015 2014 Provision at statutory rate $ $ $ Effect of state taxes Revision of previous balances — Other permanent differences Change in valuation allowance — — Income tax expense (benefit) $ $ $
Components of net deferred tax liabilities	December 31, (in thousands) 2016 2015 Assets: Stock compensation and other accrued amounts $ $ Net operating loss carryforward, net of valuation allowance Credit carryforward Liabilities: Property, plant and equipment Net deferred tax liabilities $ $

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies
Schedule of future minimum payments required under leases	Operating (in thousands) Leases 2017 $ 2018 2019 2020 2021 Later years Total future minimum lease payments $

SUPPLEMENTAL DISCLOSURE OF CA30

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Disclosure of Cash Flow Information:
Supplemental Disclosure of Cash Flow Information	Years Ended December 31, (in thousands) 2016 2015 2014 Cash paid during the period for: Interest expense (including capitalized amounts) $ $ $ Interest capitalized $ $ $ Income taxes $ $ $ Cash received for income tax refunds $ $ $

BASIS OF PRESENTATION AND SUM31

BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jan. 01, 2017USD ($)
Number of reportable segments | segment		1
Oil and Gas Properties
Impairment on oil and gas well equipment and supplies		$ 0
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	$ 719,100,000	$ 719,142,000	$ 3,716,883,000
Impairment of oil and gas properties, after tax	$ 456,900,000		2,400,000,000
Ceiling limitation used in ceiling test sensitivity analysis		11.00%
Accrued liabilities
Exploration and development		$ 82,320,000	56,721,000
Taxes other than income		18,766,000	17,545,000
Other		177,695,000	173,242,000
Goodwill
Goodwill impairment		0
Deferred income taxes		126,894,000	352,705,000
Retained Earnings (Accumulated Deficit)		(405,284,000)	33,313,000
Additional Paid in Capital		2,763,452,000	2,762,976,000
Net cash provided by operating activities		599,225,000	691,500,000	$ 1,619,365,000
Net cash (used) provided by financing activities		$ (33,321,000)	690,625,000	522,433,000
Maximum [Member]
Fixed assets, net
Fixed assets expected lives		30 years
Minimum [Member]
Fixed assets, net
Fixed assets expected lives		3 years
Restatement Adjustment | Accounting Standards Update 2016 09 [Member]
Goodwill
Net cash provided by operating activities		$ 27,000,000	34,000,000	14,000,000
Net cash (used) provided by financing activities		$ (27,000,000)	$ (34,000,000)	$ (14,000,000)
Proforma Adjustment [Member] | Accounting Standards Update 2016 09 [Member]
Goodwill
Deferred income taxes					$ (33,000,000)
Retained Earnings (Accumulated Deficit)					(31,000,000)
Additional Paid in Capital					$ 2,000,000

CAPITAL STOCK (Details)

CAPITAL STOCK (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended		12 Months Ended
	Feb. 29, 2016	May 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Capital Stock [Line Items]
Issuance of common stock, shares		6,900,000
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
Beginning balance, shares			94,820,570
Ending balance, shares			95,123,525	94,820,570
Price per share sold		$ 109
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 from Retained Earnings			$ 7,548	$ 59,313	$ 55,664
Dividend declared from APIC			$ 22,803
Dividend per share			$ 0.32	$ 0.64	$ 0.64
Additional Shares Issued [Member]
Capital Stock [Line Items]
Issuance of common stock, shares		900,000
Retained Earnings [Member]
Dividend payable
Dividend declared from Retained Earnings			$ 7,548	$ 59,313	$ 55,664
Additional Paid-in Capital [Member]
Dividend payable
Dividend declared from APIC			$ 22,803

LONG-TERM DEBT - Summary (Detai

LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2014	Apr. 30, 2012
Debt Instrument
Principal	$ 1,500,000	$ 1,500,000
Unamortized Debt Issuance Costs	(12,061)	(14,380)
Long-term debt, net	1,487,939	1,485,620
Senior Notes 5.875% [Member]
Debt Instrument
Principal	750,000	750,000
Unamortized Debt Issuance Costs	(5,691)	(6,978)
Long-term debt, net	$ 744,309	$ 743,022		$ 750,000
Interest rate (as a percent)	5.875%	5.875%		5.875%
Senior Notes 4.375% [Member]
Debt Instrument
Principal	$ 750,000	$ 750,000
Unamortized Debt Issuance Costs	(6,370)	(7,402)
Long-term debt, net	$ 743,630	$ 742,598	$ 750,000
Interest rate (as a percent)	4.375%	4.375%	4.375%

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, 2016	Dec. 31, 2015
Debt Instrument
Unamortized debt issuance costs			$ 12,061	$ 14,380
Long-term Debt, Excluding Current Maturities			$ 1,487,939	1,485,620
Redemption price during first period (as a percent)			102.938
Redemption price as a percentage fourth period and thereafter			100.00%
Revolving Credit Facility [Member]
Debt Instrument
Unamortized debt issuance costs			$ 4,500	5,700
Credit facility amount			1,000,000
Credit facility, increase amount option			$ 1,250,000
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%
Senior Notes 4.375% [Member]
Debt Instrument
Unamortized debt issuance costs			$ 6,370	$ 7,402
Issuance of senior unsecured notes	$ 740,900
Interest rate (as a percent)	4.375%		4.375%	4.375%
Effective rate			4.50%
Long-term Debt, Excluding Current Maturities	$ 750,000		$ 743,630	$ 742,598
Senior Notes 5.875% [Member]
Debt Instrument
Unamortized debt issuance costs			$ 5,691	$ 6,978
Issuance of senior unsecured notes		$ 737,000
Interest rate (as a percent)		5.875%	5.875%	5.875%
Effective rate			6.04%
Long-term Debt, Excluding Current Maturities		$ 750,000	$ 744,309	$ 743,022
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_HEDGIN35

DERIVATIVE INSTRUMENTS/HEDGING (Details)	12 Months Ended
	Dec. 31, 2016MMBTU / Ditem$ / MMBTU
Derivative
Percent of oil and gas production available for hedging	50.00%
Quater basis for oil and gas production available for hedging | item	5
Derivative Contract Oil Collar W T I Index [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	6,104,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	44.09
Ceiling, weighted average price (in dollars per unit)	54.20
Derivative Contract Oil Collar W T I Index [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)	43.08
Ceiling, weighted average price (in dollars per unit)	52.90
Derivative Contract Oil Collar W T I Index [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)	43.08
Ceiling, weighted average price (in dollars per unit)	52.90
Derivative Contract Oil Collar W T I Index [Member] | Third Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,472,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	45.09
Ceiling, weighted average price (in dollars per unit)	55.50
Derivative Contract Oil Collar W T I Index [Member] | Fourth Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,012,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	46.27
Ceiling, weighted average price (in dollars per unit)	56.98
Derivative Contract Oil Collar W T I Index [Member] | 2018 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	540,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	47.33
Ceiling, weighted average price (in dollars per unit)	59.11
Derivative Contract Oil Collar W T I Index [Member] | First Quarter - 2018 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	540,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	47.33
Ceiling, weighted average price (in dollars per unit)	59.11
Derivative Contract Gas Collar PEPL Index [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	33,710,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.59
Ceiling, weighted average price (in dollars per unit)	3.09
Derivative Contract Gas Collar PEPL Index [Member] | First Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	9,900,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.52
Ceiling, weighted average price (in dollars per unit)	3.04
Derivative Contract Gas Collar PEPL Index [Member] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	10,010,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.52
Ceiling, weighted average price (in dollars per unit)	3.04
Derivative Contract Gas Collar PEPL Index [Member] | Third Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	8,280,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.61
Ceiling, weighted average price (in dollars per unit)	3.12
Derivative Contract Gas Collar PEPL Index [Member] | Fourth Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,520,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.79
Ceiling, weighted average price (in dollars per unit)	3.22
Derivative Contract Gas Collar PEPL Index [Member] | 2018 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	2,700,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.90
Ceiling, weighted average price (in dollars per unit)	3.32
Derivative Contract Gas Collar PEPL Index [Member] | First Quarter - 2018 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	2,700,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.90
Ceiling, weighted average price (in dollars per unit)	3.32
Derivative Contract Gas Collar Perm EP [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	25,490,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.65
Ceiling, weighted average price (in dollars per unit)	3.14
Derivative Contract Gas Collar Perm EP [Member] | First Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	8,100,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.59
Ceiling, weighted average price (in dollars per unit)	3.10
Derivative Contract Gas Collar Perm EP [Member] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	8,190,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.59
Ceiling, weighted average price (in dollars per unit)	3.10
Derivative Contract Gas Collar Perm EP [Member] | Third Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,520,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.68
Ceiling, weighted average price (in dollars per unit)	3.16
Derivative Contract Gas Collar Perm EP [Member] | Fourth Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	3,680,000
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.86
Ceiling, weighted average price (in dollars per unit)	3.28
Derivative Contract Gas Collar Perm EP [Member] | 2018 [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)	3
Ceiling, weighted average price (in dollars per unit)	3.41
Derivative Contract Gas Collar Perm EP [Member] | First Quarter - 2018 [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)	3
Ceiling, weighted average price (in dollars per unit)	3.41

DERIVATIVE INSTRUMENTS_HEDGIN36

DERIVATIVE INSTRUMENTS/HEDGING (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
(Gain) loss on derivative instruments, net
(Gain) loss on derivative instruments, net	$ 55,749	$ (11,246)	$ (3,762)
(Gains) losses from settlement of derivative instruments:
Settlements on derivative instruments	7,437		7,641
Not Designated as Hedging Instrument [Member]
(Gain) loss on derivative instruments, net
(Gain) loss on derivative instruments, net	55,749	(11,246)	(3,761)
(Gains) losses from settlement of derivative instruments:
Settlements on derivative instruments	(7,437)		(7,641)
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member]
(Gain) loss on derivative instruments, net
(Gain) loss on derivative instruments, net	34,754	(6,774)	(10,512)
(Gains) losses from settlement of derivative instruments:
Settlements on derivative instruments	(970)		(11,928)
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member]
(Gain) loss on derivative instruments, net
(Gain) loss on derivative instruments, net	20,995	$ (4,472)	6,751
(Gains) losses from settlement of derivative instruments:
Settlements on derivative instruments	$ (6,467)		$ 4,287

DERIVATIVE INSTRUMENTS_HEDGIN37

DERIVATIVE INSTRUMENTS/HEDGING - Derivative assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Asset
Total gross amounts presented in accompanying balance sheet		$ 10,745
Liability
Total gross amounts presented in accompanying balance sheet	$ 49,370
Not Designated as Hedging Instrument [Member]
Asset
Total gross amounts presented in accompanying balance sheet		11,246
Net amount:		11,246
Liability
Total gross amounts presented in accompanying balance sheet	51,940
Net amount:	51,940
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] | Oil Contracts [Member] | Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet	27,892
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Non-Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet	1,059
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] | Non-Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet		$ 501
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet	21,478
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Non-Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet	$ 1,511

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2014	Apr. 30, 2012
Financial Assets (Liabilities):
Derivative instruments — assets		$ 10,745
Derivative instruments — liabilities	$ (49,370)
Fair Value, Inputs, Level 2 [Member] | Carrying Amount [Member]
Financial Assets (Liabilities):
Derivative instruments — assets		11,246
Derivative instruments — liabilities	(51,940)
Fair Value, Inputs, Level 2 [Member] | Fair Value [Member]
Financial Assets (Liabilities):
Derivative instruments — assets		$ 11,246
Derivative instruments — liabilities	$ (51,940)
Senior Notes 5.875% [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	5.875%	5.875%		5.875%
Senior Notes 5.875% [Member] | Carrying Amount [Member]
Financial Assets (Liabilities):
Long-term debt	$ (750,000)	$ (750,000)
Senior Notes 5.875% [Member] | Fair Value [Member]
Financial Assets (Liabilities):
Long-term debt	$ (782,835)	$ (723,750)
Senior Notes 4.375% [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	4.375%	4.375%	4.375%
Senior Notes 4.375% [Member] | Carrying Amount [Member]
Financial Assets (Liabilities):
Long-term debt	$ (750,000)	$ (750,000)
Senior Notes 4.375% [Member] | Fair Value [Member]
Financial Assets (Liabilities):
Long-term debt	$ (779,453)	$ (683,318)

FAIR VALUE MEASUREMENTS - Other

FAIR VALUE MEASUREMENTS - Other instruments (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other Financial Instruments
Liabilities representing checks issued but not yet presented for payment	$ 19.3	$ 23.1
Accrued payroll related general and administrative expenses	43.5	21.5
Accrued operating expenses	53.9	60.4
Allowance for Trade Receivables [Member]
Other Financial Instruments
Aggregate allowance for doubtful accounts	$ 1.6	$ 1.8

FAIR VALUE MEASUREMENTS - Conce

FAIR VALUE MEASUREMENTS - Concentration (Details) - Sales Revenue, Goods, Net [Member]	12 Months Ended
	Dec. 31, 2016	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)	20.00%	21.00%	19.00%
Oneok
Concentration Risk
Percentage of sales to revenue, major customers (as a percent)			10.00%

STOCK-BASED and OTHER COMPENS41

STOCK-BASED and OTHER COMPENSATION (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	$ 45,139	$ 36,341	$ 28,805
Less amounts capitalized to oil and gas properties	(20,616)	(16,782)	(13,804)
Compensation expense	$ 24,523	19,559	15,001
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 cost before capitalized cost	$ 42,574	$ 33,538	$ 25,748
Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Restricted stock granted (in shares)	478,639	471,119	486,843
Restricted stock granted, weighted average grant-date fair value (in dollars per share)	$ 116.31	$ 99.29	$ 101.95
Performance Based Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	$ 24,183	$ 18,991	$ 12,141
Restricted stock granted (in shares)	269,915	263,939	316,441
Restricted stock granted, weighted average grant-date fair value (in dollars per share)	$ 117.63	$ 87.12	$ 83.22
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 cost before capitalized cost	$ 18,391	$ 14,547	$ 13,607
Restricted stock granted (in shares)	208,724	207,180	170,402
Restricted stock granted, weighted average grant-date fair value (in dollars per share)	$ 114.61	$ 114.80	$ 136.72
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 cost before capitalized cost	$ 2,565	$ 2,803	$ 3,057
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 COMPENS42

STOCK-BASED and OTHER COMPENSATION - RSA and RSU activity (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock [Member]
Restricted stock and unit activity
Granted (in shares)	478,639	471,119	486,843
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Granted	$ 116.31	$ 99.29	$ 101.95
Fair value of resticted stock vested	$ 67.9	$ 52.2	$ 34.1
Performance Based Restricted Stock [Member]
Restricted stock and unit activity
Outstanding at the beginning of the period (in shares)	829,808
Vested (in shares)	(287,108)
Granted (in shares)	269,915	263,939	316,441
Canceled (in shares)	(3,345)
Outstanding at the end of the period (in shares)	809,270	829,808
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	$ 82.99
Vested	81.53
Granted	117.63	$ 87.12	$ 83.22
Canceled	87.14
Outstanding end of period	$ 96.41	$ 82.99
Service Based Restricted Stock [Member]
Restricted stock and unit activity
Outstanding at the beginning of the period (in shares)	998,182
Vested (in shares)	(243,313)
Granted (in shares)	208,724	207,180	170,402
Canceled (in shares)	(28,870)
Outstanding at the end of the period (in shares)	934,723	998,182
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	$ 91.37
Vested	92.37
Granted	114.61	$ 114.80	$ 136.72
Canceled	110.84
Outstanding end of period	$ 96.57	$ 91.37
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 COMPENS43

STOCK-BASED and OTHER COMPENSATION - Options, assumptions (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock and Units [Member]
Options, Restricted Stock and Unit Awards
Unrecognized compensation costs related to unvested awards (in dollars)	$ 96,000
Expected period to recognize unamortized compensation costs related to unvested awards	2 years 9 months 18 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)	$ 3,600
Expected period to recognize unamortized compensation costs related to unvested awards	2 years
Outstanding Stock Options
Outstanding balance at beginning of period (in shares)	299,229
Granted (in shares)	89,850	69,000	82,500
Exercised (in shares)	(63,727)	(141,517)	(211,258)
Canceled (in shares)	(1,997)
Forfeited (in shares)	(15,545)
Outstanding balance at end of period (in shares)	307,810	299,229
Exercisable at end of period (in shares)	159,449
Weighted Average Exercise Price
Outstanding balance at beginning of period (in dollars per share)	$ 93.76
Granted (in dollars per share)	114.07	$ 115.28	$ 139.02
Exercised (in dollars per share)	75.37
Canceled (in dollars per share)	139.02
Forfeited (in dollars per share)	123
Outstanding at end of period (in dollars per share)	101.72	$ 93.76
Exercisable at end of period (in dollars per share)	$ 86.99
Weighted Average Remaining Term
Weighted Average Remaining Term, Outstanding at end of period	4 years 7 months 6 days
Weighted Average Remaining Term, Exercisable at end of period	3 years 4 months 24 days
Aggregate Intrinsic Value
Aggregate Intrinsic Value Outstanding at end of period (in dollars)	$ 10,846
Aggregate Intrinsic Value Exercisable at the end of the period (in dollars)	$ 7,996
Grant-Date Fair value
Number of options exercised (in shares)	63,727	141,517	211,258
Cash received from option exercises	$ 4,804	$ 8,451	$ 11,898
Tax benefit from option exercises included in paid-in-capital		4,442
Intrinsic value of stock options exercised	2,994	7,467	15,384
Grant date fair value of options vested	$ 2,486	$ 2,734	$ 4,419
Granted (in dollars per share)	$ 33.38	$ 37.56	$ 41.69
Non-vested Stock Options
Non-vested at the beginning of the period (in shares)	157,041
Granted (in shares)	89,850	69,000	82,500
Vested (in shares)	(82,985)
Forfeited (in shares)	(15,545)
Non-vested at the end of the period (in shares)	148,361	157,041
Weighted Average Grant Date Fair Value - Non-Vested Stock Options
Non-vested as of January (in dollars per share)	$ 34.77
Granted (in dollars per share)	33.38	$ 37.56	$ 41.69
Vested (in dollars per share)	29.95
Forfeited (in dollars per share)	19.70
Non-vested as of December (in dollars per share)	35.58	34.77
Weighted Average Exercise Price - Non-Vested Stock Options
Non-vested at the beginning of the period (in dollars per share)	111.58
Granted (in dollars per share)	114.07
Vested (in dollars per share)	101.46
Forfeited (in dollars per share)	123
Non-vested at the end of the period (in dollars per share)	$ 117.55	$ 111.58
Assumptions used to determine the fair market value of options
Granted (in shares)	89,850	69,000	82,500
Weighted average grant-date fair value	$ 33.38	$ 37.56	$ 41.69
Weighted average exercise price	$ 114.07	$ 115.28	$ 139.02
Total fair value of options granted	$ 2,999	$ 2,592	$ 3,439
Expected years until exercise	4 years	5 years	4 years
Expected stock volatility (as a percent)	36.70%	36.60%	36.70%
Dividend yield (as a percent)	0.30%	0.60%	0.50%
Risk-free interest rate (as a percent)	0.96%	1.60%	1.80%
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 COMPENS44

STOCK-BASED and OTHER COMPENSATION - 401(k) Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock based and other compensation
Annual costs related to the plan	$ 6.7	$ 6.4	$ 11

EARNINGS (LOSS) PER SHARE (Deta

EARNINGS (LOSS) PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Basic:
Net income (loss)	$ (431,049)	$ (2,408,948)	$ 507,204
Participating securities' share in earnings (in dollars)			(9,906)
Net income (loss) applicable to common stockholders	(431,049)	(2,408,948)	497,298
Diluted:
Net income (loss)	(431,049)	(2,408,948)	507,204
Participating securities' share in earnings (in dollars)			(9,891)
Net income (loss) applicable to common stockholders	$ (431,049)	$ (2,408,948)	$ 497,313
Shares:
Basic shares outstanding	93,379	92,992	85,679
Dilutive effect of stock options			131
Fully diluted common stock (in shares)	93,379	92,992	85,810
Excluded antidilutive securities (in shares)	2,061	2,136	94
Earnings per share to common shareholders
Basic (in dollars per share)	$ (4.62)	$ (25.92)	$ 5.79
Diluted (in dollars per share)	$ (4.62)	$ (25.92)	$ 5.78

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations
Balance at beginning of year	$ 164,105	$ 173,008
Liabilities incurred	3,914	4,114
Liability settlements and disposals	(24,108)	(25,061)
Accretion expense	7,595	7,682
Revisions of estimated liabilities	3,017	4,362
Balance at end of year	164,105	173,008	$ 154,523	$ 164,105
Less current obligation			(13,753)	(10,248)
Long-term asset retirement obligation			$ 140,770	$ 153,857
Liability settlements and disposals related to properties that were sold	$ 14,900	$ 13,300

INCOME TAXES - Components of th

INCOME TAXES - Components of the Provision for income taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Taxes:
Federal (benefit)		$ 14,417
State (benefit)	$ (1,115)	293	$ 404
Current taxes (benefit)	(1,115)	14,710	404
Deferred Taxes:
Federal	(213,508)	(1,294,194)	282,729
State	(12,592)	(93,952)	15,564
Deferred income taxes	(226,100)	(1,388,146)	298,293
Total income tax expense (benefits)	$ (227,215)	$ (1,373,436)	$ 298,697

INCOME TAXES - Reconciliations

INCOME TAXES - Reconciliations of the income tax (benefit) expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliations of the income tax (benefit) expense
Provision at statutory rate	$ (230,393)	$ (1,323,834)	$ 282,066
Effect of state taxes	(10,780)	(60,634)	15,826
Revision of previous balances	7,181	5,997
Other permanent differences	5,296	5,035	805
Change in valuation allowance	1,481
Total income tax expense (benefits)	$ (227,215)	$ (1,373,436)	$ 298,697

INCOME TAXES - Components of ne

INCOME TAXES - Components of net deferred tax liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Long-term Assets:
Stock compensation and other accrued amounts	$ 58,306	$ 32,084
Net operating loss carryforward, net of valuation allowance	399,912	305,506
Credit carryforward	6,016	6,016
Net deferred tax assets, long-term	464,234	343,606
Long-term Liabilities:
Property, plant and equipment	(591,128)	(696,311)
Net deferred tax liabilities	$ (126,894)	$ (352,705)

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
U.S. net tax operating loss carryforward	$ 1,182.4
U.S. net tax operating loss carryforward recorded to equity when utilized to reduce taxes payable	90.9
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]
Net operating loss carryforward	$ 10.4
Valuation allowance against net operating losses	11.9
Net valuation allowance, deferred tax asset change in amount	1.5
Total valuation allowance on net operating losses	$ 82

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Minimum lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies
Rental expense	$ 12,900	$ 13,200	$ 14,300
Future minimum payments under leases
2,017	9,585
2,018	10,531
2,019	10,677
2,020	10,864
2,021	11,085
Later years	44,181
Total future minimum lease payments	$ 96,923

COMMITMENTS AND CONTINGENCIES52

COMMITMENTS AND CONTINGENCIES - Other Commitments (Details) $ in Millions	Dec. 31, 2016USD ($)
Drilling Commitments [Member]
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 157.5

COMMITMENTS AND CONTINGENCIES53

COMMITMENTS AND CONTINGENCIES - Other Commitments - Delivery, operating leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)Bcf
Non-cancelable operating leases
Future minimum operating lease arrangements	$ 96,923
Natural Gas Sales Contracts [Member]
Delivery Commitments
Volume of gas deliverable (in Bcf) | Bcf	46.4
Delivery term	22 months
Financial commitment upon nondelivery	$ 164,800
Gas Gathering And Processing Agreements [Member]
Delivery Commitments
Delivery term	10 years
Financial commitment upon nondelivery	$ 220,000
Minimum Volume Agreement [Member]
Delivery Commitments
Financial commitment upon nondelivery	7,900
Accrued liabilities	2,100
Other Transportation, Delivery And Facilities Commitments [Member]
Delivery Commitments
Other commitments	$ 35,700

COMMITMENTS AND CONTINGENCIES54

COMMITMENTS AND CONTINGENCIES - Litigation (Details) - Helmerich and Payne Case [Member] - USD ($) $ in Thousands	Apr. 01, 2014	Dec. 13, 2013	Dec. 31, 2008	Dec. 31, 2013
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 ($)	5 Months Ended	12 Months Ended
	May 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Sheridan Production Parnters [Member]
Related Party Transactions
Revenues from related party		$ 400	$ 4,100
Payments to related party		177,600	224,200
Payments from related parties for joint interest billings		73,100	81,500
Certain Affiliates Of Sheridan Production Partners [Member]
Related Party Transactions
Payments to related party		5,200	10,400
Helmerich and Payne, Inc [Member]
Related Party Transactions
Contract drilling services costs		$ 18,300,000	$ 7,900,000	$ 18,400,000
Subsidiary of Newpark Resources, Inc [Member]
Related Party Transactions
Contract drilling services costs	$ 589,200

PROPERTY SALES AND ACQUISITIO56

PROPERTY SALES AND ACQUISITIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property Sales
Acquisition of interest in oil and gas properties			$ 249,700
Sales of other assets	$ 7,889	$ 1,178	8,413
Non Core Oil and Gas Properties [Member]
Property Sales
Sale of interests in oil and gas properties			$ 446,100

SUPPLEMENTAL DISCLOSURE OF CA57

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash paid during the period for:
Interest expense (including capitalized amounts)	$ 79,590	$ 80,785	$ 66,167
Interest capitalized	20,308	28,819	32,623
Income taxes	13	558	354
Cash received for income taxes	$ 1,450	$ 1,503	$ 460