Cimarex Energy (CIMXP) 10-Q 10 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 30, 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	Mar. 31, 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		95,108,619
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 578,908	$ 652,876
Accounts receivable:
Trade, net of allowance	69,324	42,287
Oil and gas sales, net of allowance	238,149	217,395
Gas gathering, processing, and marketing, net of allowance	11,657	14,888
Other	12	27
Oil and gas well equipment and supplies	37,487	33,342
Derivative instruments	6,381
Prepaid expenses	5,715	7,335
Other current assets	1,594	1,154
Total current assets	949,227	969,304
Oil and gas properties at cost, using the full cost method of accounting:
Proved properties	16,519,581	16,225,495
Unproved properties and properties under development, not being amortized	489,888	478,277
Gross oil and gas properties	17,009,469	16,703,772
Less - accumulated depreciation, depletion, amortization and impairment	(14,434,516)	(14,349,505)
Net oil and gas properties	2,574,953	2,354,267
Fixed assets, net of accumulated depreciation of $257,561 and $246,901, respectively	203,917	205,465
Goodwill	620,232	620,232
Derivative instruments	2,438
Deferred income taxes	10,424	55,835
Other assets, net	32,808	32,621
Total assets	4,393,999	4,237,724
Accounts payable:
Trade	62,035	49,163
Gas gathering, processing, and marketing	24,147	25,323
Accrued liabilities:
Exploration and development	73,420	82,320
Taxes other than income	15,554	18,766
Other	179,952	177,695
Derivative instruments	10,838	49,370
Revenue payable	141,376	119,715
Total current liabilities	507,322	522,352
Long-term debt:
Principal	1,500,000	1,500,000
Less - unamortized debt issuance costs	(11,500)	(12,061)
Long-term debt, net	1,488,500	1,487,939
Asset retirement obligation	144,523	140,770
Derivative instruments		2,570
Other liabilities	42,705	41,104
Total liabilities	2,183,050	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, 95,116,764 and 95,123,525 shares issued, respectively	951	951
Additional paid-in capital	2,771,296	2,763,452
Retained earnings (Accumulated deficit)	(562,645)	(722,359)
Accumulated other comprehensive income	1,347	945
Total stockholders' equity	2,210,949	2,042,989
Total liabilities and stockholders' equity	$ 4,393,999	$ 4,237,724

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Condensed Consolidated Balance Sheets
Fixed assets, accumulated depreciation (in dollars)	$ 257,561	$ 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	95,116,764	95,123,525

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues:
Oil sales	$ 224,066,000	$ 117,573,000
Gas sales	131,945,000	82,608,000
NGL sales	80,426,000	33,352,000
Gas gathering and other	10,625,000	7,241,000
Gas marketing, net of related costs of $39,853 and $25,312 respectively	114,000	(174,000)
Total revenues	447,176,000	240,600,000
Costs and expenses:
Impairment of oil and gas properties	0	318,786,000
Depreciation, depletion and amortization	95,816,000	110,636,000
Asset retirement obligation	1,620,000	2,298,000
Production	62,421,000	70,702,000
Transportation, processing and other operating	55,023,000	46,443,000
Gas gathering and other	8,427,000	8,080,000
Taxes other than income	21,313,000	13,839,000
General and administrative	18,034,000	13,897,000
Stock compensation	6,288,000	5,528,000
(Gain) loss on derivative instruments, net	(43,861,000)	(428,000)
Other operating, net	616,000	90,000
Total costs and expenses	225,697,000	589,871,000
Operating income (loss)	221,479,000	(349,271,000)
Other (income) and expense:
Interest expense	21,052,000	20,805,000
Capitalized interest	(6,641,000)	(4,904,000)
Other, net	(2,210,000)	(1,650,000)
Income (loss) before income tax	209,278,000	(363,522,000)
Income tax expense (benefit)	78,306,000	(132,063,000)
Net income (loss)	$ 130,972,000	$ (231,459,000)
Earnings (loss) per share to common stockholders:
Basic (in dollars per share)	$ 1.38	$ (2.49)
Diluted (in dollars per share)	1.38	(2.49)
Dividends declared (in dollars per share)	$ 0.08	$ 0.08
Comprehensive income (loss):
Net income (loss)	$ 130,972,000	$ (231,459,000)
Other comprehensive income:
Change in fair value of investments, net of tax of $231 and $49, respectively	402,000	85,000
Total comprehensive income (loss)	$ 131,374,000	$ (231,374,000)

CONSOLIDATED STATEMENTS OF OPE5

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Consolidated Statements of Operations and Comprehensive Income (Loss)
Gas marketing, related costs	$ 39,853	$ 25,312
Change in fair value investments, tax	$ 231	$ 49

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 130,972,000	$ (231,459,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Impairments and other valuation losses	0	318,786,000
Depreciation, depletion and amortization	95,816,000	110,636,000
Asset retirement obligation	1,620,000	2,298,000
Deferred tax expense (benefit)	78,312,000	(132,063,000)
Stock compensation	6,288,000	5,528,000
(Gain) loss on derivative instruments	(43,861,000)	(428,000)
Settlements on derivative instruments	(6,060,000)	5,068,000
Changes in non-current assets and liabilities	1,019,000	1,863,000
Other, net	1,728,000	1,362,000
Changes in operating assets and liabilities:
Receivables	(44,662,000)	33,147,000
Other current assets	(2,965,000)	11,982,000
Accounts payable and other current liabilities	31,307,000	(41,315,000)
Net cash provided by operating activities	249,514,000	85,405,000
Cash flows from investing activities:
Oil and gas expenditures	(311,841,000)	(176,395,000)
Sales of oil and gas assets	4,901,000	12,971,000
Sales of other assets	45,000	88,000
Other capital expenditures	(8,082,000)	(9,477,000)
Net cash used by investing activities	(314,977,000)	(172,813,000)
Cash flows from financing activities:
Dividends paid	(7,577,000)	(15,104,000)
Employee withholding taxes paid when directly withholding shares on vested stock awards	(938,000)	(345,000)
Proceeds from exercise of stock options and other	10,000	114,000
Net cash used by financing activities	(8,505,000)	(15,335,000)
Net change in cash and cash equivalents	(73,968,000)	(102,743,000)
Cash and cash equivalents at beginning of period	652,876,000	779,382,000
Cash and cash equivalents at end of period	$ 578,908,000	$ 676,639,000

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - 3 months ended Mar. 31, 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			3		3
Dividends in Excess of Retained Earnings		(7,609)			(7,609)
Net income			130,972		130,972
Unrealized change in fair value of investments, net of tax				402	402
Issuance of restricted stock awards, shares	5
Common stock reacquired and retired		(938)			(938)
Common stock reacquired and retired, shares	(8)
Restricted stock forfeited and retired, shares	(5)
Exercise of stock options		36			36
Exercise of stock options, shares	1
Stock-based compensation		11,988			11,988
Cumulative effect adjustment of adopting ASU 2016-09		4,393	28,739		33,132
Other		(26)			(26)
Balance at Mar. 31, 2017	$ 951	$ 2,771,296	$ (562,645)	$ 1,347	$ 2,210,949
Balance, shares at Mar. 31, 2017	95,117

BASIS OF PRESENTATION

BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 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 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. 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 are also 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 March 31, 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 subject to amortization 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, less the related income tax effects. Estimated future net revenues are determined by proved reserve quantities and commodity prices net of operating costs and capital expenditures. At March 31, 2017, the carrying value of our oil and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, no ceiling test impairment was recognized. At March 31, 2016, we recognized a ceiling test impairment of $318.8 million ($202.6 million, net of tax). This impairment resulted primarily from decreases in the 12-month average trailing 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 ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and 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	3 Months Ended
	Mar. 31, 2017
Long-term debt
LONG-TERM DEBT	2. Debt at March 31, 2017 and December 31, 2016 consisted of the following: March 31, 2017 December 31, 2016 Unamortized Debt Long-term Unamortized Debt Long-term (in thousands) Principal Issuance Costs Debt, net Principal Issuance Costs Debt, net 5.875% Senior Notes $ 750,000 $ (5,381) $ 744,619 $ 750,000 $ (5,691) $ 744,309 4.375% Senior Notes 750,000 (6,119) 743,881 750,000 (6,370) 743,630 Total long-term debt $ 1,500,000 $ (11,500) $ 1,488,500 $ 1,500,000 $ (12,061) $ 1,487,939 At March 31, 2017 and December 31, 2016, we had no bank debt outstanding. 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 March 31, 2017, we had letters of credit outstanding under the Credit Facility of $2.5 million, leaving an unused borrowing availability of $997.5 million. At our option, borrowings under the Credit Facility 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 March 31, 2017, we were in compliance with all of the financial and non-financial covenants. At March 31, 2017 and December 31, 2016, we had $4. 2 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 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 March 31, 2017. The 5.875% notes are due in 2022 and the 4.375% notes are due in 2024. Interest on each of the senior notes is payable semiannually. The effective interest rate on the 5.875% notes and the 4.375% notes, including the amortization of debt issuance costs, is 6.04% and 4.50%, respectively. Subsequent Events On April 3, 2017, we commenced 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. The tender offer expired on April 7, 2017, with $253.5 million aggregate principal amount of the notes validly tendered. On April 10, 2017, we settled the tendered notes for $268.1 million, including accrued interest. On April 12, 2017, we delivered a redemption notice pursuant to the terms of the indenture for all 5.875% notes remaining outstanding. All such notes will be redeemed on or before May 12, 2017 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. On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum. We received $743.2 million in net proceeds, after deducting underwriting discounts. We estimate an additional $1.5 million of offering costs will be deducted from these net proceeds. 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, and intend to use, the proceeds to fund the settlement of the tendered 5.875% notes and the redemption of the 5.875% notes, both as discussed above.

DERIVATIVE INSTRUMENTS_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING	3 Months Ended
	Mar. 31, 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. 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. We may enter into derivative instruments covering up to 50% of our oil and natural gas production on a forward five quarter basis. The following tables summarize our outstanding derivative contracts as of March 31, 2017: First Second Third Fourth Quarter Quarter Quarter Quarter Total Oil Collars: 2017: WTI (1) Volume (Bbls) — 2,184,000 1,840,000 1,380,000 5,404,000 Wtd Avg Price - Floor $ — $ 44.23 $ 46.08 $ 47.27 $ 45.63 Wtd Avg Price - Ceiling $ — $ 53.91 $ 56.19 $ 57.51 $ 55.61 2018: WTI (1) Volume (Bbls) 900,000 364,000 — — 1,264,000 Wtd Avg Price - Floor $ 48.40 $ 50.00 $ — $ — $ 48.86 Wtd Avg Price - Ceiling $ 59.05 $ 58.96 $ — $ — $ 59.02 (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) — 12,740,000 11,040,000 8,280,000 32,060,000 Wtd Avg Price - Floor $ — $ 2.53 $ 2.60 $ 2.72 $ 2.60 Wtd Avg Price - Ceiling $ — $ 3.06 $ 3.12 $ 3.20 $ 3.12 Perm EP (2) Volume (MMBtu) — 9,410,000 7,360,000 5,520,000 22,290,000 Wtd Avg Price - Floor $ — $ 2.58 $ 2.63 $ 2.74 $ 2.64 Wtd Avg Price - Ceiling $ — $ 3.09 $ 3.13 $ 3.20 $ 3.13 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. 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 on derivative instruments, net for the periods indicated. Three Months Ended March 31, Gain on Derivative Instruments, Net (in thousands): 2017 2016 Change in fair value of derivative instruments, net $ (49,921) $ 4,640 Cash payments (receipts) on derivative instruments, net 6,060 (5,068) Gain on derivative instruments, net $ (43,861) $ (428) 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 March 31, 2017 and December 31, 2016, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts. March 31, 2017: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 4,216 $ — Gas contracts Current assets — Derivative instruments 2,165 — Oil contracts Non-current assets — Derivative instruments 770 — Gas contracts Non-current assets — Derivative instruments 1,668 — Oil contracts Current liabilities — Derivative instruments — 6,206 Gas contracts Current liabilities — Derivative instruments — 4,632 Total gross amounts presented in the balance sheet 8,819 10,838 Less: gross amounts not offset in the balance sheet (7,531) (7,531) Net amount: $ 1,288 $ 3,307 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 — Other liabilities — 1,059 Gas contracts Non-current liabilities — Other liabilities — 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	3 Months Ended
	Mar. 31, 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 March 31, 2017 and December 31, 2016: March 31, 2017 December 31, 2016 Book Fair Book Fair (in thousands) Value Value Value Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ (750,000) $ (774,270) $ (750,000) $ (782,835) 4.375% Notes due 2024 $ (750,000) $ (781,950) $ (750,000) $ (779,453) Derivative instruments — assets $ 8,819 $ 8,819 $ — $ — Derivative instruments — liabilities $ (10,838) $ (10,838) $ (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 4.375% and 5.875% 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 March 31, 2017 are: (i) liabilities of approximately $26.9 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts; (ii) accrued operating expenses of approximately $54.5 million; and (iii) accrued interest of approximately $29.8 million, primarily related to our senior unsecured notes. Included in “Accrued liabilities — other” at December 31, 2016 are: (i) 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; (ii) accrued operating expenses of approximately $53.9 million; and (iii) accrued payroll-related costs of approximately $43.5 million. Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At March 31, 2017 and December 31, 2016, the allowance for doubtful accounts was $1.8 million and $1.6 million, respectively.

CAPITAL STOCK

CAPITAL STOCK	3 Months Ended
	Mar. 31, 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 March 31, 2017, there were 95.1 million shares of common stock and no shares of preferred stock outstanding. Dividends In February 2017, the Board of Directors declared a cash dividend of $0.08 per share. The dividend is payable on June 1, 2017, to stockholders of record on May 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 $7.6 million dividend declared in February 2017 was recorded as a reduction of additional paid-in capital. Nonforfeitable dividends paid on stock awards that forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to compensation cost 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 the Board of Directors.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	3 Months Ended
	Mar. 31, 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 March 31, (in thousands) 2017 2016 Restricted stock awards Performance stock awards $ 6,402 $ 5,694 Service-based stock awards 4,924 4,165 11,326 9,859 Stock option awards 666 655 Total stock compensation cost 11,992 10,514 Less amounts capitalized to oil and gas properties (5,704) (4,986) Compensation expense $ 6,288 $ 5,528 Expense associated with stock compensation will fluctuate based on the grant-date fair value of awards, the number of awards, and the timing of the awards. The increase in expense in 2017 as compared to 2016 is primarily due to new performance stock awards granted in December 2016 and service-based stock awards granted in June 2016, partially offset by the vesting of awards subsequent to March 31, 2016 and before March 31, 2017. Additionally, pursuant to Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which we adopted on January 1, 2017, 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. This also contributed to the increase in stock compensation expense in 2017 as compared to 2016. ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments 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 relating to those amendments, representing an increase to beginning deferred income tax assets of $33.1 million, a reduction to beginning accumulated deficit of $28.7 million, and an increase to beginning additional paid-in capital of $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 three months ended March 31, 2016 by increasing net cash provided by operating activities by $0.3 million and increasing net cash used by financing activities by $0.3 million for the effects of tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the three months ended March 31, 2017 and 2016.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2017: (in thousands) Asset retirement obligation at January 1, 2017 $ 154,523 Liabilities incurred 1,522 Liability settlements and disposals (2,035) Accretion expense 1,857 Revisions of estimated liabilities 386 Asset retirement obligation at March 31, 2017 156,253 Less current obligation (11,730) Long-term asset retirement obligation $ 144,523

EARNINGS (LOSS) PER SHARE

EARNINGS (LOSS) PER SHARE	3 Months Ended
	Mar. 31, 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 March 31, (in thousands, except per share data) 2017 2016 Basic: Net income (loss) $ 130,972 $ (231,459) Participating securities’ share in earnings (1) (2,255) — Net income (loss) available to common stockholders $ 128,717 $ (231,459) Diluted: Net income (loss) $ 130,972 $ (231,459) Participating securities’ share in earnings (1) (2,254) — Net income (loss) available to common stockholders $ 128,718 $ (231,459) Shares: Basic shares outstanding 93,389 93,000 Dilutive effect of potential common shares (2) 39 — Fully diluted common stock 93,428 93,000 Earnings (loss) per share to common stockholders (3): Basic $ 1.38 $ (2.49) Diluted $ 1.38 $ (2.49) (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, 161,818 and 2,117,204 shares were excluded from the calculations for the three months ended March 31, 2017 and 2016, respectively. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2017
Income Taxes
INCOME TAXES	9. The components of our provision for income taxes are as follows: Three Months Ended March 31, Income Tax Expense (Benefit) (in thousands): 2017 2016 Current tax benefit $ (6) $ — Deferred tax expense (benefit) 78,312 (132,063) $ 78,306 $ (132,063) 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 would 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 March 31, 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	3 Months Ended
	Mar. 31, 2017
Commitments and Contingencies
COMMITMENTS AND CONTINGENCIES	10. Commitments At March 31, 2017, we had estimated commitments of approximately: (i) $145.5 million to finish drilling and completing wells and various other infrastructure projects in progress and (ii) $11.4 million to finish gathering system construction in progress. At March 31, 2017, we had firm sales contracts to deliver approximately 64.4 Bcf of natural gas over the next 19 months. If we do not deliver this gas, our estimated financial commitment, calculated using the April 2017 index price, would be approximately $169.4 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these obligations. 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 March 31, 2017, would be approximately $242.4 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 March 31, 2017, would be approximately $7.4 million. Of this total, we have accrued a liability of $2.1 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. As of March 31, 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 $41.4 million over the remaining terms of the agreements. We have various future commitments for office space under operating lease arrangements totaling approximately $94.3 million at March 31, 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	3 Months Ended
	Mar. 31, 2017
Supplemental Disclosure of Cash Flow Information:
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION	11. Three Months Ended March 31, (in thousands) 2017 2016 Cash paid during the period for: Interest expense (net of capitalized amounts of $303 and $140, respectively) $ 657 $ 454 Income taxes $ 2 $ 11 Cash received for income tax refunds $ 21 $ 25

BASIS OF PRESENTATION (Policies

BASIS OF PRESENTATION (Policies)	3 Months Ended
	Mar. 31, 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 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.
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 are also 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 March 31, 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 subject to amortization 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, less the related income tax effects. Estimated future net revenues are determined by proved reserve quantities and commodity prices net of operating costs and capital expenditures. At March 31, 2017, the carrying value of our oil and gas properties subject to the test did not exceed the calculated value of the ceiling limitation and, therefore, no ceiling test impairment was recognized. At March 31, 2016, we recognized a ceiling test impairment of $318.8 million ($202.6 million, net of tax). This impairment resulted primarily from decreases in the 12-month average trailing 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 ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and 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)	3 Months Ended
	Mar. 31, 2017
Long-term debt
Summary of debt	March 31, 2017 December 31, 2016 Unamortized Debt Long-term Unamortized Debt Long-term (in thousands) Principal Issuance Costs Debt, net Principal Issuance Costs Debt, net 5.875% Senior Notes $ 750,000 $ (5,381) $ 744,619 $ 750,000 $ (5,691) $ 744,309 4.375% Senior Notes 750,000 (6,119) 743,881 750,000 (6,370) 743,630 Total long-term debt $ 1,500,000 $ (11,500) $ 1,488,500 $ 1,500,000 $ (12,061) $ 1,487,939

DERIVATIVE INSTRUMENTS_HEDGING

DERIVATIVE INSTRUMENTS/HEDGING (Tables)	3 Months Ended
	Mar. 31, 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) — 2,184,000 1,840,000 1,380,000 5,404,000 Wtd Avg Price - Floor $ — $ 44.23 $ 46.08 $ 47.27 $ 45.63 Wtd Avg Price - Ceiling $ — $ 53.91 $ 56.19 $ 57.51 $ 55.61 2018: WTI (1) Volume (Bbls) 900,000 364,000 — — 1,264,000 Wtd Avg Price - Floor $ 48.40 $ 50.00 $ — $ — $ 48.86 Wtd Avg Price - Ceiling $ 59.05 $ 58.96 $ — $ — $ 59.02 (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) — 12,740,000 11,040,000 8,280,000 32,060,000 Wtd Avg Price - Floor $ — $ 2.53 $ 2.60 $ 2.72 $ 2.60 Wtd Avg Price - Ceiling $ — $ 3.06 $ 3.12 $ 3.20 $ 3.12 Perm EP (2) Volume (MMBtu) — 9,410,000 7,360,000 5,520,000 22,290,000 Wtd Avg Price - Floor $ — $ 2.58 $ 2.63 $ 2.74 $ 2.64 Wtd Avg Price - Ceiling $ — $ 3.09 $ 3.13 $ 3.20 $ 3.13 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.
Net (gains) and losses from settlements and changes of derivative contracts	Three Months Ended March 31, Gain on Derivative Instruments, Net (in thousands): 2017 2016 Change in fair value of derivative instruments, net $ (49,921) $ 4,640 Cash payments (receipts) on derivative instruments, net 6,060 (5,068) Gain on derivative instruments, net $ (43,861) $ (428)
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	March 31, 2017: (in thousands) Balance Sheet Location Asset Liability Oil contracts Current assets — Derivative instruments $ 4,216 $ — Gas contracts Current assets — Derivative instruments 2,165 — Oil contracts Non-current assets — Derivative instruments 770 — Gas contracts Non-current assets — Derivative instruments 1,668 — Oil contracts Current liabilities — Derivative instruments — 6,206 Gas contracts Current liabilities — Derivative instruments — 4,632 Total gross amounts presented in the balance sheet 8,819 10,838 Less: gross amounts not offset in the balance sheet (7,531) (7,531) Net amount: $ 1,288 $ 3,307 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 — Other liabilities — 1,059 Gas contracts Non-current liabilities — Other liabilities — 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)	3 Months Ended
	Mar. 31, 2017
Fair Value Measurements
Fair value measurement information for certain assets and liabilities	March 31, 2017 December 31, 2016 Book Fair Book Fair (in thousands) Value Value Value Value Financial Assets (Liabilities): 5.875% Notes due 2022 $ (750,000) $ (774,270) $ (750,000) $ (782,835) 4.375% Notes due 2024 $ (750,000) $ (781,950) $ (750,000) $ (779,453) Derivative instruments — assets $ 8,819 $ 8,819 $ — $ — Derivative instruments — liabilities $ (10,838) $ (10,838) $ (51,940) $ (51,940)

STOCK-BASED AND OTHER COMPENSAT

STOCK-BASED AND OTHER COMPENSATION (Tables)	3 Months Ended
	Mar. 31, 2017
Stock-based Compensation
Recognition of non-cash stock-based compensation cost	Three Months Ended March 31, (in thousands) 2017 2016 Restricted stock awards Performance stock awards $ 6,402 $ 5,694 Service-based stock awards 4,924 4,165 11,326 9,859 Stock option awards 666 655 Total stock compensation cost 11,992 10,514 Less amounts capitalized to oil and gas properties (5,704) (4,986) Compensation expense $ 6,288 $ 5,528

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	3 Months Ended
	Mar. 31, 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 1,522 Liability settlements and disposals (2,035) Accretion expense 1,857 Revisions of estimated liabilities 386 Asset retirement obligation at March 31, 2017 156,253 Less current obligation (11,730) Long-term asset retirement obligation $ 144,523

EARNINGS (LOSS) PER SHARE (Tabl

EARNINGS (LOSS) PER SHARE (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings (Loss) per Share
Calculations of basic and diluted net earnings (loss) per common share under the two-class method	Three Months Ended March 31, (in thousands, except per share data) 2017 2016 Basic: Net income (loss) $ 130,972 $ (231,459) Participating securities’ share in earnings (1) (2,255) — Net income (loss) available to common stockholders $ 128,717 $ (231,459) Diluted: Net income (loss) $ 130,972 $ (231,459) Participating securities’ share in earnings (1) (2,254) — Net income (loss) available to common stockholders $ 128,718 $ (231,459) Shares: Basic shares outstanding 93,389 93,000 Dilutive effect of potential common shares (2) 39 — Fully diluted common stock 93,428 93,000 Earnings (loss) per share to common stockholders (3): Basic $ 1.38 $ (2.49) Diluted $ 1.38 $ (2.49) (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, 161,818 and 2,117,204 shares were excluded from the calculations for the three months ended March 31, 2017 and 2016, respectively. (3) Earnings (loss) per share are based on actual figures rather than the rounded figures presented.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2017
Income Taxes
Components of the provision for income taxes	Three Months Ended March 31, Income Tax Expense (Benefit) (in thousands): 2017 2016 Current tax benefit $ (6) $ — Deferred tax expense (benefit) 78,312 (132,063) $ 78,306 $ (132,063) Combined federal and state effective income tax rate % %

SUPPLEMENTAL DISCLOSURE OF CA27

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2017
Supplemental Disclosure of Cash Flow Information:
Supplemental Disclosure of Cash Flow Information	Three Months Ended March 31, (in thousands) 2017 2016 Cash paid during the period for: Interest expense (net of capitalized amounts of $303 and $140, respectively) $ 657 $ 454 Income taxes $ 2 $ 11 Cash received for income tax refunds $ 21 $ 25

BASIS OF PRESENTATION (Details)

BASIS OF PRESENTATION (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017	Mar. 31, 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		$ 202,600,000
Impairment of oil and gas properties	$ 0	$ 318,786,000

LONG-TERM DEBT - Summary (Detai

LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument
Principal	$ 1,500,000	$ 1,500,000
Less - unamortized debt issuance costs	(11,500)	(12,061)
Long-term debt, net	1,488,500	1,487,939
Senior Notes 5.875% [Member]
Debt Instrument
Principal	750,000	750,000
Less - unamortized debt issuance costs	(5,381)	(5,691)
Long-term debt, net	$ 744,619	$ 744,309
Interest rate (as a percent)	5.875%	5.875%
Senior Notes 4.375% [Member]
Debt Instrument
Principal	$ 750,000	$ 750,000
Less - unamortized debt issuance costs	(6,119)	(6,370)
Long-term debt, net	$ 743,881	$ 743,630
Interest rate (as a percent)	4.375%	4.375%

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)	Apr. 10, 2017	Mar. 31, 2017	May 12, 2017	Apr. 12, 2017	Apr. 07, 2017	Apr. 03, 2017	Dec. 31, 2016
Debt Instrument
Unamortized debt issuance costs		$ 11,500,000					$ 12,061,000
Long-term Debt, Excluding Current Maturities		1,488,500,000					1,487,939,000
Revolving Credit Facility [Member]
Debt Instrument
Unamortized debt issuance costs		4,200,000					4,500,000
Borrowings outstanding		0					0
Credit facility amount		1,000,000,000
Credit facility, increase amount option		1,250,000,000
Letters of credit outstanding under the credit facility		2,500,000
Unused borrowing availability		$ 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		$ 6,119,000					$ 6,370,000
Interest rate (as a percent)		4.375%					4.375%
Effective rate		4.50%
Long-term Debt, Excluding Current Maturities		$ 743,881,000					$ 743,630,000
Senior Notes 5.875% [Member]
Debt Instrument
Unamortized debt issuance costs		$ 5,381,000					$ 5,691,000
Interest rate (as a percent)		5.875%					5.875%
Effective rate		6.04%
Long-term Debt, Excluding Current Maturities		$ 744,619,000					$ 744,309,000
Senior Notes 5.875% [Member] | Subsequent Events
Debt Instrument
Interest rate (as a percent)				5.875%		5.875%
Settled tendered notes including accrued interest	$ 268,100,000
Principal amount					$ 253,500,000
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
Senior Unsecured Notes 3.90% [Member] | Subsequent Events
Debt Instrument
Interest rate (as a percent)	3.90%
Effective rate	3.93%
Principal amount	$ 750,000,000
Debt instrument issuance price, at par percentage	99.748%
Proceeds from Issuance of Unsecured Debt	$ 743,200,000
Estimated offering cost	$ 1,500,000
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	3 Months Ended
	Mar. 31, 2017bbl / qtrMMBTU / D$ / bbl$ / MMBTU
Derivative Contract Oil Collar W T I Index [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | bbl / qtr	5,404
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	45.63
Ceiling, weighted average price (in dollars per unit) | $ / bbl	55.61
Derivative Contract Oil Collar W T I Index [Member] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | bbl / qtr	2,184
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	44.23
Ceiling, weighted average price (in dollars per unit) | $ / bbl	53.91
Derivative Contract Oil Collar W T I Index [Member] | Third Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | bbl / qtr	1,840
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	46.08
Ceiling, weighted average price (in dollars per unit) | $ / bbl	56.19
Derivative Contract Oil Collar W T I Index [Member] | Fourth Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | bbl / qtr	1,380
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	47.27
Ceiling, weighted average price (in dollars per unit) | $ / bbl	57.51
Derivative Contract Oil Collar W T I Index [Member] | 2018 [Member]
Fair values of derivative assets and liabilities
Volume | bbl / qtr	1,264
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	48.86
Ceiling, weighted average price (in dollars per unit) | $ / bbl	59.02
Derivative Contract Oil Collar W T I Index [Member] | First Quarter - 2018 [Member]
Fair values of derivative assets and liabilities
Volume | bbl / qtr	900
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	48.40
Ceiling, weighted average price (in dollars per unit) | $ / bbl	59.05
Derivative Contract Oil Collar W T I Index [Member] | Second Quarter - 2018 [Member]
Fair values of derivative assets and liabilities
Volume | bbl / qtr	364
Weighted Average Price
Floor, weighted average price (in dollars per unit) | $ / bbl	50
Ceiling, weighted average price (in dollars per unit) | $ / bbl	58.96
Derivative Contract Gas Collar PEPL Index [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	32,060
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] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	12,740
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.53
Ceiling, weighted average price (in dollars per unit)	3.06
Derivative Contract Gas Collar PEPL Index [Member] | Third Quarter - 2017 [Member]
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] | Fourth Quarter - 2017 [Member]
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] | 2018 [Member]
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] | First Quarter - 2018 [Member]
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] | Second Quarter - 2018 [Member]
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 Perm EP [Member] | 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	22,290
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.64
Ceiling, weighted average price (in dollars per unit)	3.13
Derivative Contract Gas Collar Perm EP [Member] | Second Quarter - 2017 [Member]
Fair values of derivative assets and liabilities
Volume | MMBTU / D	9,410
Weighted Average Price
Floor, weighted average price (in dollars per unit)	2.58
Ceiling, weighted average price (in dollars per unit)	3.09
Derivative Contract Gas Collar Perm EP [Member] | Third Quarter - 2017 [Member]
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] | Fourth Quarter - 2017 [Member]
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] | 2018 [Member]
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] | First Quarter - 2018 [Member]
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] | Second Quarter - 2018 [Member]
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
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
	Mar. 31, 2017	Mar. 31, 2016
Derivative instruments/hedging
Change in fair value of derivative instruments, net	$ (49,921)	$ 4,640
Cash payments (receipts) on derivative instruments, net	6,060	(5,068)
Gain on derivative instruments, net	$ (43,861)	$ (428)

DERIVATIVE INSTRUMENTS_HEDGIN33

DERIVATIVE INSTRUMENTS/HEDGING - Derivative assets and liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Asset
Total gross amounts presented in accompanying balance sheet	$ 6,381
Liability
Total gross amounts presented in accompanying balance sheet	10,838	$ 49,370
Not Designated as Hedging Instrument [Member]
Asset
Total gross amounts presented in accompanying balance sheet	8,819
Less: gross amounts not offset in the accompanying balance sheet	(7,531)
Net amount:	1,288
Liability
Total gross amounts presented in accompanying balance sheet	10,838	51,940
Less: gross amounts not offset in the accompanying balance sheet	(7,531)
Net amount:	3,307	51,940
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	4,216
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Non-Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	770
Not Designated as Hedging Instrument [Member] | Oil Contracts [Member] | Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet	6,206	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	2,165
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Non-Current Assets [Member]
Asset
Total gross amounts presented in accompanying balance sheet	1,668
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member] | Current Liabilities [Member]
Liability
Total gross amounts presented in accompanying balance sheet	$ 4,632	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	Mar. 31, 2017	Dec. 31, 2016
Financial Assets (Liabilities):
Derivative instruments — assets	$ 6,381
Derivative instruments — liabilities	(10,838)	$ (49,370)
Carrying Amount [Member]
Financial Assets (Liabilities):
Derivative instruments — assets	8,819
Derivative instruments — liabilities	(10,838)	(51,940)
Fair Value [Member]
Financial Assets (Liabilities):
Derivative instruments — assets	8,819
Derivative instruments — liabilities	$ (10,838)	$ (51,940)
Senior Notes 5.875% [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	5.875%	5.875%
Senior Notes 5.875% [Member] | Carrying Amount [Member]
Financial Assets (Liabilities):
Long-term debt	$ (750,000)	$ (750,000)
Senior Notes 5.875% [Member] | Fair Value [Member]
Financial Assets (Liabilities):
Long-term debt	$ (774,270)	$ (782,835)
Senior Notes 5.875% [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	5.875%	5.875%
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	$ (781,950)	$ (779,453)
Senior Notes 4.375% [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Assets (Liabilities):
Interest rate (as a percent)	4.375%	4.375%

FAIR VALUE MEASUREMENTS - Other

FAIR VALUE MEASUREMENTS - Other instruments (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Other Financial Instruments
Liabilities representing checks issued but not yet presented for payment	$ 26.9	$ 19.3
Accrued interest	29.8
Accrued payroll related general and administrative expenses		43.5
Accrued operating expenses	54.5	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
	Feb. 28, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Capital Stock
Common stock, shares authorized		200,000,000		200,000,000
Preferred stock, shares authorized		15,000,000		15,000,000
Common stock outstanding (in shares)		95,100,000
Preferred stock outstanding (in shares)		0
Dividends
Dividends declared (in dollars per share)	$ 0.08	$ 0.08	$ 0.08
Dividend payable
Dividend declared from APIC	$ 7,600	$ 7,609

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	$ 11,992	$ 10,514
Less amounts capitalized to oil and gas properties	(5,704)	(4,986)
Compensation expense	6,288	5,528
Retained earnings (Accumulated deficit)	(562,645)		$ (722,359)
Additional paid-in capital	2,771,296		$ 2,763,452
Net cash (used) provided by financing activities	(8,505)	(15,335)
Net cash provided by operating activities	249,514	85,405
Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	11,326	9,859
Performance Based Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	6,402	5,694
Service Based Restricted Stock [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	4,924	4,165
Employee Stock Option [Member]
Options, Restricted Stock and Unit Awards
Compensation cost before capitalized cost	666	655
Accounting Standards Update 2016 09 [Member]
Options, Restricted Stock and Unit Awards
Deferred income taxes	33,100
Retained earnings (Accumulated deficit)	28,700
Additional paid-in capital	$ 4,400
Net cash (used) provided by financing activities		300
Net cash provided by operating activities		$ 300

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations
Balance at beginning of year	$ 154,523
Liabilities incurred	1,522
Liability settlements and disposals	(2,035)
Accretion expense	1,857
Revisions of estimated liabilities	386
Balance at end of year	$ 154,523	$ 156,253	$ 154,523
Less current obligation		(11,730)
Long-term asset retirement obligation		$ 144,523	$ 140,770

EARNINGS (LOSS) PER SHARE (Deta

EARNINGS (LOSS) PER SHARE (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Basic:
Net income (loss)	$ 130,972	$ (231,459)
Participating securities' share in earnings (in dollars)	(2,255)
Net income (loss) applicable to common stockholders	128,717	(231,459)
Diluted:
Net income (loss)	130,972	(231,459)
Participating securities' share in earnings (in dollars)	(2,254)
Net income (loss) applicable to common stockholders	$ 128,718	$ (231,459)
Shares:
Basic shares outstanding	93,389,000	93,000,000
Dilutive effect of stock options	39,000
Fully diluted common stock (in shares)	93,428,000	93,000,000
Earnings per share to common shareholders
Basic (in dollars per share)	$ 1.38	$ (2.49)
Diluted (in dollars per share)	$ 1.38	$ (2.49)
Excluded antidilutive securities (in shares)	161,818	2,117,204

INCOME TAXES - Components of th

INCOME TAXES - Components of the Provision for income taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Expense (Benefit)
Current tax benefit	$ (6)
Deferred tax expense (benefit)	78,312	$ (132,063)
Total income tax expense (benefits)	$ 78,306	$ (132,063)
Combined federal and state effective income tax rate	37.40%	36.30%

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 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	3 Months Ended
	Mar. 31, 2017USD ($)
Drilling Commitments [Member]
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 145.5
Gathering System Construction [Member]
Construction, Drilling and Purchase Commitments
Commitments for purchases and other expenditures	$ 11.4

COMMITMENTS AND CONTINGENCIES43

COMMITMENTS AND CONTINGENCIES - Other Commitments - Delivery, operating leases (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)Bcf
Non-cancelable operating leases
Future minimum operating lease arrangements	$ 94.3
Natural Gas Sales Contracts [Member]
Delivery Commitments
Volume of gas deliverable (in Bcf) | Bcf	64.4
Delivery term	19 months
Financial commitment upon nondelivery	$ 169.4
Gas Gathering And Processing Agreements [Member]
Delivery Commitments
Delivery term	9 years
Financial commitment upon nondelivery	$ 242.4
Minimum Volume Agreement [Member]
Delivery Commitments
Financial commitment upon nondelivery	7.4
Accrued liabilities	2.1
Other Transportation, Delivery And Facilities Commitments [Member]
Delivery Commitments
Financial commitment upon nondelivery	$ 41.4

SUPPLEMENTAL DISCLOSURE OF CA44

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash paid during the period for:
Interest expense (net of capitalized amounts of $303 and $140, respectively)	$ 657	$ 454
Income taxes	2	11
Cash received for income tax refunds	21	25
Interest capitalized	$ 303	$ 140