Cimarex Energy (CIMXP) 10-Q 9 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Jul. 31, 2017
Document and Entity Information
Entity Registrant Name	CIMAREX ENERGY CO
Entity Central Index Key	1,168,054
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		95,278,037
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 519,595	$ 652,876
Accounts receivable:
Trade, net of allowance	85,397	42,287
Oil and gas sales, net of allowance	236,988	217,395
Gas gathering, processing, and marketing, net of allowance	13,146	14,888
Oil and gas well equipment and supplies	45,486	33,342
Derivative instruments	19,803
Prepaid expenses	5,894	7,335
Other current assets	1,567	1,181
Total current assets	927,876	969,304
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	16,769,915	16,225,495
Unproved properties and properties under development, not being amortized	535,779	478,277
Gross oil and gas properties	17,305,694	16,703,772
Less - accumulated depreciation, depletion, amortization and impairment	(14,530,251)	(14,349,505)
Net oil and gas properties	2,775,443	2,354,267
Fixed assets, net of accumulated depreciation of $268,778 and $246,901, respectively	206,114	205,465
Goodwill	620,232	620,232
Derivative instruments	442
Deferred income taxes		55,835
Other assets, net	32,873	32,621
Total assets	4,562,980	4,237,724
Accounts payable:
Trade	61,397	49,163
Gas gathering, processing, and marketing	26,436	25,323
Accrued liabilities:
Exploration and development	95,048	82,320
Taxes other than income	17,719	18,766
Other	182,580	177,695
Derivative instruments	98	49,370
Revenue payable	142,943	119,715
Total current liabilities	526,221	522,352
Long-term debt:
Principal	1,500,000	1,500,000
Less - Unamortized debt issuance costs and discount	(13,903)	(12,061)
Long-term debt, net	1,486,097	1,487,939
Deferred income taxes	48,322
Asset retirement obligation	147,363	140,770
Derivative instruments		2,570
Other liabilities	43,222	41,104
Total liabilities	2,251,225	2,194,735
Commitments and contingencies (Note 10)
Stockholders' equity:
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued
Common stock, $0.01 par value, 200,000,000 shares authorized, 95,341,554 and 95,123,525 shares issued, respectively	953	951
Additional paid-in capital	2,774,597	2,763,452
Retained earnings (Accumulated deficit)	(465,366)	(722,359)
Accumulated other comprehensive income	1,571	945
Total stockholders' equity	2,311,755	2,042,989
Total liabilities and stockholders' equity	$ 4,562,980	$ 4,237,724

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Condensed Consolidated Balance Sheets
Fixed assets, accumulated depreciation (in dollars)	$ 268,778	$ 246,901
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	95,341,554	95,123,525

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues:
Oil sales	$ 232,453	$ 162,005	$ 456,519	$ 279,578
Gas sales	132,474	76,615	264,419	159,223
NGL sales	80,886	51,939	161,312	85,291
Gas gathering and other	10,735	8,211	21,360	15,452
Gas marketing, net of related costs of $38,884, $26,435, $78,737, and $51,747, respectively	(96)	103	18	(71)
Total revenues	456,452	298,873	903,628	539,473
Costs and expenses:
Impairment of oil and gas properties		333,291		652,077
Depreciation, depletion and amortization	107,884	102,086	203,700	212,722
Asset retirement obligation	960	1,750	2,580	4,048
Production	62,578	57,213	124,999	127,915
Transportation, processing and other operating	58,624	44,436	113,647	90,879
Gas gathering and other	8,647	7,492	17,074	15,572
Taxes other than income	17,477	14,066	38,790	27,905
General and administrative	19,762	21,424	37,796	35,321
Stock compensation	6,293	7,490	12,581	13,018
(Gain) loss on derivative instruments, net	(22,509)	33,236	(66,370)	32,808
Other operating expense, net	266	24	882	114
Total costs and expenses	259,982	622,508	485,679	1,212,379
Operating income (loss)	196,470	(323,635)	417,949	(672,906)
Other (income) and expense:
Interest expense	20,095	20,824	41,147	41,629
Capitalized interest	(5,442)	(5,633)	(12,083)	(10,537)
Loss on early extinguishment of debt	28,169		28,169
Other, net	(2,231)	(2,011)	(4,441)	(3,661)
Income (loss) before income tax	155,879	(336,815)	365,157	(700,337)
Income tax expense (benefit)	58,617	(122,361)	136,923	(254,424)
Net income (loss)	$ 97,262	$ (214,454)	$ 228,234	$ (445,913)
Earnings (loss) per share to common stockholders:
Basic (in dollars per share)	$ 1.02	$ (2.31)	$ 2.40	$ (4.79)
Diluted (in dollars per share)	1.02	(2.31)	2.40	(4.79)
Dividends declared (in dollars per share)	$ 0.08	$ 0.08	$ 0.16	$ 0.16
Comprehensive income (loss):
Net income (loss)	$ 97,262	$ (214,454)	$ 228,234	$ (445,913)
Other comprehensive income:
Change in fair value of investments, net of tax of $128, $112, $359 and $161, respectively	224	195	626	280
Total comprehensive income (loss)	$ 97,486	$ (214,259)	$ 228,860	$ (445,633)

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Consolidated Statements of Operations and Comprehensive Income (Loss)
Gas marketing, related costs	$ 38,884	$ 26,435	$ 78,737	$ 51,747
Change in fair value investments, tax	$ 128	$ 112	$ 359	$ 161

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash flows from operating activities:
Net income (loss)	$ 228,234	$ (445,913)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments and other valuation losses		652,077
Depreciation, depletion and amortization	203,700	212,722
Asset retirement obligation	2,580	4,048
Deferred tax expense (benefit)	136,929	(254,424)
Stock compensation	12,581	13,018
(Gain) loss on derivative instruments	(66,370)	32,808
Settlements on derivative instruments	(5,717)	8,927
Loss on early extinguishment of debt	28,169
Changes in non-current assets and liabilities	1,076	2,548
Other, net	3,445	2,644
Changes in operating assets and liabilities:
Receivables	(61,145)	(4,327)
Other current assets	(11,104)	17,328
Accounts payable and other current liabilities	32,422	(23,670)
Net cash provided by operating activities	504,800	217,786
Cash flows from investing activities:
Oil and gas expenditures	(582,172)	(325,058)
Sales of oil and gas assets	9,163	12,630
Sales of other assets	394	224
Other capital expenditures	(18,209)	(17,774)
Net cash used by investing activities	(590,824)	(329,978)
Cash flows from financing activities:
Borrowings of long-term deb	748,110
Repayments of long-term debt	(750,000)
Call premium, financing, and underwriting fees	(29,035)	(1)
Dividends paid	(15,153)	(22,655)
Employee withholding taxes paid when directly withholding shares on vested stock awards	(1,215)	(4,082)
Proceeds from exercise of stock options and other	36	1,287
Net cash used by financing activities	(47,257)	(25,451)
Net change in cash and cash equivalents	(133,281)	(137,643)
Cash and cash equivalents at beginning of period	652,876	779,382
Cash and cash equivalents at end of period	$ 519,595	$ 641,739

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - 6 months ended Jun. 30, 2017 - USD ($) shares in Thousands, $ in Thousands	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
Balance at Dec. 31, 2016	$ 951	$ 2,763,452	$ (722,359)	$ 945	$ 2,042,989
Balance, shares at Dec. 31, 2016	95,124
Increase (Decrease) in Stockholders' Equity
Dividends on forfeited stock awards reclassified to expense		3	20		23
Dividends in Excess of Retained Earnings		(15,237)			(15,237)
Net income			228,234		228,234
Unrealized change in fair value of investments, net of tax				626	626
Issuance of restricted stock awards	$ 2	(2)
Issuance of restricted stock awards, shares	244
Common stock reacquired and retired		(1,215)			(1,215)
Common stock reacquired and retired, shares	(10)
Restricted stock forfeited and retired, shares	(17)
Exercise of stock options		36			36
Exercise of stock options, shares	1
Stock-based compensation		23,193			23,193
Cumulative effect adjustment of adopting ASU 2016-09		4,393	28,739		33,132
Other		(26)			(26)
Balance at Jun. 30, 2017	$ 953	$ 2,774,597	$ (465,366)	$ 1,571	$ 2,311,755
Balance, shares at Jun. 30, 2017	95,342

BASIS OF PRESENTATION

BASIS OF PRESENTATION	6 Months Ended
	Jun. 30, 2017
BASIS OF PRESENTATION
BASIS OF PRESENTATION	1. BASIS OF PRESENTATION The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”) pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the “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. An analysis of our oil and gas well equipment and supplies was performed as of June 30, 2017, and no impairment was required. 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 June 30, 2017 and March 31, 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 six months ended June 30, 2017. During the three and six months ended June 30, 2016, we recognized ceiling test impairments of $333.3 million ($211.8 million, net of tax) and $652.1 million ($414.3 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”) 2014-09, Revenue from Contracts with Customers (Topic 606) . In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition , and most industry-specific guidance throughout the Industry Topics of the Codification. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. We intend to adopt this standard on January 1, 2018, utilizing a modified retrospective approach. Management does not believe the effect of adoption will be material to our financial statements because we follow the sales method of accounting for our oil, gas, and NGL production, which is generally consistent with the revenue recognition provisions of the new standard. However, we anticipate the new standard will result in more robust footnote disclosures. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current 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	6 Months Ended
	Jun. 30, 2017
Long-term debt
LONG-TERM DEBT	2. Long-term debt at June 30, 2017 and December 31, 2016 consisted of the following: June 30, 2017 December 31, 2016 Unamortized Debt Issuance Costs Long-term Unamortized Debt Long-term (in thousands) Principal and Discount (1) Debt, net Principal Issuance Costs Debt, net 5.875% Senior Notes $ — $ — $ — $ 750,000 $ (5,691) $ 744,309 4.375% Senior Notes 750,000 (5,872) 744,128 750,000 (6,370) 743,630 3.90% Senior Notes 750,000 (8,031) 741,969 — — — Total long-term debt $ 1,500,000 $ (13,903) $ 1,486,097 $ 1,500,000 $ (12,061) $ 1,487,939 (1) At June 30, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $6.2 million and $1.9 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 June 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 June 30, 2017, we were in compliance with all of the financial covenants. At June 30, 2017 and December 31, 2016, we had $3.9 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 of the 5.875% notes was 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 have received $741.9 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs as of June 30, 2017. The notes bear an 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. 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 June 30, 2017. The 4.375% notes are due in 2024. Interest on each of the senior notes is payable semiannually. 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_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING	6 Months Ended
	Jun. 30, 2017
Derivative instruments/hedging
DERIVATIVE INSTRUMENTS/HEDGING	3. 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 covering up to 50% of our oil and natural gas production on a forward five 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. The following tables summarize our outstanding derivative contracts as of June 30, 2017: First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) — — 2,024,000 1,564,000 3,588,000 Wtd Avg Price - Floor $ — $ — $ 46.25 $ 47.35 $ 46.73 Wtd Avg Price - Ceiling $ — $ — $ 56.06 $ 57.18 $ 56.55 2018: WTI (1) Volume (Bbls) 1,080,000 546,000 184,000 — 1,810,000 Wtd Avg Price - Floor $ 48.33 $ 49.33 $ 48.00 $ — $ 48.60 Wtd Avg Price - Ceiling $ 58.33 $ 57.56 $ 54.76 $ — $ 57.74 (1) The index price for these collars is WTI, which refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: PEPL (1) Volume (MMBtu) — — 11,040,000 8,280,000 19,320,000 Wtd Avg Price - Floor $ — $ — $ 2.60 $ 2.72 $ 2.65 Wtd Avg Price - Ceiling $ — $ — $ 3.12 $ 3.20 $ 3.15 Perm EP (2) Volume (MMBtu) — — 7,360,000 5,520,000 12,880,000 Wtd Avg Price - Floor $ — $ — $ 2.63 $ 2.74 $ 2.68 Wtd Avg Price - Ceiling $ — $ — $ 3.13 $ 3.20 $ 3.16 2018: PEPL (1) Volume (MMBtu) 5,400,000 2,730,000 — — 8,130,000 Wtd Avg Price - Floor $ 2.73 $ 2.57 $ — $ — $ 2.68 Wtd Avg Price - Ceiling $ 3.23 $ 3.14 $ — $ — $ 3.20 Perm EP (2) Volume (MMBtu) 3,600,000 1,820,000 — — 5,420,000 Wtd Avg Price - Floor $ 2.75 $ 2.50 $ — $ — $ 2.67 Wtd Avg Price - Ceiling $ 3.22 $ 3.04 $ — $ — $ 3.16 (1) The index price for these collars is PEPL, which refers to the Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC. (2) The index price for these collars is Perm EP, which refers to the El Paso Natural Gas Company, Permian Basin Index as quoted in Platt’s Inside FERC. The following tables summarize our derivative contracts entered into subsequent to June 30, 2017: First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) — — 182,000 368,000 550,000 Wtd Avg Price - Floor $ — $ — $ 41.49 $ 41.75 $ 41.67 Wtd Avg Price - Ceiling $ — $ — $ 53.89 $ 54.34 $ 54.19 2018: WTI (1) Volume (Bbls) 360,000 364,000 368,000 — 1,092,000 Wtd Avg Price - Floor $ 41.75 $ 41.75 $ 41.75 $ — $ 41.75 Wtd Avg Price - Ceiling $ 54.34 $ 54.34 $ 54.34 $ — $ 54.34 (1) The index price for these collars is WTI, which refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: PEPL (1) Volume (MMBtu) — — 910,000 1,840,000 2,750,000 Wtd Avg Price - Floor $ — $ — $ 2.47 $ 2.45 $ 2.46 Wtd Avg Price - Ceiling $ — $ — $ 2.66 $ 2.65 $ 2.65 Perm EP (2) Volume (MMBtu) — — 910,000 1,840,000 2,750,000 Wtd Avg Price - Floor $ — $ — $ 2.37 $ 2.35 $ 2.36 Wtd Avg Price - Ceiling $ — $ — $ 2.57 $ 2.55 $ 2.56 2018: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Wtd Avg Price - Floor $ 2.45 $ 2.45 $ 2.45 $ — $ 2.45 Wtd Avg Price - Ceiling $ 2.65 $ 2.65 $ 2.65 $ — $ 2.65 Perm EP (2) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Wtd Avg Price - Floor $ 2.35 $ 2.35 $ 2.35 $ — $ 2.35 Wtd Avg Price - Ceiling $ 2.55 $ 2.55 $ 2.55 $ — $ 2.55 (1) The index price for these collars is PEPL, which refers to the Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC. (2) The index price for these collars is Perm EP, which refers to the El Paso Natural Gas Company, Permian Basin Index as quoted in Platt’s Inside FERC. Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor price. 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. 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 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 Six Months Ended June 30, June 30, (Gain) Loss on Derivative Instruments, Net (in thousands): 2017 2016 2017 2016 Change in fair value of derivative instruments, net $ (22,166) $ 37,095 $ (72,087) $ 41,735 Cash (receipts) payments on derivative instruments, net (343) (3,859) 5,717 (8,927) (Gain) loss on derivative instruments, net $ (22,509) $ 33,236 $ (66,370) $ 32,808 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 June 30, 2017 and December 31, 2016, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. June 30, 2017: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 14,756 $ — Gas contracts Current assets — Derivative instruments 5,047 — Oil contracts Non-current assets — Derivative instruments 442 — Gas contracts Current liabilities — Derivative instruments — 98 Total gross amounts presented in the balance sheet 20,245 98 Less: gross amounts not offset in the balance sheet (98) (98) Net amount: $ 20,147 $ — 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	6 Months Ended
	Jun. 30, 2017
Fair Value Measurements
FAIR VALUE MEASUREMENTS	4. 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 June 30, 2017 and December 31, 2016: June 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) $ (787,748) $ (750,000) $ (779,453) 3.90% Notes due 2027 $ (750,000) $ (754,335) $ — $ — Derivative instruments — assets $ 20,245 $ 20,245 $ — $ — Derivative instruments — liabilities $ (98) $ (98) $ (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 June 30, 2017 are: (i) accrued operating expenses of approximately $55.2 million; (ii) liabilities of approximately $39.5 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts prior to being funded from other bank accounts; and (iii) accrued general and administrative, primarily payroll-related, costs of approximately $28.7 million. Included in “Accrued liabilities — other” at December 31, 2016 are: (i) accrued operating expenses of approximately $53.9 million; (ii) accrued general and administrative, primarily payroll-related, costs of approximately $43.5 million, and (iii) liabilities of approximately $19.3 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts prior to being funded from other bank accounts. 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 June 30, 2017 and December 31, 2016, the allowance for doubtful accounts was $1.8 million and $1.6 million, respectively.

CAPITAL STOCK

CAPITAL STOCK	6 Months Ended
	Jun. 30, 2017
Capital Stock
CAPITAL STOCK	5. Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At June 30, 2017, there were 95.3 million shares of common stock and no shares of preferred stock outstanding. Dividends In May 2017, our Board of Directors declared a cash dividend of $0.08 per share. The dividend is payable on September 1, 2017, to stockholders of record on August 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 $15.2 million in dividends declared year-to-date June 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	6 Months Ended
	Jun. 30, 2017
Stock-based Compensation
STOCK-BASED COMPENSATION	6. We have recognized stock-based compensation cost as shown below for the periods indicated. Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2017 2016 2017 2016 Restricted stock awards Performance stock awards $ 6,438 $ 7,215 $ 12,840 $ 12,909 Service-based stock awards 4,208 4,751 9,132 8,916 10,646 11,966 21,972 21,825 Stock option awards 579 748 1,245 1,403 Total stock compensation cost 11,225 12,714 23,217 23,228 Less amounts capitalized to oil and gas properties (4,932) (5,224) (10,636) (10,210) Compensation expense $ 6,293 $ 7,490 $ 12,581 $ 13,018 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 decrease in total stock compensation cost in the 2017 periods presented above as compared to 2016 periods presented above is primarily due to awards vesting prior to the 2017 periods and retirements that occurred during the second quarter of 2016 that involved the accelerated vesting of awards during that period, both of which were partially offset by awards granted either during or subsequent to the 2016 periods. We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017. ASU 2016-09 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 2016-09, 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 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures 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 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method. In accordance with this method, we adjusted the statement of cash flows for the six months ended June 30, 2016 by increasing net cash provided by operating activities by $4.1 million and increasing net cash used by financing activities by $4.1 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 six months ended June 30, 2017 and 2016.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	6 Months Ended
	Jun. 30, 2017
Asset Retirement Obligations
ASSET RETIREMENT OBLIGATIONS	7. 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 six months ended June 30, 2017: (in thousands) Asset retirement obligation at January 1, 2017 $ 154,523 Liabilities incurred 4,104 Liability settlements and disposals (7,550) Accretion expense 3,749 Revisions of estimated liabilities 1,763 Asset retirement obligation at June 30, 2017 156,589 Less current obligation (9,226) Long-term asset retirement obligation $ 147,363

EARNINGS (LOSS) PER SHARE

EARNINGS (LOSS) PER SHARE	6 Months Ended
	Jun. 30, 2017
Earnings (Loss) per Share
EARNINGS (LOSS) PER SHARE	8. The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below: Three Months Ended Six Months Ended June 30, June 30, (in thousands, except per share data) 2017 2016 2017 2016 Basic: Net income (loss) $ 97,262 $ (214,454) $ 228,234 $ (445,913) Participating securities’ share in earnings (1) (1,643) — (3,898) — Net income (loss) available to common stockholders $ 95,619 $ (214,454) $ 224,336 $ (445,913) Diluted: Net income (loss) $ 97,262 $ (214,454) $ 228,234 $ (445,913) Participating securities’ share in earnings (1) (1,642) — (3,897) — Net income (loss) available to common stockholders $ 95,620 $ (214,454) $ 224,337 $ (445,913) Shares: Basic shares outstanding 93,402 93,075 93,396 93,075 Dilutive effect of potential common shares (2) 33 — 35 — Fully diluted common stock 93,435 93,075 93,431 93,075 Earnings (loss) per share to common stockholders (3): Basic $ 1.02 $ (2.31) $ 2.40 $ (4.79) Diluted $ 1.02 $ (2.31) $ 2.40 $ (4.79) (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, 300.5 thousand and 255.0 thousand shares were excluded from the calculations for the three and six months ended June 30, 2017 and 2.3 million and 2.3 million shares were excluded from the calculations for the three and six months ended June 30, 2016. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

INCOME TAXES

INCOME TAXES	6 Months Ended
	Jun. 30, 2017
Income Taxes
INCOME TAXES	9. The components of our provision for income taxes are as follows: Three Months Ended Six Months Ended June 30, June 30, Income Tax Expense (Benefit) (in thousands): 2017 2016 2017 2016 Current tax benefit $ — $ — $ (6) $ — Deferred tax expense (benefit) 58,617 (122,361) 136,929 (254,424) $ 58,617 $ (122,361) $ 136,923 $ (254,424) Combined federal and state effective income tax rate % % % % 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 June 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 2013 through 2015 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities, which remain open to examination for tax years 2012 through 2015. 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	6 Months Ended
	Jun. 30, 2017
Commitments and Contingencies
COMMITMENTS AND CONTINGENCIES	10. Commitments At June 30, 2017, we had estimated commitments of approximately: (i) $159.6 million to finish drilling and completing wells and various other infrastructure projects in progress and (ii) $13.7 million to finish gathering system construction in progress. At June 30, 2017, we had firm sales contracts to deliver approximately 181.3 Bcf of natural gas over the next 7.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2017 index price, would be approximately $451.9 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these obligations. In connection with gas gathering and processing agreements, we have volume commitments over the next nine years. If we do not deliver this gas, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2017, would be approximately $322.3 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 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 June 30, 2017, would be approximately $13.5 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. As of June 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 $40.0 million over the remaining terms of the agreements. We have various future commitments for office space under operating lease arrangements totaling approximately $92.0 million at June 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	6 Months Ended
	Jun. 30, 2017
Supplemental Disclosure of Cash Flow Information:
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION	11. Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2017 2016 2017 2016 Cash paid during the period for: Interest expense (net of capitalized amounts of $11,659, $9,917, $11,962, and $10,057, respectively) $ 28,115 $ 29,223 $ 28,772 $ 29,677 Income taxes $ 1 $ 2 $ 3 $ 13 Cash received for income tax refunds $ — $ — $ 21 $ 25

BASIS OF PRESENTATION (Policies

BASIS OF PRESENTATION (Policies)	6 Months Ended
	Jun. 30, 2017
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 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. An analysis of our oil and gas well equipment and supplies was performed as of June 30, 2017, and no impairment was required. 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 June 30, 2017 and March 31, 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 six months ended June 30, 2017. During the three and six months ended June 30, 2016, we recognized ceiling test impairments of $333.3 million ($211.8 million, net of tax) and $652.1 million ($414.3 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	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) . In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition , and most industry-specific guidance throughout the Industry Topics of the Codification. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. We intend to adopt this standard on January 1, 2018, utilizing a modified retrospective approach. Management does not believe the effect of adoption will be material to our financial statements because we follow the sales method of accounting for our oil, gas, and NGL production, which is generally consistent with the revenue recognition provisions of the new standard. However, we anticipate the new standard will result in more robust footnote disclosures. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The key provision of this ASU is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet. The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current 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)	6 Months Ended
	Jun. 30, 2017
Long-term debt
Summary of debt	June 30, 2017 December 31, 2016 Unamortized Debt Issuance Costs Long-term Unamortized Debt Long-term (in thousands) Principal and Discount (1) Debt, net Principal Issuance Costs Debt, net 5.875% Senior Notes $ — $ — $ — $ 750,000 $ (5,691) $ 744,309 4.375% Senior Notes 750,000 (5,872) 744,128 750,000 (6,370) 743,630 3.90% Senior Notes 750,000 (8,031) 741,969 — — — Total long-term debt $ 1,500,000 $ (13,903) $ 1,486,097 $ 1,500,000 $ (12,061) $ 1,487,939 At June 30, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $6.2 million and $1.9 million, respectively. The 4.375% notes were issued at par.

DERIVATIVE INSTRUMENTS_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING (Tables)	6 Months Ended
	Jun. 30, 2017
Derivative instruments/hedging
Outstanding hedging contracts relative to future production	First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) — — 2,024,000 1,564,000 3,588,000 Wtd Avg Price - Floor $ — $ — $ 46.25 $ 47.35 $ 46.73 Wtd Avg Price - Ceiling $ — $ — $ 56.06 $ 57.18 $ 56.55 2018: WTI (1) Volume (Bbls) 1,080,000 546,000 184,000 — 1,810,000 Wtd Avg Price - Floor $ 48.33 $ 49.33 $ 48.00 $ — $ 48.60 Wtd Avg Price - Ceiling $ 58.33 $ 57.56 $ 54.76 $ — $ 57.74 (1) The index price for these collars is WTI, which refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: PEPL (1) Volume (MMBtu) — — 11,040,000 8,280,000 19,320,000 Wtd Avg Price - Floor $ — $ — $ 2.60 $ 2.72 $ 2.65 Wtd Avg Price - Ceiling $ — $ — $ 3.12 $ 3.20 $ 3.15 Perm EP (2) Volume (MMBtu) — — 7,360,000 5,520,000 12,880,000 Wtd Avg Price - Floor $ — $ — $ 2.63 $ 2.74 $ 2.68 Wtd Avg Price - Ceiling $ — $ — $ 3.13 $ 3.20 $ 3.16 2018: PEPL (1) Volume (MMBtu) 5,400,000 2,730,000 — — 8,130,000 Wtd Avg Price - Floor $ 2.73 $ 2.57 $ — $ — $ 2.68 Wtd Avg Price - Ceiling $ 3.23 $ 3.14 $ — $ — $ 3.20 Perm EP (2) Volume (MMBtu) 3,600,000 1,820,000 — — 5,420,000 Wtd Avg Price - Floor $ 2.75 $ 2.50 $ — $ — $ 2.67 Wtd Avg Price - Ceiling $ 3.22 $ 3.04 $ — $ — $ 3.16 (1) The index price for these collars is PEPL, which refers to the Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC. (2) The index price for these collars is Perm EP, which refers to the El Paso Natural Gas Company, Permian Basin Index as quoted in Platt’s Inside FERC.
Schedule of derivative contract entered into subsequent to balance sheet date	First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) — — 182,000 368,000 550,000 Wtd Avg Price - Floor $ — $ — $ 41.49 $ 41.75 $ 41.67 Wtd Avg Price - Ceiling $ — $ — $ 53.89 $ 54.34 $ 54.19 2018: WTI (1) Volume (Bbls) 360,000 364,000 368,000 — 1,092,000 Wtd Avg Price - Floor $ 41.75 $ 41.75 $ 41.75 $ — $ 41.75 Wtd Avg Price - Ceiling $ 54.34 $ 54.34 $ 54.34 $ — $ 54.34 (1) The index price for these collars is WTI, which refers to the West Texas Intermediate price as quoted on the New York Mercantile Exchange. First Second Third Fourth Quarter Quarter Quarter Quarter Total Gas Collars: 2017: PEPL (1) Volume (MMBtu) — — 910,000 1,840,000 2,750,000 Wtd Avg Price - Floor $ — $ — $ 2.47 $ 2.45 $ 2.46 Wtd Avg Price - Ceiling $ — $ — $ 2.66 $ 2.65 $ 2.65 Perm EP (2) Volume (MMBtu) — — 910,000 1,840,000 2,750,000 Wtd Avg Price - Floor $ — $ — $ 2.37 $ 2.35 $ 2.36 Wtd Avg Price - Ceiling $ — $ — $ 2.57 $ 2.55 $ 2.56 2018: PEPL (1) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Wtd Avg Price - Floor $ 2.45 $ 2.45 $ 2.45 $ — $ 2.45 Wtd Avg Price - Ceiling $ 2.65 $ 2.65 $ 2.65 $ — $ 2.65 Perm EP (2) Volume (MMBtu) 1,800,000 1,820,000 1,840,000 — 5,460,000 Wtd Avg Price - Floor $ 2.35 $ 2.35 $ 2.35 $ — $ 2.35 Wtd Avg Price - Ceiling $ 2.55 $ 2.55 $ 2.55 $ — $ 2.55 (1) The index price for these collars is PEPL, which refers to the Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt’s Inside FERC. (2) The index price for these collars is Perm EP, which refers to the El Paso Natural Gas Company, Permian Basin Index as quoted in Platt’s Inside FERC.
Net (gains) and losses from settlements and changes of derivative contracts	Three Months Ended Six Months Ended June 30, June 30, (Gain) Loss on Derivative Instruments, Net (in thousands): 2017 2016 2017 2016 Change in fair value of derivative instruments, net $ (22,166) $ 37,095 $ (72,087) $ 41,735 Cash (receipts) payments on derivative instruments, net (343) (3,859) 5,717 (8,927) (Gain) loss on derivative instruments, net $ (22,509) $ 33,236 $ (66,370) $ 32,808
Schedule of amounts and classifications of entity's derivative assets and liabilities as well as the potential effect of netting arrangements on contracts with the same counterparty	June 30, 2017: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 14,756 $ — Gas contracts Current assets — Derivative instruments 5,047 — Oil contracts Non-current assets — Derivative instruments 442 — Gas contracts Current liabilities — Derivative instruments — 98 Total gross amounts presented in the balance sheet 20,245 98 Less: gross amounts not offset in the balance sheet (98) (98) Net amount: $ 20,147 $ — 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)	6 Months Ended
	Jun. 30, 2017
Fair Value Measurements
Fair value measurement information for certain assets and liabilities	June 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) $ (787,748) $ (750,000) $ (779,453) 3.90% Notes due 2027 $ (750,000) $ (754,335) $ — $ — Derivative instruments — assets $ 20,245 $ 20,245 $ — $ — Derivative instruments — liabilities $ (98) $ (98) $ (51,940) $ (51,940)

STOCK-BASED AND OTHER COMPENSAT

STOCK-BASED AND OTHER COMPENSATION (Tables)	6 Months Ended
	Jun. 30, 2017
Stock-based Compensation
Recognition of non-cash stock-based compensation cost	Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2017 2016 2017 2016 Restricted stock awards Performance stock awards $ 6,438 $ 7,215 $ 12,840 $ 12,909 Service-based stock awards 4,208 4,751 9,132 8,916 10,646 11,966 21,972 21,825 Stock option awards 579 748 1,245 1,403 Total stock compensation cost 11,225 12,714 23,217 23,228 Less amounts capitalized to oil and gas properties (4,932) (5,224) (10,636) (10,210) Compensation expense $ 6,293 $ 7,490 $ 12,581 $ 13,018

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	6 Months Ended
	Jun. 30, 2017
Asset Retirement Obligations
Change in the carrying amount of the asset retirement obligation	(in thousands) Asset retirement obligation at January 1, 2017 $ 154,523 Liabilities incurred 4,104 Liability settlements and disposals (7,550) Accretion expense 3,749 Revisions of estimated liabilities 1,763 Asset retirement obligation at June 30, 2017 156,589 Less current obligation (9,226) Long-term asset retirement obligation $ 147,363

EARNINGS (LOSS) PER SHARE (Tabl

EARNINGS (LOSS) PER SHARE (Tables)	6 Months Ended
	Jun. 30, 2017
Earnings (Loss) per Share
Calculations of basic and diluted net earnings (loss) per common share under the two-class method	8. The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below: Three Months Ended Six Months Ended June 30, June 30, (in thousands, except per share data) 2017 2016 2017 2016 Basic: Net income (loss) $ 97,262 $ (214,454) $ 228,234 $ (445,913) Participating securities’ share in earnings (1) (1,643) — (3,898) — Net income (loss) available to common stockholders $ 95,619 $ (214,454) $ 224,336 $ (445,913) Diluted: Net income (loss) $ 97,262 $ (214,454) $ 228,234 $ (445,913) Participating securities’ share in earnings (1) (1,642) — (3,897) — Net income (loss) available to common stockholders $ 95,620 $ (214,454) $ 224,337 $ (445,913) Shares: Basic shares outstanding 93,402 93,075 93,396 93,075 Dilutive effect of potential common shares (2) 33 — 35 — Fully diluted common stock 93,435 93,075 93,431 93,075 Earnings (loss) per share to common stockholders (3): Basic $ 1.02 $ (2.31) $ 2.40 $ (4.79) Diluted $ 1.02 $ (2.31) $ 2.40 $ (4.79) (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, 300.5 thousand and 255.0 thousand shares were excluded from the calculations for the three and six months ended June 30, 2017 and 2.3 million and 2.3 million shares were excluded from the calculations for the three and six months ended June 30, 2016. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	6 Months Ended
	Jun. 30, 2017
Income Taxes
Components of the provision for income taxes	Three Months Ended Six Months Ended June 30, June 30, Income Tax Expense (Benefit) (in thousands): 2017 2016 2017 2016 Current tax benefit $ — $ — $ (6) $ — Deferred tax expense (benefit) 58,617 (122,361) 136,929 (254,424) $ 58,617 $ (122,361) $ 136,923 $ (254,424) Combined federal and state effective income tax rate % % % %

SUPPLEMENTAL DISCLOSURE OF CA27

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2017
Supplemental Disclosure of Cash Flow Information:
Supplemental Disclosure of Cash Flow Information	Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2017 2016 2017 2016 Cash paid during the period for: Interest expense (net of capitalized amounts of $11,659, $9,917, $11,962, and $10,057, respectively) $ 28,115 $ 29,223 $ 28,772 $ 29,677 Income taxes $ 1 $ 2 $ 3 $ 13 Cash received for income tax refunds $ — $ — $ 21 $ 25

BASIS OF PRESENTATION (Details)

BASIS OF PRESENTATION (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Oil and Gas Properties
Impairment On Oil And Gas Well Equipment And Supplies		$ 0
Discount rate for calculating present value of estimated future net revenues from proved reserves (as a percent)		10.00%
Impairment of oil and gas properties, after tax	$ 211,800		$ 414,300
Impairment of oil and gas properties	$ 333,291		$ 652,077

LONG-TERM DEBT - Summary (Detai

LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands	Jun. 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	(13,903)			(12,061)
Long-term debt, net	$ 1,486,097			1,487,939
Senior Notes 5.875% [Member]
Debt Instrument
Principal				750,000
Less - Unamortized debt issuance costs and discount				(5,691)
Long-term debt, net				$ 744,309
Interest rate (as a percent)	5.875%	5.875%	5.875%	5.875%
Senior Notes 4.375% [Member]
Debt Instrument
Principal	$ 750,000			$ 750,000
Less - Unamortized debt issuance costs and discount	(5,872)			(6,370)
Long-term debt, net	$ 744,128			$ 743,630
Interest rate (as a percent)	4.375%			4.375%
Senior Notes 3.90% [Member]
Debt Instrument
Principal	$ 750,000
Less - Unamortized debt issuance costs and discount	(8,031)
Long-term debt, net	$ 741,969
Interest rate (as a percent)	3.90%		3.90%

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)	May 12, 2017	Apr. 10, 2017	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Debt Instrument
Unamortized debt issuance costs and discount			$ 13,903,000	$ 13,903,000	$ 12,061,000
Long-term Debt, Excluding Current Maturities			1,486,097,000	1,486,097,000	1,487,939,000
Loss on early extinguishment of debt			28,169,000	28,169,000
Revolving Credit Facility [Member]
Debt Instrument
Unamortized debt issuance costs and discount			3,900,000	3,900,000	4,500,000
Borrowings outstanding			0	0	0
Credit facility amount			1,000,000,000	1,000,000,000
Credit facility, increase amount option			1,250,000,000	1,250,000,000
Letters of credit outstanding under the credit facility			2,500,000	2,500,000
Unused borrowing availability			997,500,000	$ 997,500,000
Debt-to-Capital ratio				65.00%
Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument
Commitment fee percentage				0.125%
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument
Commitment fee percentage				0.35%
Senior Notes 4.375% [Member]
Debt Instrument
Unamortized debt issuance costs and discount			$ 5,872,000	$ 5,872,000	$ 6,370,000
Interest rate (as a percent)			4.375%	4.375%	4.375%
Effective rate			4.50%	4.50%
Long-term Debt, Excluding Current Maturities			$ 744,128,000	$ 744,128,000	$ 743,630,000
Senior Notes 5.875% [Member]
Debt Instrument
Unamortized debt issuance costs and discount					$ 5,691,000
Interest rate (as a percent)	5.875%	5.875%	5.875%	5.875%	5.875%
Settled tendered notes including accrued interest		$ 268,100,000
Principal amount		253,500,000
Long-term Debt, Excluding Current Maturities					$ 744,309,000
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
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
Settling of notes	$ 512,000,000
Loss on early extinguishment of debt			$ 28,200,000
Redemption premium			22,600,000
Write off of Deferred Debt Issuance Cost			5,300,000
Senior Notes 3.90% [Member]
Debt Instrument
Unamortized debt issuance costs			6,200,000	$ 6,200,000
Unamortized discount			1,900,000	1,900,000
Unamortized debt issuance costs and discount			$ 8,031,000	$ 8,031,000
Interest rate (as a percent)		3.90%	3.90%	3.90%
Effective rate		3.93%	4.01%	4.01%
Principal amount		$ 750,000,000
Debt instrument issuance price, at par percentage		99.748%
Long-term Debt, Excluding Current Maturities			$ 741,969,000	$ 741,969,000
Proceeds from Issuance of Unsecured Debt		$ 741,900,000
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument
Interest rate margin (as a percent)				1.125%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument
Interest rate margin (as a percent)				2.00%
Base Rate [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument
Interest rate margin (as a percent)				0.125%
Base Rate [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument
Interest rate margin (as a percent)				1.00%

DERIVATIVE INSTRUMENTS_HEDGIN31

DERIVATIVE INSTRUMENTS/HEDGING (Details) bbl / qtr in Thousands, MMBTU / D in Thousands	6 Months Ended
	Jun. 30, 2017bbl / qtrMMBTU / D$ / bbl$ / MMBTU
Derivative Contract Oil Collar W T I Index [Member] | 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	3,588
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	46.73
Ceiling, weighted average price (in dollars per unit) | $ / bbl	56.55
Derivative Contract Oil Collar W T I Index [Member] | 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	550
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	41.67
Ceiling, weighted average price (in dollars per unit) | $ / bbl	54.19
Derivative Contract Oil Collar W T I Index [Member] | Third Quarter - 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	2,024
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	46.25
Ceiling, weighted average price (in dollars per unit) | $ / bbl	56.06
Derivative Contract Oil Collar W T I Index [Member] | Third Quarter - 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	182
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	41.49
Ceiling, weighted average price (in dollars per unit) | $ / bbl	53.89
Derivative Contract Oil Collar W T I Index [Member] | Fourth Quarter - 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	1,564
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	47.35
Ceiling, weighted average price (in dollars per unit) | $ / bbl	57.18
Derivative Contract Oil Collar W T I Index [Member] | Fourth Quarter - 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	368
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	41.75
Ceiling, weighted average price (in dollars per unit) | $ / bbl	54.34
Derivative Contract Oil Collar W T I Index [Member] | 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	1,810
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	48.60
Ceiling, weighted average price (in dollars per unit) | $ / bbl	57.74
Derivative Contract Oil Collar W T I Index [Member] | 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	1,092
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	41.75
Ceiling, weighted average price (in dollars per unit) | $ / bbl	54.34
Derivative Contract Oil Collar W T I Index [Member] | First Quarter - 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	1,080
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	48.33
Ceiling, weighted average price (in dollars per unit) | $ / bbl	58.33
Derivative Contract Oil Collar W T I Index [Member] | First Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	360
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	41.75
Ceiling, weighted average price (in dollars per unit) | $ / bbl	54.34
Derivative Contract Oil Collar W T I Index [Member] | Second Quarter - 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	546
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	49.33
Ceiling, weighted average price (in dollars per unit) | $ / bbl	57.56
Derivative Contract Oil Collar W T I Index [Member] | Second Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	364
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	41.75
Ceiling, weighted average price (in dollars per unit) | $ / bbl	54.34
Derivative Contract Oil Collar W T I Index [Member] | Third Quarter - 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	184
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	48
Ceiling, weighted average price (in dollars per unit) | $ / bbl	54.76
Derivative Contract Oil Collar W T I Index [Member] | Third Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | bbl / qtr	368
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	41.75
Ceiling, weighted average price (in dollars per unit) | $ / bbl	54.34
Derivative Contract Gas Collar PEPL Index [Member] | 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	19,320
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.65
Ceiling, weighted average price (in dollars per unit)	3.15
Derivative Contract Gas Collar PEPL Index [Member] | 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	2,750
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.46
Ceiling, weighted average price (in dollars per unit)	2.65
Derivative Contract Gas Collar PEPL Index [Member] | Third Quarter - 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	11,040
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.60
Ceiling, weighted average price (in dollars per unit)	3.12
Derivative Contract Gas Collar PEPL Index [Member] | Third Quarter - 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	910
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.47
Ceiling, weighted average price (in dollars per unit)	2.66
Derivative Contract Gas Collar PEPL Index [Member] | Fourth Quarter - 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	8,280
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.72
Ceiling, weighted average price (in dollars per unit)	3.20
Derivative Contract Gas Collar PEPL Index [Member] | Fourth Quarter - 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.45
Ceiling, weighted average price (in dollars per unit)	2.65
Derivative Contract Gas Collar PEPL Index [Member] | 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	8,130
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.68
Ceiling, weighted average price (in dollars per unit)	3.20
Derivative Contract Gas Collar PEPL Index [Member] | 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,460
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.45
Ceiling, weighted average price (in dollars per unit)	2.65
Derivative Contract Gas Collar PEPL Index [Member] | First Quarter - 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,400
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.73
Ceiling, weighted average price (in dollars per unit)	3.23
Derivative Contract Gas Collar PEPL Index [Member] | First Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,800
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.45
Ceiling, weighted average price (in dollars per unit)	2.65
Derivative Contract Gas Collar PEPL Index [Member] | Second Quarter - 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	2,730
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.57
Ceiling, weighted average price (in dollars per unit)	3.14
Derivative Contract Gas Collar PEPL Index [Member] | Second Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,820
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.45
Ceiling, weighted average price (in dollars per unit)	2.65
Derivative Contract Gas Collar PEPL Index [Member] | Third Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.45
Ceiling, weighted average price (in dollars per unit)	2.65
Derivative Contract Gas Collar Perm EP [Member] | 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	12,880
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.68
Ceiling, weighted average price (in dollars per unit)	3.16
Derivative Contract Gas Collar Perm EP [Member] | 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	2,750
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.36
Ceiling, weighted average price (in dollars per unit)	2.56
Derivative Contract Gas Collar Perm EP [Member] | Third Quarter - 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	7,360
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.63
Ceiling, weighted average price (in dollars per unit)	3.13
Derivative Contract Gas Collar Perm EP [Member] | Third Quarter - 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	910
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.37
Ceiling, weighted average price (in dollars per unit)	2.57
Derivative Contract Gas Collar Perm EP [Member] | Fourth Quarter - 2017 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,520
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.74
Ceiling, weighted average price (in dollars per unit)	3.20
Derivative Contract Gas Collar Perm EP [Member] | Fourth Quarter - 2017 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.35
Ceiling, weighted average price (in dollars per unit)	2.55
Derivative Contract Gas Collar Perm EP [Member] | 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,420
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.67
Ceiling, weighted average price (in dollars per unit)	3.16
Derivative Contract Gas Collar Perm EP [Member] | 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	5,460
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.35
Ceiling, weighted average price (in dollars per unit)	2.55
Derivative Contract Gas Collar Perm EP [Member] | First Quarter - 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	3,600
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.75
Ceiling, weighted average price (in dollars per unit)	3.22
Derivative Contract Gas Collar Perm EP [Member] | First Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,800
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.35
Ceiling, weighted average price (in dollars per unit)	2.55
Derivative Contract Gas Collar Perm EP [Member] | Second Quarter - 2018 [Member] | Outstanding as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,820
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.50
Ceiling, weighted average price (in dollars per unit)	3.04
Derivative Contract Gas Collar Perm EP [Member] | Second Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,820
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.35
Ceiling, weighted average price (in dollars per unit)	2.55
Derivative Contract Gas Collar Perm EP [Member] | Third Quarter - 2018 [Member] | Subsequent as of June 30, 2017
Fair values of derivative assets and liabilities
Volume | MMBTU / D	1,840
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.35
Ceiling, weighted average price (in dollars per unit)	2.55
Maximum [Member]
Derivative
Percent of oil and gas production available for hedging	50.00%

DERIVATIVE INSTRUMENTS_HEDGIN32

DERIVATIVE INSTRUMENTS/HEDGING - (Gain) loss on derivative instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Derivative instruments/hedging
Change in fair value of derivative instruments, net	$ (22,166)	$ 37,095	$ (72,087)	$ 41,735
Cash (receipts) payments on derivative instruments, net	(343)	(3,859)	5,717	(8,927)
(Gain) loss on derivative instruments, net	$ (22,509)	$ 33,236	$ (66,370)	$ 32,808

DERIVATIVE INSTRUMENTS_HEDGIN33

DERIVATIVE INSTRUMENTS/HEDGING - Derivative assets and liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Asset
Total gross amounts presented in accompanying balance sheet	$ 19,803
Liability
Total gross amounts presented in accompanying balance sheet	98	$ 49,370
Not Designated as Hedging Instrument [Member]
Asset
Total gross amounts presented in accompanying balance sheet	20,245
Less: gross amounts not offset in the accompanying balance sheet	(98)
Net amount:	20,147
Liability
Total gross amounts presented in accompanying balance sheet	98	51,940
Less: gross amounts not offset in the accompanying balance sheet	(98)
Net amount:		51,940
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	14,756
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Non-Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	442
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet		27,892
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Non-Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet		1,059
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	5,047
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet	$ 98	21,478
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Non-Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet		$ 1,511

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	Jun. 30, 2017	May 12, 2017	Apr. 10, 2017	Dec. 31, 2016
Financial Assets (Liabilities):
Derivative instruments — assets	$ 19,803
Derivative instruments — liabilities	(98)			$ (49,370)
Carrying Amount [Member]
Financial Assets (Liabilities):
Derivative instruments — assets	20,245
Derivative instruments — liabilities	(98)			(51,940)
Fair Value [Member]
Financial Assets (Liabilities):
Derivative instruments — assets	20,245
Derivative instruments — liabilities	$ (98)			$ (51,940)
Senior Notes 5.875% [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	5.875%	5.875%	5.875%	5.875%
Senior Notes 5.875% [Member] | Carrying Amount [Member]
Financial Assets (Liabilities):
Long-term debt				$ (750,000)
Senior Notes 5.875% [Member] | Fair Value [Member]
Financial Assets (Liabilities):
Long-term debt				$ (782,835)
Senior Notes 4.375% [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	4.375%			4.375%
Senior Notes 4.375% [Member] | Carrying Amount [Member]
Financial Assets (Liabilities):
Long-term debt	$ (750,000)			$ (750,000)
Senior Notes 4.375% [Member] | Fair Value [Member]
Financial Assets (Liabilities):
Long-term debt	$ (787,748)			$ (779,453)
Senior Notes 3.90% [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	3.90%		3.90%
Senior Notes 3.90% [Member] | Carrying Amount [Member]
Financial Assets (Liabilities):
Long-term debt	$ (750,000)
Senior Notes 3.90% [Member] | Fair Value [Member]
Financial Assets (Liabilities):
Long-term debt	$ (754,335)

FAIR VALUE MEASUREMENTS - Other

FAIR VALUE MEASUREMENTS - Other instruments (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Other Financial Instruments
Liabilities representing checks issued but not yet presented for payment	$ 39.5	$ 19.3
Accrued payroll related general and administrative expenses	28.7	43.5
Accrued operating expenses	55.2	53.9
Allowance for Trade Receivables [Member]
Other Financial Instruments
Aggregate allowance for doubtful accounts	$ 1.8	$ 1.6

CAPITAL STOCK (Details)

CAPITAL STOCK (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	May 31, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Capital Stock
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	$ 0.16	$ 0.16
Dividend payable
Dividend declared from APIC				$ 15,237

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	$ 11,225	$ 12,714	$ 23,217	$ 23,228
Less amounts capitalized to oil and gas properties	(4,932)	(5,224)	(10,636)	(10,210)
Compensation expense	6,293	7,490	12,581	13,018
Retained earnings (Accumulated deficit)	(465,366)		(465,366)		$ (722,359)
Additional paid-in capital	2,774,597		2,774,597		$ 2,763,452
Net cash (used) provided by financing activities			(47,257)	(25,451)
Net cash provided by operating activities			504,800	217,786
Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	10,646	11,966	21,972	21,825
Performance Based Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	6,438	7,215	12,840	12,909
Service Based Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	4,208	4,751	9,132	8,916
Employee Stock Option [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	579	$ 748	1,245	1,403
Accounting Standards Update 2016 09 [Member]
Options, Restricted Stock and Unit Awards
Deferred income tax assets	33,100		33,100
Retained earnings (Accumulated deficit)	28,700		28,700
Additional paid-in capital	$ 4,400		$ 4,400
Net cash (used) provided by financing activities				4,100
Net cash provided by operating activities				$ 4,100

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Asset Retirement Obligations
Balance at beginning of year	$ 154,523
Liabilities incurred	4,104
Liability settlements and disposals	(7,550)
Accretion expense	3,749
Revisions of estimated liabilities	1,763
Balance at end of year	$ 154,523	$ 156,589	$ 154,523
Less current obligation		(9,226)
Long-term asset retirement obligation		$ 147,363	$ 140,770

EARNINGS (LOSS) PER SHARE (Deta

EARNINGS (LOSS) PER SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Basic:
Net income (loss)	$ 97,262	$ (214,454)	$ 228,234	$ (445,913)
Participating securities' share in earnings (in dollars)	(1,643)		(3,898)
Net income (loss) applicable to common stockholders	95,619	(214,454)	224,336	(445,913)
Diluted:
Net income (loss)	97,262	(214,454)	228,234	(445,913)
Participating securities' share in earnings (in dollars)	(1,642)		(3,897)
Net income (loss) applicable to common stockholders	$ 95,620	$ (214,454)	$ 224,337	$ (445,913)
Shares:
Basic shares outstanding	93,402,000	93,075,000	93,396,000	93,075,000
Dilutive effect of stock options	33,000		35,000
Fully diluted common stock (in shares)	93,435,000	93,075,000	93,431,000	93,075,000
Earnings per share to common shareholders
Basic (in dollars per share)	$ 1.02	$ (2.31)	$ 2.40	$ (4.79)
Diluted (in dollars per share)	$ 1.02	$ (2.31)	$ 2.40	$ (4.79)
Excluded antidilutive securities (in shares)	300,500	2,300,000	255,000	2,300,000

INCOME TAXES - Components of th

INCOME TAXES - Components of the Provision for income taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Tax Expense (Benefit)
Current tax benefit			$ (6)
Deferred tax expense (benefit)	$ 58,617	$ (122,361)	136,929	$ (254,424)
Total income tax expense (benefits)	$ 58,617	$ (122,361)	$ 136,923	$ (254,424)
Combined federal and state effective income tax rate	37.60%	36.30%	37.50%	36.30%

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Income Taxes
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 - Other Commitments (Details) $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)
Drilling Commitments [Member]
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 159.6
Gathering System Construction [Member]
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 13.7

COMMITMENTS AND CONTINGENCIES43

COMMITMENTS AND CONTINGENCIES - Other Commitments - Delivery, operating leases (Details) $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)Bcf
Non-cancelable operating leases
Future minimum operating lease arrangements	$ 92
Natural Gas Sales Contracts [Member]
Delivery Commitments
Volume of gas deliverable (in Bcf) | Bcf	181.3
Delivery term	7 years 7 months 6 days
Financial commitment upon nondelivery	$ 451.9
Gas Gathering And Processing Agreements [Member]
Delivery Commitments
Delivery term	9 years
Financial commitment upon nondelivery	$ 322.3
Minimum Volume Agreement [Member]
Delivery Commitments
Financial commitment upon nondelivery	13.5
Accrued liabilities	1.9
Other Transportation, Delivery And Facilities Commitments [Member]
Delivery Commitments
Financial commitment upon nondelivery	$ 40

SUPPLEMENTAL DISCLOSURE OF CA44

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Cash paid during the period for:
Interest expense (net of capitalized amounts of $11,659, $9,917, $11,962, and $10,057, respectively)	$ 28,115	$ 29,223	$ 28,772	$ 29,677
Income taxes	1	2	3	13
Cash received for income tax refunds			21	25
Interest capitalized	$ 11,659	$ 9,917	$ 11,962	$ 10,057