Civitas Resources (CIVI) 10-K 29 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	Bonanza Creek Energy, Inc.
Entity Central Index Key	1,509,589
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		49,741,134
Entity Public Float			$ 901,272,418

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 21,341	$ 2,584
Accounts receivable:
Oil and gas sales	25,322	54,574
Joint interest and other	31,224	37,202
Prepaid expenses and other	4,078	12,522
Inventory of oilfield equipment	8,543	15,353
Derivative asset	29,566	86,240
Total current assets	120,074	208,475
Property and equipment (successful efforts method), at cost:
Proved properties	1,618,970	1,924,380
Less: accumulated depreciation, depletion and amortization	(943,081)	(592,073)
Total proved properties, net	675,889	1,332,307
Unproved properties	185,530	206,721
Wells in progress	51,196	139,208
Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion and amortization of $636,917 in 2015 (note 3)	214,922	0
Natural gas plant, net of accumulated depreciation of $8,457 in 2014	0	67,840
Other property and equipment, net of accumulated depreciation of $9,407 in 2015 and $6,087 in 2014	9,729	10,401
Total property and equipment, net	1,137,266	1,756,477
Long-term derivative asset	0	17,765
Other noncurrent assets	16,027	23,372
Total assets	1,273,367	2,006,089
Current liabilities:
Accounts payable and accrued expenses (note 6)	96,360	145,788
Oil and gas revenue distribution payable	27,613	40,659
Contractual obligation for land acquisition	12,000	12,000
Total current liabilities	135,973	198,447
Long-term liabilities:
Long-term debt (note 7)	885,392	840,619
Contractual obligation for land acquisition	0	11,186
Ad valorem taxes	17,069	28,635
Deferred income taxes	0	165,667
Asset retirement obligations	14,935	21,464
Asset retirement obligations for assets held for sale	10,591	0
Total liabilities	$ 1,063,960	$ 1,266,018
Commitments and contingencies (note 8)
Stockholders’ equity:
Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding	$ 0	$ 0
Common stock, $.001 par value, 225,000,000 shares authorized, 49,754,408 and 41,287,270 issued and outstanding in 2015 and 2014, respectively	49	41
Additional paid-in capital	806,386	591,511
Retained earnings (deficit)	(597,028)	148,519
Total stockholders’ equity	209,407	740,071
Total liabilities and stockholders’ equity	$ 1,273,367	$ 2,006,089

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Oil and gas properties held for sale, accumulated depreciation, depletion and amortization (in dollars)	$ 636,917
Natural gas plant, accumulated depreciation (in dollars)		$ 8,457
Other property and equipment, accumulated depreciation (in dollars)	$ 9,407	$ 6,087
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	225,000,000	225,000,000
Common stock, shares issued	49,754,408	41,287,270
Common stock, shares outstanding	49,754,408	41,287,270

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating net revenues:
Oil and gas sales	$ 292,679	$ 558,633	$ 421,860
Operating expenses:
Lease operating expense	76,406	72,411	47,771
Severance and ad valorem taxes	18,629	50,430	27,203
Exploration	15,827	5,346	4,213
Depreciation, depletion and amortization	244,921	228,789	140,176
Impairment of oil and gas properties	740,478	167,592	0
Abandonment and impairment of unproved properties	33,543	0	0
General and administrative (including $14,552, $20,716, and $12,638, respectively, of stock-based compensation)	70,319	81,571	55,502
Total operating expenses	1,200,123	606,139	274,865
Income (loss) from operations	(907,444)	(47,506)	146,995
Other income (expense):
Derivative gain (loss)	56,558	121,615	(12,472)
Interest expense	(57,052)	(46,447)	(21,972)
Other income (loss)	(2,503)	345	(43)
Total other income (expense)	(2,997)	75,513	(34,487)
Income (loss) from continuing operations before taxes	(910,441)	28,007	112,508
Current income tax expense	(773)	(149)	(248)
Deferred income tax benefit (expense)	165,667	(10,876)	(42,678)
Income (loss) from continuing operations	(745,547)	16,982	69,582
Discontinued operations:
Loss from operations associated with oil and gas properties	0	(85)	(644)
Gain on sale of oil and gas properties	0	5,496	0
Income tax benefit (expense)	0	(2,110)	246
Gain (loss) from discontinued operations	0	3,301	(398)
Net income (loss)	(745,547)	20,283	69,184
Comprehensive income (loss)	$ (745,547)	$ 20,283	$ 69,184
Basic income (loss) per share:
Basic income (loss) per common share from continuing operations (in dollars per share)	$ (15.57)	$ 0.42	$ 1.73
Basic income per common share from discontinued operations (in dollars per share)	0	0.08	(0.01)
Basic net income (loss) per common share (in dollars per share)	(15.57)	0.50	1.72
Diluted income (loss) per share:
Diluted income (loss) per common share from continuing operations (in dollars per share)	(15.57)	0.41	1.72
Diluted income from discontinued operations (in dollars per share)	0	0.08	(0.01)
Diluted net income (loss) per common share (in dollars per share)	$ (15.57)	$ 0.49	$ 1.71
Basic weighted-average common shares outstanding	47,874	40,139	39,337
Diluted weighted-average common shares outstanding	47,874	40,290	39,403

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
General and administrative, stock compensation	$ 14,552	$ 20,716	$ 12,638

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (745,547)	$ 20,283	$ 69,184
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	244,921	228,856	140,547
Deferred income taxes	(165,667)	12,986	42,432
Impairment of oil and gas properties	740,478	167,592	0
Abandonment and impairment of unproved properties	33,543	0	0
Dry hole expense	5,630	0	1,709
Stock-based compensation	14,552	20,716	12,638
Amortization of deferred financing costs and debt premium	2,280	1,588	1,505
Accretion of contractual obligation for land acquisition	814	1,153	761
Derivative (gain) loss	(56,558)	(121,615)	12,472
Gain on sale of oil and gas properties	0	(5,322)	0
Other	1,429	(12)	(8)
Changes in current assets and liabilities:
Accounts receivable	35,230	(21,376)	(26,315)
Prepaid expenses and other assets	8,444	(10,884)	1,394
Accounts payable and accrued liabilities	(23,655)	35,392	50,897
Excess income tax benefit from the vesting of stock awards	0	0	(128)
Settlement of asset retirement obligations	(867)	(1,637)	(73)
Net cash provided by operating activities	95,027	327,720	307,015
Cash flows from investing activities:
Acquisition of oil and gas properties	(16,270)	(179,566)	(13,797)
Deposits for acquisitions	1,549	(1,549)	0
Proceeds from sale of oil and gas properties	0	6,700	0
Payments of contractual obligation	(12,000)	(12,000)	(12,000)
Exploration and development of oil and gas properties	(425,918)	(641,204)	(417,835)
Natural gas plant capital expenditures	(112)	(282)	(5,202)
Derivative cash settlements	130,996	12,238	(11,330)
(Increase) decrease in restricted cash	2,987	(3,062)	79
Additions to property and equipment - non oil and gas	(2,809)	(6,269)	(5,138)
Net cash used in investing activities	(321,577)	(824,994)	(465,223)
Cash flows from financing activities:
Proceeds from credit facility	137,000	263,000	102,000
Payments to credit facility	(91,000)	(230,000)	(260,000)
Proceeds from sale of common stock	209,308	0	0
Offering costs related to sale of common stock	(6,620)	0	0
Proceeds from sale of Senior Notes	0	300,000	500,000
Offering costs related to sale of Senior Notes	(99)	(7,070)	(11,721)
Payment of employee tax withholdings in exchange for the return of common stock	(2,683)	(6,007)	(4,440)
Deferred financing costs	(599)	(647)	(445)
Premium on Senior Notes	0	0	9,000
Excess income tax benefit from the vesting of stock awards	0	0	128
Net cash provided by financing activities	245,307	319,276	334,522
Net change in cash and cash equivalents	18,757	(177,998)	176,314
Cash and cash equivalents:
Beginning of period	2,584	180,582	4,268
End of period	21,341	2,584	180,582
Supplemental cash flow disclosure:
Cash paid for interest	54,566	36,325	12,860
Stock issued for the acquisition of oil and gas properties	0	49,050	0
Stock issued for litigation settlement	326	0	0
Cash paid for income taxes	820	1,400	100
Contractual obligation for land acquisition	12,000	22,033	33,272
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$ (50,385)	$ 1,873	$ 29,273

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY Statement - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings
Balance at beginning of period at Dec. 31, 2012	$ 578,518	$ 40	$ 519,426	$ 59,052
Shares outstanding, beginning of period (in shares) at Dec. 31, 2012		40,115,536
Restricted common stock issued, net of excess income tax benefit (in shares)		310,439
Restricted common stock issued, net of excess income tax benefit	128		128
Restricted common stock forfeited (in shares)		(31,817)
Restricted stock used for tax withholdings	(4,440)		(4,440)
Restricted stock used for tax withholdings (in shares)		(108,239)
Stock-based compensation	12,638		12,638
Net income (loss)	69,184			69,184
Balance at end of period at Dec. 31, 2013	656,028	$ 40	527,752	128,236
Shares outstanding, end of period (in shares) at Dec. 31, 2013		40,285,919
Restricted common stock issued, net of excess income tax benefit (in shares)		309,458
Restricted common stock forfeited (in shares)		(31,597)
Restricted stock used for tax withholdings	(6,007)		(6,007)
Restricted stock used for tax withholdings (in shares)		(130,002)
Stock-based compensation	20,716		20,716
Stock issued upon acquisition of oil and gas properties (in shares)		853,492
Stock issued upon acquisition of oil and gas properties	49,051	$ 1	49,050
Net income (loss)	20,283			20,283
Balance at end of period at Dec. 31, 2014	740,071	$ 41	591,511	148,519
Shares outstanding, end of period (in shares) at Dec. 31, 2014		41,287,270
Restricted common stock issued, net of excess income tax benefit (in shares)		601,282
Restricted common stock issued, net of excess income tax benefit	1	$ 1
Restricted common stock forfeited (in shares)		(123,574)
Restricted stock used for tax withholdings	(2,683)		(2,683)
Restricted stock used for tax withholdings (in shares)		(108,070)
Restricted common stock forfeited	(1)	$ (1)
Sale of common stock (in shares)		8,050,000
Sale of common stock	202,688	$ 8	202,680
Issuance of common stock (in shares)		47,500
Issuance of common stock	326		326
Stock-based compensation	14,552		14,552
Net income (loss)	(745,547)			(745,547)
Balance at end of period at Dec. 31, 2015	$ 209,407	$ 49	$ 806,386	$ (597,028)
Shares outstanding, end of period (in shares) at Dec. 31, 2015		49,754,408

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Operations Bonanza Creek Energy, Inc. (the “Company” or “BCEI”) is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of December 31, 2015 , the Company’s assets and operations were concentrated primarily in the Wattenberg Field in Colorado and in the Dorcheat Macedonia Field in southern Arkansas. Basis of Presentation The consolidated balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2015 , through the filing date of this report. Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. Accounts Receivable The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one to two months and the Company has experienced minimal bad debts. Inventory of Oilfield Equipment Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or market, which approximates fair value. Oil and Gas Producing Activities The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units-of-production method based upon proved reserves. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on our internal budgeting model originating from the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. The Company assesses its unproved properties periodically for impairment on a property-by-property basis, which requires significant judgment. The Company considers the following factors in its assessment of the impairment of unproved properties: • the remaining amount of unexpired term under leases; • its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; • its evaluation of the continuing successful results from the application of completion technology by the Company or by other operators in areas adjacent to or near its unproved properties; • its evaluation of the current fair market value of acreage; and • strategic shifts in development areas. For additional discussion, please refer to Note 4 - Impairments . The Company records the fair value of an asset retirement obligation as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. The increase in carrying value is included in proved properties in the accompanying consolidated balance sheets (“accompanying balance sheets”). For additional discussion, please refer to Note 11 - Asset Retirement Obligations. Gains and losses arising from sales of oil and gas properties will be included in income. However, a partial sale of proved properties within an existing field that does not significantly affect the unit-of-production depletion rate will be accounted for as a normal retirement with no gain or loss recognized. The sale of a partial interest within a proved property is accounted for as a recovery of cost. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. Natural Gas Plants Natural gas plants are recorded at cost and depreciated using the straight-line method over a 30 year useful life. The Company assesses the facilities for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable and an impairment loss is recorded as necessary. Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three to ten years. Assets Held for Sale Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent decreases to the estimated fair value less the costs to sell impact the measurement of assets held for sale. Any properties deemed held for sale as of the balance sheet date are presented separately on the accompanying balance sheets at the lower of net book value or fair value less cost to sell. For additional discussion, please refer to Note 3 - Assets Held for Sale . Revenue Recognition The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil, natural gas and natural gas liquids ("NGLs") when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company factors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. Payment is generally received within 30 to 90 days after the date of production. The Company has interests with other producers in certain properties in which case the Company uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as of December 31, 2015 and 2014 . For gathering and processing services, the Company either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are, in turn, sold and recognized as revenue in accordance with the criteria outlined above. Income Taxes The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Uncertain Tax Positions The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2014 , 2013 and 2012 are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions. Concentrations of Credit Risk The Company maintains cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit. The Company is exposed to credit risk in the event of nonpayment by counterparties whose creditworthiness is continuously evaluated. For the year ended December 31, 2015 , Kaiser-Silo Energy Company accounted for 31% , Lion Oil Trading & Transportation, Inc. accounted for 16% , Plains Marketing LP accounted for 11% and Duke Energy Field Services accounted for 11% , of our oil and natural gas sales. For the years ended December 31, 2014 and 2013 Plains Marketing LP accounted for 29% and 37% , respectively, Lion Oil Trading & Transportation, Inc. accounted for 19% and 23% , respectively, and High Sierra Crude Oil & Marketing accounted for 11% and 15% , respectively, of our oil and natural gas sales. Oil and Gas Derivative Activities The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts, which are generally placed with major financial institutions or with counterparties which management believes to be of high credit quality, may take the form of futures contracts, swaps, options, or collars. The oil contracts are indexed to NYMEX WTI prices, and natural gas contracts are indexed to NYMEX HH prices, which have a high degree of historical correlation with actual prices received by the Company, before differentials. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value. For additional discussion, please refer to Note 13 - Derivatives . Earnings Per Share Earnings per basic and diluted share are calculated under the two-class method. Pursuant to the two-class method, the Company’s unvested restricted stock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted-average number of common shares outstanding during the period. The two-class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated to common stock shareholders for purposes of calculating earnings per share. Participating shares are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding shares. Earnings per diluted share is computed on the basis of the weighted-average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using the more dilutive of the treasury method or two-class method. In periods of net loss, shares that are dilutive become anti-dilutive. For additional discussion, please refer to Note 14 - Earnings Per Share . Stock-Based Compensation The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. For additional discussion, please refer to Note 9 - Stock-Based Compensation. Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, revolving credit facility, senior notes, and derivative instruments. Cash and cash equivalents, trade receivables, trade payables and accrued liabilities are carried at cost and approximate fair value due to the short-term nature of these instruments. Our revolving credit facility has a variable interest rate so it approximates fair value. Our senior notes are recorded at cost, and their fair value is disclosed within Note 12 - Fair Value Measurements . Derivative instruments are recorded at fair value. The book value of the contractual obligation for land acquisition approximates fair value due to it being discounted at a market-based interest rate. Prior Year Reclassifications Certain prior year balances have been reclassified to conform to the current year presentation, and such reclassifications had no impact on net income (loss) or stockholders’ equity previously reported. Recently Issued and Adopted Accounting Standards Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board ("FASB") Update No. 2014-08 - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity . The update was aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. Subsequent to adoption of this guidance, the Company determined that assets that were deemed as held for sale during 2015 did not qualify for discontinued operations. As such, the presentation within the accompanying balance sheets and the consolidated statements of operations and comprehensive income ("accompanying statements of operations") reflect them as standard assets held for sale versus our California asset sales that occurred in 2014 and 2012 that were presented as discontinued operations. For additional discussion, please refer to Note 2 - Acquisitions and Divestitures and Note 3 - Assets Held for Sale. In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers . The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company’s financial statements or disclosures. In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period . The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company currently does not have any awards that fall within this guidance, but will apply it if such an award is issued. In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements - Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. In April 2015, the FASB issued Update No. 2015-03 – Interest – Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs . The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. This authoritative accounting guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years on a retrospective basis. The Company has taken the necessary steps to be ready for adoption of this update and does not currently believe it will have a material effect on the Company’s financial statements or disclosures. In July 2015, the FASB issued Update No. 2015-11 - Inventory . The update requires that inventory be measured at the lower of cost or net realizable value. This authoritative guidance is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. In August 2015, the FASB issued Update No. 2015-14 - Revenue from Contracts with Customers to defer the effective date of the new revenue recognition standard by one year. The new revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company’s financial statements or disclosures. In November 2015, the FASB issued Update No. 2015-17 - Income Taxes to simplify the presentation of deferred income taxes by classifying deferred tax assets and liabilities as noncurrent only. The new guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early application is permitted. The Company has evaluated the provisions of this guidance and determined it will have minimal impact on the Company’s financial statements and disclosures. In January 2016, the FASB issued Update No. 2016-01 - Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact in relation to the Company's derivatives, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	ACQUISITIONS AND DIVESTITURES In July 2014, the Company acquired approximately 34,000 net acres of oil and gas properties, leasehold mineral interests and related assets located in the Wattenberg Field (“Wattenberg Field Acquisition”) from a private operator. The Company paid approximately $174.6 million (inclusive of customary acquisition costs) in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the time of closing, for the acquired assets. The Wattenberg Field Acquisition had an effective date of June 1, 2014 and closed on July 8, 2014 . The results of operations for the Wattenberg Field Acquisition have been included in the Company’s consolidated financial statements from the date of closing. Pro forma information is not presented as the pro forma results would not have been materially different from the information presented in the accompanying statements of operations due to the lack of production and operating activities. The Wattenberg Field Acquisition was recorded using the purchase method of accounting. The following table summarizes the allocation of consideration paid (inclusive of customary acquisition costs) to the tangible assets acquired and liabilities assumed in the Wattenberg Field Acquisition. Asset Valuation Amount (in thousands) Purchase price $ 223,678 Allocation of purchase price: Proved properties $ 25,014 Unproved properties 198,757 Asset retirement obligation (93 ) Total $ 223,678 On July 31, 2012 , the Company acquired leases to approximately 5,600 net acres in the Wattenberg Field from the State of Colorado, State Board of Land Commissioners. The Company paid approximately $12.0 million at closing and $12.0 million in each of July 2013 , July 2014, and July 2015. The Company will pay approximately $12.0 million in July 2016 . The future payments were discounted based on our effective borrowing rate to arrive at the purchase price of $57.0 million . Future payments include imputed interest and are secured by a $12.0 million letter of credit. Following each payment the amount secured by the letter of credit will be amended to reflect the reduction in obligation. Discontinued Operations During June 2012 , the Company sold the majority of its oil and gas properties in California classifying them as discontinued operations with its remaining property being sold in the first quarter of 2014 for approximately $6.0 million . The Company recorded a gain on sale of oil and gas properties in the amount of $5.5 million for the year ended December 31, 2014 .

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
ASSETS HELD FOR SALE	ASSETS HELD FOR SALE As of December 31, 2015 , the accompanying balance sheets present $214.9 million of assets held for sale, net of accumulated depreciation, depletion and amortization, which consists of the Company’s Rocky Mountain Infrastructure, LLC subsidiary (“RMI”), all assets within the Company's Mid-Continent region and all assets in the North Park Basin that the Company no longer intends to develop given the current pricing environment. There is a corresponding asset retirement obligation liability of approximately $10.6 million for assets held for sale recorded in the asset retirement obligations for assets held for sale financial statement line item in the accompanying balance sheets. There were no other material assets or liabilities associated with the assets held for sale. For the year ended December 31, 2015 , the Company recorded write-downs to fair value less estimated costs to sell of $321.2 million for its Mid-Continent region assets. These write-downs are recorded in the impairment of oil and gas properties line item in the accompanying statements of operations. The previously entered into and announced purchase agreement to divest of RMI was terminated by the company as it did not close. The Company plans to re-market the assets. The Company adopted Update No. 2014-08 - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity on January 1, 2015 , which requires a disposal to represent a strategic shift that has a major effect on an entity's operations and financial results to qualify for discontinued operations. The Company determined that none of these potential asset sales qualify for discontinued operations accounting as they did not result in a strategic shift of the Company.

IMPAIRMENTS

IMPAIRMENTS	12 Months Ended
	Dec. 31, 2015
Tangible Asset Impairment Charges [Abstract]
IMPAIRMENTS	IMPAIRMENTS For the year ended December 31, 2015 , the Company impaired its assets held for sale within the Mid-Continent region to their fair value resulting in proved property impairments of $ 321.2 million and $419.3 million of proved property impairments in the Rocky Mountain region due to low commodity prices. The Company incurred unproved properties impairments of $ 24.8 million for non-core leases expiring within the Wattenberg Field and $ 8.7 million of impairment charges to fully impair the North Park Basin due to a change in the Company's development plan during the year. For additional discussion, please refer to Note 12 - Fair Value Measurements. For the year ended December 31, 2014 , the Company recorded proved property impairments of $ 127.3 million in the Dorcheat Macedonia Field due to low commodity prices, $ 25.0 million of proved property impairments in the McKamie Patton Field due to low commodity prices and natural field decline, and $ 15.3 million of proved property impairments in the McCallum Field due to low commodity prices. The Company did not have any unproved property impairments for 2014, and did not have any proved or unproved property impairments in 2013 .

OTHER ASSETS

OTHER ASSETS	12 Months Ended
	Dec. 31, 2015
Other Assets [Abstract]
OTHER ASSETS	OTHER ASSETS The Company has unamortized deferred financing costs related to the revolving credit facility and Senior Notes. As of December 31, 2015 2014 (in thousands) Certificates of deposit $ — $ 228 Restricted cash 241 3,000 Deposit for acquisition of oil and gas properties — 1,549 Deferred financing costs 15,786 18,595 Other noncurrent assets $ 16,027 $ 23,372

ACCOUNTS PAYABLE AND ACCRUED EX

ACCOUNTS PAYABLE AND ACCRUED EXPENSES	12 Months Ended
	Dec. 31, 2015
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND ACCRUED EXPENSES	ACCOUNTS PAYABLE AND ACCRUED EXPENSES Accounts payable and accrued expenses contain the following: As of December 31, 2015 2014 (in thousands) Drilling and completion costs $ 32,459 $ 82,844 Accounts payable trade 1,085 5,493 Accrued general and administrative cost 10,643 13,541 Lease operating expense 4,731 3,569 Accrued reclamation cost 162 162 Accrued interest 14,231 14,839 Production and ad valorem taxes and other 33,049 25,340 Total accounts payable and accrued expenses $ 96,360 $ 145,788

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Long-term debt consisted of the following as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in thousands) Revolving credit facility $ 79,000 $ 33,000 6.75% Senior Notes due 2021 500,000 500,000 Unamortized premium on 6.75% Senior Notes 6,392 7,619 5.75% Senior Notes due 2023 300,000 300,000 Total long-term debt $ 885,392 $ 840,619 Revolving Credit Facility The revolving credit facility, dated March 29, 2011, as amended, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, provides for borrowings of up to $1.0 billion . The revolving credit facility provides for interest rates plus an applicable margin to be determined based on LIBOR or a base rate, at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.50% to 2.50% depending on the utilization level, and the base rate borrowings bear interest at the “Bank Prime Rate,” as defined in the revolving credit facility, plus 0.50% to 1.50% . On May 13, 2015 , the revolving credit facility was amended (the “2015 Amendment”) to decrease the borrowing base from $600.0 million to $550.0 million and subsequently amended on October 19, 2015 to decrease the borrowing base from $550.0 million to $475.0 million . The $ 475.0 million borrowing base now equals the commitment level under the Credit Agreement. The borrowing base is redetermined semiannually no later than May 15 and November 15 and may be re-determined up to one additional time between such scheduled determinations upon request by the Company or lenders holding 66 2 / 3 % of the aggregate commitments. The revolving credit facility is collateralized by substantially all of the Company’s assets and matures on September 15, 2017 . As of December 31, 2015 , the Company had $79.0 million outstanding under the revolving credit facility with an available borrowing capacity of $384.0 million , after reduction for the outstanding letter of credit of $12.0 million . As of December 31, 2014 , the Company had $33.0 million outstanding under the revolving credit facility with an available borrowing capacity of $543.0 million , if the Company elected to take advantage of the entire $600.0 million borrowing base available at that date, after reduction for the outstanding letter of credit of $24.0 million . For additional discussion on the letter of credit, please refer to Note 2 - Acquisitions and Divestitures. The revolving credit facility restricts, among other items, certain dividend payments, additional indebtedness, asset sales, loans, investments and mergers. The revolving credit facility also contains certain financial covenants, which require the maintenance of certain financial and leverage ratios, as defined by the revolving credit facility. The 2015 Amendment (i) removed the maximum total debt to trailing twelve-month debt to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense and other non-cash charges (“EBITDAX”) covenant of 4.00 to 1.00 and (ii) introduced both a maximum senior secured debt (defined as borrowings under the revolving credit facility, balances drawn under letters of credit, and any outstanding second lien debt) to trailing twelve-month EBITDAX covenant of 2.50 to 1.00 and a minimum trailing twelve-month interest to trailing twelve-month EBITDAX coverage covenant of 2.50 to 1.00. The revolving credit facility also contains a minimum current ratio covenant of 1.00 to 1.00, where the available borrowing base is part of current assets. The Company was in compliance with all financial and non-financial covenants as of December 31, 2015 , and through the filing date of this report. 5.75% Senior Notes On July 15, 2014 , the Company issued $ 300.0 million aggregate principal amount of 5.75% Senior Notes that mature on February 1, 2023 (“5.75% Senior Notes”). Interest on the 5.75% Senior Notes began accruing on July 15, 2014 , and interest is payable on February 1 and August 1 of each year, beginning on February 1, 2015 . The 5.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the revolving credit facility. The net proceeds from the sale of the 5.75% Senior Notes were $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions. At any time prior to August 1, 2017 , subject to certain limitations, the Company may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.75% of the principal amount, plus accrued and unpaid interest, with an amount of cash not greater than the net cash proceeds of an equity offering. The Company may redeem all or a part of the 5.75% Senior Notes at any time prior to August 1, 2018 subject to a “make-whole” premium and accrued and unpaid interest. On or after August 1, 2018 , the Company may redeem all or a part of the 5.75% Senior Notes at the redemption price of 102.875% for 2018 , 101.438% for 2019 , and 100.0% for 2020 and thereafter, during the twelve-month period beginning on August 1 of each applicable year, in each case, plus accrued and unpaid interest. 6.75% Senior Notes On April 9, 2013 , the Company issued $300.0 million aggregate principal amount of 6.75% Senior Notes that mature on April 15, 2021 ("6.75% Senior Notes"). Interest on the Senior Notes began accruing on April 9, 2013 , and interest is payable on April 15 and October 15 of each year, which began on October 15, 2013 . On November 15, 2013 , the Company issued an additional $200.0 million aggregate principal amount of 6.75% Senior Notes as an additional issuance of its existing 6.75% Senior Notes. The 6.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Company’s revolving credit facility. The net proceeds from the sale of the 6.75% Senior Notes were $496.7 million after the premium and deduction of $12.3 million of expenses and underwriting discounts and commissions. At any time prior to April 15, 2016 , the Company may redeem up to 35% of the aggregate principal amount at a redemption price of 106.75% of the principal amount, plus accrued and unpaid interest. The Company may redeem all or a part of the 6.75% Senior Notes at any time prior to April 15, 2017 at the redemption price equal to 100% of the principal amount, plus the applicable “make-whole” premium and accrued and unpaid interest. On or after April 15, 2017 , the Company may redeem all or a part of the 6.75% Senior Notes at the redemption price of 103.375% for 2017 , 101.688% for 2018 , and 100.0% for 2019 and thereafter, during the twelve-month period beginning on April 15 of each applicable year, plus accrued and unpaid interest. On November 12, 2013 and July 15, 2014 , the Company filed automatic registration statements on Form S‑3 to register the 5.75% Senior Notes and 6.75% Senior Notes, respectively, (“5.75% Senior Notes” and, together with the “6.75% Senior Notes”, the “Senior Notes”) and guarantees of the Senior Notes. As of December 31, 2015 , all of the existing subsidiaries of the Company are guarantors of the Senior Notes, and all such subsidiaries are 100% owned by the Company. The guarantees by the subsidiaries are full and unconditional (except for customary release provisions) and constitute joint and several obligations of the subsidiaries. The Company has no independent assets or operations unrelated to its investments in its consolidated subsidiaries. There are no significant restrictions on the Company’s ability or the ability of any subsidiary guarantor to obtain funds from its subsidiaries by such means as a dividend or loan.

COMMITMENTS AND CONTINGENT LIAB

COMMITMENTS AND CONTINGENT LIABILITIES	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Legal Proceedings From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with accounting authoritative guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the filing date of this report, there were no material pending or overtly threatened legal actions against the Company of which it is aware. Commitments In October 2014 , the Company entered into two purchase and transportation agreements to deliver fixed determinable quantities of crude oil. The first agreement went into effect during the second quarter of 2015 for 12,580 barrels per day over an initial five -year term. The second agreement is currently anticipated to take effect in the fourth quarter of 2016 for 15,000 barrels per day over an initial seven -year term. The aggregate financial commitment fee is $503.7 million at December 31, 2015 . While the volume commitment may be met with Company volumes or third-party volumes, delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments. The Company rents office facilities under various non-cancelable operating lease agreements. The annual minimum payments on the transportation and operating lease agreements for the next five years and total minimum lease payments thereafter are presented below: Commitments (in thousands) 2016 $ 69,278 2017 92,308 2018 92,360 2019 92,413 2020 55,373 2021 and thereafter 114,976 Total $ 516,708 The Company’s office leases extend through 2020 . Rent expense for the years ended December 31, 2015 , 2014 and 2013 was $2.6 million , $2.0 million and $1.4 million , respectively. Subsequent to year-end, we entered into a minimum non-cancelable sublease for a total of $1.5 million payable through 2020 .

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION Management Incentive Plan On December 23, 2010 , the Company established the Management Incentive Plan (the “Plan”) for the benefit of certain employees, officers and other individuals performing services for the Company. The maximum number of shares of Class B common stock available under the Plan was 10,000 and these shares were converted into 437,787 shares of our restricted common stock upon completion of the Company’s initial public offering. The conversion rate was determined based on a formula factoring in the rate of return to the pre-IPO common stockholders. The 437,787 shares of common stock that were granted were valued at the IPO stated price of $17.00 per share and vested over a three-year period. There was no stock-based compensation expense during 2015 , as all common stock granted under the Plan was fully vested as of December 31, 2014 with no unrecognized compensation remaining. Stock-based compensation expense of $4.8 million and $2.5 million was recorded during the years ended December 31, 2014 and 2013 , respectively. BCEC Investment Trust The BCEC Investment Trust was formed to hold shares of our common stock received by Bonanza Creek Energy Company, LLC, our predecessor, in connection with our December 23, 2010 corporate restructuring. On February 5, 2013 , 13,825 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to former employees. While the shares had been issued in December 2010 , for accounting purposes, the date of distribution to former employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date, which was $34.18 per share. On February 11, 2013 , 59,372 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to certain then current employees. While the shares had been issued in December 2010 , for accounting purposes, the date of distribution to employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date, which was $34.89 per share. These distributions resulted in stock-based compensation expense of $2.5 million for the year ended December 31, 2013 . Long Term Incentive Plan The Company’s 2011 Long Term Incentive Plan, as amended and restated (the "LTIP"), has different forms of equity issuances allowed under it as further described in this section. Restricted Stock under the Long Term Incentive Plan The Company grants shares of restricted stock to directors, eligible employees and officers under its LTIP. Each share of restricted stock represents one share of the Company’s common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. Each share of restricted stock is entitled to a non-forfeitable dividend, if the Company were to declare one, and has the same voting rights as a share of the Company’s common stock. Shares of restricted stock are valued at the closing price of the Company’s common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award. The Company granted 568,832 , 297,030 and 292,396 shares of restricted stock under the LTIP to certain employees during 2015 , 2014 and 2013 , respectively. The fair value of the restricted stock granted in 2015 , 2014 and 2013 was $13.8 million , $13.9 million and $12.4 million , respectively. The Company recognized compensation expense of $11.1 million , $13.9 million and $6.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. As of December 31, 2015 unrecognized compensation cost was $14.4 million and will be amortized through 2018 . In 2015 , 2014 and 2013 , the Company issued 32,450 , 12,919 and 18,043 shares, respectively, of restricted common stock under the LTIP to its non-employee directors. The Company recognized compensation expense of $0.7 million , $0.7 million and $0.4 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. These awards vest approximately one year after issuance. A summary of the status and activity of non-vested restricted stock is presented below: For the Years Ended December 31, 2015 2014 2013 Restricted Stock Weighted- Average Grant-Date Fair Value Restricted Stock Weighted- Average Grant-Date Fair Value Restricted Stock Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 589,529 $ 37.66 836,002 $ 25.11 929,336 $ 17.06 Granted 601,282 $ 24.04 309,949 $ 45.87 310,439 $ 39.89 Vested (335,419 ) $ 32.09 (524,818 ) $ 25.95 (371,956 ) $ 17.44 Forfeited (123,574 ) $ 34.86 (31,604 ) $ 32.73 (31,817 ) $ 24.09 Non-vested at end of year 731,818 $ 29.47 589,529 $ 37.66 836,002 $ 25.11 Cash flows resulting from excess tax benefits are to be classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the years ended December 31, 2015 and 2014 . The Company recorded $0.1 million for the year ended December 31, 2013 as cash inflows from financing activities. Performance Stock Units under the Long Term Incentive Plan The Company grants performance stock units (“PSUs”) to certain officers under its LTIP. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. PSUs granted prior to 2014 are determined based on the Company’s performance over a three -year measurement period and vest in their entirety at the end of the measurement period. Satisfaction of the performance conditions for the PSUs granted in 2014 and thereafter are determined at the end of each annual measurement period over the course of the three -year performance cycle in an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number of PSUs may be earned during the performance cycle). For all grants, the PSUs will be settled in shares of the Company’s common stock following the end of the three -year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The performance criterion for the PSUs is based on a comparison of the Company’s total shareholder return (“TSR”) for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. Compensation expense associated with PSUs is recognized as general and administrative expense over the measurement period. The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, as well as the volatilities for each of the Company’s peers. The following table presents the assumptions used to determine the fair value of the PSUs granted during the years ended December 31, 2015 , 2014 and 2013 . For the For the Years Ended 2015 2014 2013 Expected term of award 3 3 3 Risk-free interest rate 0.15% - 0.99% 0.12% - 0.9% 0.4% - 0.9% Expected volatility 65 % 40% - 45% 40% During 2015 , 2014 and 2013 , the Company granted 144,363 , 82,312 and 41,622 PSUs, respectively, under the LTIP to certain officers. The fair value of the PSUs granted in 2015 , 2014 and 2013 was $4.8 million , $3.5 million and $1.2 million , respectively. The Company recognized compensation expense of $2.8 million , $1.3 million and $0.3 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. As of December 31, 2015 , unrecognized compensation expense for PSUs was $4.7 million and will be amortized through 2018 . A summary of the status and activity of PSUs is presented in the following table: For the Years Ended December 31, 2015 2014 2013 PSU Weighted-Average PSU Weighted-Average PSU Weighted-Average Non-vested at beginning of year (1) 94,173 $ 37.55 40,191 $ 32.05 — $ — Granted (1) 144,363 $ 33.44 82,312 $ 41.94 41,622 $ 32.01 Vested (1) (107,053 ) $ 34.84 (28,330 ) $ 42.50 — $ — Forfeited (1) (16,650 ) $ 37.00 — $ — (1,431 ) $ 30.85 Non-vested at end of year (1) 114,833 $ 35.27 94,173 $ 37.55 40,191 $ 32.05 ___________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two , depending on the level of satisfaction of the performance condition. During the year ended December 31, 2015, PSUs awarded in 2013 and the second tranche of the 2014 awards were earned at a 1.00-times multiplier and 0.91-times multiplier, respectively, in accordance with the terms of the respective PSU awards. The earned shares are settled and released at the end of the three -year performance cycle. During the year ended December 31, 2014, the first tranche of the PSUs awarded in 2014 , which were earned at a 1.33 -times multiplier in accordance with the terms of the PSU awards. The earned shares are settled and released at the end of the three -year performance cycle. 401(k) Plan The Company has a defined contribution pension plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary. The Company’s matching contributions to the 401(k) Plan were $1.9 million , $1.4 million and $0.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax bases of assets and liabilities and amounts reported in the Company’s balance sheet. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes. The provision for income taxes consists of the following: For the Years Ended December 31, 2015 2014 2013 (in thousands) Current tax expense (benefit) Federal $ (192 ) $ 165 $ 122 State 965 (16 ) 126 Deferred tax expense (benefit) (165,667 ) 12,986 42,432 Total income tax expense (benefit) $ (164,894 ) $ 13,135 $ 42,680 Temporary differences between the financial statement carrying amounts and tax bases of assets and liabilities that give rise to the net deferred tax liability result from the following components: As of December 31, 2015 2014 (in thousands) Deferred tax liabilities: Oil and gas properties $ — $ 201,635 Derivative asset 11,328 40,060 Total deferred tax liabilities 11,328 241,695 Deferred tax assets: Federal and state tax net operating loss carryforward 82,013 59,952 Oil and gas properties 93,712 — Reclamation costs 9,907 8,344 Stock compensation 3,907 3,845 AMT credit 402 812 State bonus depreciation addback 1,613 2,083 Other long-term liabilities 322 992 Total deferred tax assets 191,876 76,028 Less: Valuation allowance 180,548 — Total deferred tax assets after valuation allowance 11,328 76,028 Total non-current net deferred tax liability $ — $ 165,667 The Company has $218.7 million and $177.3 million of net operating loss carryovers for federal income tax purposes of which $14.5 million is not recorded as a benefit for financial statement purposes as it relates to tax deductions that are different from the stock-based compensation expense recorded for financial statement purposes as of December 31, 2015 and 2014 , respectively. The federal net operating loss carryforward begins to expire in 2031 . The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable. Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences, as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Federal statutory tax expense (benefit) $ (318,654 ) $ 11,696 $ 39,152 Increase (decrease) in tax resulting from: State tax expense net of federal benefit (30,178 ) 1,106 3,834 Rate change and other 3,390 333 (306 ) Valuation allowance 180,548 — — Total income tax expense (benefit) $ (164,894 ) $ 13,135 $ 42,680 Reconciliation of the Company’s effective tax rate to the expected federal tax rate of 35% in 2015 , 2014 , and 2013 is as follows: For the Years Ended December 31, 2015 2014 2013 Expected federal tax rate 35.00 % 35.00 % 35.00 % State income taxes 3.31 % 3.29 % 3.43 % Change in tax rate (0.37 )% 1.01 % (0.28 )% Valuation allowance (19.83 )% — % — % Effective tax rate 18.11 % 39.30 % 38.15 % During the year ended December 31, 2015 , the decrease in tax rate was primarily due to placing a valuation allowance against net deferred tax assets. Total deferred income tax benefit in the accompanying statements of operations is $165.7 million . The valuation allowance increased by $181.7 million in 2015. During the year ended December 31, 2014 , the increase in tax rate was primarily due to an increase in permanent differences. Total deferred income tax expense in the accompanying statements of operations is $13.0 million . During the year ended December 31, 2013 , the decrease in tax rate was primarily due to a decrease in taxable income apportioned to California and Arkansas and an increase in taxable income apportioned to Colorado. The decrease in the effective tax rate with the change in tax rate was applied to the January 1, 2013 deferred income tax liability resulting in a decrease to the net deferred tax liability and deferred income tax expense of $0.4 million . The total deferred income tax expense in the accompanying statements of operations was $42.4 million . The Company had no unrecognized tax benefits as of December 31, 2015 , 2014 and 2013 .

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties. The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred and ranges from 8% to 18% . A reconciliation of the Company’s asset retirement obligation is as follows: As of December 31, 2015 2014 (in thousands) Beginning of year $ 21,626 $ 11,218 Additional liabilities incurred 560 4,190 Accretion expense 1,944 1,382 Obligations on properties sold — (833 ) Liabilities settled (469 ) (557 ) Revisions to estimate 2,027 6,226 End of year $ 25,688 $ 21,626 Revisions to the liability could occur due to changes in the estimated economic lives, abandonment costs of the wells, inflation rates, credit-adjusted risk-free rates, along with newly enacted regulatory requirements. In 2015 , accretion expense increased over 2014 primarily due to the increase in the credit-adjusted risk-free rate, as well as an increased well count from the drilling and completion of new wells in the current year and from the wells added with the Wattenberg Field Acquisition in 2014. Revisions to estimates for the year ended December 31, 2015 were a result of decreased estimated economic well lives coupled with an increase in the inflation rate on wells that had an asset retirement obligation as of the beginning of the year. For each of the years ended December 31, 2015 and 2014 , the Company has accrued approximately $ 0.2 million of asset retirement obligations in accounts payable and accrued expenses on the accompanying balance sheets. The Company has accrued $10.6 million of asset retirement obligations in the asset retirement obligations for assets held for sale on the accompanying balance sheets for the year ended December 31, 2015. For additional discussion, please refer to Note 6 - Accounts Payable and Accrued Expenses.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as 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. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices are available in active markets for identical assets or liabilities Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable Level 3: Significant inputs to the valuation model are unobservable Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31, 2015 and 2014 and their classification within the fair value hierarchy: As of December 31, 2015 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 29,566 $ — Proved properties (2) $ — $ — $ 811,913 Unproved properties (2) $ — $ — $ 185,530 Asset retirement obligations (3) $ — $ — $ 2,027 As of December 31, 2014 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 104,005 $ — Proved properties (2) $ — $ — $ 407,900 Asset retirement obligations (3) $ — $ — $ 6,226 _______________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents non-financial assets that are measured at fair value on a nonrecurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and does not reflect the entire asset balance as presented on the accompanying balance sheets. Please refer to the Proved Oil and Gas Properties and Unproved Oil and Gas Properties sections below for additional discussion. (3) This represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion. Derivatives Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. As of December 31, 2015 , all derivative arrangements were concentrated with four counterparties, all of which are lenders under the Company’s revolving credit facility. Subsequent to year end, the derivative arrangements were concentrated with three counterparties, all of which are lenders under the Company's revolving credit facility. Proved Oil and Gas Properties Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. Depending on the availability of data, the Company uses Level 3 inputs and either the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The Company impaired the Mid-Continent region which had a carrying value of $431.2 million to its fair value of $110.0 million and recognized an impairment of $321.2 million for the year ended December 31, 2015 . The Company impaired the Rocky Mountain region which had a carrying value of $1,121.2 million to its fair value of $701.9 million and recognized an impairment of $419.3 million for the year ended December 31, 2015 . The Company impaired the Dorcheat Macedonia Field which had a carrying value of $519.2 million to its fair value of $391.9 million and recognized an impairment of $127.3 million for the year ended December 31, 2014 . The Company impaired the McKamie Patton Field which had a carrying value of $41.0 million to its fair value of $16.0 million and recognized an impairment of $25.0 million for the year ended December 31, 2014 . The Company impaired the McCallum Field which had a carrying value of $15.3 million to its fair value of zero and recognized an impairment of $15.3 million for the year ended December 31, 2014 . For additional discussion on impairments, please refer to Note 4 - Impairments . Unproved Oil and Gas Properties Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be fully recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, remaining lease life and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. The Company impaired non-core acreage in the Wattenberg Field due to lease expirations, which had a carrying value of $210.3 million to its fair value of $185.5 million and recognized an impairment of unproved properties for the year ended December 31, 2015 of $24.8 million . The Company also fully impaired the North Park Basin in June 2015 , due to a change in the Company’s development plan, recognizing an impairment of unproved properties of $8.7 million . There were no unproved properties measured at fair value as of December 31, 2014 . Asset Retirement Obligation The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. The Company had $2.0 million and $6.2 million of asset retirement obligations recorded at fair value as of December 31, 2015 and 2014 , respectively. Long-term Debt As of December 31, 2015 , the Company had $500.0 million of outstanding 6.75% Senior Notes and $300.0 million of outstanding 5.75% Senior Notes, all of which are unsecured senior obligations. The 6.75% Senior Notes are recorded at cost, plus the unamortized premium, on the accompanying balance sheets at $506.4 million and $507.6 million as of December 31, 2015 and 2014 , respectively. The fair value of the 6.75% Senior Notes as of December 31, 2015 and 2014 was $301.3 million and $440.0 million , respectively. The 5.75% Senior Notes are recorded at cost on the accompanying balance sheets at $300.0 million as of December 31, 2015 and 2014 . The fair value of the 5.75% Senior Notes as of December 31, 2015 and 2014 was $163.1 million and $243.0 million , respectively. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’s revolving credit facility approximates fair value as the applicable interest rates are floating. The outstanding balance under the revolving credit facility as of December 31, 2015 and 2014 was $79.0 million and $33.0 million , respectively.

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVES	DERIVATIVES The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps and collar arrangements for oil and none of the derivative instruments qualify as having hedging relationships. In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. If the index price is below the strike price of our short-puts associated with the Company’s three -way collars, the Company will receive a payment from our hedging counterparty equal to the difference between the strike prices of the short-put and long-put multiplied by the monthly volume associated with the three -way collar. As of December 31, 2015 , and as of the filing date of this report, the Company had the following derivative commodity contracts in place: Settlement Period Derivative Instrument Total Volumes (Bbls per day) Average Short Floor Price Average Floor Price Average Ceiling Price Fair Market Value of Assets (in thousands) Oil 2016 3-Way Collar 5,500 $ 70.00 $ 85.00 $ 96.83 $ 29,566 Total $ 29,566 Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following tables contain a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of December 31, 2015 and 2014 : As of December 31, 2015 Balance Sheet Location Fair Value (in thousands) Derivative Assets: Commodity contracts Current assets $ 29,566 Commodity contracts Noncurrent assets — Derivative Liabilities: Commodity contracts Current liabilities — Commodity contracts Long-term liabilities — Total derivative asset $ 29,566 As of December 31, 2014 Balance Sheet Location Fair Value (in thousands) Derivative Assets: Commodity contracts Current assets $ 86,240 Commodity contracts Noncurrent assets 17,765 Derivative Liabilities: Commodity contracts Current liabilities — Commodity contracts Long-term liabilities — Total derivative asset $ 104,005 The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations: For the Years Ended December 31, 2015 2014 2013 (in thousands) Derivative cash settlement gain (loss): Oil contracts (1) $ 128,258 $ 11,523 $ (11,755 ) Gas contracts 2,738 715 425 Total derivative cash settlement gain (loss) (2) $ 130,996 $ 12,238 $ (11,330 ) Change in fair value gain (loss) $ (74,438 ) $ 109,377 $ (1,142 ) Total derivative gain (loss) (3) $ 56,558 $ 121,615 $ (12,472 ) ___________________________ (1) During the year ended December 31, 2015 , the Company paid $10.5 million to convert its three -way collars, that settled during the third and fourth quarters of 2015 , to two -way collars. (2) Derivative cash settlement gain (loss) for the years ended December 31, 2015 , 2014 and 2013 is reported in the derivative cash settlements line item on the accompanying statements of cash flows within the net cash used in investing activities. (3) Total derivative gain (loss) for the years ended December 31, 2015 , 2014 and 2013 is reported in the derivative (gain) loss line item on the accompanying statements of cash flows within the net cash provided by operating activities.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE The Company issues shares of restricted stock entitling the holders to receive non-forfeitable dividends, if and when, the Company was to declare a dividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two -class method. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders and losses to common shareholders only. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company’s common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the measurement period applicable to such PSUs. Please refer to Note 9 - Stock-Based Compensation for additional discussion. The following table sets forth the calculation of income (loss) per basic and diluted shares from continuing and discontinued operations and net income (loss) for the years ended December 31, 2015 , 2014 and 2013 : For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share amounts) Income (loss) from continuing operations: Income (loss) from continuing operations $ (745,547 ) $ 16,982 $ 69,582 Less: undistributed income (loss) to unvested restricted stock — 315 1,673 Undistributed income (loss) to common shareholders (745,547 ) 16,667 67,909 Basic income (loss) per common share from continuing operations $ (15.57 ) $ 0.42 $ 1.73 Diluted income (loss) per common share from continuing operations $ (15.57 ) $ 0.41 $ 1.72 Income (loss) from discontinued operations: Income (loss) from discontinued operations $ — $ 3,301 $ (398 ) Less: undistributed income (loss) to unvested restricted stock — 62 (10 ) Undistributed income (loss) to common shareholders — 3,239 (388 ) Basic income (loss) per common share from discontinued operations $ — $ 0.08 $ (0.01 ) Diluted income (loss) per common share from discontinued operations $ — $ 0.08 $ (0.01 ) Net income (loss): Net income (loss) $ (745,547 ) $ 20,283 $ 69,184 Less: undistributed income (loss) to unvested restricted stock — 377 1,663 Undistributed income (loss) to common shareholders (745,547 ) 19,906 67,521 Basic net income (loss) per common share $ (15.57 ) $ 0.50 $ 1.72 Diluted net income (loss) per common share $ (15.57 ) $ 0.49 $ 1.71 Weighted-average shares outstanding - basic 47,874 40,139 39,337 Add: dilutive effect of contingent PSUs — 151 66 Weighted-average shares outstanding - diluted 47,874 40,290 39,403 The Company was in a net loss position for the year ended December 31, 2015 , which made the 277,634 potentially dilutive shares, anti-dilutive. The Company had no anti-dilutive shares for the years ended December 31, 2014 and 2013 . The participating shareholders are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding common shareholders.

CAPITAL STOCK

CAPITAL STOCK	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
CAPITAL STOCK	CAPITAL STOCK On February 6, 2015 , the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.7 million after deducting underwriter discounts, commissions and offering expenses of approximately $6.6 million . The Company used a portion of the net proceeds to repay all of the then outstanding borrowings under its revolving credit facility and for general corporate purposes, including its drilling and development program and other capital expenditures.

OIL AND GAS ACTIVITIES

OIL AND GAS ACTIVITIES	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
OIL AND GAS ACTIVITIES	OIL AND GAS ACTIVITIES The Company’s oil and natural gas activities are entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Acquisition (1) $ 16,270 $ 228,616 $ 13,797 Development (2)(3) 393,187 659,633 452,455 Exploration 6,284 5,345 2,590 Total (4) $ 415,741 $ 893,594 $ 468,842 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2015 , 2014 and 2013 were $15.3 million , $202.7 million and $3.4 million , respectively. Acquisition costs for proved properties for the years ended December 31, 2015 , 2014 and 2013 were $1.0 million , $25.9 million and $10.4 million , respectively. (2) Development costs include workover costs of $10.0 million , $9.8 million and $6.0 million charged to lease operating expense during the years ended December 31, 2015 , 2014 and 2013 , respectively. (3) Development costs include gas plant capital expenditures of $0.1 million and $4.3 million for the years ended December 31, 2015 and 2013 , respectively. (4) Includes amounts relating to asset retirement obligations of $2.4 million , $6.3 million and $2.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Suspended Well Costs During the year ended December 31, 2015 , the Company incurred $9.5 million of drilling costs for three exploratory wells, one of which was located in the North Park Basin and the other two were outside of the Company's current development area in southern Arkansas and deemed them all dry holes by the end of 2015. During the year ended December 31, 2014 , the Company incurred drilling costs for one exploratory well of $1.0 million and deemed it a dry hole by the end of 2014 . During the year ended December 31, 2013 , the Company incurred drilling costs for one exploratory well of $0.6 million and deemed it a dry hole by the end of 2013 .

DISCLOSURES ABOUT OIL AND GAS P

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The proved reserve estimates at December 31, 2015 and 2014 are internally generated with an audit performed by NSAI, our third party independent reserve engineers, whereas the December 31, 2013 proved reserve estimates were prepared by NSAI. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of BCEI’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of BCEI’s changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2015 , 2014 and 2013 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (1) (MMcf) (MBbl) (1) Balance-December 31, 2012 33,266 118,548 — Extensions and discoveries (2) 20,123 59,936 — Production (4,257 ) (9,976 ) — Purchases of minerals in place 1,228 3,958 — Revisions to previous estimates (3) (3,878 ) (32,852 ) — Balance-December 31, 2013 46,482 139,614 — Extensions and discoveries (2) 13,222 41,963 — Sales of minerals in place (43 ) (73 ) — Production (6,018 ) (14,114 ) — Purchases of minerals in place 709 1,214 — Revisions to previous estimates (3) 3,760 19,947 — Balance-December 31, 2014 58,112 188,551 — Three stream conversion adjustment (3,352 ) — 3,352 Extensions and discoveries (2) 6,936 15,849 2,430 Production (6,072 ) (14,110 ) (1,676 ) Purchases of minerals in place 719 3,521 234 Revisions to previous estimates (3) 1,050 (49,584 ) 15,578 Balance-December 31, 2015 57,393 144,227 19,918 Proved developed reserves: December 31, 2013 22,273 59,250 — December 31, 2014 30,542 94,494 — December 31, 2015 28,892 77,480 10,359 Proved undeveloped reserves: December 31, 2013 24,209 80,364 — December 31, 2014 27,570 94,057 — December 31, 2015 28,501 66,747 9,559 ________________________ (1) Natural gas liquid reserves were classified with oil reserves through December 31, 2014. Natural gas liquids are separately accounted for effective as of January 1, 2015, resulting in three-stream presentation. Effective January 1, 2015 the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in the Company's reporting of estimated reserve volumes. Prior period estimated reserve volumes have not been reclassified to conform to the current presentation given the prospective nature of the agreements. (2) At December 31, 2015 , horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 11,708 MBoe, which is 97% of our total additions of 12,008 MBoe. The remainder of the additions were the result of vertical drilling during the year in the Dorcheat Macedonia Field, Mid-Continent region. At December 31, 2014 , horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 18,980 MBoe, which is 94% of our total additions of 20,216 MBoe. The remainder of the additions came from our Dorcheat Madedonia Field, Mid-Continent region. At December 31, 2013 , horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 28,908 MBoe, which is 96% of our total additions of 30,112 MBoe. The remainder of the additions came from our Dorcheat Madedonia and McKamie Patton Fields, Mid-Continent region. (3) As of December 31, 2015 , the Company revised its proved reserves upward by 8,364 Mboe. The Company was successful in offsetting the negative pricing revision of 28,810 Mboe that resulted from a decrease in commodity price from $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014 to $50.28 per Bbl WTI and $2.59 per MMBtu HH for the year ended December 31, 2015 , by reducing the costs to drill and complete wells in both the Rocky Mountain and Mid-Continent regions and improving reserves by increasing productivity of proved developed producing wells in the Wattenberg Field horizontal program. Total positive engineering revisions as of December 31, 2015 , were 37,174 MBoe, of which 30,086 MBoe ( 81% ) related to reserve changes in the Wattenberg Field. In the Wattenberg Field, the majority of the positive revisions resulted from a combination of decreased drilling and completion costs of 29% ( $3.0 million per standard reach lateral well as of December 31, 2015 compared to $4.2 million as of December 31, 2014 ) and an increase in productivity from horizontal proved developed producing wells which increased the offsetting proved undeveloped reserves. The increase in proved developed producing reserves is primarily attributed to the installation of infrastructure in the east side of the Wattenberg Field. Another significant contribution to the positive reserve revision in the Wattenberg Field is a contract change as of January 1, 2015 which gives the Company ownership of the natural gas liquids from the Company's gas production. This conversion from two stream (wet gas and oil) to three stream (dry gas, natural gas liquids and oil) added 8,560 MBoe to the Company's proved reserves as of December 31, 2015 . As of December 31, 2014 , we revised our proved reserves upward by 7,333 Mboe, excluding pricing revisions, due primarily to the addition of 49 new proved undeveloped locations on 80 -acre spacing, directly offsetting economic proved producing wells drilled prior to 2014 , 21 diagonal offsets to economic proved producing wells and 12 proved undeveloped locations greater than one offset to economic proved producing wells but within developed areas and surrounded by proved producing wells. As of December 31, 2014 , approximately 70% of our horizontal development in the Wattenberg Field was in the Niobrara B formation. A total of 119 horizontal proved undeveloped locations were added to the proved reserves at December 31, 2014 to either extensions and discoveries or revisions to previous estimates. The positive engineering revision was offset by a small negative performance revision of approximately 540 MBoe. A small negative pricing revision of 248 MBoe resulted from a decrease in average commodity price from $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 to $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014 . At December 31, 2013 , we revised our proved reserves downward by 9,867 MBoe, excluding pricing revisions, due primarily to the change in focus from vertical to horizontal development in the Wattenberg Field. This accounted for 69% of the downward revision and included the elimination of 45 net vertical locations from proved undeveloped, the elimination of all proved non‑ producing reserves associated with vertical well refracs and recompletions, and lower performance from the vertical producers due to increased line pressure. The high line pressure also affected the horizontal reserves creating a negative revision of 1.8 MMBoe, or 18% of the total downward revision. We had a small positive pricing revision of 514 MBoe from an increase in commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 . The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with accounting authoritative guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company's oil and natural gas properties. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Future cash flows $ 3,122,574 $ 5,780,745 $ 4,799,149 Future production costs (1,706,607 ) (2,257,572 ) (1,681,419 ) Future development costs (697,045 ) (952,041 ) (776,512 ) Future income tax expense — (457,625 ) (576,024 ) Future net cash flows 718,922 2,113,507 1,765,194 10% annual discount for estimated timing of cash flows (391,106 ) (1,006,131 ) (839,911 ) Standardized measure of discounted future net cash flows $ 327,816 $ 1,107,376 $ 925,283 Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end. The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning of period $ 1,107,376 $ 925,283 $ 683,441 Sale of oil and gas produced, net of production costs (197,643 ) (435,792 ) (346,679 ) Net changes in prices and production costs (1,117,624 ) (331,930 ) 94,881 Extensions, discoveries and improved recoveries 76,429 492,144 571,384 Development costs incurred 84,180 116,958 67,063 Changes in estimated development cost 178,003 (15,131 ) 127,034 Purchases of minerals in place (971 ) 30,919 5,442 Sales of minerals in place — (1,173 ) — Revisions of previous quantity estimates (170,277 ) 122,169 (212,034 ) Net change in income taxes 233,086 68,856 (150,704 ) Accretion of discount 134,046 122,722 83,468 Changes in production rates and other 1,211 12,351 1,987 End of period $ 327,816 $ 1,107,376 $ 925,283 The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2015 , 2014 and 2013 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location. For the Years Ended December 31, 2015 2014 2013 Oil (per Bbl) $ 44.00 $ 84.28 $ 92.03 Gas (per Mcf) $ 2.33 $ 5.24 $ 4.67 Natural gas liquids (per Bbl) $ 12.90 N/A N/A

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2015 and 2014 : Three Months Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) 2015 Oil and gas sales $ 73,076 $ 90,422 $ 72,149 $ 57,032 Operating loss (1) (11,688 ) (4,546 ) (9,133 ) (21,910 ) Net loss (18,421 ) (41,164 ) (112,299 ) (573,663 ) Basic net loss per common share $ (0.41 ) $ (0.83 ) $ (2.25 ) $ (12.08 ) Diluted net loss per common share $ (0.41 ) $ (0.83 ) $ (2.25 ) $ (12.08 ) 2014 Oil and gas sales (2) $ 127,395 $ 151,682 $ 156,371 $ 123,185 Operating profit (1)(2) 58,432 63,284 59,579 25,707 Net income (loss) 13,531 1,158 48,782 (43,188 ) Basic net income (loss) per common share $ 0.34 $ 0.03 $ 1.18 $ (1.05 ) Diluted net income (loss) per common share $ 0.34 $ 0.03 $ 1.18 $ (1.06 ) _________________________ (1) Oil and gas sales less lease operating expense, severance and ad valorem taxes, depreciation, and depletion and amortization. (2) Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold as of December 31, 2014 .

SUMMARY OF SIGNIFICANT ACCOUN26

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2015 , through the filing date of this report.
Use of Estimates	Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments.
Accounts Receivable	Accounts Receivable The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one to two months and the Company has experienced minimal bad debts.
Inventory of Oilfield Equipment	Inventory of Oilfield Equipment Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or market, which approximates fair value.
Oil and Gas Producing Activities	Oil and Gas Producing Activities The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units-of-production method based upon proved reserves. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on our internal budgeting model originating from the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. The Company assesses its unproved properties periodically for impairment on a property-by-property basis, which requires significant judgment. The Company considers the following factors in its assessment of the impairment of unproved properties: • the remaining amount of unexpired term under leases; • its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; • its evaluation of the continuing successful results from the application of completion technology by the Company or by other operators in areas adjacent to or near its unproved properties; • its evaluation of the current fair market value of acreage; and • strategic shifts in development areas. For additional discussion, please refer to Note 4 - Impairments . The Company records the fair value of an asset retirement obligation as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. The increase in carrying value is included in proved properties in the accompanying consolidated balance sheets (“accompanying balance sheets”). For additional discussion, please refer to Note 11 - Asset Retirement Obligations. Gains and losses arising from sales of oil and gas properties will be included in income. However, a partial sale of proved properties within an existing field that does not significantly affect the unit-of-production depletion rate will be accounted for as a normal retirement with no gain or loss recognized. The sale of a partial interest within a proved property is accounted for as a recovery of cost. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. Natural Gas Plants Natural gas plants are recorded at cost and depreciated using the straight-line method over a 30 year useful life. The Company assesses the facilities for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable and an impairment loss is recorded as necessary.
Other Property and Equipment	Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three to ten years.
Assets Held for Sale	Assets Held for Sale Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent decreases to the estimated fair value less the costs to sell impact the measurement of assets held for sale. Any properties deemed held for sale as of the balance sheet date are presented separately on the accompanying balance sheets at the lower of net book value or fair value less cost to sell. For additional discussion, please refer to Note 3 - Assets Held for Sale .
Revenue Recognition	Revenue Recognition The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil, natural gas and natural gas liquids ("NGLs") when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company factors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. Payment is generally received within 30 to 90 days after the date of production. The Company has interests with other producers in certain properties in which case the Company uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as of December 31, 2015 and 2014 . For gathering and processing services, the Company either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are, in turn, sold and recognized as revenue in accordance with the criteria outlined above.
Income Taxes	Income Taxes The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
Uncertain Tax Positions	Uncertain Tax Positions The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2014 , 2013 and 2012 are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions.
Concentrations of Credit Risk	Concentrations of Credit Risk The Company maintains cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit. The Company is exposed to credit risk in the event of nonpayment by counterparties whose creditworthiness is continuously evaluated. For the year ended December 31, 2015 , Kaiser-Silo Energy Company accounted for 31% , Lion Oil Trading & Transportation, Inc. accounted for 16% , Plains Marketing LP accounted for 11% and Duke Energy Field Services accounted for 11% , of our oil and natural gas sales. For the years ended December 31, 2014 and 2013 Plains Marketing LP accounted for 29% and 37% , respectively, Lion Oil Trading & Transportation, Inc. accounted for 19% and 23% , respectively, and High Sierra Crude Oil & Marketing accounted for 11% and 15% , respectively, of our oil and natural gas sales.
Oil and Gas Derivative Activities	Oil and Gas Derivative Activities The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts, which are generally placed with major financial institutions or with counterparties which management believes to be of high credit quality, may take the form of futures contracts, swaps, options, or collars. The oil contracts are indexed to NYMEX WTI prices, and natural gas contracts are indexed to NYMEX HH prices, which have a high degree of historical correlation with actual prices received by the Company, before differentials. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value. For additional discussion, please refer to Note 13 - Derivatives .
Earnings Per Share	Earnings Per Share Earnings per basic and diluted share are calculated under the two-class method. Pursuant to the two-class method, the Company’s unvested restricted stock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted-average number of common shares outstanding during the period. The two-class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated to common stock shareholders for purposes of calculating earnings per share. Participating shares are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding shares. Earnings per diluted share is computed on the basis of the weighted-average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using the more dilutive of the treasury method or two-class method. In periods of net loss, shares that are dilutive become anti-dilutive. For additional discussion, please refer to Note 14 - Earnings Per Share .
Stock-Based Compensation	Stock-Based Compensation The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. For additional discussion, please refer to Note 9 - Stock-Based Compensation.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, revolving credit facility, senior notes, and derivative instruments. Cash and cash equivalents, trade receivables, trade payables and accrued liabilities are carried at cost and approximate fair value due to the short-term nature of these instruments. Our revolving credit facility has a variable interest rate so it approximates fair value. Our senior notes are recorded at cost, and their fair value is disclosed within Note 12 - Fair Value Measurements . Derivative instruments are recorded at fair value. The book value of the contractual obligation for land acquisition approximates fair value due to it being discounted at a market-based interest rate.
Prior Year Reclassifications	Prior Year Reclassifications Certain prior year balances have been reclassified to conform to the current year presentation, and such reclassifications had no impact on net income (loss) or stockholders’ equity previously reported.
Recently Issued Accounting Standards	Recently Issued and Adopted Accounting Standards Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board ("FASB") Update No. 2014-08 - Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity . The update was aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. Subsequent to adoption of this guidance, the Company determined that assets that were deemed as held for sale during 2015 did not qualify for discontinued operations. As such, the presentation within the accompanying balance sheets and the consolidated statements of operations and comprehensive income ("accompanying statements of operations") reflect them as standard assets held for sale versus our California asset sales that occurred in 2014 and 2012 that were presented as discontinued operations. For additional discussion, please refer to Note 2 - Acquisitions and Divestitures and Note 3 - Assets Held for Sale. In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers . The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company’s financial statements or disclosures. In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period . The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company currently does not have any awards that fall within this guidance, but will apply it if such an award is issued. In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements - Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. In April 2015, the FASB issued Update No. 2015-03 – Interest – Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs . The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. This authoritative accounting guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years on a retrospective basis. The Company has taken the necessary steps to be ready for adoption of this update and does not currently believe it will have a material effect on the Company’s financial statements or disclosures. In July 2015, the FASB issued Update No. 2015-11 - Inventory . The update requires that inventory be measured at the lower of cost or net realizable value. This authoritative guidance is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures. In August 2015, the FASB issued Update No. 2015-14 - Revenue from Contracts with Customers to defer the effective date of the new revenue recognition standard by one year. The new revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company’s financial statements or disclosures. In November 2015, the FASB issued Update No. 2015-17 - Income Taxes to simplify the presentation of deferred income taxes by classifying deferred tax assets and liabilities as noncurrent only. The new guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early application is permitted. The Company has evaluated the provisions of this guidance and determined it will have minimal impact on the Company’s financial statements and disclosures. In January 2016, the FASB issued Update No. 2016-01 - Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact in relation to the Company's derivatives, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the allocation of consideration paid (inclusive of customary acquisition costs) to the tangible assets acquired and liabilities assumed in the Wattenberg Field Acquisition. Asset Valuation Amount (in thousands) Purchase price $ 223,678 Allocation of purchase price: Proved properties $ 25,014 Unproved properties 198,757 Asset retirement obligation (93 ) Total $ 223,678

OTHER ASSETS (Tables)

OTHER ASSETS (Tables)	12 Months Ended
	Dec. 31, 2015
Other Assets [Abstract]
Schedule of other assets	The Company has unamortized deferred financing costs related to the revolving credit facility and Senior Notes. As of December 31, 2015 2014 (in thousands) Certificates of deposit $ — $ 228 Restricted cash 241 3,000 Deposit for acquisition of oil and gas properties — 1,549 Deferred financing costs 15,786 18,595 Other noncurrent assets $ 16,027 $ 23,372

ACCOUNTS PAYABLE AND ACCRUED 29

ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Tables)	12 Months Ended
	Dec. 31, 2015
Payables and Accruals [Abstract]
Schedule of accounts payable and accrued expenses	Accounts payable and accrued expenses contain the following: As of December 31, 2015 2014 (in thousands) Drilling and completion costs $ 32,459 $ 82,844 Accounts payable trade 1,085 5,493 Accrued general and administrative cost 10,643 13,541 Lease operating expense 4,731 3,569 Accrued reclamation cost 162 162 Accrued interest 14,231 14,839 Production and ad valorem taxes and other 33,049 25,340 Total accounts payable and accrued expenses $ 96,360 $ 145,788

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consisted of the following as of December 31, 2015 and 2014 : As of December 31, 2015 2014 (in thousands) Revolving credit facility $ 79,000 $ 33,000 6.75% Senior Notes due 2021 500,000 500,000 Unamortized premium on 6.75% Senior Notes 6,392 7,619 5.75% Senior Notes due 2023 300,000 300,000 Total long-term debt $ 885,392 $ 840,619

COMMITMENTS AND CONTINGENT LI31

COMMITMENTS AND CONTINGENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	The Company rents office facilities under various non-cancelable operating lease agreements. The annual minimum payments on the transportation and operating lease agreements for the next five years and total minimum lease payments thereafter are presented below: Commitments (in thousands) 2016 $ 69,278 2017 92,308 2018 92,360 2019 92,413 2020 55,373 2021 and thereafter 114,976 Total $ 516,708

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of the status and activity of non-vested restricted stock	A summary of the status and activity of non-vested restricted stock is presented below: For the Years Ended December 31, 2015 2014 2013 Restricted Stock Weighted- Average Grant-Date Fair Value Restricted Stock Weighted- Average Grant-Date Fair Value Restricted Stock Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 589,529 $ 37.66 836,002 $ 25.11 929,336 $ 17.06 Granted 601,282 $ 24.04 309,949 $ 45.87 310,439 $ 39.89 Vested (335,419 ) $ 32.09 (524,818 ) $ 25.95 (371,956 ) $ 17.44 Forfeited (123,574 ) $ 34.86 (31,604 ) $ 32.73 (31,817 ) $ 24.09 Non-vested at end of year 731,818 $ 29.47 589,529 $ 37.66 836,002 $ 25.11
Schedule of assumptions used to determine the fair value of the PSUs granted	The following table presents the assumptions used to determine the fair value of the PSUs granted during the years ended December 31, 2015 , 2014 and 2013 . For the For the Years Ended 2015 2014 2013 Expected term of award 3 3 3 Risk-free interest rate 0.15% - 0.99% 0.12% - 0.9% 0.4% - 0.9% Expected volatility 65 % 40% - 45% 40%
Summary of the status and activity of PSUs	A summary of the status and activity of PSUs is presented in the following table: For the Years Ended December 31, 2015 2014 2013 PSU Weighted-Average PSU Weighted-Average PSU Weighted-Average Non-vested at beginning of year (1) 94,173 $ 37.55 40,191 $ 32.05 — $ — Granted (1) 144,363 $ 33.44 82,312 $ 41.94 41,622 $ 32.01 Vested (1) (107,053 ) $ 34.84 (28,330 ) $ 42.50 — $ — Forfeited (1) (16,650 ) $ 37.00 — $ — (1,431 ) $ 30.85 Non-vested at end of year (1) 114,833 $ 35.27 94,173 $ 37.55 40,191 $ 32.05 ___________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two , depending on the level of satisfaction of the performance condition.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes	The provision for income taxes consists of the following: For the Years Ended December 31, 2015 2014 2013 (in thousands) Current tax expense (benefit) Federal $ (192 ) $ 165 $ 122 State 965 (16 ) 126 Deferred tax expense (benefit) (165,667 ) 12,986 42,432 Total income tax expense (benefit) $ (164,894 ) $ 13,135 $ 42,680
Schedule of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities that give rise to net deferred tax liability	Temporary differences between the financial statement carrying amounts and tax bases of assets and liabilities that give rise to the net deferred tax liability result from the following components: As of December 31, 2015 2014 (in thousands) Deferred tax liabilities: Oil and gas properties $ — $ 201,635 Derivative asset 11,328 40,060 Total deferred tax liabilities 11,328 241,695 Deferred tax assets: Federal and state tax net operating loss carryforward 82,013 59,952 Oil and gas properties 93,712 — Reclamation costs 9,907 8,344 Stock compensation 3,907 3,845 AMT credit 402 812 State bonus depreciation addback 1,613 2,083 Other long-term liabilities 322 992 Total deferred tax assets 191,876 76,028 Less: Valuation allowance 180,548 — Total deferred tax assets after valuation allowance 11,328 76,028 Total non-current net deferred tax liability $ — $ 165,667
Schedule of reconciliation of the Company's statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences	Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences, as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Federal statutory tax expense (benefit) $ (318,654 ) $ 11,696 $ 39,152 Increase (decrease) in tax resulting from: State tax expense net of federal benefit (30,178 ) 1,106 3,834 Rate change and other 3,390 333 (306 ) Valuation allowance 180,548 — — Total income tax expense (benefit) $ (164,894 ) $ 13,135 $ 42,680
Schedule of reconciliation of the Company's effective tax rate to expected federal tax rate	Reconciliation of the Company’s effective tax rate to the expected federal tax rate of 35% in 2015 , 2014 , and 2013 is as follows: For the Years Ended December 31, 2015 2014 2013 Expected federal tax rate 35.00 % 35.00 % 35.00 % State income taxes 3.31 % 3.29 % 3.43 % Change in tax rate (0.37 )% 1.01 % (0.28 )% Valuation allowance (19.83 )% — % — % Effective tax rate 18.11 % 39.30 % 38.15 %

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of change in asset retirement obligations assumed	A reconciliation of the Company’s asset retirement obligation is as follows: As of December 31, 2015 2014 (in thousands) Beginning of year $ 21,626 $ 11,218 Additional liabilities incurred 560 4,190 Accretion expense 1,944 1,382 Obligations on properties sold — (833 ) Liabilities settled (469 ) (557 ) Revisions to estimate 2,027 6,226 End of year $ 25,688 $ 21,626

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities at fair value on recurring basis	The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31, 2015 and 2014 and their classification within the fair value hierarchy: As of December 31, 2015 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 29,566 $ — Proved properties (2) $ — $ — $ 811,913 Unproved properties (2) $ — $ — $ 185,530 Asset retirement obligations (3) $ — $ — $ 2,027 As of December 31, 2014 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 104,005 $ — Proved properties (2) $ — $ — $ 407,900 Asset retirement obligations (3) $ — $ — $ 6,226 _______________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents non-financial assets that are measured at fair value on a nonrecurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and does not reflect the entire asset balance as presented on the accompanying balance sheets. Please refer to the Proved Oil and Gas Properties and Unproved Oil and Gas Properties sections below for additional discussion. (3) This represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2015
Summary of all the Company's derivative positions reported on the accompanying balance sheets	The following tables contain a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of December 31, 2015 and 2014 : As of December 31, 2015 Balance Sheet Location Fair Value (in thousands) Derivative Assets: Commodity contracts Current assets $ 29,566 Commodity contracts Noncurrent assets — Derivative Liabilities: Commodity contracts Current liabilities — Commodity contracts Long-term liabilities — Total derivative asset $ 29,566 As of December 31, 2014 Balance Sheet Location Fair Value (in thousands) Derivative Assets: Commodity contracts Current assets $ 86,240 Commodity contracts Noncurrent assets 17,765 Derivative Liabilities: Commodity contracts Current liabilities — Commodity contracts Long-term liabilities — Total derivative asset $ 104,005
Summary of the components of the derivative gain (loss) presented on the accompanying statements of operations	The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations: For the Years Ended December 31, 2015 2014 2013 (in thousands) Derivative cash settlement gain (loss): Oil contracts (1) $ 128,258 $ 11,523 $ (11,755 ) Gas contracts 2,738 715 425 Total derivative cash settlement gain (loss) (2) $ 130,996 $ 12,238 $ (11,330 ) Change in fair value gain (loss) $ (74,438 ) $ 109,377 $ (1,142 ) Total derivative gain (loss) (3) $ 56,558 $ 121,615 $ (12,472 ) ___________________________ (1) During the year ended December 31, 2015 , the Company paid $10.5 million to convert its three -way collars, that settled during the third and fourth quarters of 2015 , to two -way collars. (2) Derivative cash settlement gain (loss) for the years ended December 31, 2015 , 2014 and 2013 is reported in the derivative cash settlements line item on the accompanying statements of cash flows within the net cash used in investing activities. (3) Total derivative gain (loss) for the years ended December 31, 2015 , 2014 and 2013 is reported in the derivative (gain) loss line item on the accompanying statements of cash flows within the net cash provided by operating activities.
Commodity derivative
Summary of derivative commodity contracts in place	As of December 31, 2015 , and as of the filing date of this report, the Company had the following derivative commodity contracts in place: Settlement Period Derivative Instrument Total Volumes (Bbls per day) Average Short Floor Price Average Floor Price Average Ceiling Price Fair Market Value of Assets (in thousands) Oil 2016 3-Way Collar 5,500 $ 70.00 $ 85.00 $ 96.83 $ 29,566 Total $ 29,566

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of calculation of earnings per basic and diluted shares from continuing and discontinued operations	The following table sets forth the calculation of income (loss) per basic and diluted shares from continuing and discontinued operations and net income (loss) for the years ended December 31, 2015 , 2014 and 2013 : For the Years Ended December 31, 2015 2014 2013 (in thousands, except per share amounts) Income (loss) from continuing operations: Income (loss) from continuing operations $ (745,547 ) $ 16,982 $ 69,582 Less: undistributed income (loss) to unvested restricted stock — 315 1,673 Undistributed income (loss) to common shareholders (745,547 ) 16,667 67,909 Basic income (loss) per common share from continuing operations $ (15.57 ) $ 0.42 $ 1.73 Diluted income (loss) per common share from continuing operations $ (15.57 ) $ 0.41 $ 1.72 Income (loss) from discontinued operations: Income (loss) from discontinued operations $ — $ 3,301 $ (398 ) Less: undistributed income (loss) to unvested restricted stock — 62 (10 ) Undistributed income (loss) to common shareholders — 3,239 (388 ) Basic income (loss) per common share from discontinued operations $ — $ 0.08 $ (0.01 ) Diluted income (loss) per common share from discontinued operations $ — $ 0.08 $ (0.01 ) Net income (loss): Net income (loss) $ (745,547 ) $ 20,283 $ 69,184 Less: undistributed income (loss) to unvested restricted stock — 377 1,663 Undistributed income (loss) to common shareholders (745,547 ) 19,906 67,521 Basic net income (loss) per common share $ (15.57 ) $ 0.50 $ 1.72 Diluted net income (loss) per common share $ (15.57 ) $ 0.49 $ 1.71 Weighted-average shares outstanding - basic 47,874 40,139 39,337 Add: dilutive effect of contingent PSUs — 151 66 Weighted-average shares outstanding - diluted 47,874 40,290 39,403

OIL AND GAS ACTIVITIES (Tables)

OIL AND GAS ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of costs incurred in oil and natural gas producing activities	The Company’s oil and natural gas activities are entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Acquisition (1) $ 16,270 $ 228,616 $ 13,797 Development (2)(3) 393,187 659,633 452,455 Exploration 6,284 5,345 2,590 Total (4) $ 415,741 $ 893,594 $ 468,842 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2015 , 2014 and 2013 were $15.3 million , $202.7 million and $3.4 million , respectively. Acquisition costs for proved properties for the years ended December 31, 2015 , 2014 and 2013 were $1.0 million , $25.9 million and $10.4 million , respectively. (2) Development costs include workover costs of $10.0 million , $9.8 million and $6.0 million charged to lease operating expense during the years ended December 31, 2015 , 2014 and 2013 , respectively. (3) Development costs include gas plant capital expenditures of $0.1 million and $4.3 million for the years ended December 31, 2015 and 2013 , respectively. (4) Includes amounts relating to asset retirement obligations of $2.4 million , $6.3 million and $2.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.

DISCLOSURES ABOUT OIL AND GAS39

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Summary of BCEI's changes in quantities of proved oil, natural gas liquids and natural gas reserves	All of BCEI’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of BCEI’s changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2015 , 2014 and 2013 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (1) (MMcf) (MBbl) (1) Balance-December 31, 2012 33,266 118,548 — Extensions and discoveries (2) 20,123 59,936 — Production (4,257 ) (9,976 ) — Purchases of minerals in place 1,228 3,958 — Revisions to previous estimates (3) (3,878 ) (32,852 ) — Balance-December 31, 2013 46,482 139,614 — Extensions and discoveries (2) 13,222 41,963 — Sales of minerals in place (43 ) (73 ) — Production (6,018 ) (14,114 ) — Purchases of minerals in place 709 1,214 — Revisions to previous estimates (3) 3,760 19,947 — Balance-December 31, 2014 58,112 188,551 — Three stream conversion adjustment (3,352 ) — 3,352 Extensions and discoveries (2) 6,936 15,849 2,430 Production (6,072 ) (14,110 ) (1,676 ) Purchases of minerals in place 719 3,521 234 Revisions to previous estimates (3) 1,050 (49,584 ) 15,578 Balance-December 31, 2015 57,393 144,227 19,918 Proved developed reserves: December 31, 2013 22,273 59,250 — December 31, 2014 30,542 94,494 — December 31, 2015 28,892 77,480 10,359 Proved undeveloped reserves: December 31, 2013 24,209 80,364 — December 31, 2014 27,570 94,057 — December 31, 2015 28,501 66,747 9,559 ________________________ (1) Natural gas liquid reserves were classified with oil reserves through December 31, 2014. Natural gas liquids are separately accounted for effective as of January 1, 2015, resulting in three-stream presentation. Effective January 1, 2015 the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in the Company's reporting of estimated reserve volumes. Prior period estimated reserve volumes have not been reclassified to conform to the current presentation given the prospective nature of the agreements. (2) At December 31, 2015 , horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 11,708 MBoe, which is 97% of our total additions of 12,008 MBoe. The remainder of the additions were the result of vertical drilling during the year in the Dorcheat Macedonia Field, Mid-Continent region. At December 31, 2014 , horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 18,980 MBoe, which is 94% of our total additions of 20,216 MBoe. The remainder of the additions came from our Dorcheat Madedonia Field, Mid-Continent region. At December 31, 2013 , horizontal development in the Wattenberg Field, Rocky Mountain region, resulted in additions in extensions and discoveries of 28,908 MBoe, which is 96% of our total additions of 30,112 MBoe. The remainder of the additions came from our Dorcheat Madedonia and McKamie Patton Fields, Mid-Continent region. (3) As of December 31, 2015 , the Company revised its proved reserves upward by 8,364 Mboe. The Company was successful in offsetting the negative pricing revision of 28,810 Mboe that resulted from a decrease in commodity price from $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014 to $50.28 per Bbl WTI and $2.59 per MMBtu HH for the year ended December 31, 2015 , by reducing the costs to drill and complete wells in both the Rocky Mountain and Mid-Continent regions and improving reserves by increasing productivity of proved developed producing wells in the Wattenberg Field horizontal program. Total positive engineering revisions as of December 31, 2015 , were 37,174 MBoe, of which 30,086 MBoe ( 81% ) related to reserve changes in the Wattenberg Field. In the Wattenberg Field, the majority of the positive revisions resulted from a combination of decreased drilling and completion costs of 29% ( $3.0 million per standard reach lateral well as of December 31, 2015 compared to $4.2 million as of December 31, 2014 ) and an increase in productivity from horizontal proved developed producing wells which increased the offsetting proved undeveloped reserves. The increase in proved developed producing reserves is primarily attributed to the installation of infrastructure in the east side of the Wattenberg Field. Another significant contribution to the positive reserve revision in the Wattenberg Field is a contract change as of January 1, 2015 which gives the Company ownership of the natural gas liquids from the Company's gas production. This conversion from two stream (wet gas and oil) to three stream (dry gas, natural gas liquids and oil) added 8,560 MBoe to the Company's proved reserves as of December 31, 2015 . As of December 31, 2014 , we revised our proved reserves upward by 7,333 Mboe, excluding pricing revisions, due primarily to the addition of 49 new proved undeveloped locations on 80 -acre spacing, directly offsetting economic proved producing wells drilled prior to 2014 , 21 diagonal offsets to economic proved producing wells and 12 proved undeveloped locations greater than one offset to economic proved producing wells but within developed areas and surrounded by proved producing wells. As of December 31, 2014 , approximately 70% of our horizontal development in the Wattenberg Field was in the Niobrara B formation. A total of 119 horizontal proved undeveloped locations were added to the proved reserves at December 31, 2014 to either extensions and discoveries or revisions to previous estimates. The positive engineering revision was offset by a small negative performance revision of approximately 540 MBoe. A small negative pricing revision of 248 MBoe resulted from a decrease in average commodity price from $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 to $94.99 per Bbl WTI and $4.35 per MMBtu HH for the year ended December 31, 2014 . At December 31, 2013 , we revised our proved reserves downward by 9,867 MBoe, excluding pricing revisions, due primarily to the change in focus from vertical to horizontal development in the Wattenberg Field. This accounted for 69% of the downward revision and included the elimination of 45 net vertical locations from proved undeveloped, the elimination of all proved non‑ producing reserves associated with vertical well refracs and recompletions, and lower performance from the vertical producers due to increased line pressure. The high line pressure also affected the horizontal reserves creating a negative revision of 1.8 MMBoe, or 18% of the total downward revision. We had a small positive pricing revision of 514 MBoe from an increase in commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013 .
Schedule of standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Future cash flows $ 3,122,574 $ 5,780,745 $ 4,799,149 Future production costs (1,706,607 ) (2,257,572 ) (1,681,419 ) Future development costs (697,045 ) (952,041 ) (776,512 ) Future income tax expense — (457,625 ) (576,024 ) Future net cash flows 718,922 2,113,507 1,765,194 10% annual discount for estimated timing of cash flows (391,106 ) (1,006,131 ) (839,911 ) Standardized measure of discounted future net cash flows $ 327,816 $ 1,107,376 $ 925,283
Schedule of changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the Years Ended December 31, 2015 2014 2013 (in thousands) Beginning of period $ 1,107,376 $ 925,283 $ 683,441 Sale of oil and gas produced, net of production costs (197,643 ) (435,792 ) (346,679 ) Net changes in prices and production costs (1,117,624 ) (331,930 ) 94,881 Extensions, discoveries and improved recoveries 76,429 492,144 571,384 Development costs incurred 84,180 116,958 67,063 Changes in estimated development cost 178,003 (15,131 ) 127,034 Purchases of minerals in place (971 ) 30,919 5,442 Sales of minerals in place — (1,173 ) — Revisions of previous quantity estimates (170,277 ) 122,169 (212,034 ) Net change in income taxes 233,086 68,856 (150,704 ) Accretion of discount 134,046 122,722 83,468 Changes in production rates and other 1,211 12,351 1,987 End of period $ 327,816 $ 1,107,376 $ 925,283
Schedule of average wellhead prices used in determining future net revenues related to standardized measure calculation	The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2015 , 2014 and 2013 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location. For the Years Ended December 31, 2015 2014 2013 Oil (per Bbl) $ 44.00 $ 84.28 $ 92.03 Gas (per Mcf) $ 2.33 $ 5.24 $ 4.67 Natural gas liquids (per Bbl) $ 12.90 N/A N/A

QUARTERLY FINANCIAL DATA (UNA40

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2015 and 2014 : Three Months Ended March 31 June 30 September 30 December 31 (in thousands, except per share data) 2015 Oil and gas sales $ 73,076 $ 90,422 $ 72,149 $ 57,032 Operating loss (1) (11,688 ) (4,546 ) (9,133 ) (21,910 ) Net loss (18,421 ) (41,164 ) (112,299 ) (573,663 ) Basic net loss per common share $ (0.41 ) $ (0.83 ) $ (2.25 ) $ (12.08 ) Diluted net loss per common share $ (0.41 ) $ (0.83 ) $ (2.25 ) $ (12.08 ) 2014 Oil and gas sales (2) $ 127,395 $ 151,682 $ 156,371 $ 123,185 Operating profit (1)(2) 58,432 63,284 59,579 25,707 Net income (loss) 13,531 1,158 48,782 (43,188 ) Basic net income (loss) per common share $ 0.34 $ 0.03 $ 1.18 $ (1.05 ) Diluted net income (loss) per common share $ 0.34 $ 0.03 $ 1.18 $ (1.06 ) _________________________ (1) Oil and gas sales less lease operating expense, severance and ad valorem taxes, depreciation, and depletion and amortization. (2) Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold as of December 31, 2014 .

SUMMARY OF SIGNIFICANT ACCOUN41

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details):	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Period for receipt of payment on oil and natural gas sales, minimum	30 days
Period for receipt of payment on oil and natural gas sales, maximum	90 days
Minimum
Property, Plant and Equipment [Line Items]
Receivable collection period		1 month
Maximum
Property, Plant and Equipment [Line Items]
Receivable collection period		2 months
Natural Gas Processing Plant
Property, Plant and Equipment [Line Items]
PP&E useful life		30 years
Property, Plant and Equipment, Other Types | Minimum
Property, Plant and Equipment [Line Items]
PP&E useful life		3 years
Property, Plant and Equipment, Other Types | Maximum
Property, Plant and Equipment [Line Items]
PP&E useful life		10 years

SUMMARY OF SIGNIFICANT ACCOUN42

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations of Credit Risk (Details) - Sales - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Lion Oil Trading And Transportation Inc
Concentration Risk [Line Items]
Percent of oil and natural gas sales	16.00%	19.00%	23.00%
Kaiser Francis Oil Company
Concentration Risk [Line Items]
Percent of oil and natural gas sales	31.00%
Plains Marketing L P
Concentration Risk [Line Items]
Percent of oil and natural gas sales	11.00%	29.00%	37.00%
Duke Energy Field Services
Concentration Risk [Line Items]
Percent of oil and natural gas sales	11.00%
High Sierra Crude Oil And Marketing
Concentration Risk [Line Items]
Percent of oil and natural gas sales		11.00%	15.00%

ACQUISITIONS AND DIVESTITURES43

ACQUISITIONS AND DIVESTITURES (Details) $ / shares in Units, $ in Thousands	Jul. 08, 2014USD ($)a$ / sharesshares	Jul. 31, 2012USD ($)a	Jul. 31, 2015USD ($)	Jul. 31, 2014USD ($)	Jul. 31, 2013USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
2,016							$ 69,278
Proceeds from sale of oil and gas properties							0	$ 6,700	$ 0
Gain on sale of oil and gas properties							0	5,496	$ 0
Oil and gas properties in California
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties						$ 6,000
Gain on sale of oil and gas properties								$ 5,500
Wattenberg Field Acquisition
Business Acquisition [Line Items]
Net area of acquired properties (in acres) | a	34,000
Cash paid for acquisition	$ 174,600
Issuance of shares of common stock to acquiree | shares	853,492
Per share value of shares of common stock sold to acquiree (in dollars per share) | $ / shares	$ 57.47
Annual cash payment		$ 12,000	$ 12,000	$ 12,000	$ 12,000
2,016							$ 12,000
Purchase price	$ 223,678	57,000
Letter of credit		$ 12,000
Acquired leases in Wattenberg field
Business Acquisition [Line Items]
Net area of acquired properties (in acres) | a		5,600

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - Allocation of Consideration Paid to Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Jul. 08, 2014	Jul. 31, 2012	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Asset retirement obligation			$ (25,688)	$ (21,626)	$ (11,218)
Wattenberg Field Acquisition
Business Acquisition [Line Items]
Purchase price	$ 223,678	$ 57,000
Proved properties	25,014
Unproved properties	198,757
Asset retirement obligation	$ (93)

ASSETS HELD FOR SALE (Details)

ASSETS HELD FOR SALE (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets held for sale, net	$ 214,922	$ 0
Asset retirement obligations for assets held for sale	10,591	$ 0
Mid-Continent Region
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proved oil and gas property impairments	321,200
Rocky Mountain Infrastructure, LLC Subsidiary, Mid-Continent Region Assets, and North Park Field Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets held for sale, net	214,900
Asset retirement obligations for assets held for sale	$ 10,600

IMPAIRMENTS (Details)

IMPAIRMENTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Mid-Continent Region
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and gas property impairments	$ 321.2
Rocky Mountain Region
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and gas property impairments	419.3
Wattenburg Field Region [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproven oil and gas property impairments	24.8
North Park Basin Region
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproven oil and gas property impairments	$ 8.7
Dorcheat Macedonia Field
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and gas property impairments		$ 127.3
McKamie Patton Field
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and gas property impairments		25
McCallum Field
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and gas property impairments		$ 15.3

OTHER ASSETS (Details)

OTHER ASSETS (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Assets [Abstract]
Certificates of deposit	$ 0	$ 228
Restricted cash	241	3,000
Deposit for acquisition of oil and gas properties	0	1,549
Deferred financing costs	15,786	18,595
Total	$ 16,027	$ 23,372

ACCOUNTS PAYABLE AND ACCRUED 48

ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts payable and accrued expenses contain the following:
Drilling and completion costs	$ 32,459	$ 82,844
Accounts payable trade	1,085	5,493
Accrued general and administrative cost	10,643	13,541
Lease operating expense	4,731	3,569
Accrued reclamation cost	162	162
Accrued interest	14,231	14,839
Production and ad valorem taxes and other	33,049	25,340
Total accounts payable and accrued expenses	$ 96,360	$ 145,788

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Jul. 15, 2014	Apr. 09, 2013
LONG-TERM DEBT
Long-term debt	$ 885,392	$ 840,619
6.75% Senior Notes
LONG-TERM DEBT
Long-term debt	500,000
Long term debt - gross	500,000	500,000
Unamortized premium on 6.75% Senior Notes	$ 6,392	$ 7,619
Interest rate (as a percent)	6.75%	6.75%		6.75%
5.75% Senior Notes
LONG-TERM DEBT
Long-term debt	$ 300,000	$ 300,000
Long term debt - gross	$ 300,000	$ 300,000
Interest rate (as a percent)	5.75%	5.75%	5.75%
Revolver
LONG-TERM DEBT
Long-term debt	$ 79,000	$ 33,000

LONG-TERM DEBT - NARRATIVE (Det

LONG-TERM DEBT - NARRATIVE (Details)	May. 13, 2015USD ($)	Jul. 15, 2014USD ($)	Nov. 15, 2013USD ($)	Mar. 29, 2011USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 19, 2015USD ($)option	Apr. 09, 2013USD ($)
LONG-TERM DEBT
Long-term debt					$ 885,392,000	$ 840,619,000
Maximum total debt to trailing twelve month EBITDAX covenant				4
Maximum senior secured debt to trailing twelve month EBITDAX covenant	2.50
Minimum trailing twelve month interest to trailing twelve month EBITDAX coverage covenant	2.50
Minimum current ratio covenant	1
Amount of independent operations other than ownership interest in subsidiaries and affiliates					0
5.75% Senior Notes
LONG-TERM DEBT
Long-term debt					$ 300,000,000	$ 300,000,000
Amount of notes issued		$ 300,000,000
Interest rate (as a percent)		5.75%			5.75%	5.75%
Net proceeds from debt		$ 293,400,000
Debt issuance costs		$ 6,600,000
5.75% Senior Notes | Redeemable in 2017
LONG-TERM DEBT
Debt redemption percent					105.75%
5.75% Senior Notes | Redeemable in 2017 | Maximum
LONG-TERM DEBT
Percent of principal amount redeemable					35.00%
5.75% Senior Notes | Redeemable in 2018
LONG-TERM DEBT
Debt redemption percent					102.875%
5.75% Senior Notes | Redeemable in 2019
LONG-TERM DEBT
Debt redemption percent					101.438%
5.75% Senior Notes | Redeemable in 2020
LONG-TERM DEBT
Debt redemption percent					100.00%
6.75% Senior Notes
LONG-TERM DEBT
Long-term debt					$ 500,000,000
Amount of notes issued			$ 200,000,000					$ 300,000,000
Interest rate (as a percent)					6.75%	6.75%		6.75%
Net proceeds from debt			496,700,000
Debt issuance costs			$ 12,300,000
Ownership percent of subsidiaries					100.00%
Amount of independent assets other than ownership interest in subsidiaries and affiliates					$ 0
6.75% Senior Notes | Redeemable in 2017
LONG-TERM DEBT
Percent of principal amount redeemable						100.00%
Debt redemption percent					103.375%
6.75% Senior Notes | Redeemable in 2018
LONG-TERM DEBT
Debt redemption percent					101.688%
6.75% Senior Notes | Redeemable in 2019
LONG-TERM DEBT
Debt redemption percent					100.00%
6.75% Senior Notes | Redeemable Prior to April 15, 2016
LONG-TERM DEBT
Debt redemption percent					106.75%
6.75% Senior Notes | Redeemable Prior to April 15, 2016 | Maximum
LONG-TERM DEBT
Percent of principal amount redeemable						35.00%
Revolver
LONG-TERM DEBT
Maximum borrowing capacity					$ 1,000,000,000
Borrowing base amount	$ 550,000,000			$ 600,000,000			$ 475,000,000
Number of options to re-determine borrowing base | option							1
Approval of lenders to re-determine borrowing base, percent required							66.67%
Long-term debt					79,000,000	$ 33,000,000
Remaining borrowing capacity					384,000,000	543,000,000
Letters of credit outstanding					$ 12,000,000	$ 24,000,000
Revolver | LIBOR | Minimum
LONG-TERM DEBT
Basis spread on variable rate				1.50%
Revolver | LIBOR | Maximum
LONG-TERM DEBT
Basis spread on variable rate				2.50%
Revolver | Prime Rate | Minimum
LONG-TERM DEBT
Basis spread on variable rate				0.50%
Revolver | Prime Rate | Maximum
LONG-TERM DEBT
Basis spread on variable rate				1.50%

COMMITMENTS AND CONTINGENT LI51

COMMITMENTS AND CONTINGENT LIABILITIES (Details) $ in Thousands	1 Months Ended	3 Months Ended		12 Months Ended
	Oct. 31, 2014agreement	Dec. 31, 2016bbl	Jun. 30, 2015bbl	Dec. 31, 2015USD ($)claim	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 29, 2016USD ($)
Commitments [Line Items]
Number of claims | claim				0
Number of purchase and transportation agreements | agreement	2
Minimum commitment of crude oil | bbl			12,580
Term of commitment period			5 years
Aggregate financial commitment				$ 503,700
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,016				69,278
2,017				92,308
2,018				92,360
2,019				92,413
2,020				55,373
2021 and thereafter				114,976
Total				516,708
Rent expense				$ 2,600	$ 2,000	$ 1,400
Subsequent Event
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Sublease payable							$ 1,500
Forecast
Commitments [Line Items]
Minimum commitment of crude oil | bbl		15,000
Term of commitment period		7 years

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details)	Feb. 11, 2013$ / sharesshares	Feb. 05, 2013$ / sharesshares	Dec. 23, 2010$ / sharesshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares
STOCK-BASED COMPENSATION
Percent of employer match, up to				6.00%
Matching contribution for 401k plan				$ 1,900,000	$ 1,400,000	$ 800,000
Restricted Stock Units (RSUs) [Member]
STOCK-BASED COMPENSATION
Proceeds of Excess Income Tax Benefit from Vesting of Stock Awards				$ 0	0	100,000
PSUs
STOCK-BASED COMPENSATION
Ratio at which award holders get common stock of the company				1.33
PSUs | Minimum
STOCK-BASED COMPENSATION
Ratio at which award holders get common stock of the company				0
PSUs | Maximum
STOCK-BASED COMPENSATION
Ratio at which award holders get common stock of the company				2
Management Incentive Plan [Member] | Restricted shares
STOCK-BASED COMPENSATION
Granted (in shares) | shares			437,787
Share price (in USD per share) | $ / shares			$ 17
Stock-based compensation expense				$ 0	4,800,000	2,500,000
Unrecognized compensation cost					$ 0
Management Incentive Plan Of Principal Owner [Member]
STOCK-BASED COMPENSATION
Stock-based compensation expense						$ 2,500,000
Management Incentive Plan Of Principal Owner [Member] | Former Employees [Member]
STOCK-BASED COMPENSATION
Shares granted in period | shares		13,825
Weighted average grant date fair value, grants in period (in USD per share) | $ / shares		$ 34.18
Management Incentive Plan Of Principal Owner [Member] | Employees
STOCK-BASED COMPENSATION
Shares granted in period | shares	59,372
Weighted average grant date fair value, grants in period (in USD per share) | $ / shares	$ 34.89
2011 Long Term Incentive Plan | Restricted shares
STOCK-BASED COMPENSATION
Granted (in shares) | shares				601,282	309,949	310,439
Ratio of restricted stock to common stock to be released from restrictions upon completion of the vesting period | shares				1
Vesting portion of shares				0.333
Vesting period				3 years
2011 Long Term Incentive Plan | Restricted shares | Employees
STOCK-BASED COMPENSATION
Granted (in shares) | shares				568,832	297,030	292,396
Stock-based compensation expense				$ 11,100,000	$ 13,900,000	$ 6,900,000
Fair value of shares granted				13,800,000	$ 13,900,000	$ 12,400,000
2011 Long Term Incentive Plan | Grant2013 [Member] | Employees
STOCK-BASED COMPENSATION
Unrecognized compensation cost				$ 14,400,000
2011 Long Term Incentive Plan | Grant2013 [Member] | Non Employee Director [Member]
STOCK-BASED COMPENSATION
Granted (in shares) | shares				32,450	12,919	18,043
Stock-based compensation expense				$ 650,000	$ 734,000	$ 445,000
Vesting period				1 year
2011 Long Term Incentive Plan | PSUs
STOCK-BASED COMPENSATION
Granted (in shares) | shares				144,363	82,312	41,622
Vesting percent				66.67%
Percentage of awards earned during performance cycle				200.00%
2011 Long Term Incentive Plan | PSUs | Minimum
STOCK-BASED COMPENSATION
Ratio at which award holders get common stock of the company				0
2011 Long Term Incentive Plan | PSUs | Maximum
STOCK-BASED COMPENSATION
Ratio at which award holders get common stock of the company				2
2011 Long Term Incentive Plan | PSUs | Employees
STOCK-BASED COMPENSATION
Stock-based compensation expense				$ 2,800,000	$ 1,300,000	$ 300,000
Fair value of shares granted				4,800,000	$ 3,500,000	$ 1,200,000
2011 Long Term Incentive Plan | PSUs | Officers
STOCK-BASED COMPENSATION
Unrecognized compensation cost				$ 4,700,000
Measurement period				3 years
2011 Long Term Incentive Plan | PSUs | Officers | Minimum
STOCK-BASED COMPENSATION
Ratio at which award holders get common stock of the company				0
2011 Long Term Incentive Plan | PSUs | Officers | Maximum
STOCK-BASED COMPENSATION
Ratio at which award holders get common stock of the company				2
Common Class B [Member] | Management Incentive Plan [Member]
STOCK-BASED COMPENSATION
Shares available for grant | shares			10,000

STOCK-BASED COMPENSATION SUMMAR

STOCK-BASED COMPENSATION SUMMARY OF STATUS AND ACTIVITY OF NON-VESTED RESTRICTED STOCK (Details) - 2011 Long Term Incentive Plan - Restricted shares - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock
Non-vested at beginning of year (in shares)	589,529	836,002	929,336
Granted (in shares)	601,282	309,949	310,439
Vested (in shares)	(335,419)	(524,818)	(371,956)
Forfeited (in shares)	(123,574)	(31,604)	(31,817)
Non-vested at end of year (in shares)	731,818	589,529	836,002
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)	$ 37.66	$ 25.11	$ 17.06
Granted (in dollars per share)	24.04	45.87	39.89
Vested (in dollars per share)	32.09	25.95	17.44
Forfeited (in dollars per share)	34.86	32.73	24.09
Non-vested at end of year (in dollars per share)	$ 29.47	$ 37.66	$ 25.11

STOCK-BASED COMPENSATION ASSUMP

STOCK-BASED COMPENSATION ASSUMPTIONS USED TO CALCULATE FAIR VALUE OF PSUs (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Minimum
STOCK-BASED COMPENSATION
Risk-free interest rate (as a percent)	8.00%
Maximum
STOCK-BASED COMPENSATION
Risk-free interest rate (as a percent)	18.00%
2011 Long Term Incentive Plan | PSUs
STOCK-BASED COMPENSATION
Expected term of award	3 years	3 years	3 years
Expected volatility (as a percent)	65.00%
2011 Long Term Incentive Plan | PSUs | Minimum
STOCK-BASED COMPENSATION
Risk-free interest rate (as a percent)	0.15%	0.12%	0.12%
Expected volatility (as a percent)		40.00%	40.00%
2011 Long Term Incentive Plan | PSUs | Maximum
STOCK-BASED COMPENSATION
Risk-free interest rate (as a percent)	0.99%	0.90%	0.90%
Expected volatility (as a percent)		45.00%	45.00%

STOCK-BASED COMPENSATION SUMM55

STOCK-BASED COMPENSATION SUMMARY OF STATUS AND ACTIVITY OF PSUS (Details) - 2011 Long Term Incentive Plan - PSUs - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
PSUs
Non-vested at beginning of year (in shares)	94,173	40,191	0
Granted (in shares)	144,363	82,312	41,622
Vested (in shares)	(107,053)	(28,330)	0
Forfeited (in shares)	(16,650)	0	(1,431)
Non-vested at end of year (in shares)	114,833	94,173	40,191
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)	$ 37.55	$ 32.05	$ 0
Granted (in dollars per share)	33.44	41.94	32.01
Vested (in dollars per share)	34.84	42.50	0
Forfeited (in dollars per share)	37	0	30.85
Non-vested at end of year (in dollars per share)	$ 35.27	$ 37.55	$ 32.05

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current tax expense
Federal	$ (192)	$ 165	$ 122
State	965	(16)	126
Deferred tax expense	(165,667)	12,986	42,432
Total income tax expense (benefit)	(164,894)	13,135	42,680
Deferred tax liabilities:
Oil and gas properties	0	201,635
Derivative asset	11,328	40,060
Total deferred tax liabilities	11,328	241,695
Deferred tax assets:
Federal and state tax net operating loss carryforward	82,013	59,952
Oil and gas properties	93,712	0
Reclamation costs	9,907	8,344
Stock compensation	3,907	3,845
AMT credit	402	812
State bonus depreciation addback	1,613	2,083
Other long-term liabilities	322	992
Total deferred tax assets	191,876	76,028
Less: Valuation allowance	180,548	0
Total deferred tax assets after valuation allowance	11,328	76,028
Total non-current net deferred tax liability	0	165,667
Net operating loss carryforwards
Net operating loss carryovers for federal income tax purposes	218,700	177,300
Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes		14,500
Reconciliation statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences
Federal statutory tax expense (benefit)	(318,654)	11,696	39,152
Increase (decrease) in tax resulting from:
State tax expense net of federal benefit	(30,178)	1,106	3,834
Rate change and other	3,390	333	(306)
Valuation allowance	180,548	0	0
Total income tax expense (benefit)	$ (164,894)	$ 13,135	$ 42,680
Reconciliation of effective tax rate to expected federal tax rate
Expected federal tax rate (as a percent)	35.00%	35.00%	35.00%
State income taxes (as a percent)	3.31%	3.29%	3.43%
Change in tax rate (as a percent)	(0.37%)	1.01%	(0.28%)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent	(19.83%)	0.00%	0.00%
Effective tax rate (as a percent)	18.11%	39.30%	38.15%
Deferred income tax benefit (expense)	$ 165,667	$ (10,876)	$ (42,678)
Increase (decrease) in deferred tax asset valuation allowance	$ 181,700
Deferred income tax expense due to change in the effective tax rate			$ 400

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Asset retirement obligations for assets held for sale	$ 10,591	$ 0
Change in asset retirement obligations
Beginning of year	21,626	11,218
Additional liabilities incurred	560	4,190
Accretion expense	1,944	1,382
Obligations on properties sold	0	(833)
Liabilities settled	(469)	(557)
End of year	25,688	21,626
Accrued reclamation cost	162	$ 162
Assets Held-for-sale
Business Acquisition [Line Items]
Asset retirement obligations for assets held for sale	$ 10,600
Maximum
Business Acquisition [Line Items]
Discount rate (as a percent)	18.00%
Minimum
Business Acquisition [Line Items]
Discount rate (as a percent)	8.00%

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Financial assets and liabilities accounted for at fair value
Proved properties	$ 1,618,970	$ 1,924,380
Unproved properties	185,530	206,721
Asset retirement obligations	14,935	21,464
Level 1
Financial assets and liabilities accounted for at fair value
Derivative assets	0	0
Proved properties	0	0
Unproved properties	0
Asset retirement obligations	0	0
Level 2
Financial assets and liabilities accounted for at fair value
Derivative assets	29,566	104,005
Proved properties	0	0
Unproved properties	0
Asset retirement obligations	0	0
Level 3
Financial assets and liabilities accounted for at fair value
Derivative assets	0	0
Proved properties	811,913	407,900
Unproved properties	185,530
Asset retirement obligations	$ 2,027	$ 6,226

FAIR VALUE MEASUREMENTS - NARRA

FAIR VALUE MEASUREMENTS - NARRATIVE (Details)	1 Months Ended	12 Months Ended
	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)counterparty	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 29, 2016counterparty	Jul. 15, 2014	Apr. 09, 2013
Derivatives measured at fair value
Total number of counterparties in derivative financial instruments | counterparty		4
Proved properties		$ 1,618,970,000	$ 1,924,380,000
Unproved properties		185,530,000	206,721,000
Unproved oil and gas property impairments		33,543,000	0	$ 0
Asset retirement obligations		14,935,000	21,464,000
Outstanding amount		885,392,000	840,619,000
Revolver
Derivatives measured at fair value
Outstanding amount		79,000,000	$ 33,000,000
6.75% Senior Notes
Derivatives measured at fair value
Outstanding amount		$ 500,000,000
Interest rate (as a percent)		6.75%	6.75%				6.75%
Long-term debt		$ 506,400,000	$ 507,600,000
5.75% Senior Notes
Derivatives measured at fair value
Outstanding amount		$ 300,000,000	$ 300,000,000
Interest rate (as a percent)		5.75%	5.75%			5.75%
Level 3
Derivatives measured at fair value
Proved properties		$ 811,913,000	$ 407,900,000
Unproved properties		185,530,000
Revisions to estimate		2,000,000	6,226,000
Asset retirement obligations		2,027,000	6,226,000
Estimate of Fair Value Measurement | 6.75% Senior Notes
Derivatives measured at fair value
Fair value of senior notes		301,300,000	440,000,000
Estimate of Fair Value Measurement | 5.75% Senior Notes
Derivatives measured at fair value
Fair value of senior notes		163,100,000	243,000,000
Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Unproved properties			0
Asset retirement obligations			6,200,000
Mid-Continent Region
Derivatives measured at fair value
Proved properties			431,200,000
Proved oil and gas property impairments		321,200,000
Mid-Continent Region | Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Proved properties			110,000,000
Rocky Mountain Region
Derivatives measured at fair value
Proved properties			1,121,200,000
Proved oil and gas property impairments		419,300,000
Rocky Mountain Region | Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Proved properties			701,900,000
Dorcheat Macedonia Field
Derivatives measured at fair value
Proved properties			519,200,000
Proved oil and gas property impairments			127,300,000
Dorcheat Macedonia Field | Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Proved properties			391,900,000
McKamie Patton Field
Derivatives measured at fair value
Proved properties			41,000,000
Proved oil and gas property impairments			25,000,000
McKamie Patton Field | Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Proved properties			16,000,000
McCallum Field
Derivatives measured at fair value
Proved properties			15,300,000
Proved oil and gas property impairments			15,300,000
McCallum Field | Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Proved properties			$ 0
Wattenberg Field
Derivatives measured at fair value
Unproved properties		210,300,000
Unproved oil and gas property impairments		24,800,000
Wattenberg Field | Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Unproved properties		$ 185,500,000
North Park Basin
Derivatives measured at fair value
Unproved oil and gas property impairments	$ 8,700,000
Subsequent Event
Derivatives measured at fair value
Total number of counterparties in derivative financial instruments | counterparty					3

DERIVATIVES - CONTRACTS IN PLAC

DERIVATIVES - CONTRACTS IN PLACE (Details) $ in Thousands	Dec. 31, 2015USD ($)bbl / dderivative$ / bbl	Dec. 31, 2014USD ($)
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of derivative instruments qualified for hedging instruments | derivative	0
Commodity derivative
Derivative contract
Fair Market Value of Assets | $	$ 29,566	$ 104,005
Commodity derivative | 3-Way Collar | Oil | 2016
Derivative contract
Total Volumes (in units per day) | bbl / d	5,500
Average short floor price (in USD per barrel or mmbtu)	70
Average floor price (in USD per barrel or mmbtu)	85
Average ceiling price (in USD per barrel or mmbtu)	96.83
Fair Market Value of Assets | $	$ 29,566

DERIVATIVES - SUMMARY OF DERIVA

DERIVATIVES - SUMMARY OF DERIVATIVE POSITIONS (Details) - Commodity derivative - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives measured at fair value
Total derivative asset	$ 29,566	$ 104,005
Current assets
Derivatives measured at fair value
Derivative assets	29,566	86,240
Noncurrent assets
Derivatives measured at fair value
Derivative assets	0	17,765
Current liabilities
Derivatives measured at fair value
Derivative liabilities	0	0
Long-term liabilities
Derivatives measured at fair value
Derivative liabilities	$ 0	$ 0

DERIVATIVES - COMPONENTS OF DER

DERIVATIVES - COMPONENTS OF DERIVATIVE GAINS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components of the derivative gain (loss)
Derivative gain	$ 56,558	$ 121,615	$ (12,472)
Amount paid to convert three-way collars to two-way collars	10,500
Commodity derivative
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	130,996	12,238	(11,330)
Change in fair value gain (loss)	(74,438)	109,377	(1,142)
Derivative gain	56,558	121,615	(12,472)
Commodity derivative | Oil
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	128,258	11,523	(11,755)
Commodity derivative | Natural gas
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	$ 2,738	$ 715	$ 425

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015USD ($)$ / shares	Sep. 30, 2015USD ($)$ / shares	Jun. 30, 2015USD ($)$ / shares	Mar. 31, 2015USD ($)$ / shares	Dec. 31, 2014USD ($)$ / shares	Sep. 30, 2014USD ($)$ / shares	Jun. 30, 2014USD ($)$ / shares	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)$ / sharesshares
Income (loss) from continuing operations:
Income (loss) from continuing operations									$ (745,547)	$ 16,982	$ 69,582
Less: undistributed income (loss) to unvested restricted stock									0	315	1,673
Undistributed income (loss) to common shareholders									$ (745,547)	$ 16,667	$ 67,909
Basic income (loss) per common share from continuing operations (in dollars per share) | $ / shares									$ (15.57)	$ 0.42	$ 1.73
Diluted income (loss) per common share from continuing operations (in dollars per share) | $ / shares									$ (15.57)	$ 0.41	$ 1.72
Income (loss) from discontinued operations:
Gain (loss) from discontinued operations									$ 0	$ 3,301	$ (398)
Less: undistributed income to unvested restricted stock									0	62	(10)
Undistributed income (loss) to common shareholders									$ 0	$ 3,239	$ (388)
Basic income per common share from discontinued operations (in dollars per share) | $ / shares									$ 0	$ 0.08	$ (0.01)
Diluted income from discontinued operations (in dollars per share) | $ / shares									$ 0	$ 0.08	$ (0.01)
Net income (loss):
Net income (loss)	$ (573,663)	$ (112,299)	$ (41,164)	$ (18,421)	$ (43,188)	$ 48,782	$ 1,158	$ 13,531	$ (745,547)	$ 20,283	$ 69,184
Less: undistributed income (loss) to unvested restricted stock									0	377	1,663
Undistributed income (loss) to common shareholders									$ (745,547)	$ 19,906	$ 67,521
Basic net income (loss) per common share (in dollars per share) | $ / shares	$ (12.08)	$ (2.25)	$ (0.83)	$ (0.41)	$ (1.05)	$ 1.18	$ 0.03	$ 0.34	$ (15.57)	$ 0.50	$ 1.72
Diluted net income (loss) per common share (in dollars per share) | $ / shares	$ (12.08)	$ (2.25)	$ (0.83)	$ (0.41)	$ (1.06)	$ 1.18	$ 0.03	$ 0.34	$ (15.57)	$ 0.49	$ 1.71
Weighted-average shares outstanding - basic | shares									47,874,000	40,139,000	39,337,000
Add: dilutive effect of contingent PSUs | shares									0	151,000	66,000
Weighted-average shares outstanding - diluted | shares									47,874,000	40,290,000	39,403,000
Antidilutive securities excluded from EPS calculation | shares									277,634	0	0
PSUs
EARNINGS PER SHARE
Percentage of awards earned during performance cycle									1.33
PSUs | Minimum
EARNINGS PER SHARE
Percentage of awards earned during performance cycle									0
PSUs | Maximum
EARNINGS PER SHARE
Percentage of awards earned during performance cycle									2

CAPITAL STOCK (Details)

CAPITAL STOCK (Details) - USD ($) $ in Thousands	Feb. 06, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net proceeds		$ 209,308	$ 0	$ 0
Underwriter discounts, commissions and offering expenses		$ 6,620	$ 0	$ 0
IPO
Shares of common stock sold in initial public offering	8,050,000
Net proceeds	$ 202,700
Underwriter discounts, commissions and offering expenses	$ 6,600

OIL AND GAS ACTIVITIES (Details

OIL AND GAS ACTIVITIES (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)well	Dec. 31, 2014USD ($)well	Dec. 31, 2013USD ($)well
Costs incurred in oil and natural gas producing activities
Acquisition	$ 16,270	$ 228,616	$ 13,797
Development	393,187	659,633	452,455
Exploration	6,284	5,345	2,590
Total	415,741	893,594	468,842
Acquisition costs for unproved properties	15,300	202,700	3,400
Proved property acquisitions	1,000	25,900	10,400
Workover costs charged to lease operating expense	10,000	9,800	6,000
Gas plant capital expenditures	100		4,300
ARO included in total cost incurred	2,400	6,300	2,800
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Dry hole expense	$ 9,500	$ 1,000	$ 600
Number of exploratory wells for which drilling was commenced and deemed as dry | well	3	1	1
North Park Basin Region
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Number of exploratory wells for which drilling was commenced and deemed as dry | well	1
Southern Arkansas
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Number of exploratory wells for which drilling was commenced and deemed as dry | well		2

DISCLOSURES ABOUT OIL AND GAS66

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES - Change in Quantities of Proved Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands, $ / lateral_well in Millions	12 Months Ended
	Dec. 31, 2015MBoe$ / MMBTU$ / lateral_well$ / bblbblMcf	Dec. 31, 2014aMBoelocationoffset$ / MMBTU$ / lateral_well$ / bblbblMcf	Dec. 31, 2013MBoeMMBoelocation$ / MMBTU$ / bblbblMcf	Dec. 31, 2012$ / MMBTU$ / bblbblMcf
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Extensions and discoveries | MBoe	12,007,500	20,216	30,112
Revision to previous estimates for proved reserves - increase (decrease) | MBoe	8,364	7,333
Revisions to previous estimates for pricing - increase (decrease) | MBoe			514
Revisions to previous estimates - increase (decrease) | MBoe	37,174		(9,867)
Conversion adjustment positive impact (in MBoe) | MBoe	8,560
Increase (decrease) in proved undeveloped locations | location		49
Area of spacing on which new proved undeveloped locations are added | a		80
Number of diagonal offsets to economic proved producing wells | offset		21
Increase in proved undeveloped locations offsetting economic proved producing wells | location		12
Minimum number of offset to economic proved producing wells | offset		1
Downward revision in vertical reserves (as a percent)			69.00%
Number of locations that were moved from unproved to proved undeveloped | location			45
Negative revisions to previous estimates due to high pressure line | MMBoe			1.8
Downward revision in horizontal reserves (as a percent)			18.00%
Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Extensions and discoveries | MBoe	11,708	18,980	28,908
Extensions and discoveries (as a percent)	97.00%	94.00%	96.00%
Revisions to previous estimates for pricing - increase (decrease) | MBoe	(28,810)	(248)
Revisions to previous estimates - increase (decrease) | MBoe	30,086
Percent of revisions to previous estimate	81.00%
Percent decrease in drilling and completion costs	29.00%
Decrease in drilling and completion costs (in USD per standard reach lateral well) | $ / lateral_well	3	4.2
Increase (decrease) in proved undeveloped locations | location		119
Percentage of horizontal development in the Niobrara B formation		70.00%
Revisions to previous estimates for performance | MBoe		(540)
Oil
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	58,112	46,482	33,266
Three stream conversion adjustment	(3,352)
Extensions and discoveries	6,936	13,222	20,123
Sales of mineral in place		(43)
Production	(6,072)	(6,018)	(4,257)
Purchases of minerals in place	719	709	1,228
Revisions to previous estimates	1,050	3,760	(3,878)
Balance at the end of the period	57,393	58,112	46,482	33,266
Proved developed reserves:	28,892	30,542	22,273
Proved undeveloped reserves:	28,501	27,570	24,209
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | $ / bbl			96.91	94.71
Oil | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | $ / bbl	50.28	94.99	96.91
Natural gas
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period | Mcf	188,551	139,614	118,548
Three stream conversion adjustment | Mcf	0
Extensions and discoveries | Mcf	15,849	41,963	59,936
Sales of mineral in place | Mcf		(73)
Production | Mcf	(14,110)	(14,114)	(9,976)
Purchases of minerals in place | Mcf	3,521	1,214	3,958
Revisions to previous estimates | Mcf	(49,584)	19,947	(32,852)
Balance at the end of the period | Mcf	144,227	188,551	139,614	118,548
Proved developed reserves: | Mcf	77,480	94,494	59,250
Proved undeveloped reserves: | Mcf	66,747	94,057	80,364
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | $ / MMBTU			3.67	2.76
Natural gas | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Oil and gas commodity price (in dollars per Bbl/ MMBtu) | $ / MMBTU	2.59	4.35	3.67
Natural gas liquids
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	0	0	0
Three stream conversion adjustment	3,352
Extensions and discoveries	2,430	0	0
Sales of mineral in place		0
Production	(1,676)	0	0
Purchases of minerals in place	234	0	0
Revisions to previous estimates	15,578	0	0
Balance at the end of the period	19,918	0	0	0
Proved developed reserves:	10,359	0	0
Proved undeveloped reserves:	9,559	0	0

DISCLOSURES ABOUT OIL AND GAS67

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES - Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash flows				$ 3,122,574	$ 5,780,745	$ 4,799,149
Future production costs				(1,706,607)	(2,257,572)	(1,681,419)
Future development costs				(697,045)	(952,041)	(776,512)
Future income tax expense				0	(457,625)	(576,024)
Future net cash flows				718,922	2,113,507	1,765,194
10% annual discount for estimated timing of cash flows				(391,106)	(1,006,131)	(839,911)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 1,107,376	$ 925,283	$ 683,441	$ 327,816	$ 1,107,376	$ 925,283
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Beginning of period	1,107,376	925,283	683,441
Sale of oil and gas produced, net of production costs	(197,643)	(435,792)	(346,679)
Net changes in prices and production costs	(1,117,624)	(331,930)	94,881
Extensions, discoveries and improved recoveries	76,429	492,144	571,384
Development costs incurred	84,180	116,958	67,063
Changes in estimated development cost	178,003	(15,131)	127,034
Purchases of mineral in place	(971)	30,919	5,442
Sales of mineral in place	0	(1,173)	0
Revisions of previous quantity estimates	(170,277)	122,169	(212,034)
Net change in income taxes	233,086	68,856	(150,704)
Accretion of discount	134,046	122,722	83,468
Changes in production rates and other	1,211	12,351	1,987
End of period	$ 327,816	$ 1,107,376	$ 925,283

DISCLOSURES ABOUT OIL AND GAS68

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES - Average Wellhead Prices Used in Determining Future Net Revenues (Details)	12 Months Ended
	Dec. 31, 2015$ / bbl$ / MMcf	Dec. 31, 2014$ / bbl$ / MMcf	Dec. 31, 2013$ / bbl$ / MMcf
Oil
Average wellhead prices
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas)	44	84.28	92.03
Natural gas
Average wellhead prices
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | $ / MMcf	2.33	5.24	4.67
Natural gas liquids
Average wellhead prices
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas)	12.90

QUARTERLY FINANCIAL DATA (UNA69

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Oil and gas sales	$ 57,032	$ 72,149	$ 90,422	$ 73,076	$ 123,185	$ 156,371	$ 151,682	$ 127,395	$ 292,679	$ 558,633	$ 421,860
Operating profit (loss)	(21,910)	(9,133)	(4,546)	(11,688)	25,707	59,579	63,284	58,432	(907,444)	(47,506)	146,995
Net income (loss)	$ (573,663)	$ (112,299)	$ (41,164)	$ (18,421)	$ (43,188)	$ 48,782	$ 1,158	$ 13,531	$ (745,547)	$ 20,283	$ 69,184
Basic net income (loss) per common share (in dollars per share)	$ (12.08)	$ (2.25)	$ (0.83)	$ (0.41)	$ (1.05)	$ 1.18	$ 0.03	$ 0.34	$ (15.57)	$ 0.50	$ 1.72
Diluted net income (loss) per common share (in dollars per share)	$ (12.08)	$ (2.25)	$ (0.83)	$ (0.41)	$ (1.06)	$ 1.18	$ 0.03	$ 0.34	$ (15.57)	$ 0.49	$ 1.71