Cimarex Energy (CIMXP) 10-Q 8 Nov 17 2017 Q3 Quarterly report Financial data

DOCUMENT AND ENTITY INFORMATION

DOCUMENT AND ENTITY INFORMATION - shares	9 Months Ended
	Sep. 30, 2017	Oct. 31, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	CIMAREX ENERGY CO
Entity Central Index Key	1,168,054
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus (i.e. Q1,Q2,Q3,FY)	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		95,260,901

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 422,808	$ 652,876
Accounts receivable, net of allowance:
Trade	101,927	42,287
Oil and gas sales	286,602	217,395
Gas gathering, processing, and marketing	14,656	14,888
Oil and gas well equipment and supplies	54,545	33,342
Derivative instruments	6,924	0
Prepaid expenses	3,913	7,335
Other current assets	2,757	1,181
Total current assets	894,132	969,304
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	17,071,532	16,225,495
Unproved properties and properties under development, not being amortized	572,651	478,277
Gross oil and gas properties	17,644,183	16,703,772
Less—accumulated depreciation, depletion, amortization, and impairment	(14,629,884)	(14,349,505)
Net oil and gas properties	3,014,299	2,354,267
Fixed assets, net of accumulated depreciation of $278,991 and $246,901, respectively	208,320	205,465
Goodwill	620,232	620,232
Derivative instruments	129	0
Deferred income taxes	0	55,835
Other assets	31,942	32,621
Total assets	4,769,054	4,237,724
Accounts payable:
Trade	61,634	49,163
Gas gathering, processing, and marketing	27,254	25,323
Accrued liabilities:
Exploration and development	105,663	82,320
Taxes other than income	22,651	18,766
Other	215,067	177,695
Derivative instruments	5,778	49,370
Revenue payable	154,578	119,715
Total current liabilities	592,625	522,352
Long-term debt:
Principal	1,500,000	1,500,000
Less—unamortized debt issuance costs and discount	(13,491)	(12,061)
Long-term debt, net	1,486,509	1,487,939
Deferred income taxes	99,695	0
Asset retirement obligation	144,635	140,770
Derivative instruments	212	2,570
Other liabilities	43,315	41,104
Total liabilities	2,366,991	2,194,735
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued	0	0
Common stock, $0.01 par value, 200,000,000 shares authorized, 95,260,701 and 95,123,525 shares issued, respectively	953	951
Additional paid-in capital	2,773,260	2,763,452
Retained earnings (accumulated deficit)	(373,955)	(722,359)
Accumulated other comprehensive income	1,805	945
Total stockholders’ equity	2,402,063	2,042,989
Total liabilities and stockholders' equity	$ 4,769,054	$ 4,237,724

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Fixed assets, accumulated depreciation	$ 278,991	$ 246,901
Preferred stock, par value (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 (dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	95,260,701	95,123,525

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues:
Oil sales	$ 231,441	$ 166,079	$ 687,960	$ 445,657
Gas sales	125,707	109,278	390,126	268,501
NGL sales	95,191	50,464	256,503	135,755
Gas gathering and other	11,056	9,824	32,416	25,276
Gas marketing, net of related costs of $41,978, $32,266, $120,715, and $84,013, respectively	286	72	304	1
Total revenues	463,681	335,717	1,367,309	875,190
Costs and expenses:
Impairment of oil and gas properties	0	105,593	0	757,670
Depreciation, depletion, and amortization	111,396	90,277	315,096	302,999
Asset retirement obligation	1,497	2,033	4,077	6,081
Production	65,410	52,976	190,409	180,891
Transportation, processing, and other operating	58,387	48,706	172,034	139,585
Gas gathering and other	8,856	7,905	25,930	23,477
Taxes other than income	24,314	15,974	63,104	43,879
General and administrative	21,039	20,118	58,835	55,439
Stock compensation	7,038	5,764	19,619	18,782
(Gain) loss on derivative instruments, net	16,109	(9,758)	(50,261)	23,050
Other operating expense, net	95	179	977	293
Total costs and expenses	314,141	339,767	799,820	1,552,146
Operating income (loss)	149,540	(4,050)	567,489	(676,956)
Other (income) and expense:
Interest expense	16,838	20,931	57,985	62,560
Capitalized interest	(5,373)	(5,421)	(17,456)	(15,958)
Loss on early extinguishment of debt	0	0	28,169	0
Other, net	(4,563)	(3,828)	(9,004)	(7,489)
Income (loss) before income tax	142,638	(15,732)	507,795	(716,069)
Income tax expense (benefit)	51,239	(5,059)	188,162	(259,483)
Net income (loss)	$ 91,399	$ (10,673)	$ 319,633	$ (456,586)
Earnings (loss) per share to common stockholders:
Basic (in dollars per share)	$ 0.96	$ (0.12)	$ 3.36	$ (4.90)
Diluted (in dollars per share)	0.96	(0.12)	3.36	(4.90)
Dividends declared (in dollars per share)	$ 0.08	$ 0.08	$ 0.24	$ 0.24
Comprehensive income (loss):
Net income (loss)	$ 91,399	$ (10,673)	$ 319,633	$ (456,586)
Other comprehensive income:
Change in fair value of investments, net of tax of $134, $165, $494, and $325, respectively	234	287	860	567
Total comprehensive income (loss)	$ 91,633	$ (10,386)	$ 320,493	$ (456,019)

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement [Abstract]
Gas marketing, related costs	$ 41,978	$ 32,266	$ 120,715	$ 84,013
Change in fair value investments, tax	$ 134	$ 165	$ 494	$ 325

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net income (loss)	$ 319,633	$ (456,586)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairment of oil and gas properties	0	757,670
Depreciation, depletion, and amortization	315,096	302,999
Asset retirement obligation	4,077	6,081
Deferred income taxes	188,168	(258,368)
Stock compensation	19,619	18,782
(Gain) loss on derivative instruments, net	(50,261)	23,050
Settlements on derivative instruments	(2,742)	9,718
Loss on early extinguishment of debt	28,169	0
Changes in non-current assets and liabilities	2,144	4,121
Other, net	4,630	2,931
Changes in operating assets and liabilities:
Receivables	(128,921)	(1,723)
Other current assets	(19,372)	23,034
Accounts payable and other current liabilities	75,565	9,079
Net cash provided by operating activities	755,805	440,788
Cash flows from investing activities:
Oil and gas capital expenditures	(901,949)	(485,114)
Sales of oil and gas assets	8,136	19,013
Sales of other assets	510	5,718
Other capital expenditures	(31,332)	(24,013)
Net cash used by investing activities	(924,635)	(484,396)
Cash flows from financing activities:
Borrowings of long-term debt	748,110	0
Repayments of long-term debt	(750,000)	0
Call premium, financing, and underwriting fees	(29,194)	(1)
Dividends paid	(22,743)	(30,243)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards	(7,637)	(11,457)
Proceeds from exercise of stock options	226	4,623
Net cash used by financing activities	(61,238)	(37,078)
Net decrease in cash and cash equivalents	(230,068)	(80,686)
Cash and cash equivalents at beginning of period	652,876	779,382
Cash and cash equivalents at end of period	$ 422,808	$ 698,696

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED) - 9 months ended Sep. 30, 2017 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income
Balance at beginning of period, shares at Dec. 31, 2016		95,124
Balance at beginning of period at Dec. 31, 2016	$ 2,042,989	$ 951	$ 2,763,452	$ (722,359)	$ 945
Increase (Decrease) in Stockholders' Equity
Dividends paid on stock awards subsequently forfeited	42		10	32
Dividends in excess of retained earnings	(22,854)		(22,854)
Net income	319,633			319,633
Unrealized change in fair value of investments, net of tax	860				860
Issuance of restricted stock awards, shares		250
Issuance of restricted stock awards		$ 3	(3)
Common stock reacquired and retired, shares		(78)
Common stock reacquired and retired	(7,637)	$ (1)	(7,636)
Restricted stock forfeited and retired, shares		(39)
Exercise of stock options, shares		4
Exercise of stock options	226		226
Stock-based compensation	35,698		35,698
Other	(26)		(26)
Balance at end of period, shares at Sep. 30, 2017		95,261
Balance at end of period at Sep. 30, 2017	2,402,063	$ 953	2,773,260	(373,955)	$ 1,805
Increase (Decrease) in Stockholders' Equity
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6)	$ 33,132		$ 4,393	$ 28,739

BASIS OF PRESENTATION

BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BASIS OF PRESENTATION	BASIS OF PRESENTATION The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the “Explanatory Note”, financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K/A for the year ended December 31, 2016 . In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. Certain amounts in the prior year financial statements have been reclassified to conform to the 2017 financial statement presentation. Use of Estimates Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies. Oil and Gas Well Equipment and Supplies Our oil and gas well equipment and supplies are valued at the lower of cost and 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 have not recorded an impairment to our oil and gas well equipment and supplies during the nine months ended September 30, 2017 . Declines in the price of oil and gas well equipment and supplies 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. Accounting rules require us to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures. At each quarter-end date during the nine months ended September 30, 2017 , the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognized a ceiling test impairment during the nine months ended September 30, 2017 . During the three and nine months ended September 30, 2016 , we recognized ceiling test impairments of $105.6 million ( $67.1 million , net of tax) and $757.7 million ( $481.4 million , net of tax), respectively. These impairments resulted primarily from decreases in the trailing twelve-month average prices for oil, natural gas, and NGLs utilized in determining the future net revenues from proved reserves. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. The calculated ceiling limitation 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 various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-9, Revenue from Contracts with Customers (Topic 606) , which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. 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 adopt the standard using either the full retrospective approach or a modified retrospective approach. We intend to adopt the standard utilizing a modified retrospective approach. Management does not expect the new standard will have a material impact on net income (loss) or cash flows from operations; however, we continue to evaluate the “gross versus net” presentation of certain revenues and associated expenses in the consolidated statements of operations and comprehensive income. Any such presentation changes would have no impact on operating income or net income (loss). We are currently developing accounting policies, business processes, and control activities that we expect to implement in connection with the new standard. In February 2016, the FASB issued ASU 2016-2, 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 generally accepted accounting principles (“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. We are in the process of evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases. We do not intend to adopt the standard early.

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2017
Long-term Debt, Unclassified [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt at September 30, 2017 and December 31, 2016 consisted of the following: September 30, 2017 December 31, 2016 (in thousands) Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net Principal Unamortized Debt Issuance Costs Long-term Debt, net 5.875% Senior Notes $ — $ — $ — $ 750,000 $ (5,691 ) $ 744,309 4.375% Senior Notes 750,000 (5,626 ) 744,374 750,000 (6,370 ) 743,630 3.90% Senior Notes 750,000 (7,865 ) 742,135 — — — Total long-term debt $ 1,500,000 $ (13,491 ) $ 1,486,509 $ 1,500,000 $ (12,061 ) $ 1,487,939 (1) At September 30, 2017 , the unamortized debt issuance costs and discount related to the 3.90% notes were $6.0 million and $1.8 million , respectively. The 4.375% notes were issued at par. Bank Debt We have a senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has aggregate commitments of $1.0 billion , with an option for us 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 September 30, 2017 , we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, 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 September 30, 2017 , we were in compliance with all of the financial covenants. At September 30, 2017 and December 31, 2016 , we had $3.6 million and $4.5 million , respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in Other assets on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility. Senior Notes On April 10, 2017, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5 million aggregate principal amount of the notes validly tendered. We settled these tendered notes for $268.1 million , including accrued interest. On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million , including accrued interest. During the three months ended June 30, 2017, we recognized a loss on early extinguishment of debt related to these transactions of $28.2 million , composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs. The original maturity date of the 5.875% notes was May 1, 2022. On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum. We received $741.8 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of 3.90% and interest is payable semiannually on May 15 and November 15, with the first payment to be made November 15, 2017. Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed 5.875% notes. In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1. Each of our senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of September 30, 2017 . The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization of debt issuance costs and discount, as applicable, is 4.50% and 4.01% , respectively.

DERIVATIVE INSTRUMENTS

DERIVATIVE INSTRUMENTS	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedges, Assets [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS We periodically use derivative instruments to mitigate volatility in commodity prices. 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. We may enter into derivative instruments with durations of five to six quarters covering up to 50% of our oil and natural gas production on a forward eight quarter basis. 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 derivative positions. As of September 30, 2017 , we have entered into collars and basis swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI Midland price and the WTI NYMEX (Cushing Oklahoma) price. For our Permian and Mid-Continent gas production, the contract prices in the PEPL and Perm EP collars are consistent with the index prices used to sell our production. The following tables summarize our outstanding derivative contracts as of September 30, 2017 : First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) — — — 1,932,000 1,932,000 Weighted Avg Price - Floor $ — $ — $ — $ 46.29 $ 46.29 Weighted Avg Price - Ceiling $ — $ — $ — $ 56.64 $ 56.64 2018: WTI (1) Volume (Bbls) 1,980,000 1,456,000 1,104,000 552,000 5,092,000 Weighted Avg Price - Floor $ 47.05 $ 46.94 $ 45.92 $ 48.00 $ 46.87 Weighted Avg Price - Ceiling $ 56.41 $ 55.40 $ 54.21 $ 53.95 $ 55.38 (1) The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”). First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: PEPL (1) Volume (MMBtu) — — — 11,040,000 11,040,000 Weighted Avg Price - Floor $ — $ — $ — $ 2.65 $ 2.65 Weighted Avg Price - Ceiling $ — $ — $ — $ 3.07 $ 3.07 Perm EP (2) Volume (MMBtu) — — — 7,360,000 7,360,000 Weighted Avg Price - Floor $ — $ — $ — $ 2.64 $ 2.64 Weighted Avg Price - Ceiling $ — $ — $ — $ 3.04 $ 3.04 2018: PEPL (1) Volume (MMBtu) 9,000,000 6,370,000 3,680,000 920,000 19,970,000 Weighted Avg Price - Floor $ 2.62 $ 2.50 $ 2.45 $ 2.50 $ 2.54 Weighted Avg Price - Ceiling $ 3.00 $ 2.87 $ 2.67 $ 2.65 $ 2.88 Perm EP (2) Volume (MMBtu) 6,300,000 4,550,000 2,760,000 920,000 14,530,000 Weighted Avg Price - Floor $ 2.59 $ 2.42 $ 2.37 $ 2.40 $ 2.48 Weighted Avg Price - Ceiling $ 2.94 $ 2.75 $ 2.56 $ 2.58 $ 2.78 (1) The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC. (2) The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC. First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Basis Swaps: 2017: WTI Midland (1) Volume (Bbls) — — — 460,000 460,000 Weighted Avg Differential (2) $ — $ — $ — $ 0.94 $ 0.94 2018: WTI Midland (1) Volume (Bbls) 720,000 728,000 736,000 276,000 2,460,000 Weighted Avg Differential (2) $ 0.87 $ 0.87 $ 0.87 $ 0.76 $ 0.86 (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI NYMEX less the weighted average differential shown in the table. The following tables summarize our derivative contracts entered into subsequent to September 30, 2017 : First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2018: WTI (1) Volume (Bbls) 540,000 546,000 552,000 552,000 2,190,000 Weighted Avg Price - Floor $ 48.00 $ 48.00 $ 48.00 $ 48.00 $ 48.00 Weighted Avg Price - Ceiling $ 55.21 $ 55.21 $ 55.21 $ 55.21 $ 55.21 2019: WTI (1) Volume (Bbls) 540,000 546,000 — — 1,086,000 Weighted Avg Price - Floor $ 48.00 $ 48.00 $ — $ — $ 48.00 Weighted Avg Price - Ceiling $ 55.21 $ 55.21 $ — $ — $ 55.21 (1) The index price for these collars is WTI NYMEX. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2018: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 1,840,000 7,300,000 Weighted Avg Price - Floor $ 2.40 $ 2.40 $ 2.40 $ 2.40 $ 2.40 Weighted Avg Price - Ceiling $ 2.64 $ 2.64 $ 2.64 $ 2.64 $ 2.64 Perm EP (2) Volume (MMBtu) 900,000 910,000 920,000 920,000 3,650,000 Weighted Avg Price - Floor $ 2.30 $ 2.30 $ 2.30 $ 2.30 $ 2.30 Weighted Avg Price - Ceiling $ 2.42 $ 2.42 $ 2.42 $ 2.42 $ 2.42 2019: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 — — 3,620,000 Weighted Avg Price - Floor $ 2.40 $ 2.40 $ — $ — $ 2.40 Weighted Avg Price - Ceiling $ 2.64 $ 2.64 $ — $ — $ 2.64 Perm EP (2) Volume (MMBtu) 900,000 910,000 — — 1,810,000 Weighted Avg Price - Floor $ 2.30 $ 2.30 $ — $ — $ 2.30 Weighted Avg Price - Ceiling $ 2.42 $ 2.42 $ — $ — $ 2.42 (1) The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC. (2) The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC. First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Basis Swaps: 2018: WTI Midland (1) Volume (Bbls) 450,000 455,000 460,000 460,000 1,825,000 Weighted Avg Differential (2) $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.47 2019: WTI Midland (1) Volume (Bbls) 450,000 455,000 — — 905,000 Weighted Avg Differential (2) $ 0.47 $ 0.47 $ — $ — $ 0.47 (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI NYMEX less the weighted average differential shown in the table. Derivative Gains and Losses Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated. Three Months Ended Nine Months Ended (Gain) Loss on Derivative Instruments, Net (in thousands): 2017 2016 2017 2016 Change in fair value of derivative instruments, net $ 19,085 $ (8,967 ) $ (53,003 ) $ 32,768 Cash (receipts) payments on derivative instruments, net (2,976 ) (791 ) 2,742 (9,718 ) (Gain) loss on derivative instruments, net $ 16,109 $ (9,758 ) $ (50,261 ) $ 23,050 Derivative Fair Value 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 accounting policy is to not offset asset and liability positions in our balance sheets. The following tables present the amounts and classifications of our derivative assets and liabilities as of September 30, 2017 and December 31, 2016 , as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. September 30, 2017: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 2,288 $ — Gas contracts Current assets — Derivative instruments 4,636 — Oil contracts Non-current assets — Derivative instruments 110 — Gas contracts Non-current assets — Derivative instruments 19 — Oil contracts Current liabilities — Derivative instruments — 4,919 Gas contracts Current liabilities — Derivative instruments — 859 Oil contracts Non-current liabilities — Derivative instruments — 210 Gas contracts Non-current liabilities — Derivative instruments — 2 Total gross amounts presented in the balance sheet 7,053 5,990 Less: gross amounts not offset in the balance sheet (4,540 ) (4,540 ) Net amount $ 2,513 $ 1,450 December 31, 2016: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current liabilities — Derivative instruments $ — $ 27,892 Gas contracts Current liabilities — Derivative instruments — 21,478 Oil contracts Non-current liabilities — Derivative instruments — 1,059 Gas contracts Non-current liabilities — Derivative instruments — 1,511 Total gross amounts presented in the balance sheet — 51,940 Less: gross amounts not offset in the balance sheet — — Net amount $ — $ 51,940 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 derivative liability positions. Because some of the member banks have discontinued derivative activities, in the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability. The following table provides fair value measurement information for certain assets and liabilities as of September 30, 2017 and December 31, 2016 : September 30, 2017 December 31, 2016 Book Fair Book Fair (in thousands) Value Value Value Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ — $ — $ (750,000 ) $ (782,835 ) 4.375% Notes due 2024 $ (750,000 ) $ (794,663 ) $ (750,000 ) $ (779,453 ) 3.90% Notes due 2027 $ (750,000 ) $ (764,408 ) $ — $ — Derivative instruments — assets $ 7,053 $ 7,053 $ — $ — Derivative instruments — liabilities $ (5,990 ) $ (5,990 ) $ (51,940 ) $ (51,940 ) 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 fair value (Level 1) of our fixed rate notes was based on their last traded value before period end. The fair value of our derivative instruments (Level 2) 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 3 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 September 30, 2017 are: (i) accrued operating expenses of approximately $59.1 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $36.2 million . Included in “Accrued liabilities — other” at December 31, 2016 are: (i) accrued operating expenses of approximately $53.9 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $43.5 million . Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. 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 September 30, 2017 and December 31, 2016 , the allowance for doubtful accounts was $1.9 million and $1.6 million , respectively.

CAPITAL STOCK

CAPITAL STOCK	9 Months Ended
	Sep. 30, 2017
Stockholders' Equity Note [Abstract]
CAPITAL STOCK	CAPITAL STOCK Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At September 30, 2017 , there were 95.3 million shares of common stock and no shares of preferred stock outstanding. Dividends In August 2017 , our Board of Directors declared a cash dividend of $0.08 per share. The dividend is payable on or before December 1, 2017 , to stockholders of record on November 15, 2017 . 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. The $22.9 million in dividends declared year-to-date September 30, 2017 were recorded as a reduction of additional paid-in capital. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to compensation expense in the period in which the forfeitures occur. Future dividend payments will depend on our level of earnings, financing requirements, and other factors considered relevant by our Board of Directors.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	9 Months Ended
	Sep. 30, 2017
Compensation and Retirement Disclosure [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION We have recognized stock-based compensation cost as shown below for the periods indicated. Three Months Ended Nine Months Ended (in thousands) 2017 2016 2017 2016 Restricted stock awards: Performance stock awards $ 6,508 $ 5,465 $ 19,348 $ 18,374 Service-based stock awards 5,317 4,624 14,449 13,540 11,825 10,089 33,797 31,914 Stock option awards 698 571 1,943 1,974 Total stock compensation cost 12,523 10,660 35,740 33,888 Less amounts capitalized to oil and gas properties (5,485 ) (4,896 ) (16,121 ) (15,106 ) Compensation expense $ 7,038 $ 5,764 $ 19,619 $ 18,782 Periodic stock compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. The increase in total stock compensation cost in the 2017 periods as compared to the 2016 periods is primarily due to awards granted either during or subsequent to the 2016 periods. These increases were partially offset by the following decreases: (i) awards vesting prior to or during the 2017 periods, (ii) reversals of previously recognized expense on 2017 forfeitures, and (iii) expense associated with the voluntary Early Retirement Incentive Program during the 2016 periods . We adopted Accounting Standards Update 2016-9, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-9”) on January 1, 2017. ASU 2016-9 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows. Pursuant to ASU 2016-9, we made an accounting policy election to account for forfeitures in compensation cost when they occur, rather than including an estimate of the number of awards that are expected to vest in our compensation cost. The amendments within ASU 2016-9 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million , reduced beginning accumulated deficit by $28.7 million , and increased beginning additional paid-in capital by $4.4 million . The amendments within ASU 2016-9 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method. In accordance with this method, we adjusted the statement of cash flows for the nine months ended September 30, 2016 by increasing net cash provided by operating activities by $11.5 million and increasing net cash used by financing activities by $11.5 million for the payment of tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the nine months ended September 30, 2017 and 2016 .

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation [Abstract]
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 plugging and abandonment of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is accreted each period. If there is a change in the estimated cost or timing of retirement, 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 depreciation and depletion calculations. The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the nine months ended September 30, 2017 : (in thousands) Asset retirement obligation at January 1, 2017 $ 154,523 Liabilities incurred 5,730 Liability settlements and disposals (10,287 ) Accretion expense 5,637 Revisions of estimated liabilities 1,644 Asset retirement obligation at September 30, 2017 157,247 Less current obligation (12,612 ) Long-term asset retirement obligation $ 144,635

EARNINGS (LOSS) PER SHARE

EARNINGS (LOSS) PER SHARE	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
EARNINGS (LOSS) PER SHARE	EARNINGS (LOSS) PER SHARE The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below: Three Months Ended Nine Months Ended (in thousands, except per share data) 2017 2016 2017 2016 Basic: Net income (loss) $ 91,399 $ (10,673 ) $ 319,633 $ (456,586 ) Participating securities’ share in earnings (1) (1,572 ) — (5,478 ) — Net income (loss) available to common stockholders $ 89,827 $ (10,673 ) $ 314,155 $ (456,586 ) Diluted: Net income (loss) $ 91,399 $ (10,673 ) $ 319,633 $ (456,586 ) Participating securities’ share in earnings (1) (1,572 ) — (5,476 ) — Net income (loss) available to common stockholders $ 89,827 $ (10,673 ) $ 314,157 $ (456,586 ) Shares: Basic shares outstanding 93,501 93,221 93,431 93,221 Dilutive effect of potential common shares (2) 30 — 34 — Fully diluted common stock 93,531 93,221 93,465 93,221 Earnings (loss) per share to common stockholders (3): Basic $ 0.96 $ (0.12 ) $ 3.36 $ (4.90 ) Diluted $ 0.96 $ (0.12 ) $ 3.36 $ (4.90 ) (1) Participating securities are not included in undistributed earnings when a loss exists. (2) Inclusion of certain shares would have an anti-dilutive effect; therefore, 298.7 thousand and 302.9 thousand shares were excluded from the calculations for the three and nine months ended September 30, 2017 and 2.1 million and 2.1 million shares were excluded from the calculations for the three and nine months ended September 30, 2016 . (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The components of our provision for income taxes are as follows: Three Months Ended Nine Months Ended Income Tax Expense (Benefit) (in thousands): 2017 2016 2017 2016 Current tax benefit $ — $ (1,115 ) $ (6 ) $ (1,115 ) Deferred tax expense (benefit) 51,239 (3,944 ) 188,168 (258,368 ) $ 51,239 $ (5,059 ) $ 188,162 $ (259,483 ) Combined federal and state effective income tax rate 35.9 % 32.2 % 37.1 % 36.2 % At December 31, 2016 , we had a U.S. net tax operating loss carryforward of approximately $1,182.4 million , which will expire in tax years 2031 through 2036. We believe that the carryforward will be utilized before it expires. We also had an alternative minimum tax credit carryforward of approximately $6.0 million . At September 30, 2017 , we had no unrecognized tax benefits that would impact our effective tax rate and have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2014 through 2016 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 2013 through 2016. Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 35% primarily due to state income taxes and non-deductible expenses.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Commitments At September 30, 2017 , we had estimated commitments of approximately: (i) $181.2 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $24.6 million to finish gathering system construction in progress. At September 30, 2017 , we had firm sales contracts to deliver approximately 207.2 Bcf of natural gas over the next 7.3 years . If we do not deliver this gas, our estimated financial commitment, calculated using the October 2017 index price, would be approximately $491.0 million . The value of 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 volumetric obligations. In connection with gas gathering and processing agreements, we have volume commitments over the next 8.6 years . If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2017 , would be approximately $312.3 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 volumetric obligations. We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of September 30, 2017 , would be approximately $13.7 million . Of this total, we have accrued a liability of $1.9 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. At September 30, 2017 , we have various firm transportation agreements for pipeline capacity with end dates ranging from 2017 - 2025 under which we will have to pay an estimated $37.6 million over the remaining terms of the agreements. These agreements were entered into to support our residue marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation. We have various future commitments for office space under operating lease arrangements totaling approximately $89.6 million at September 30, 2017 . All of the noted commitments were routine and made in the ordinary course of our business. Litigation We have various litigation matters related to the ordinary course of our business. We assess the probability of estimable amounts related to these matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, we believe the resolution of them, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.

SUPPLEMENTAL DISCLOSURE OF CASH

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Three Months Ended Nine Months Ended (in thousands) 2017 2016 2017 2016 Cash paid for: Interest expense (net of capitalized amounts of $477, $286, $12,439, and $10,343, respectively) $ 109 $ 527 $ 28,881 $ 30,204 Income taxes $ — $ — $ 3 $ 13 Cash income tax refunds received $ — $ 1,115 $ 21 $ 1,140

BASIS OF PRESENTATION (Policies

BASIS OF PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of presentation	BASIS OF PRESENTATION The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the “Explanatory Note”, financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K/A for the year ended December 31, 2016 . In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. Certain amounts in the prior year financial statements have been reclassified to conform to the 2017 financial statement presentation.
Use of Estimates	Use of Estimates Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies.
Oil and Gas Properties	Oil and Gas Properties We use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures. At each quarter-end date during the nine months ended September 30, 2017 , the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognized a ceiling test impairment during the nine months ended September 30, 2017 . During the three and nine months ended September 30, 2016 , we recognized ceiling test impairments of $105.6 million ( $67.1 million , net of tax) and $757.7 million ( $481.4 million , net of tax), respectively. These impairments resulted primarily from decreases in the trailing twelve-month average prices for oil, natural gas, and NGLs utilized in determining the future net revenues from proved reserves. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. The calculated ceiling limitation 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 various components of our balance sheet. Any impairment of oil and gas properties is not reversible at a later date. Oil and Gas Well Equipment and Supplies Our oil and gas well equipment and supplies are valued at the lower of cost and 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 have not recorded an impairment to our oil and gas well equipment and supplies during the nine months ended September 30, 2017 . Declines in the price of oil and gas well equipment and supplies 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.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-9, Revenue from Contracts with Customers (Topic 606) , which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. 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 adopt the standard using either the full retrospective approach or a modified retrospective approach. We intend to adopt the standard utilizing a modified retrospective approach. Management does not expect the new standard will have a material impact on net income (loss) or cash flows from operations; however, we continue to evaluate the “gross versus net” presentation of certain revenues and associated expenses in the consolidated statements of operations and comprehensive income. Any such presentation changes would have no impact on operating income or net income (loss). We are currently developing accounting policies, business processes, and control activities that we expect to implement in connection with the new standard. In February 2016, the FASB issued ASU 2016-2, 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 generally accepted accounting principles (“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. We are in the process of evaluating the potential impact of adopting this guidance, but believe the primary effect will be to record assets and liabilities for contracts currently accounted for as operating leases. We do not intend to adopt the standard early.

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	9 Months Ended
	Sep. 30, 2017
Long-term Debt, Unclassified [Abstract]
Summary of debt	Long-term debt at September 30, 2017 and December 31, 2016 consisted of the following: September 30, 2017 December 31, 2016 (in thousands) Principal Unamortized Debt Issuance Costs and Discount (1) Long-term Debt, net Principal Unamortized Debt Issuance Costs Long-term Debt, net 5.875% Senior Notes $ — $ — $ — $ 750,000 $ (5,691 ) $ 744,309 4.375% Senior Notes 750,000 (5,626 ) 744,374 750,000 (6,370 ) 743,630 3.90% Senior Notes 750,000 (7,865 ) 742,135 — — — Total long-term debt $ 1,500,000 $ (13,491 ) $ 1,486,509 $ 1,500,000 $ (12,061 ) $ 1,487,939 (1) At September 30, 2017 , the unamortized debt issuance costs and discount related to the 3.90% notes were $6.0 million and $1.8 million , respectively. The 4.375% notes were issued at par.

DERIVATIVE INSTRUMENTS (Tables)

DERIVATIVE INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedges, Assets [Abstract]
Schedule of outstanding hedging contracts relative to future production	The following tables summarize our outstanding derivative contracts as of September 30, 2017 : First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) — — — 1,932,000 1,932,000 Weighted Avg Price - Floor $ — $ — $ — $ 46.29 $ 46.29 Weighted Avg Price - Ceiling $ — $ — $ — $ 56.64 $ 56.64 2018: WTI (1) Volume (Bbls) 1,980,000 1,456,000 1,104,000 552,000 5,092,000 Weighted Avg Price - Floor $ 47.05 $ 46.94 $ 45.92 $ 48.00 $ 46.87 Weighted Avg Price - Ceiling $ 56.41 $ 55.40 $ 54.21 $ 53.95 $ 55.38 (1) The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”). First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: PEPL (1) Volume (MMBtu) — — — 11,040,000 11,040,000 Weighted Avg Price - Floor $ — $ — $ — $ 2.65 $ 2.65 Weighted Avg Price - Ceiling $ — $ — $ — $ 3.07 $ 3.07 Perm EP (2) Volume (MMBtu) — — — 7,360,000 7,360,000 Weighted Avg Price - Floor $ — $ — $ — $ 2.64 $ 2.64 Weighted Avg Price - Ceiling $ — $ — $ — $ 3.04 $ 3.04 2018: PEPL (1) Volume (MMBtu) 9,000,000 6,370,000 3,680,000 920,000 19,970,000 Weighted Avg Price - Floor $ 2.62 $ 2.50 $ 2.45 $ 2.50 $ 2.54 Weighted Avg Price - Ceiling $ 3.00 $ 2.87 $ 2.67 $ 2.65 $ 2.88 Perm EP (2) Volume (MMBtu) 6,300,000 4,550,000 2,760,000 920,000 14,530,000 Weighted Avg Price - Floor $ 2.59 $ 2.42 $ 2.37 $ 2.40 $ 2.48 Weighted Avg Price - Ceiling $ 2.94 $ 2.75 $ 2.56 $ 2.58 $ 2.78 (1) The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC. (2) The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC. First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Basis Swaps: 2017: WTI Midland (1) Volume (Bbls) — — — 460,000 460,000 Weighted Avg Differential (2) $ — $ — $ — $ 0.94 $ 0.94 2018: WTI Midland (1) Volume (Bbls) 720,000 728,000 736,000 276,000 2,460,000 Weighted Avg Differential (2) $ 0.87 $ 0.87 $ 0.87 $ 0.76 $ 0.86 (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI NYMEX less the weighted average differential shown in the table.
Schedule of derivative contract entered into subsequent to balance sheet date	The following tables summarize our derivative contracts entered into subsequent to September 30, 2017 : First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2018: WTI (1) Volume (Bbls) 540,000 546,000 552,000 552,000 2,190,000 Weighted Avg Price - Floor $ 48.00 $ 48.00 $ 48.00 $ 48.00 $ 48.00 Weighted Avg Price - Ceiling $ 55.21 $ 55.21 $ 55.21 $ 55.21 $ 55.21 2019: WTI (1) Volume (Bbls) 540,000 546,000 — — 1,086,000 Weighted Avg Price - Floor $ 48.00 $ 48.00 $ — $ — $ 48.00 Weighted Avg Price - Ceiling $ 55.21 $ 55.21 $ — $ — $ 55.21 (1) The index price for these collars is WTI NYMEX. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2018: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 1,840,000 7,300,000 Weighted Avg Price - Floor $ 2.40 $ 2.40 $ 2.40 $ 2.40 $ 2.40 Weighted Avg Price - Ceiling $ 2.64 $ 2.64 $ 2.64 $ 2.64 $ 2.64 Perm EP (2) Volume (MMBtu) 900,000 910,000 920,000 920,000 3,650,000 Weighted Avg Price - Floor $ 2.30 $ 2.30 $ 2.30 $ 2.30 $ 2.30 Weighted Avg Price - Ceiling $ 2.42 $ 2.42 $ 2.42 $ 2.42 $ 2.42 2019: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 — — 3,620,000 Weighted Avg Price - Floor $ 2.40 $ 2.40 $ — $ — $ 2.40 Weighted Avg Price - Ceiling $ 2.64 $ 2.64 $ — $ — $ 2.64 Perm EP (2) Volume (MMBtu) 900,000 910,000 — — 1,810,000 Weighted Avg Price - Floor $ 2.30 $ 2.30 $ — $ — $ 2.30 Weighted Avg Price - Ceiling $ 2.42 $ 2.42 $ — $ — $ 2.42 (1) The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC. (2) The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC. First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Basis Swaps: 2018: WTI Midland (1) Volume (Bbls) 450,000 455,000 460,000 460,000 1,825,000 Weighted Avg Differential (2) $ 0.47 $ 0.47 $ 0.47 $ 0.47 $ 0.47 2019: WTI Midland (1) Volume (Bbls) 450,000 455,000 — — 905,000 Weighted Avg Differential (2) $ 0.47 $ 0.47 $ — $ — $ 0.47 (1) The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude. (2) The index price we receive under these basis swaps is WTI NYMEX less the weighted average differential shown in the table.
Schedule of net (gains) and losses from settlements and changes of derivative contracts	The following table presents the components of (Gain) loss on derivative instruments, net for the periods indicated. Three Months Ended Nine Months Ended (Gain) Loss on Derivative Instruments, Net (in thousands): 2017 2016 2017 2016 Change in fair value of derivative instruments, net $ 19,085 $ (8,967 ) $ (53,003 ) $ 32,768 Cash (receipts) payments on derivative instruments, net (2,976 ) (791 ) 2,742 (9,718 ) (Gain) loss on derivative instruments, net $ 16,109 $ (9,758 ) $ (50,261 ) $ 23,050
Schedule of amounts and classifications of entity's derivative assets and liabilities	The following tables present the amounts and classifications of our derivative assets and liabilities as of September 30, 2017 and December 31, 2016 , as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. September 30, 2017: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 2,288 $ — Gas contracts Current assets — Derivative instruments 4,636 — Oil contracts Non-current assets — Derivative instruments 110 — Gas contracts Non-current assets — Derivative instruments 19 — Oil contracts Current liabilities — Derivative instruments — 4,919 Gas contracts Current liabilities — Derivative instruments — 859 Oil contracts Non-current liabilities — Derivative instruments — 210 Gas contracts Non-current liabilities — Derivative instruments — 2 Total gross amounts presented in the balance sheet 7,053 5,990 Less: gross amounts not offset in the balance sheet (4,540 ) (4,540 ) Net amount $ 2,513 $ 1,450 December 31, 2016: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current liabilities — Derivative instruments $ — $ 27,892 Gas contracts Current liabilities — Derivative instruments — 21,478 Oil contracts Non-current liabilities — Derivative instruments — 1,059 Gas contracts Non-current liabilities — Derivative instruments — 1,511 Total gross amounts presented in the balance sheet — 51,940 Less: gross amounts not offset in the balance sheet — — Net amount $ — $ 51,940

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Schedule of fair value measurement information for certain assets and liabilities	The following table provides fair value measurement information for certain assets and liabilities as of September 30, 2017 and December 31, 2016 : September 30, 2017 December 31, 2016 Book Fair Book Fair (in thousands) Value Value Value Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ — $ — $ (750,000 ) $ (782,835 ) 4.375% Notes due 2024 $ (750,000 ) $ (794,663 ) $ (750,000 ) $ (779,453 ) 3.90% Notes due 2027 $ (750,000 ) $ (764,408 ) $ — $ — Derivative instruments — assets $ 7,053 $ 7,053 $ — $ — Derivative instruments — liabilities $ (5,990 ) $ (5,990 ) $ (51,940 ) $ (51,940 )

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	9 Months Ended
	Sep. 30, 2017
Compensation and Retirement Disclosure [Abstract]
Schedule of recognition of non-cash stock-based compensation cost	We have recognized stock-based compensation cost as shown below for the periods indicated. Three Months Ended Nine Months Ended (in thousands) 2017 2016 2017 2016 Restricted stock awards: Performance stock awards $ 6,508 $ 5,465 $ 19,348 $ 18,374 Service-based stock awards 5,317 4,624 14,449 13,540 11,825 10,089 33,797 31,914 Stock option awards 698 571 1,943 1,974 Total stock compensation cost 12,523 10,660 35,740 33,888 Less amounts capitalized to oil and gas properties (5,485 ) (4,896 ) (16,121 ) (15,106 ) Compensation expense $ 7,038 $ 5,764 $ 19,619 $ 18,782

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	9 Months Ended
	Sep. 30, 2017
Asset Retirement Obligation [Abstract]
Schedule of the change in the carrying amount of the asset retirement obligation	The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the nine months ended September 30, 2017 : (in thousands) Asset retirement obligation at January 1, 2017 $ 154,523 Liabilities incurred 5,730 Liability settlements and disposals (10,287 ) Accretion expense 5,637 Revisions of estimated liabilities 1,644 Asset retirement obligation at September 30, 2017 157,247 Less current obligation (12,612 ) Long-term asset retirement obligation $ 144,635

EARNINGS (LOSS) PER SHARE (Tabl

EARNINGS (LOSS) PER SHARE (Tables)	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Schedule of calculations of basic and diluted net earnings (loss) per common share under the two-class method	The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below: Three Months Ended Nine Months Ended (in thousands, except per share data) 2017 2016 2017 2016 Basic: Net income (loss) $ 91,399 $ (10,673 ) $ 319,633 $ (456,586 ) Participating securities’ share in earnings (1) (1,572 ) — (5,478 ) — Net income (loss) available to common stockholders $ 89,827 $ (10,673 ) $ 314,155 $ (456,586 ) Diluted: Net income (loss) $ 91,399 $ (10,673 ) $ 319,633 $ (456,586 ) Participating securities’ share in earnings (1) (1,572 ) — (5,476 ) — Net income (loss) available to common stockholders $ 89,827 $ (10,673 ) $ 314,157 $ (456,586 ) Shares: Basic shares outstanding 93,501 93,221 93,431 93,221 Dilutive effect of potential common shares (2) 30 — 34 — Fully diluted common stock 93,531 93,221 93,465 93,221 Earnings (loss) per share to common stockholders (3): Basic $ 0.96 $ (0.12 ) $ 3.36 $ (4.90 ) Diluted $ 0.96 $ (0.12 ) $ 3.36 $ (4.90 ) (1) Participating securities are not included in undistributed earnings when a loss exists. (2) Inclusion of certain shares would have an anti-dilutive effect; therefore, 298.7 thousand and 302.9 thousand shares were excluded from the calculations for the three and nine months ended September 30, 2017 and 2.1 million and 2.1 million shares were excluded from the calculations for the three and nine months ended September 30, 2016 . (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Schedule of components of the provision for income taxes	The components of our provision for income taxes are as follows: Three Months Ended Nine Months Ended Income Tax Expense (Benefit) (in thousands): 2017 2016 2017 2016 Current tax benefit $ — $ (1,115 ) $ (6 ) $ (1,115 ) Deferred tax expense (benefit) 51,239 (3,944 ) 188,168 (258,368 ) $ 51,239 $ (5,059 ) $ 188,162 $ (259,483 ) Combined federal and state effective income tax rate 35.9 % 32.2 % 37.1 % 36.2 %

SUPPLEMENTAL DISCLOSURE OF CA27

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Elements [Abstract]
Schedule of supplemental disclosure of cash flow information	Three Months Ended Nine Months Ended (in thousands) 2017 2016 2017 2016 Cash paid for: Interest expense (net of capitalized amounts of $477, $286, $12,439, and $10,343, respectively) $ 109 $ 527 $ 28,881 $ 30,204 Income taxes $ — $ — $ 3 $ 13 Cash income tax refunds received $ — $ 1,115 $ 21 $ 1,140

BASIS OF PRESENTATION (Details)

BASIS OF PRESENTATION (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Oil and Gas Properties
Discount rate for calculating present value of estimated future net revenues from proved reserves (as a percent)			10.00%
Impairment of oil and gas properties	$ 0	$ 105,593	$ 0	$ 757,670
Impairment of oil and gas properties, after tax		$ 67,100		$ 481,400

LONG-TERM DEBT - Summary (Detai

LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands	Sep. 30, 2017	May 12, 2017	Apr. 10, 2017	Dec. 31, 2016
Debt Instrument
Principal	$ 1,500,000			$ 1,500,000
Less—unamortized debt issuance costs and discount	(13,491)			(12,061)
Long-term debt, net	1,486,509			1,487,939
5.875% Senior Notes
Debt Instrument
Principal	0		$ 253,500	750,000
Less—unamortized debt issuance costs and discount	0			(5,691)
Long-term debt, net	$ 0			744,309
Interest rate (as a percent)	5.875%	5.875%	5.875%
4.375% Senior Notes
Debt Instrument
Principal	$ 750,000			750,000
Less—unamortized debt issuance costs and discount	(5,626)			(6,370)
Long-term debt, net	$ 744,374			743,630
Interest rate (as a percent)	4.375%
3.90% Senior Notes
Debt Instrument
Principal	$ 750,000		$ 750,000	0
Less—unamortized debt issuance costs and discount	(7,865)			0
Long-term debt, net	$ 742,135			$ 0
Interest rate (as a percent)	3.90%		3.90%
Unamortized debt issuance costs	$ 6,000
Unamortized discount	$ 1,800

LONG-TERM DEBT - Bank Debt (Det

LONG-TERM DEBT - Bank Debt (Details) - USD ($)	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Unamortized debt issuance costs and discount	$ 13,491,000	$ 12,061,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Credit facility amount	1,000,000,000
Credit facility, increase amount option	1,250,000,000
Borrowings outstanding	0
Letters of credit outstanding under the credit facility	2,500,000
Unused borrowing availability	$ 997,500,000
Debt-to-capital ratio	65.00%
Unamortized debt issuance costs and discount	$ 3,600,000	$ 4,500,000
Minimum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Commitment fee percentage	0.125%
Maximum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Commitment fee percentage	0.35%
London Interbank Offered Rate (LIBOR) | Minimum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	1.125%
London Interbank Offered Rate (LIBOR) | Maximum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	2.00%
Base Rate | Minimum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	0.125%
Base Rate | Maximum | Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate margin (as a percent)	1.00%

LONG-TERM DEBT - Senior Notes (

LONG-TERM DEBT - Senior Notes (Details) - USD ($)	May 12, 2017	Apr. 10, 2017	Sep. 30, 2017	Jun. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Debt Instrument
Principal amount			$ 1,500,000,000			$ 1,500,000,000		$ 1,500,000,000
Gain (loss) on extinguishment of debt			$ 0		$ 0	$ (28,169,000)	$ 0
5.875% Senior Notes
Debt Instrument
Interest rate (as a percent)	5.875%	5.875%	5.875%			5.875%
Tender price of debt instrument for each $1000 principal amount		$ 1,031.67
Principal amount used for ratio of debt instrument tender price		1,000
Principal amount		253,500,000	$ 0			$ 0		750,000,000
Settled tendered notes including accrued interest		$ 268,100,000
Redemption price of debt instrument for each $1000 principal amount	$ 1,029.38
Principal amount used for ratio of debt instrument redemption price	1,000
Repayments of debt	$ 512,000,000
Gain (loss) on extinguishment of debt				$ (28,200,000)
Redemption premium				22,600,000
Write off of deferred debt issuance cost				$ 5,300,000
3.90% Senior Notes
Debt Instrument
Interest rate (as a percent)		3.90%	3.90%			3.90%
Principal amount		$ 750,000,000	$ 750,000,000			$ 750,000,000		0
Debt instrument issuance price, at par percentage		99.748%
Effective rate		3.93%	4.01%			4.01%
Proceeds from issuance of unsecured debt		$ 741,800,000
4.375% Senior Notes
Debt Instrument
Interest rate (as a percent)			4.375%			4.375%
Principal amount			$ 750,000,000			$ 750,000,000		$ 750,000,000
Effective rate			4.50%			4.50%

DERIVATIVE INSTRUMENTS - Summar

DERIVATIVE INSTRUMENTS - Summary (Details) bbl / qtr in Thousands, MMBTU / D in Thousands	9 Months Ended
	Sep. 30, 2017bbl / qtrMMBTU / D$ / bbl$ / MMBTU
Derivative Contract Oil Collar WTI Index | 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	1,932
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	46.29
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	56.64
Derivative Contract Oil Collar WTI Index | Fourth Quarter - 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	1,932
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	46.29
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	56.64
Derivative Contract Oil Collar WTI Index | 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	5,092
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	46.87
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.38
Derivative Contract Oil Collar WTI Index | 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	2,190
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | First Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	1,980
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	47.05
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	56.41
Derivative Contract Oil Collar WTI Index | First Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	540
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | Second Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	1,456
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	46.94
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.40
Derivative Contract Oil Collar WTI Index | Second Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	546
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | Third Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	1,104
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	45.92
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	54.21
Derivative Contract Oil Collar WTI Index | Third Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	552
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | Fourth Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	552
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	53.95
Derivative Contract Oil Collar WTI Index | Fourth Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	552
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	1,086
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | First Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	540
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | Second Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	546
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	48
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	55.21
Derivative Contract Oil Collar WTI Index | Third Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	0
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	0
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	0
Derivative Contract Oil Collar WTI Index | Fourth Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	0
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls) | $ / bbl	0
Weighted Avg Price - Ceiling (in USD per Bbls) | $ / bbl	0
Derivative Contract Gas Collar PEPL Index | 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	11,040
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.65
Weighted Avg Price - Ceiling (in USD per Bbls)	3.07
Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	11,040
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.65
Weighted Avg Price - Ceiling (in USD per Bbls)	3.07
Derivative Contract Gas Collar PEPL Index | 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	19,970
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.54
Weighted Avg Price - Ceiling (in USD per Bbls)	2.88
Derivative Contract Gas Collar PEPL Index | 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	7,300
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | First Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	9,000
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.62
Weighted Avg Price - Ceiling (in USD per Bbls)	3
Derivative Contract Gas Collar PEPL Index | First Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	1,800
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | Second Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	6,370
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.50
Weighted Avg Price - Ceiling (in USD per Bbls)	2.87
Derivative Contract Gas Collar PEPL Index | Second Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	1,820
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | Third Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	3,680
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.45
Weighted Avg Price - Ceiling (in USD per Bbls)	2.67
Derivative Contract Gas Collar PEPL Index | Third Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	1,840
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	920
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.50
Weighted Avg Price - Ceiling (in USD per Bbls)	2.65
Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	1,840
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	3,620
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | First Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	1,800
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | Second Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	1,820
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.64
Derivative Contract Gas Collar PEPL Index | Third Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	0
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	0
Weighted Avg Price - Ceiling (in USD per Bbls)	0
Derivative Contract Gas Collar PEPL Index | Fourth Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	0
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	0
Weighted Avg Price - Ceiling (in USD per Bbls)	0
Derivative Contract Gas Collar Perm EP | 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	7,360
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.64
Weighted Avg Price - Ceiling (in USD per Bbls)	3.04
Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	7,360
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.64
Weighted Avg Price - Ceiling (in USD per Bbls)	3.04
Derivative Contract Gas Collar Perm EP | 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	14,530
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.48
Weighted Avg Price - Ceiling (in USD per Bbls)	2.78
Derivative Contract Gas Collar Perm EP | 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	3,650
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | First Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	6,300
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.59
Weighted Avg Price - Ceiling (in USD per Bbls)	2.94
Derivative Contract Gas Collar Perm EP | First Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	900
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | Second Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	4,550
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.42
Weighted Avg Price - Ceiling (in USD per Bbls)	2.75
Derivative Contract Gas Collar Perm EP | Second Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	910
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | Third Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	2,760
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.37
Weighted Avg Price - Ceiling (in USD per Bbls)	2.56
Derivative Contract Gas Collar Perm EP | Third Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	920
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	920
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.40
Weighted Avg Price - Ceiling (in USD per Bbls)	2.58
Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	920
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	1,810
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | First Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	900
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | Second Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	910
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	2.30
Weighted Avg Price - Ceiling (in USD per Bbls)	2.42
Derivative Contract Gas Collar Perm EP | Third Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	0
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	0
Weighted Avg Price - Ceiling (in USD per Bbls)	0
Derivative Contract Gas Collar Perm EP | Fourth Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | MMBTU / D	0
Weighted Average Price
Weighted Avg Price - Floor (in USD per Bbls)	0
Weighted Avg Price - Ceiling (in USD per Bbls)	0
Derivative Contract Oil Basis Swaps WTI Midland Index | 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	460
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.94
Derivative Contract Oil Basis Swaps WTI Midland Index | Fourth Quarter - 2017 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	460
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.94
Derivative Contract Oil Basis Swaps WTI Midland Index | 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	2,460
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.86
Derivative Contract Oil Basis Swaps WTI Midland Index | 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	1,825
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | First Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	720
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.87
Derivative Contract Oil Basis Swaps WTI Midland Index | First Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	450
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | Second Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	728
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.87
Derivative Contract Oil Basis Swaps WTI Midland Index | Second Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	455
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | Third Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	736
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.87
Derivative Contract Oil Basis Swaps WTI Midland Index | Third Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	460
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | Fourth Quarter - 2018 | Outstanding at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	276
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.76
Derivative Contract Oil Basis Swaps WTI Midland Index | Fourth Quarter - 2018 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	460
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	905
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | First Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	450
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | Second Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	455
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0.47
Derivative Contract Oil Basis Swaps WTI Midland Index | Third Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	0
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0
Derivative Contract Oil Basis Swaps WTI Midland Index | Fourth Quarter - 2019 | Subsequent at end of period
Fair values of derivative assets and liabilities
Volume (Bbls) | bbl / qtr	0
Weighted Average Price
Weighted Avg Differential (in USD per Bbls) | $ / bbl	0
Maximum
Derivative
Percent of oil and gas production available for hedging	50.00%

DERIVATIVE INSTRUMENTS - (Gain)

DERIVATIVE INSTRUMENTS - (Gain) loss on derivative instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments and Hedges, Assets [Abstract]
Change in fair value of derivative instruments, net	$ 19,085	$ (8,967)	$ (53,003)	$ 32,768
Cash (receipts) payments on derivative instruments, net	(2,976)	(791)	2,742	(9,718)
(Gain) loss on derivative instruments, net	$ 16,109	$ (9,758)	$ (50,261)	$ 23,050

DERIVATIVE INSTRUMENTS - Deriva

DERIVATIVE INSTRUMENTS - Derivative assets and liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Asset
Total gross amounts presented in the balance sheet	$ 6,924	$ 0
Liability
Total gross amounts presented in the balance sheet	5,778	49,370
Not Designated as Hedging Instrument
Asset
Total gross amounts presented in the balance sheet	7,053
Less: gross amounts not offset in the balance sheet	(4,540)
Net amount	2,513
Liability
Total gross amounts presented in the balance sheet	5,990	51,940
Less: gross amounts not offset in the balance sheet	(4,540)	0
Net amount	1,450	51,940
Not Designated as Hedging Instrument | Oil contracts | Current assets — Derivative instruments
Asset
Total gross amounts presented in the balance sheet	2,288
Not Designated as Hedging Instrument | Oil contracts | Non-current assets — Derivative instruments
Asset
Total gross amounts presented in the balance sheet	110
Not Designated as Hedging Instrument | Oil contracts | Current liabilities — Derivative instruments
Liability
Total gross amounts presented in the balance sheet	4,919	27,892
Not Designated as Hedging Instrument | Oil contracts | Non-current liabilities — Derivative instruments
Liability
Total gross amounts presented in the balance sheet	210	1,059
Not Designated as Hedging Instrument | Gas contracts | Current assets — Derivative instruments
Asset
Total gross amounts presented in the balance sheet	4,636
Not Designated as Hedging Instrument | Gas contracts | Non-current assets — Derivative instruments
Asset
Total gross amounts presented in the balance sheet	19
Not Designated as Hedging Instrument | Gas contracts | Current liabilities — Derivative instruments
Liability
Total gross amounts presented in the balance sheet	859	21,478
Not Designated as Hedging Instrument | Gas contracts | Non-current liabilities — Derivative instruments
Liability
Total gross amounts presented in the balance sheet	$ 2	$ 1,511

FAIR VALUE MEASUREMENTS -Summar

FAIR VALUE MEASUREMENTS -Summary (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Financial Assets (Liabilities):
Derivative instruments — assets	$ 6,924	$ 0
Derivative instruments — liabilities	(5,778)	(49,370)
Book Value
Financial Assets (Liabilities):
Derivative instruments — assets	7,053	0
Derivative instruments — liabilities	(5,990)	(51,940)
Fair Value
Financial Assets (Liabilities):
Derivative instruments — assets	7,053	0
Derivative instruments — liabilities	(5,990)	(51,940)
5.875% Notes due 2022 | Book Value
Financial Assets (Liabilities):
Long-term debt	0	(750,000)
5.875% Notes due 2022 | Fair Value
Financial Assets (Liabilities):
Long-term debt	0	(782,835)
4.375% Notes due 2024 | Book Value
Financial Assets (Liabilities):
Long-term debt	(750,000)	(750,000)
4.375% Notes due 2024 | Fair Value
Financial Assets (Liabilities):
Long-term debt	(794,663)	(779,453)
3.90% Notes due 2027 | Book Value
Financial Assets (Liabilities):
Long-term debt	(750,000)	0
3.90% Notes due 2027 | Fair Value
Financial Assets (Liabilities):
Long-term debt	$ (764,408)	$ 0

FAIR VALUE MEASUREMENTS - Other

FAIR VALUE MEASUREMENTS - Other instruments (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Other Financial Instruments
Accrued operating expenses	$ 59.1	$ 53.9
Accrued payroll related general and administrative expenses	36.2	43.5
Allowance for Trade Receivables
Other Financial Instruments
Aggregate allowance for doubtful accounts	$ 1.9	$ 1.6

CAPITAL STOCK (Details)

CAPITAL STOCK (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended
	Aug. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Common stock, shares authorized		200,000,000		200,000,000		200,000,000
Preferred stock, shares authorized		15,000,000		15,000,000		15,000,000
Common stock outstanding (in shares)		95,300,000		95,300,000
Preferred stock outstanding (in shares)		0		0
Dividends
Dividends declared (in dollars per share)	$ 0.08	$ 0.08	$ 0.08	$ 0.24	$ 0.24
Dividend declared from APIC				$ 22,854

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Options, Restricted Stock and Unit Awards
Stock compensation	$ 12,523	$ 10,660	$ 35,740	$ 33,888
Less amounts capitalized to oil and gas properties	(5,485)	(4,896)	(16,121)	(15,106)
Compensation expense	7,038	5,764	19,619	18,782
Cumulative effect adjustment of adopting ASU 2016-09	33,132		33,132
Net cash provided by operating activities			755,805	440,788
Net cash provided by financing activities			(61,238)	(37,078)
Restricted stock awards:
Options, Restricted Stock and Unit Awards
Stock compensation	11,825	10,089	33,797	31,914
Performance stock awards
Options, Restricted Stock and Unit Awards
Stock compensation	6,508	5,465	19,348	18,374
Service-based stock awards
Options, Restricted Stock and Unit Awards
Stock compensation	5,317	4,624	14,449	13,540
Stock option awards
Options, Restricted Stock and Unit Awards
Stock compensation	698	$ 571	1,943	1,974
Retained Earnings (Accumulated Deficit)
Options, Restricted Stock and Unit Awards
Cumulative effect adjustment of adopting ASU 2016-09	28,739		28,739
Additional Paid-in Capital
Options, Restricted Stock and Unit Awards
Cumulative effect adjustment of adopting ASU 2016-09	$ 4,393		$ 4,393
Accounting Standards Update 2016-09, Statutory Tax Withholding Component [Member]
Options, Restricted Stock and Unit Awards
Net cash provided by operating activities				11,500
Net cash provided by financing activities				$ 11,500

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Asset Retirement Obligations
Balance at beginning of year	$ 154,523
Liabilities incurred	5,730
Liability settlements and disposals	(10,287)
Accretion expense	5,637
Revisions of estimated liabilities	1,644
Balance at end of year	157,247
Less current obligation	(12,612)
Long-term asset retirement obligation	$ 144,635	$ 140,770

EARNINGS (LOSS) PER SHARE (Deta

EARNINGS (LOSS) PER SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Basic:
Net income (loss)	$ 91,399	$ (10,673)	$ 319,633	$ (456,586)
Participating securities’ share in earnings	(1,572)	0	(5,478)	0
Net income (loss) available to common stockholders	89,827	(10,673)	314,155	(456,586)
Diluted:
Net income (loss)	91,399	(10,673)	319,633	(456,586)
Participating securities’ share in earnings	(1,572)	0	(5,476)	0
Net income (loss) available to common stockholders	$ 89,827	$ (10,673)	$ 314,157	$ (456,586)
Shares:
Basic shares outstanding	93,501,000	93,221,000	93,431,000	93,221,000
Dilutive effect of potential common shares	30,000	0	34,000	0
Fully diluted common stock (in shares)	93,531,000	93,221,000	93,465,000	93,221,000
Earnings (loss) per share to common stockholders:
Basic (in dollars per share)	$ 0.96	$ (0.12)	$ 3.36	$ (4.90)
Diluted (in dollars per share)	$ 0.96	$ (0.12)	$ 3.36	$ (4.90)
Excluded antidilutive securities (in shares)	298,700	2,100,000	302,900	2,100,000

INCOME TAXES - Components of th

INCOME TAXES - Components of the Provision for income taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Expense (Benefit)
Current tax benefit	$ 0	$ (1,115)	$ (6)	$ (1,115)
Deferred tax expense (benefit)	51,239	(3,944)	188,168	(258,368)
Total income tax expense (benefits)	$ 51,239	$ (5,059)	$ 188,162	$ (259,483)
Combined federal and state effective income tax rate	35.90%	32.20%	37.10%	36.20%

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
U.S. net tax operating loss carryforward		$ 1,182.4
Alternative minimum tax credit carryforward		$ 6
Unrecognized tax benefits that would impact the entity's effective rate	$ 0
Provisions for interest or penalties related to uncertain tax positions	$ 0
U.S. statutory rate (as a percent)	35.00%

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Summary (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)Bcf
Construction, Drilling and Purchase Commitments
Operating leases, future minimum payments due	$ 89.6
Drilling Commitments
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	181.2
Gathering System Construction
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 24.6
Natural Gas Sales Contracts
Construction, Drilling and Purchase Commitments
Oil and gas delivery commitments and contracts, remaining contractual volume (in bcf) | Bcf	207.2
Oil and gas delivery commitments and contracts, period	7 years 3 months 6 days
Maximum financial commitment resulting from inability to meet gas delivery commitments	$ 491
Gas Gathering And Processing Agreements
Construction, Drilling and Purchase Commitments
Oil and gas delivery commitments and contracts, period	8 years 7 months 1 day
Maximum financial commitment resulting from inability to meet gas delivery commitments	$ 312.3
Minimum Volume Agreement
Construction, Drilling and Purchase Commitments
Maximum financial commitment resulting from inability to meet gas delivery commitments	13.7
Accrued liabilities, current	1.9
Other Transportation And Delivery Commitments And Facilities Commitments
Construction, Drilling and Purchase Commitments
Maximum financial commitment resulting from inability to meet gas delivery commitments	$ 37.6

SUPPLEMENTAL DISCLOSURE OF CA44

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Cash paid for:
Interest expense (net of capitalized amounts of $477, $286, $12,439, and $10,343, respectively)	$ 109	$ 527	$ 28,881	$ 30,204
Income taxes	0	0	3	13
Cash income tax refunds received	0	1,115	21	1,140
Interest capitalized	$ 477	$ 286	$ 12,439	$ 10,343