Northern Oil and Gas (NOG) 10-K 23 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 21, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN OIL & GAS, INC.
Entity Central Index Key	1,104,485
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 68
Entity Common Stock, Shares Outstanding		65,944,133
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

BALANCE SHEETS

BALANCE SHEETS - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and Cash Equivalents	$ 102,183,191	$ 6,486,098
Accounts Receivable, Net	46,851,682	35,840,042
Advances to Operators	604,977	1,577,204
Prepaid and Other Expenses	2,333,288	1,584,129
Derivative Instruments	0	4,517
Income Tax Receivable	785,016	1,402,179
Total Current Assets	152,758,154	46,894,169
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved	2,585,490,133	2,428,595,048
Unproved	1,699,344	2,623,802
Other Property and Equipment	981,303	977,349
Total Property and Equipment	2,588,170,780	2,432,196,199
Less – Accumulated Depreciation, Depletion and Impairment	(2,114,951,189)	(2,055,987,766)
Total Property and Equipment, Net	473,219,591	376,208,433
Deferred Income Taxes	785,000	0
Other Noncurrent Assets, Net	5,490,934	8,430,359
Total Assets	632,253,679	431,532,961
Current Liabilities:
Accounts Payable	93,152,297	56,146,847
Accrued Expenses	6,339,425	6,094,938
Accrued Interest	4,836,112	4,682,894
Derivative Instruments	18,681,891	10,001,564
Asset Retirement Obligations	565,521	517,423
Total Current Liabilities	123,575,246	77,443,666
Long-term Debt, Net	979,324,222	832,625,125
Derivative Instruments	11,496,929	1,738,329
Asset Retirement Obligations	8,562,607	6,990,877
Other Noncurrent Liabilities	135,225	156,632
TOTAL LIABILITIES	1,123,094,229	918,954,629
COMMITMENTS AND CONTINGENCIES (NOTE 8)
STOCKHOLDERS’ DEFICIT
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding	0	0
Common Stock, Par Value $.001; 142,500,000 Authorized (12/31/2017 – 66,791,633 Shares Outstanding and 12/31/2016 – 63,259,781 Shares Outstanding)	66,792	63,260
Additional Paid-In Capital	449,666,390	443,895,032
Retained Deficit	(940,573,732)	(931,379,960)
Total Stockholders’ Deficit	(490,840,550)	(487,421,668)
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$ 632,253,679	$ 431,532,961

BALANCE SHEETS (Parenthetical)

BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred Stock, shares authorized (in shares)	5,000,000	5,000,000
Preferred Stock, shares outstanding (in shares)	0	0
Common Stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common Stock, shares authorized (in shares)	142,500,000	142,500,000
Common Stock, shares outstanding (in shares)	66,791,633	63,259,781

STATEMENTS OF OPERATIONS

STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES
Oil and Gas Sales	$ 223,963,010	$ 159,690,883	$ 202,638,640
Gain (Loss) on Derivative Instruments, Net	(14,666,655)	(14,818,734)	72,382,907
Other Revenue	23,314	31,347	35,866
Total Revenues	209,319,669	144,903,496	275,057,413
OPERATING EXPENSES
Production Expenses	49,732,861	45,680,110	52,107,984
Production Taxes	20,604,256	15,513,608	21,566,634
General and Administrative Expense	18,987,801	14,757,641	19,042,004
Depletion, Depreciation, Amortization and Accretion	59,500,155	61,244,158	137,769,812
Impairment of Oil and Natural Gas Properties	0	237,012,834	1,163,959,246
Total Expenses	148,825,073	374,208,351	1,394,445,680
INCOME (LOSS) FROM OPERATIONS	60,494,596	(229,304,855)	(1,119,388,267)
OTHER INCOME (EXPENSE)
Interest Expense, Net of Capitalization	(70,286,341)	(64,485,623)	(58,360,387)
Write-off of Debt Issuance Costs	(95,135)	(1,089,507)	0
Loss on the Extinguishment of Debt	(992,950)	0	0
Other Income (Expense)	116,042	(15,902)	(30,091)
Total Other Income (Expense)	(71,258,384)	(65,591,032)	(58,390,478)
LOSS BEFORE INCOME TAXES	(10,763,788)	(294,895,887)	(1,177,778,745)
INCOME TAX BENEFIT	(1,570,016)	(1,402,179)	(202,424,204)
NET LOSS	$ (9,193,772)	$ (293,493,708)	$ (975,354,541)
Net Income (Loss) Per Common Share - Basic (in dollars per share)	$ (0.15)	$ (4.80)	$ (16.08)
Net Income (Loss) Per Common Share - Diluted (in dollars per share)	$ (0.15)	$ (4.80)	$ (16.08)
Weighted Average Shares Outstanding - Basic (in shares)	62,408,855	61,173,547	60,652,447
Weighted Average Shares Outstanding - Diluted (in shares)	62,408,855	61,173,547	60,652,447

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$ (9,193,772)	$ (293,493,708)	$ (975,354,541)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depletion, Depreciation, Amortization and Accretion	59,500,155	61,244,158	137,769,812
Amortization of Debt Issuance Costs	4,122,226	3,822,967	3,696,532
Write-off of Debt Issuance Costs	95,135	1,089,507	0
Loss on Extinguishment of Debt	992,950	0	0
Amortization of 8% Senior Notes Premium/Discount	495,892	501,324	(248,268)
(Gain) Loss on the Sale of Other Property & Equipment	0	30,356	(61,787)
Deferred Income Taxes	(785,000)	0	(202,350,555)
Loss (Gain) on the Mark-to-Market of Derivative Instruments	18,443,443	76,346,935	88,715,603
Legal Settlement	2,820,000	0	0
Share-Based Compensation Expense	3,286,566	3,464,040	5,234,115
Impairment of Oil and Natural Gas Properties	0	237,012,834	1,163,959,246
Other	31,623	373,983	1,696,114
Changes in Working Capital and Other Items:
Accounts Receivable	(9,717,487)	15,604,984	27,701,606
Prepaid Expenses and Other	(749,159)	(691,261)	2,220
Accounts Payable	2,611,492	(365,103)	(4,545,304)
Accrued Interest	142,318	(90,593)	590,630
Accrued Expenses	253,517	(1,556,673)	210,295
Income Tax Payable/(Receivable)	617,163	(1,402,179)	0
Net Cash Provided By Operating Activities	72,967,062	101,891,571	247,015,718
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Oil and Natural Gas Properties and Development Capital Expenditures, Net	(119,407,244)	(92,935,905)	(289,055,440)
Proceeds from Sale of Oil and Natural Gas Properties	171,451	2,172,003	138,524
Proceeds from Sale of Other Property and Equipment	0	14,500	72,000
Purchases of Other Property and Equipment	(3,954)	(214,685)	(90,751)
Net Cash Used For Investing Activities	(119,239,747)	(90,964,087)	(288,935,667)
CASH FLOWS FROM FINANCING ACTIVITIES
Advances on Revolving Credit Facility	36,000,000	63,000,000	150,000,000
Repayments on Revolving Credit Facility	(180,000,000)	(69,000,000)	(298,000,000)
Borrowings Under Term Loan Credit Agreement	300,000,000	0	0
Issuance of Senior Unsecured Notes	0	0	190,000,000
Debt Issuance Costs Paid	(13,361,833)	(428,515)	(5,687,596)
Restricted Stock Surrenders - Tax Obligations	(668,389)	(1,403,260)	(339,578)
Net Cash Provided By (Used For) Financing Activities	141,969,778	(7,831,775)	35,972,826
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	95,697,093	3,095,709	(5,947,123)
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD	6,486,098	3,390,389	9,337,512
CASH AND CASH EQUIVALENTS – END OF PERIOD	102,183,191	6,486,098	3,390,389
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	65,565,698	60,480,783	55,209,662
Cash Paid During the Period for Income Taxes	0	0	3,258,160
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable	85,002,458	50,713,195	59,520,415
Capitalized Asset Retirement Obligations	1,187,791	1,353,307	421,394
Non-Cash Compensation Capitalized in Oil and Gas Properties	$ 274,653	$ 971,313	$ 1,330,693

STATEMENTS OF CASH FLOWS (Paren

STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2017
8% Senior Notes [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Interest rate percentage	8.00%

STATEMENTS OF STOCKHOLDERS' EQU

STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) - USD ($)	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Deficit) [Member]
Balance at Dec. 31, 2014	$ 770,861,641	$ 61,067	$ 433,332,285	$ 337,468,289
Balance (in shares) at Dec. 31, 2014		61,066,712
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock	2,113	$ 2,113
Issuance of Common Stock (in shares)		2,112,998
Share Based Compensation	7,228,252		7,228,252
Restricted Stock Surrenders - Tax Obligations	(339,578)	$ (59)	(339,519)
Restricted Stock Surrenders - Tax Obligations (in shares)		(59,326)
Net Income (Loss)	(975,354,541)			(975,354,541)
Balance at Dec. 31, 2015	(197,602,113)	$ 63,121	440,221,018	(637,886,252)
Balance (in shares) at Dec. 31, 2015		63,120,384
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock	2,110	$ 2,110
Issuance of Common Stock (in shares)		2,109,814
Restricted Stock Forfeitures	(2,155,872)	$ (1,595)	(2,154,277)
Restricted Stock Forfeitures (in shares)		(1,594,542)
Share Based Compensation	7,231,175		7,231,175
Restricted Stock Surrenders - Tax Obligations	(1,403,260)	$ (376)	(1,402,884)
Restricted Stock Surrenders - Tax Obligations (in shares)		(375,875)
Net Income (Loss)	(293,493,708)			(293,493,708)
Balance at Dec. 31, 2016	(487,421,668)	$ 63,260	443,895,032	(931,379,960)
Balance (in shares) at Dec. 31, 2016		63,259,781
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock	2,820,911	$ 3,911	2,817,000
Issuance of Common Stock (in shares)		3,911,355
Restricted Stock Forfeitures	(23,697)	$ (109)	(23,588)
Restricted Stock Forfeitures (in shares)		(108,993)
Share Based Compensation	3,646,065		3,646,065
Restricted Stock Surrenders - Tax Obligations	(668,389)	$ (270)	(668,119)
Restricted Stock Surrenders - Tax Obligations (in shares)		(270,510)
Net Income (Loss)	(9,193,772)			(9,193,772)
Balance at Dec. 31, 2017	$ (490,840,550)	$ 66,792	$ 449,666,390	$ (940,573,732)
Balance (in shares) at Dec. 31, 2017		66,791,633

ORGANIZATION AND NATURE OF BUSI

ORGANIZATION AND NATURE OF BUSINESS	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND NATURE OF BUSINESS	ORGANIZATION AND NATURE OF BUSINESS Northern Oil and Gas, Inc. (the “Company,” “Northern,” “our” and words of similar import), a Minnesota corporation, is an independent energy company engaged in the acquisition, exploration, exploitation, development and production of crude oil and natural gas properties. The Company’s common stock trades on the NYSE American market under the symbol “NOG”. Northern’s principal business is crude oil and natural gas exploration, development, and production with operations in North Dakota and Montana that primarily target the Bakken and Three Forks formations in the Williston Basin of the United States. The Company acquires leasehold interests that comprise of non-operated working interests in wells and in drilling projects within its area of operations. As of December 31, 2017 , approximately 87% of Northern’s 143,253 total net acres were developed.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	SIGNIFICANT ACCOUNTING POLICIES These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In connection with preparing the financial statements for the year ended December 31, 2017 , the Company has evaluated subsequent events for potential recognition and disclosure through the date of this filing and determined that there were no subsequent events which required recognition or disclosure in the financial statements through the date of this filing. Use of Estimates The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved crude oil and natural gas reserve volumes, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, impairment of oil and natural gas properties, and deferred income taxes. Actual results may differ from those estimates. Reclassifications Certain prior period balances in the balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net loss, cash flows or stockholders’ deficit previously reported. Cash and Cash Equivalents Northern considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than $250,000 , the Company does not have FDIC coverage on the entire amount of bank deposits. The Company believes this risk is minimal. In addition, the Company is subject to Security Investor Protection Corporation (“SIPC”) protection on a vast majority of its financial assets. Accounts Receivable Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net on the balance sheets. As of December 31, 2017 and 2016 , the allowance for doubtful accounts was $5.6 million and $4.9 million , respectively. The amount charged to operations for doubtful accounts was $0.7 million , $0.8 million and $6.2 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. As of December 31, 2017 and 2016 , the amount charged against the allowance for doubtful accounts was zero and $0.4 million , respectively. As of December 31, 2017 and 2016 , the Company included accounts receivable of $5.5 million and $6.8 million , respectively, in Other Noncurrent Assets, Net due to their long-term nature. Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Other Property and Equipment Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets. Depreciation expense was $0.2 million , $0.2 million , and $0.3 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Oil and Gas Properties Northern follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2017 , 2016 and 2015 , respectively: Years Ended December 31, 2017 2016 2015 Capitalized Certain Payroll and Other Internal Costs $ 930,289 $ 1,890,480 $ 2,717,913 Capitalized Interest Costs 147,775 356,196 1,506,172 Total $ 1,078,064 $ 2,246,676 $ 4,224,085 As of December 31, 2017 , the Company held leasehold interests in the Williston Basin on acreage located in North Dakota and Montana targeting the Bakken and Three Forks formations. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In the years ended December 31, 2017 , 2016 and 2015 , there were no property sales that resulted in a significant alteration. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing twelve-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives designated as hedges for accounting purposes, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. The Company did not have any ceiling test impairment for the year ended December 31, 2017 . As a result of low commodity prices and their effect on the proved reserve values of properties, the Company recorded non-cash ceiling test impairments for the years ended December 31, 2016 and 2015 of $237.0 million , and $1.2 billion , respectively. The impairment charges affected the Company’s reported net income but did not reduce the Company’s cash flow. If a significantly lower pricing environment reoccurs, the Company expects it could be required to further writedown the value of its oil and natural gas properties. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the Company’s actual ceiling test calculation and impairment analyses in future periods. Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. For the years ended December 31, 2017 , 2016 and 2015 , the Company expired leases of $18.7 million , $13.4 million , and $19.0 million , respectively. At December 31, 2017 , the Company performed an impairment review using prices that reflect an average of 2017 ’s monthly prices as prescribed pursuant to the SEC’s guidelines. If lower average monthly pricing is reflected in the trailing twelve-month average pricing calculation, the present value of the Company’s future net revenues could decline and further impairment could be recognized. SEC defined prices for each quarter-end in 2017 were as follows: SEC Defined Prices for 12-Months Ended NYMEX Oil Price (per Bbl) Henry Hub Gas Price (per MMBtu) December 31, 2017 $ 51.34 $ 2.98 September 30, 2017 49.81 3.01 June 30, 2017 48.95 3.01 March 31, 2017 47.61 2.74 Asset Retirement Obligations The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board (“FASB”) ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. Business Combinations The Company accounts for its acquisitions that qualify as a business using the acquisition method under FASB ASC Topic 805, “Business Combinations.” Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. Debt Issuance Costs Debt issuance costs include origination, legal and other fees to issue debt in connection with the Company’s term loan credit agreement, senior unsecured notes and prior Revolving Credit Facility. These debt issuance costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method (see Note 4). The amortization of debt issuance costs for the years ended December 31, 2017 , 2016 and 2015 was $4.1 million , $3.8 million and $3.7 million , respectively. During the year ended December 31, 2017 and 2016 , $0.1 million and $1.1 million of debt issuance costs were written-off as a result of a reduction in the borrowing base of the Revolving Credit Facility, which was repaid using the proceeds from the term loan credit agreement entered into on November 1, 2017. As a result of the repayment of the Revolving Credit Facility, the Company incurred a loss on the extinguishment of debt of $1.0 million during 2017 . Bond Premium/Discount on Senior Notes On May 13, 2013, the Company recorded a bond premium of $10.5 million in connection with the “ 8.000% Senior Notes Due 2020” (see Note 4). This bond premium is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization of the bond premium was $1.5 million for each of the years ended December 31, 2017 , 2016 and 2015 . On May 18, 2015, the Company recorded a bond discount of $10.0 million in connection with the “ 8.000% Senior Notes Due 2020” (see Note 4). This bond discount is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization of the bond discount for the years ended December 31, 2017 , 2016 and 2015 was $2.0 million , $2.0 million and $1.2 million , respectively. Revenue Recognition The Company recognizes crude oil and natural gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2017 , 2016 and 2015 , the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells. Concentrations of Market and Credit Risk The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The Company operates in the exploration, development and production sector of the crude oil and natural gas industry. The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk. Restructuring Costs The Company accounts for restructuring costs in accordance with FASB ASC Topic 420, “Exit or Disposal Cost Obligations.” Under these standards, the costs associated with restructuring are recorded during the period in which the liability is incurred. During the year ended December 31, 2015, the Company recognized $0.5 million in restructuring costs for employee severance and related benefit costs incurred as part of a reduction in workforce and the closing of its Denver office, which included $0.1 million of non-cash expense related to acceleration of certain equity awards previously granted under the Company’s 2013 Incentive Plan. There were no restructuring costs incurred for the years ended December 31, 2017 and 2016, respectively. Stock-Based Compensation The Company records expense associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants, the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant. In determining the fair value of performance-based share awards subject to market conditions, the Company utilizes a Monte Carlo simulation prepared by an independent third party. For stock options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate. Stock Issuance The Company records any stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable. Income Taxes The Company’s income tax expense, deferred tax assets and deferred tax liabilities reflect management’s best assessment of estimated current and future taxes to be paid. The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The Company’s only taxing jurisdiction is the United States (federal and state). Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2017 , driven primarily by the full cost ceiling impairments over that period. Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flows. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control. Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance. In determining whether to establish a valuation allowance on the Company’s deferred tax assets, management concluded that the objectively verifiable evidence of cumulative negative earnings for the three-year period ended December 31, 2017 , is difficult to overcome with any forms of positive evidence that may exist. Accordingly, the valuation allowance against the Company’s deferred tax asset at December 31, 2017 and 2016 was $227.0 million and $341.3 million , respectively. Net Income Per Common Share Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and restricted stock. The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method. The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2017 , 2016 and 2015 are as follows: Years Ended December 31, 2017 2016 2015 Weighted Average Common Shares Outstanding – Basic 62,408,855 61,173,547 60,652,447 Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock — — — Weighted Average Common Shares Outstanding – Diluted 62,408,855 61,173,547 60,652,447 Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect 1,109,511 829,313 322,393 As of December 31, 2017 , 2016 and 2015 , potentially dilutive shares from stock option awards were 250,000 , 391,872 , and 141,872 , respectively. There options were all exercisable at December 31, 2017 , 2016 and 2015 . The Company also has potentially dilutive shares from restricted stock awards outstanding of 1,721,533 , 1,905,104 , and 2,365,396 at December 31, 2017 , 2016 and 2015 , respectively. Derivative Instruments and Price Risk Management The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil. The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company may also use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. The Company follows the provisions of FASB ASC 815, “Derivatives and Hedging” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value and marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations. See Note 13 for a description of the derivative contracts into which the Company has entered. Impairment Long-lived assets to be held and used are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Crude oil and natural gas properties accounted for using the full cost method of accounting are excluded from this requirement but continue to be subject to the full cost method’s impairment rules. There was no impairment in 2017 related to crude oil and natural gas properties. In 2016 and 2015, the Company recorded $237.0 million and $1.2 billion , respectively, in impairment related to crude oil and natural gas properties. There was no impairment of other long-lived assets recorded for the years ended December 31, 2017 , 2016 and 2015 . New Accounting Pronouncements From time to time, new accounting pronouncements are issued by the FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. The Company has completed the process of evaluating the effect of the adoption and determined there were no changes required to our reported revenues as a result of the adoption. The majority of our revenue arrangements generally consist of a single performance obligation to transfer promised goods or services. Based on our evaluation process and review of our contracts with customers, the timing and amount of revenue recognized based on the standard is consistent with our revenue recognition policy under previous guidance. The Company adopted the new standard effective January 1, 2018, using the modified retrospective approach, and will expand our financial statement disclosures in order to comply with the standard. We have determined the adoption of the standard will not have a material impact on our results of operations, cash flows, or financial position. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The standard requires lessees to recognize the assets and liabilities that arise from leases on the balance sheet. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact of the new guidance on its financial statements, however, based on its current operating leases, it is not expected to have a material impact. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This guidance provides guidance of eight specific cash flow issues. This amendment is effective for periods beginning after December 15, 2017, with early adoption permitted. The Company adopted this standard on January 1, 2018 and anticipates it will not have a material impact on its financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition and early adoption is permitted. The Company adopted this standard on January 1, 2018 and will apply this guidance to its next business combination.

CRUDE OIL AND NATURAL GAS PROPE

CRUDE OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
CRUDE OIL AND NATURAL GAS PROPERTIES	CRUDE OIL AND NATURAL GAS PROPERTIES The value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at December 31, 2017 and 2016 were approximately $85.0 million and $50.7 million , respectively. 2017 Acquisitions During 2017, the Company acquired approximately 1,934 net acres, for an average cost of approximately $2,352 per net acre, in its key prospect areas in the form of effective leases. 2016 Acquisitions During 2016, the Company acquired approximately 3,399 net acres, for an average cost of approximately $1,515 per net acre, in its key prospect areas in the form of effective leases. On October 6, 2016, the Company entered into a definitive purchase and sale agreement with a third party, for their interests in 144 gross ( 3.8 net) producing oil and gas wells and associated acreage. The motivation for the acquisition was the expectation that it was accretive to cash flow and earnings per share. On October 26, 2016, the Company closed the transaction for cash consideration of $9.4 million which is comprised of $8.9 million related to producing properties and a $0.5 million reimbursement of drilling costs on in process wells. The results of operations from the October 26, 2016 closing date through December 31, 2016, represented approximately $1.2 million of revenue and $0.5 million of direct operating expenses. The combined pro forma information has not been presented due to its immateriality. No material transaction costs were incurred in connection with this purchase and there was no goodwill recorded from this acquisition. 2015 Acquisitions During 2015, the Company acquired approximately 4,355 net acres, for an average cost of approximately $1,314 per net acre, in its key prospect areas in the form of effective leases. Divestitures From time-to-time the Company may divest assets. In addition, the Company may trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage. Unproved Properties Unproved properties not being amortized comprise approximately 14,377 net acres and 26,432 net acres of undeveloped leasehold interests at December 31, 2017 and 2016 , respectively. The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves. Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years . The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2017 by year incurred. Years Ended December 31, 2017 2016 2015 Prior Years Property Acquisition $ 565,352 $ 509,877 $ 502,794 $ 121,321 Development — — — — Total $ 565,352 $ 509,877 $ 502,794 $ 121,321 All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. The Company historically has acquired its properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling. The Company assesses all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the years ended December 31, 2017 , 2016 and 2015 , the Company included $0.6 million , $7.0 million and $37.6 million , respectively, related to expiring leases within costs subject to the depletion calculation. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Natural Gas Exploration and Production Activities Oil and gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s crude oil and natural gas production activities are provided in the Company’s related statements of income. Costs Incurred and Capitalized Costs The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2017 2016 2015 Costs Incurred for the Year: Proved Property Acquisition and Other $ 15,722,378 $ 18,531,518 $ 9,068,139 Unproved Property Acquisition 716,681 2,301,285 3,346,214 Development 139,531,567 63,621,429 116,255,535 Total $ 155,970,626 $ 84,454,232 $ 128,669,888 Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2017 by year incurred. Years Ended December 31, 2017 2016 2015 Prior Years Property Acquisition $ 565,352 $ 509,877 $ 502,794 $ 121,321 Development — — — — Total $ 565,352 $ 509,877 $ 502,794 $ 121,321 Oil and Natural Gas Reserves and Related Financial Data Information with respect to the Company’s crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Ryder Scott Company, independent petroleum consultants based on information provided by the Company. Oil and Natural Gas Reserve Data The following tables present the Company’s independent petroleum consultants’ estimates of its proved crude oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Natural Gas Oil BOE Proved Developed and Undeveloped Reserves at December 31, 2014 70,935,117 88,913,305 100,735,825 Revisions of Previous Estimates (23,552,809 ) (36,277,018 ) (40,202,486 ) Extensions, Discoveries and Other Additions 8,170,259 9,346,864 10,708,574 Production (4,651,583 ) (5,168,687 ) (5,943,951 ) Proved Developed and Undeveloped Reserves at December 31, 2015 50,900,984 56,814,464 65,297,962 Revisions of Previous Estimates (8,697,825 ) (13,995,801 ) (15,445,439 ) Extensions, Discoveries and Other Additions 7,695,309 7,142,439 8,424,991 Purchases of Minerals in Place 960,758 640,108 800,234 Production (4,026,899 ) (4,325,919 ) (4,997,069 ) Proved Developed and Undeveloped Reserves at December 31, 2016 46,832,327 46,275,291 54,080,679 Revisions of Previous Estimates 8,838,976 889,814 2,362,977 Extensions, Discoveries and Other Additions 27,637,350 20,184,388 24,790,613 Production (5,187,886 ) (4,537,295 ) (5,401,943 ) Proved Developed and Undeveloped Reserves at December 31, 2017 78,120,767 62,812,198 75,832,326 Proved Developed Reserves: December 31, 2014 38,277,770 44,666,408 51,046,037 December 31, 2015 33,619,954 36,573,821 42,177,147 December 31, 2016 32,808,111 32,245,139 37,713,158 December 31, 2017 46,518,005 38,592,506 46,345,507 Proved Undeveloped Reserves: December 31, 2014 32,657,347 44,246,897 49,689,788 December 31, 2015 17,281,030 20,240,643 23,120,815 December 31, 2016 14,024,216 14,030,152 16,367,521 December 31, 2017 31,602,762 24,219,692 29,486,819 Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years. Notable changes in proved reserves for the year ended December 31, 2017 included the following: • Extensions and discoveries . In 2017 , total extensions and discoveries of 24.8 MMBOE were primarily attributable to successful drilling in the Williston Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 5.9 MMBOE as a result of successful drilling in the Williston Basin and 18.9 MMBOE as a result of additional proved undeveloped locations. • Revisions to previous estimates . In 2017 , revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 2.4 MMBOE. Included in these revisions were 1.8 MMBOE of upward adjustments caused by higher crude oil and natural gas prices and a 3.1 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2017 to December 31, 2016 which was partially offset by 2.5 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule. Notable changes in proved reserves for the year ended December 31, 2016 included the following: • Extensions and discoveries . In 2016 , total extensions and discoveries of 8.4 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Purchases of minerals in place . In 2016 , total purchases of minerals in place of 0.8 MMBOE were primarily attributable to an acquisition with a third party (See Note 3). • Revisions to previous estimates . In 2016 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 15.4 MMBOE. Included in these revisions were 15.7 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 3.4 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule which was partially offset by a 3.6 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2016 to December 31, 2015 . Notable changes in proved reserves for the year ended December 31, 2015 included the following: • Extensions and discoveries . In 2015 , total extensions and discoveries of 10.7 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Revisions to previous estimates . In 2015 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 40.2 MMBOE. Included in these revisions were 52.6 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 12.4 MMBOE of net upward adjustments attributable to reservoir analysis and well performance when comparing the Company’s reserve estimates at December 31, 2015 to December 31, 2014. Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas . Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves. Years Ended December 31, 2017 2016 2015 Future Cash Inflows $ 3,143,603,968 $ 1,708,870,912 $ 2,470,707,712 Future Production Costs (1,265,524,800 ) (775,534,832 ) (981,256,096 ) Future Development Costs (409,360,320 ) (220,869,664 ) (356,401,888 ) Future Income Tax Expense (27,476,230 ) (2,477,353 ) (5,740,623 ) Future Net Cash Inflows $ 1,441,242,618 $ 709,989,063 $ 1,127,309,105 10% Annual Discount for Estimated Timing of Cash Flows (687,256,521 ) (330,963,050 ) (552,510,342 ) Standardized Measure of Discounted Future Net Cash Flows $ 753,986,097 $ 379,026,013 $ 574,798,763 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2017 $ 3.34 $ 45.90 December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03 The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of its assets at December 31, 2017 , the Company’s future income taxes were significantly reduced. Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: Years Ended December 31, 2017 2016 2015 Beginning of Period $ 379,026,013 $ 574,798,763 $ 1,405,379,543 Sales of Oil and Natural Gas Produced, Net of Production Costs (153,625,893 ) (98,497,165 ) (128,964,023 ) Extensions and Discoveries 217,145,871 59,542,911 96,770,078 Previously Estimated Development Cost Incurred During the Period 46,833,826 23,271,960 114,208,095 Net Change of Prices and Production Costs 216,216,656 (174,656,448 ) (1,384,474,928 ) Change in Future Development Costs (34,753,469 ) 57,481,060 235,578,690 Revisions of Quantity and Timing Estimates 28,914,878 (130,664,183 ) (363,975,445 ) Accretion of Discount 37,942,243 57,569,313 170,222,344 Change in Income Taxes (3,617,100 ) 497,950 295,949,531 Purchases of Minerals in Place — 9,576,760 — Other 19,903,072 105,092 134,104,878 End of Period $ 753,986,097 $ 379,026,013 $ 574,798,763

LONG TERM DEBT

LONG TERM DEBT	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
LONG TERM DEBT	LONG TERM DEBT The Company’s long-term debt consists of the following: December 31, 2017 Principal Balance Unamortized Net Discount Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 700,000,000 $ (1,197,954 ) $ (6,847,557 ) $ 691,954,489 Term Loan Credit Agreement 300,000,000 — (12,630,267 ) $ 287,369,733 Total $ 1,000,000,000 $ (1,197,954 ) $ (19,477,824 ) $ 979,324,222 December 31, 2016 Principal Balance Unamortized Net Discount Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 700,000,000 $ (1,693,847 ) $ (9,681,028 ) $ 688,625,125 Revolving Credit Facility (1) 144,000,000 — — $ 144,000,000 Total $ 844,000,000 $ (1,693,847 ) $ (9,681,028 ) $ 832,625,125 ____________ (1) Debt issuance costs related to our revolving credit facility were $1.6 million and are recorded in “Other Noncurrent Assets, Net” on the balance sheet as of December 31, 2016 Term Loan Credit Agreement On November 1, 2017 (the “Effective Date”), the Company entered into a term loan credit agreement with TPG Specialty Lending, Inc., as administrative agent and collateral agent (in such capacities, the “Agent”), and the lenders from time to time party thereto. The term loan credit agreement provides for the issuance of an aggregate principal amount of up to $500 million in term loans to the Company, consisting of (i) $300 million in initial term loans that were made on the Effective Date (the “Initial Loans”), (ii) $100 million in delayed draw term loans available to the Company, subject to satisfaction of certain conditions precedent described therein, for a period of 18 months after the Effective Date (the “Delayed Draw Loans”), and (iii) up to $100 million in incremental term loans on an uncommitted basis and subject, among other things, to one or more lenders agreeing in the future to make such loans (the “Incremental Loans”) (the Initial Loans, Delayed Draw Loans and the Incremental Loans, collectively, the “Loans”). Amounts borrowed and repaid under the term loan credit agreement may not be reborrowed. The term loan facility provided by the term loan credit agreement matures on November 1, 2022. Proceeds from the Initial Loans were used on the Effective Date to repay in its entirety borrowings outstanding under the Company’s prior Revolving Credit Facility. Borrowings under the term loan credit agreement bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus a 7.75% per annum margin. The “Adjusted LIBO Rate” is equal to the product of: (i) 3 month LIBOR multiplied by (ii) the statutory reserve rate. Upon the occurrence and continuance of an event of default all outstanding Loans shall bear interest at a rate equal to 3.00% per annum plus the then-effective rate of interest. Interest is payable on the last business day of each March, June, September and December. A commitment fee is paid on the unused amount of the delayed draw commitments based on an annual rate of 2.00% (the “Commitment Fee”). The term loan credit agreement also requires the Company to prepay the loans with 100.00% of the net cash proceeds received from certain asset sales, swap terminations, incurrences of borrowed money indebtedness, equity issuances, casualty events and extraordinary receipts, subject to certain exceptions and specified reinvestment rights. Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the term loan credit agreement are subject to the payment of a yield maintenance amount for any such prepayment, termination, refinancing, reduction or acceleration occurring within one year of the funding of the applicable Loan that allows the lenders to attain approximately the same yield as if such Loan remained outstanding for the entire 1 -year period plus a call protection amount equal to the product of the principal amount of Loans so prepaid, terminated, refinanced, reduced or accelerated multiplied by 7.00% ; for any such prepayment, termination, refinancing, reduction or acceleration occurring on or after the one-year anniversary of the funding of the applicable Loan, a call protection amount equal to the product of the principal amount of Loans so prepaid, terminated, refinanced, reduced or accelerated multiplied by (i) 7.00% if occurring within 18 months of the funding of such Loan, (ii) 3.00% if occurring after the 18 -month anniversary but on or prior to the 30 -month anniversary of the funding of such Loan, or (iii) 1.00% if occurring after the 30 -month anniversary but on or prior to the 42 -month anniversary of the funding of such Loan, will be due, in each case, as set forth in the term loan credit agreement. Additionally, to the extent that the Loans are refinanced in full or the delayed draw commitments are terminated or reduced prior to the date that is 18 months after the Effective Date, the Company will be required to pay a yield maintenance amount in respect of the Commitment Fee that would have accrued on the delayed draw commitments as set forth in the term loan credit agreement. The term loan credit agreement contains negative covenants that limit the Company’s ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain derivatives contracts, change the nature of our business or operations, merge, consolidate, or make certain types of investments and require the outstanding principal amount of the Company’s 8.00% senior unsecured notes due 2020 to be no more than $30 million by March 1, 2020. In addition, the term loan credit agreement requires that the Company comply with the following financial covenants: (i) as of any date of determination, the ratio of Total PDP PV-10 (as defined in the term loan credit agreement) plus the aggregate amount of all unrestricted cash and cash equivalents (in accounts subject to control agreements) to the amount of Senior Secured Debt (as defined in the term loan credit agreement) shall not be less than 1.30 to 1.00 , (ii) as of the last day of any fiscal quarter, the ratio of Net Senior Secured Debt (as defined in the term loan credit agreement) to EBITDAX (as defined in the term loan credit agreement) for the period of four fiscal quarters then ending on such day will not be greater than 3.75 to 1.00 and (iii) as of any date of determination the Company’s unrestricted cash and cash equivalents (in accounts subject to control agreements) plus the aggregate undrawn delayed draw commitments available to the Company shall not be less than $20.0 million . The obligations of the Company under the term loan credit agreement may be accelerated upon the occurrence of an Event of Default (as defined in the term loan credit agreement). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change in Control (as defined in the term loan credit agreement). The Company’s obligations under the term loan credit agreement are secured by mortgages on substantially all of the oil and gas properties of the Company subject to the limitations set forth in the Credit Agreement. In connection with the term loan credit agreement, the Company entered into a guaranty and collateral agreement in favor of the Agent for the secured parties, pursuant to which the obligations of the Company under the term loan credit agreement and any swap agreements entered into with swap counterparties are secured by a first-priority security interest in substantially all of the assets of the Company. Revolving Credit Facility The Company’s Revolving Credit Facility, described in the paragraphs that follow, was retired and repaid in full on November 1, 2017. In February 2012, the Company entered into an amended and restated credit agreement providing for a revolving credit facility (the “Revolving Credit Facility”), which replaced its previous revolving credit facility with a syndicated facility. The Revolving Credit Facility, was secured by substantially all of the Company’s assets and provided for a commitment equal to the lesser of the facility amount or the borrowing base. Borrowings under the Revolving Credit Facility could either be at the Alternate Base Rate (as defined in the credit agreement) plus a spread ranging from 1.00% to 2.00% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined in the credit agreement) plus a spread ranging from 2.00% to 3.00% . The applicable spread at any time was dependent upon the amount of borrowings relative to the borrowing base at such time. The Company could elect, from time to time, to convert all or any part of its LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. A commitment fee was paid on the undrawn balance based on an annual rate of either 0.375% or 0.50% . All of the Company’s obligations under the Revolving Credit Facility were secured by a first priority security interest in any and all assets of the Company. 8.000% Senior Notes Due 2020 On May 18, 2012, the Company issued at par value $300 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “Original Notes”). On May 13, 2013, the Company issued at a price of 105.25% of par an additional $200 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “2013 Follow-on Notes”). On May 18, 2015, the Company issued at a price of 95.000% of par an additional $200 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “2015 Mirror Notes” and, together with the Original Notes and the 2013 Follow-on Notes, the “Notes”). Interest is payable on the Notes semi-annually in arrears on each of June 1 and December 1. The Company currently does not have any subsidiaries and, as a result, the Notes are not currently guaranteed. Any subsidiaries the Company forms in the future may be required to unconditionally guarantee, jointly and severally, payment obligation under the Notes on a senior unsecured basis. The issuance of the Original Notes resulted in net proceeds to the Company of approximately $291.2 million , the issuance of the 2013 Follow-on Notes resulted in net proceeds to the Company of approximately $200.1 million , and the issuance of the 2015 Mirror Notes resulted in net proceeds to the Company of approximately $184.9 million . Collectively, the net proceeds are in use to fund the Company’s exploration, development and acquisition program and for general corporate purposes (including repayment of borrowings that were outstanding under the Revolving Credit Facility at the time the Notes were issued). On and after June 1, 2016, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 104% for the twelve-month period beginning on June 1, 2016, 102% for the twelve-month period beginning June 1, 2017 and 100% beginning on June 1, 2018, plus accrued and unpaid interest to the redemption date. The Original Notes and the 2013 Follow-on Notes are governed by an Indenture, dated as of May 18, 2012, by and among the Company and Wilmington Trust, National Association (the “Original Indenture”). The 2015 Mirror Notes are governed by an Indenture, dated as of May 18, 2015, by and among the Company and Wilmington Trust, National Association (the “Mirror Indenture”). The terms and conditions of the Mirror Indenture conform, in all material respects, to the terms and conditions set forth in the Original Indenture. As such, the Mirror Indenture, together with the Original Indenture, are referred to herein as the “Indenture.” The Indenture restricts the Company’s ability to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or, repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries (if any) will cease to be subject to such covenants. The Indenture contains customary events of default, including: • default in any payment of interest on any Note when due, continued for 30 days ; • default in the payment of principal of or premium, if any, on any Note when due; • failure by the Company to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods; • payment defaults and accelerations with respect to other indebtedness of the Company and certain of its subsidiaries, if any, in the aggregate principal amount of $25.0 million or more; • certain events of bankruptcy, insolvency or reorganization of the Company or a significant subsidiary or group of restricted subsidiaries that, taken together, would constitute a significant subsidiary; • failure by the Company or any significant subsidiary or group of restricted subsidiaries that, taken together, would constitute a significant subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days ; and • any guarantee of the Notes by a guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

COMMON AND PREFERRED STOCK

COMMON AND PREFERRED STOCK	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
COMMON AND PREFERRED STOCK	COMMON AND PREFERRED STOCK The Company’s Amended and Restated Articles of Incorporation authorize the issuance of up to 147,500,000 shares. The shares are classified in two classes, consisting of 142,500,000 shares of common stock, par value $0.001 per share, and 5,000,000 shares of preferred stock, par value $0.001 per share. The board of directors is authorized to establish one or more series of preferred stock, setting forth the designation of each such series, and fixing the relative rights and preferences of each such series. The Company has neither designated nor issued any shares of preferred stock. Common Stock The following is a schedule of changes in the number of shares of common stock outstanding since the beginning of 2015 : Years Ended December 31, 2017 2016 2015 Beginning Balance 63,259,781 63,120,384 61,066,712 Restricted Stock Grants (Note 6) 911,355 2,109,814 2,112,998 Legal Settlement 3,000,000 — — Surrenders - Tax Obligations (270,510 ) (375,875 ) (57,929 ) Other Forfeitures (108,993 ) (1,594,542 ) (1,397 ) Ending Balance 66,791,633 63,259,781 63,120,384 2017 Activity In 2017, 0.3 million shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $0.7 million , which is based on the market prices on the dates the shares were surrendered. In 2017, 3.0 million shares of common stock were issued in connection with a legal settlement with the Company’s former chief executive officer. See Note 8 for further information. In 2017, 0.1 million shares of common stock were forfeited by our interim chief executive officer and chief financial officer in connection with a performance-based vesting metric that was not achieved under a restricted stock award. 2016 Activity In 2016, 0.4 million shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $1.4 million , which is based on the market prices on the dates the shares were surrendered. In 2016, 1.5 million restricted shares of common stock were forfeited in connection with the termination of the employment of the Company’s former chief executive officer. The total amount of share-based compensation expense that was reversed in connection with the termination was approximately $1.8 million . 2015 Activity In 2015, the Company’s former chief executive officer received 1.4 million restricted shares of common stock in connection with a new employment agreement. In 2015, 0.1 million shares of common stock were surrendered by certain employees of the Company to cover tax obligations in connection with their restricted stock awards. The total value of these shares was approximately $0.3 million , which is based on the market prices on the dates the shares were surrendered. Stock Repurchase Program In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150 million of the Company’s outstanding common stock. The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions. In 2017 , 2016 and 2015 , the Company did not repurchase shares of its common stock under the stock repurchase program. The Company’s accounting policy upon the repurchase of shares is to deduct its par value from Common Stock and to reflect any excess of cost over par value as a deduction from Additional Paid-in Capital.

STOCK OPTIONS_STOCK-BASED COMPE

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS	STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS The Company maintains its 2013 Incentive Plan (the “2013 Plan”) to provide a means whereby the Company may be able, by granting equity and other types of awards, to attract, retain and motivate capable and loyal employees, non-employee directors, consultants and advisors of the Company, for the benefit of the Company and its shareholders. As of December 31, 2017 , there were 2.9 million shares available for future awards under the 2013 Plan. Restricted Stock Awards During the years ended December 31, 2017 , 2016 and 2015 , the Company issued 911,355 , 2,109,814 and 2,112,998 , respectively, restricted shares of common stock under the 2013 Plan as compensation to officers, employees and directors of the Company. Unvested restricted shares vest over various terms with all restricted shares vesting no later than April 2020. As of December 31, 2017 , there was approximately $3.1 million of total unrecognized compensation expense related to unvested restricted stock that will be recognized over a weighted-average period of approximately 1.8 years years. The Company has historically assumed a zero percent forfeiture rate, thus recognizing forfeitures as they occur, for restricted stock due to the small number of officers, employees and directors that have received restricted stock awards. The following table reflects the outstanding restricted stock awards and activity related thereto for the years ended December 31, 2017 , 2016 and 2015 : Year Ended Year Ended Year Ended Number of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Restricted Stock Awards: Restricted Shares Outstanding at the Beginning of the Year 1,905,104 $ 4.59 2,365,396 $ 7.15 538,499 $ 13.54 Shares Granted 911,355 2.10 2,109,814 3.83 2,112,998 6.29 Shares Forfeited (108,993 ) 3.59 (1,594,542 ) 4.67 (1,397 ) 14.79 Lapse of Restrictions (985,933 ) 4.05 (975,564 ) 7.34 (284,704 ) 12.24 Restricted Shares Outstanding at the End of the Year 1,721,533 $ 3.65 1,905,104 $ 4.59 2,365,396 $ 7.15 Stock Option Awards On November 1, 2007, the board of directors granted options to purchase 560,000 shares of the Company’s common stock under the Company’s 2006 Incentive Stock Option Plan. The Company granted options to purchase 500,000 shares of the Company’s common stock to members of the board and options to purchase 60,000 shares of the Company’s common stock to one employee pursuant to an employment agreement. These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date. On November 1, 2017, the remaining options expired. The board of directors previously determined that no future grants will be made pursuant to the 2006 Incentive Stock Option Plan. On February 12, 2016, the board of directors granted options to purchase 250,000 shares of the Company’s common stock under the Company’s 2013 Plan. The Company granted options to purchase 250,000 shares of the Company’s common stock to one of its board members in connection with his appointment as chairman of the board of directors in January 2016. These options were granted with an exercise price of $2.79 per share and were fully vested on the grant date. As a result of the options being fully vested on the grant date, the Company recorded share-based compensation expense of $0.4 million for the year ended December 31, 2016. Changes in stock option awards for the years ended December 31, 2017 , 2016 , and 2015 were as follows: Stock Option Awards Weighted-Average Price Weighted Average Contractual Term Intrinsic Value Outstanding as of December 31, 2014 (1) 141,872 $ 5.18 2.8 $ 66,680 Granted — — Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2015 (1) 141,872 $ 5.18 1.8 $ — Granted 250,000 $ 2.79 Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2016 (1) 391,872 $ 3.66 2.9 $ — Granted — — Exercised — — Expired or canceled (141,872) — Outstanding as of December 31, 2017 (1) 250,000 $ 2.79 1.0 $ — ____________ (1) All of the stock options outstanding were vested and exercisable at the end of the period. Performance Equity Awards The Company has granted performance equity awards under its 2017 Long Term Incentive Program to certain officers. The awards are subject to market conditions that are based on the Company’s 2017 total shareholder return on both an absolute and relative basis. Depending on the Company’s stock price performance, on both an absolute basis and on a relative basis compared to the defined peer group, the award recipients may earn between 0% and 150% of their 2017 base salaries, with any such amounts expected to be settled in restricted shares of the Company’s common stock that will vest over a three -year service-based period beginning in 2018 . The Company used a Monte Carlo simulation model to estimate the fair value of the awards based on the expected outcome of the Company’s stock price performance, on both an absolute basis and on a relative basis compared to the defined peer group, using key valuation assumptions. The assumptions used for the Monte Carlo model to determine the fair value of the awards and associated compensation expense included a forecast period for the relevant stock price period in 2017 , a risk-free interest rate of 0.97% and 80% for the Company’s stock price volatility. The maximum value of the performance shares issuable if all participants earned the maximum award would total $1.3 million . For the year ended December 31, 2017 , the Company recorded $0.1 million of compensation expense related to these performance equity awards.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS Michael Frantz, a member of the Company’s board of directors since August 2016, is the Vice President, Investments of TRT Holdings, Inc. Michael Popejoy, a member of the Company’s board of directors since January 2017, is the Senior Vice President of Energy for TRT Holdings, Inc. TRT Holdings and its affiliates (collectively, “TRT”) are significant common stockholders of the Company and also a holder of the Company’s 8% senior unsecured notes, due 2020 (the “Notes”). The Company believes TRT owned in excess of $200 million aggregate principal amount of the Notes at December 31, 2017 . The principal amounts of any Notes held by TRT are included in the Company’s long-term debt balances, and the Company’s interest expense includes interest attributable to any Notes held by TRT. All transactions involving related parties are approved or ratified by the Company’s Audit Committee.

COMMITMENTS & CONTINGENCIES

COMMITMENTS & CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS & CONTINGENCIES	COMMITMENTS & CONTINGENCIES Litigation The Company is engaged in various proceedings incidental to the normal course of business. Due to their nature, such legal proceedings involve inherent uncertainties, including but not limited to, court rulings, negotiations between affected parties and governmental intervention. Based upon the information available to the Company and discussions with legal counsel, it is the Company’s opinion that the outcome of the various legal actions and claims that are incidental to its business will not have a material impact on the Company’s financial position, results of operations or cash flows. Such matters, however, are subject to many uncertainties, and the outcome of any matter is not predictable with assurance. The Company’s interests in certain crude oil and natural gas leases from the State of North Dakota are subject to an ongoing dispute over the ownership of minerals underlying the bed of the Missouri River within the boundaries of the Fort Berthold Reservation. The ongoing dispute is between the State of North Dakota and three affiliated tribes, both of whom have purported to lease mineral rights in tracts of riverbed within the reservation boundaries. In the event the ongoing dispute results in a final judgment that is adverse to the Company’s interests, the Company would be required to reverse approximately $5.5 million in revenue (net of accrued taxes) that has been accrued since the first quarter of 2013 based on the Company’s purported interest in the crude oil and natural gas leases at issue. Due to the long-term nature of this title dispute, the $5.5 million in accounts receivable is included in “Other Noncurrent Assets, Net” on the balance sheets. The Company fully maintains the validity of its interests in the crude oil and natural gas leases. On August 16, 2016, Michael Reger filed a complaint against the Company in the State of Minnesota, Fourth Judicial District, alleging breach of contract and defamation in connection with the Company’s termination of Mr. Reger’s employment as chief executive officer on August 15, 2016. On September 25, 2017, the Company entered into a settlement agreement and general release with Mr. Reger pursuant to which, among other things, Mr. Reger agreed to dismiss his lawsuit against the Company and the Company agreed to pay him $750,000 in cash and issue him 3,000,000 shares of the Company’s common stock. On August 18, 2016, plaintiff Jeffrey Fries, individually and on behalf of all others similarly situated, filed a class action complaint in the United States District Court for the Southern District of New York against the Company, Michael Reger (our former chief executive officer), and Thomas Stoelk (our former chief financial officer and interim chief executive officer) as defendants. An amended complaint was filed by plaintiffs in July 2017. Defendants (including the Company) filed a motion to dismiss the amended complaint in August 2017. The court granted the Company’s motion to dismiss in January 2018, but permitted plaintiff the opportunity to further amend the complaint. A second amended complaint was filed by plaintiffs in January 2018. The complaint purports to bring a federal securities class action on behalf of a class of persons who acquired the Company’s securities between March 1, 2013 and August 15, 2016, and seeks to recover damages caused by defendants’ alleged violations of the federal securities laws and to pursue remedies under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. The Company intends to continue to vigorously defend itself in this matter.

ASSET RETIREMENT OBLIGATION

ASSET RETIREMENT OBLIGATION	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation [Abstract]
ASSET RETIREMENT OBLIGATION	ASSET RETIREMENT OBLIGATION The Company has asset retirement obligations (“ARO”) associated with the future plugging and abandonment of proved properties and related facilities. Initially, the fair value of a liability for an ARO is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO, a corresponding adjustment is made to the oil and gas property balance. For example, as the Company analyzes actual plugging and abandonment information, the Company may revise its estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of its wells. During 2017 and 2016 , the Company increased its existing ARO by $0.6 million and $0.8 million , respectively, due to an increase in the estimated costs to plug and abandon the Company’s wells. The following table summarizes the Company’s asset retirement obligation transactions recorded during the year ended December 31, 2017 and 2016 . Years Ended December 31, 2017 2016 Beginning Asset Retirement Obligation $ 7,508,300 $ 5,816,356 Liabilities Acquired or Incurred During the Period 578,441 585,729 Liabilities Removed Due to Divestitures — (21,426 ) Revision of Estimates 609,351 789,003 Accretion of Discount on Asset Retirement Obligations 536,732 405,991 Liabilities Settled During the Period (104,696 ) (67,353 ) Ending Asset Retirement Obligation $ 9,128,128 $ 7,508,300

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. The income tax provision (benefit) for the year ended December 31, 2017 , 2016 , and 2015 consists of the following: 2017 2016 2015 Current Federal $ (785,016 ) $ (1,402,179 ) $ (73,649 ) State — — — Deferred Federal 126,501,000 (99,298,900 ) (398,002,555 ) State (12,983,000 ) (9,707,000 ) (36,608,000 ) Valuation Allowance (114,303,000 ) 109,005,900 232,260,000 Total Expense (Benefit) $ (1,570,016 ) $ (1,402,179 ) $ (202,424,204 ) The following is a reconciliation of the reported amount of income tax benefit for the years ended December 31, 2017 , 2016 , and 2015 to the amount of income tax expenses that would result from applying the statutory rate to pretax loss. 2017 2016 2015 Income (Loss) Before Taxes and NOL $ (10,763,788 ) $ (294,895,887 ) $ (1,177,778,745 ) Federal Statutory Rate 35.00 % 35.00 % 35.00 % Taxes Computed at Federal Statutory Rates (3,767,000 ) (103,214,000 ) (412,223,000 ) State Taxes, Net of Federal Taxes (8,476,000 ) (6,306,000 ) (23,825,000 ) Non-Deductible Compensation 22,000 82,000 470,000 Share Based Compensation Tax Deficiency — (834,900 ) 307,000 Federal Rate Reduction 124,493,000 — — Other 460,984 (135,179 ) 586,796 Valuation Allowance (114,303,000 ) 109,005,900 232,260,000 Reported Provision (Benefit) $ (1,570,016 ) $ (1,402,179 ) $ (202,424,204 ) A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During 2017 , in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil and natural gas. Based on all the evidence available, management determined it was more likely than not that the net deferred tax assets, other than the deferred tax asset related to the Company’s alternative minimum tax credit, were not realizable, therefore a valuation allowance of $227.0 million was recorded at December 31, 2017 . At December 31, 2017 , the Company has an alternative minimum tax credit for federal income tax purposes of $0.8 million . Under the Tax Cuts and Jobs Act, enacted in December 2017, the alternative minimum tax credit will be refundable in future years. At December 31, 2017 , the Company had a net operating loss carryforward for federal income tax purposes of $714.5 million . If unutilized, the federal net operating losses will expire from 2031 to 2037 . The significant components of the Company’s deferred tax assets (liabilities) were as follows: Years Ended December 31, 2017 2016 Net Operating Loss (NOLs) and Tax Credit Carryforwards $ 174,864,900 $ 224,679,900 Share Based Compensation 797,000 1,032,000 Accrued Interest 1,144,000 1,727,000 Allowance for Doubtful Accounts 1,360,000 1,795,000 Crude Oil and Natural Gas Properties and Other Properties 42,329,000 107,642,000 Derivative Instruments 7,393,000 4,341,000 Other (140,000 ) 49,000 Total Net Deferred Tax Assets (Liabilities) Before Valuation Allowance 227,747,900 341,265,900 Valuation Allowance (226,962,900 ) (341,265,900 ) Total Net Deferred Tax Assets $ 785,000 $ — Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards. The Company has no liabilities for unrecognized tax benefits. The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense. For the years ended December 31, 2017 , 2016 and 2015 , the Company did not recognize any interest or penalties in its statements of operations, nor did it have any interest or penalties accrued in its balance sheet at December 31, 2017 and 2016 relating to unrecognized benefits. The tax years 2017 , 2016 , 2015 , 2014 , 2013, 2012, 2011 and 2010 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company is subject. The Protecting Americans from Tax Hikes Act of 2015 (PATH) was enacted on December 18, 2015. PATH retroactively extended various temporary individual and business tax incentives for 2015 and in some instances extended certain incentives through 2019. Bonus tax depreciation, a favorable tax incentive for the Company, was extended from 2015 through 2019. In 2017 and 2016 , the Company utilized $0.8 million and $1.4 million of its alternative minimum tax credit, respectively, as a result of favorable tax incentives within PATH. On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (“the Act”) which made significant changes that affect the Company. Beginning January 1, 2018, the Company will be taxed at a 21% federal corporate tax rate. The Company has reflected the impact of this rate enactment on its deferred tax assets and liabilities at December 31, 2017, the Company is required to reflect the change in the period in which the law is enacted. The impact of this change was a net reduction in deferred tax assets of $124.5 million , before valuation allowance. The Company’s valuation allowance was reduced by $125.3 million . Due to the Company’s valuation allowance position the net effect of the Act was a tax benefit of $0.8 million . The Act also repeals the corporate alternative minimum tax for tax years beginning after December 31, 2017 and provides that prior alternative minimum tax credits will be refundable. The Company has credits that are expected to be refunded between 2018 and 2021 as a result of the Act and monetization opportunities under current tax laws. The Act is a comprehensive tax reform bill containing a number of other provisions that either currently or in the future could impact the Company. The Company has completed the analysis of the Act and does not expect a material change due to the transition impacts. Any changes that do arise due to changes in interpretations of the Act, legislative action to address questions that arise because of the Act, changes in accounting standards for income taxes or related interpretations in response to the Act, or any updates or changes to estimates the Company has utilized to calculate the transition impacts will be disclosed in future periods as they arise. The effect of certain limitations effective for the tax year 2018 and forward, specifically related to the deductibility of executive compensation and interest expense, have been evaluated.

OPERATING LEASES

OPERATING LEASES	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
OPERATING LEASES	OPERATING LEASES The Company leases office space under operating leases expiring on various dates through 2021 . Minimum future annual lease payments for the calendar years presented are as follows: Amount 2018 $ 342,000 2019 352,000 2020 361,000 2021 340,000 Total $ 1,395,000 The following has been recorded to rent expense for the periods presented: Years Ended December 31, 2017 2016 2015 Rent Expense $ 369,000 $ 320,000 $ 287,000 The Company’s office space lease agreements contain scheduled escalation in lease payment during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred rent liability for the difference between the straight-line amount and the actual amounts of the lease payments. Rent expense is included in the statement of operations in the “General and Administrative Expense” line item.

FAIR VALUE

FAIR VALUE	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
FAIR VALUE	FAIR VALUE Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following: Level 1 - Quoted prices in active markets for identical assets or liabilities. Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. Financial Assets and Liabilities As required, financial assets and liabilities are classified in their entirety 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 requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016 . Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Asset (crude oil swaps) $ — $ — $ — Commodity Derivatives – Current Liabilities (crude oil swaps) — (18,681,891 ) — Commodity Derivatives – Non-Current Asset (crude oil swaps) — — — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — (11,496,929 ) — Total $ — $ (30,178,820 ) $ — Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Asset (crude oil swaps) $ — $ 4,517 $ — Commodity Derivatives – Current Liabilities (crude oil swaps and collars) — (10,001,564 ) — Commodity Derivatives – Non-Current Asset (crude oil swaps) — — — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — (1,738,329 ) — Total $ — $ (11,735,376 ) $ — The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include crude oil swaps, collars, and swaptions (see Note 13). The fair value of the Company’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The Company’s and the counterparties’ nonperformance risk is evaluated. The fair value of all derivative contracts is reflected on the balance sheet. The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months. Fair Value of Other Financial Instruments The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The carrying amount of the Company’s long-term debt reported in the balance sheet at December 31, 2017 is $979.3 million , which includes $692.0 million of senior unsecured notes including a net discount of $1.2 million and $287.4 million of borrowings under the Company’s term loan credit agreement (see Note 4). The fair value of the Company’s senior unsecured notes, which are publicly traded, is $528.0 million at December 31, 2017 . The Company’s term loan credit agreement approximates its fair value because of its floating rate structure. Non-Financial Assets and Liabilities The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC 410. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and natural gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligations liability is deemed to use Level 3 inputs. Asset retirement obligations incurred for the year ended December 31, 2017 were approximately $0.6 million . Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. There were no transfers of financial assets or liabilities between Level 1, Level 2 or Level 3 inputs for the years ended December 31, 2017 and 2016 .

DERIVATIVE INSTRUMENTS AND PRIC

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT	DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT The Company utilizes commodity swap contracts, swaptions and collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the crude oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. All derivative instruments are recorded on the Company’s balance sheet as either assets or liabilities measured at their fair value (see Note 12). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value are recognized in the revenues section of the Company’s statements of operations as a gain or loss on derivative instruments. Mark-to-market gains and losses represent changes in fair values of derivatives that have not been settled. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period-end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period. Years Ended 2017 2016 2015 Cash Received (Paid) on Derivatives (1) $ 3,776,788 $ 61,528,201 $ 161,098,510 Non-Cash Gain (Loss) on Derivatives (18,443,443 ) (76,346,935 ) (88,715,603 ) Gain (Loss) on Derivative Instruments, Net $ (14,666,655 ) $ (14,818,734 ) $ 72,382,907 _____________ (1) Net cash paid for crude oil swaps for the year ended December 31, 2017 include approximately $0.7 million of payments from crude oil derivative contracts that were settled prior to their contractual maturities as a result of the termination of the Company’s revolving credit facility. Net cash receipts for the year ended December 31, 2015 includes approximately $0.2 million of proceeds received from crude oil derivative contracts that were settled prior to their contractual maturities. The Company has master netting agreements on individual crude oil contracts with certain counterparties and therefore the current asset and liability are netted on the balance sheet and the non-current asset and liability are netted on the balance sheet for contracts with these counterparties. The following table reflects open commodity swap contracts as of December 31, 2017 , the associated volumes and the corresponding fixed price. Settlement Period Oil (Barrels) Fixed Price ($) Swaps-Crude Oil 01/01/18 – 08/31/18 160,000 49.99 01/01/18 – 08/31/18 160,000 50.04 01/01/18 – 08/31/18 160,000 49.99 01/01/18 – 08/31/18 160,000 50.17 01/01/18 – 09/30/18 270,000 53.99 01/01/18 – 09/30/18 270,000 53.99 01/01/18 – 09/30/18 273,000 55.19 01/01/18 – 12/31/18 180,000 53.30 01/01/18 – 12/31/18 365,000 54.80 01/01/18 – 12/31/18 365,000 54.09 01/01/18 – 12/31/18 365,000 54.42 10/01/18 – 12/31/18 92,000 52.50 10/01/18 – 12/31/18 92,000 52.55 10/01/18 – 12/31/18 46,000 54.50 10/01/18 – 12/31/18 92,000 52.50 01/01/19 – 03/31/19 45,000 54.22 01/01/19 – 03/31/19 63,000 53.65 01/01/19 – 12/31/19 365,000 51.05 01/01/19 – 12/31/19 365,000 51.05 01/01/19 – 12/31/19 182,500 52.70 01/01/19 – 12/31/19 365,000 51.05 01/01/19 – 12/31/19 182,500 52.15 01/01/19 – 12/31/19 182,500 52.75 04/01/19 – 06/30/19 45,500 53.59 04/01/19 – 06/30/19 36,400 53.10 07/01/19 – 09/30/19 46,000 53.07 07/01/19 – 09/30/19 9,200 52.65 01/01/20 – 03/31/20 27,300 51.81 01/01/20 – 12/31/20 366,000 49.77 01/01/20 – 12/31/20 183,000 51.30 01/01/20 – 12/31/20 109,800 51.70 01/01/20 – 12/31/20 366,000 49.75 01/01/20 – 12/31/20 183,000 51.10 04/01/20 – 06/30/20 9,100 51.50 As of December 31, 2017 , the Company had a total volume on open commodity swaps of 6.2 million barrels at a weighted average price of approximately $52.24 per barrel. The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2017 , by year with associated volumes. Weighted Average Price Year Volumes (Bbl) Weighted 2018 3,050,000 53.26 2019 1,887,600 51.80 2020 1,244,200 50.41 The Company determines the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by ailing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. For further details regarding the Company’s derivative contracts see Note 12, Fair Value in the Notes to the Financial Statements. The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at December 31, 2017 and 2016 , respectively. Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement: December 31, Type of Crude Oil Contract Balance Sheet Location 2017 2016 Derivative Assets: Swap Contracts Current Assets $ — $ 4,517 Total Derivative Assets $ — $ 4,517 Derivative Liabilities: Swap Contracts Current Liabilities $ (18,681,891 ) $ (9,512,724 ) Swap Contracts Non-Current Liabilities (11,496,929 ) (1,738,329 ) Swaption Contracts Current Liabilities — (333,046 ) Costless Collars Current Liabilities — (155,794 ) Total Derivative Liabilities $ (30,178,820 ) $ (11,739,893 ) The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. When the Company has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments these assets and liabilities are netted on the balance sheet. The tables presented below provide reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet. The amounts presented exclude derivative settlement receivables and payables as of the balance sheet dates. Estimated Fair Value at December 31, 2017 Gross Amounts of Recognized Assets (Liabilities) Gross Amounts Offset in the Net Amounts of Assets (Liabilities) Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ — $ — $ — Non-Current Assets — — — Total Derivative Assets $ — $ — $ — Offsetting of Derivative Liabilities: Current Liabilities $ (18,681,891 ) $ — $ (18,681,891 ) Non-Current Liabilities (11,496,929 ) — (11,496,929 ) Total Derivative Liabilities $ (30,178,820 ) $ — $ (30,178,820 ) Estimated Fair Value at December 31, 2016 Gross Amounts of Recognized Assets (Liabilities) Gross Amounts Offset in the Net Amounts of Assets (Liabilities) Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 20,962 $ (16,445 ) $ 4,517 Non-Current Assets — — — Total Derivative Assets $ 20,962 $ (16,445 ) $ 4,517 Offsetting of Derivative Liabilities: Current Liabilities $ (10,018,009 ) $ 16,445 $ (10,001,564 ) Non-Current Liabilities (1,738,329 ) — (1,738,329 ) Total Derivative Liabilities $ (11,756,338 ) $ 16,445 $ (11,739,893 ) All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”) entered into with BP Energy Company, Macquarie Bank Limited, and Fifth Third Bank. The Company’s obligations under the derivative instruments are secured pursuant to the term loan credit agreement and related agreements, and no additional collateral had been posted by the Company as of December 31, 2017 . The ISDAs may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. See Note 12 for the aggregate fair value of all derivative instruments that were in a net liability position at December 31, 2017 and 2016 .

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE The following is a reconciliation of the numerator and denominator used to calculate basic earnings per share and diluted earnings per share for the years ended December 31, 2017 , 2016 , and 2015 : 2017 2016 2015 Net Loss Shares Per Share Net Loss Shares Per Share Net Income Shares Per Share Basic EPS $ (9,193,772 ) 62,408,855 $ (0.15 ) $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 ) Dilutive Effect of Options — — — — — — — — — Diluted EPS $ (9,193,772 ) 62,408,855 $ (0.15 ) $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 ) For the year ended December 31, 2017 , 2016 and 2015 restricted stock of 1,109,511 , 829,313 , and 322,393 shares of common stock were excluded from EPS due to the anti-dilutive effect, respectively.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2017
Compensation Related Costs [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS In 2009, the Company adopted a defined contribution 401(k) plan for substantially all of its employees. The plan provides for Company matching of employee contributions to the plan. During 2017 , 2016 and 2015 , the Company provided a match contribution equal to 100% of an eligible employee’s deferral contribution, up to 8% of the employee’s earnings up to the maximum allowable amount. The Company contributed approximately $178,000 , $238,000 and $279,000 to the 401(k) plan for the years ended December 31, 2017 , 2016 and 2015 , respectively.

SUPPLEMENTAL OIL AND GAS INFORM

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)	CRUDE OIL AND NATURAL GAS PROPERTIES The value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at December 31, 2017 and 2016 were approximately $85.0 million and $50.7 million , respectively. 2017 Acquisitions During 2017, the Company acquired approximately 1,934 net acres, for an average cost of approximately $2,352 per net acre, in its key prospect areas in the form of effective leases. 2016 Acquisitions During 2016, the Company acquired approximately 3,399 net acres, for an average cost of approximately $1,515 per net acre, in its key prospect areas in the form of effective leases. On October 6, 2016, the Company entered into a definitive purchase and sale agreement with a third party, for their interests in 144 gross ( 3.8 net) producing oil and gas wells and associated acreage. The motivation for the acquisition was the expectation that it was accretive to cash flow and earnings per share. On October 26, 2016, the Company closed the transaction for cash consideration of $9.4 million which is comprised of $8.9 million related to producing properties and a $0.5 million reimbursement of drilling costs on in process wells. The results of operations from the October 26, 2016 closing date through December 31, 2016, represented approximately $1.2 million of revenue and $0.5 million of direct operating expenses. The combined pro forma information has not been presented due to its immateriality. No material transaction costs were incurred in connection with this purchase and there was no goodwill recorded from this acquisition. 2015 Acquisitions During 2015, the Company acquired approximately 4,355 net acres, for an average cost of approximately $1,314 per net acre, in its key prospect areas in the form of effective leases. Divestitures From time-to-time the Company may divest assets. In addition, the Company may trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage. Unproved Properties Unproved properties not being amortized comprise approximately 14,377 net acres and 26,432 net acres of undeveloped leasehold interests at December 31, 2017 and 2016 , respectively. The Company believes that the majority of its unproved costs will become subject to depletion within the next five years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will be dependent upon the timing of future drilling activities and delineation of its reserves. Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years . The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2017 by year incurred. Years Ended December 31, 2017 2016 2015 Prior Years Property Acquisition $ 565,352 $ 509,877 $ 502,794 $ 121,321 Development — — — — Total $ 565,352 $ 509,877 $ 502,794 $ 121,321 All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion. Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion. The Company historically has acquired its properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. The Company generally participates in drilling activities on a heads up basis by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling. The Company assesses all items classified as unproved property on an annual basis, or if certain circumstances exist, more frequently, for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the years ended December 31, 2017 , 2016 and 2015 , the Company included $0.6 million , $7.0 million and $37.6 million , respectively, related to expiring leases within costs subject to the depletion calculation. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Natural Gas Exploration and Production Activities Oil and gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s crude oil and natural gas production activities are provided in the Company’s related statements of income. Costs Incurred and Capitalized Costs The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2017 2016 2015 Costs Incurred for the Year: Proved Property Acquisition and Other $ 15,722,378 $ 18,531,518 $ 9,068,139 Unproved Property Acquisition 716,681 2,301,285 3,346,214 Development 139,531,567 63,621,429 116,255,535 Total $ 155,970,626 $ 84,454,232 $ 128,669,888 Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2017 by year incurred. Years Ended December 31, 2017 2016 2015 Prior Years Property Acquisition $ 565,352 $ 509,877 $ 502,794 $ 121,321 Development — — — — Total $ 565,352 $ 509,877 $ 502,794 $ 121,321 Oil and Natural Gas Reserves and Related Financial Data Information with respect to the Company’s crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Ryder Scott Company, independent petroleum consultants based on information provided by the Company. Oil and Natural Gas Reserve Data The following tables present the Company’s independent petroleum consultants’ estimates of its proved crude oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Natural Gas Oil BOE Proved Developed and Undeveloped Reserves at December 31, 2014 70,935,117 88,913,305 100,735,825 Revisions of Previous Estimates (23,552,809 ) (36,277,018 ) (40,202,486 ) Extensions, Discoveries and Other Additions 8,170,259 9,346,864 10,708,574 Production (4,651,583 ) (5,168,687 ) (5,943,951 ) Proved Developed and Undeveloped Reserves at December 31, 2015 50,900,984 56,814,464 65,297,962 Revisions of Previous Estimates (8,697,825 ) (13,995,801 ) (15,445,439 ) Extensions, Discoveries and Other Additions 7,695,309 7,142,439 8,424,991 Purchases of Minerals in Place 960,758 640,108 800,234 Production (4,026,899 ) (4,325,919 ) (4,997,069 ) Proved Developed and Undeveloped Reserves at December 31, 2016 46,832,327 46,275,291 54,080,679 Revisions of Previous Estimates 8,838,976 889,814 2,362,977 Extensions, Discoveries and Other Additions 27,637,350 20,184,388 24,790,613 Production (5,187,886 ) (4,537,295 ) (5,401,943 ) Proved Developed and Undeveloped Reserves at December 31, 2017 78,120,767 62,812,198 75,832,326 Proved Developed Reserves: December 31, 2014 38,277,770 44,666,408 51,046,037 December 31, 2015 33,619,954 36,573,821 42,177,147 December 31, 2016 32,808,111 32,245,139 37,713,158 December 31, 2017 46,518,005 38,592,506 46,345,507 Proved Undeveloped Reserves: December 31, 2014 32,657,347 44,246,897 49,689,788 December 31, 2015 17,281,030 20,240,643 23,120,815 December 31, 2016 14,024,216 14,030,152 16,367,521 December 31, 2017 31,602,762 24,219,692 29,486,819 Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years. Notable changes in proved reserves for the year ended December 31, 2017 included the following: • Extensions and discoveries . In 2017 , total extensions and discoveries of 24.8 MMBOE were primarily attributable to successful drilling in the Williston Basin as well as the addition of proved undeveloped locations. Included in these extensions and discoveries were 5.9 MMBOE as a result of successful drilling in the Williston Basin and 18.9 MMBOE as a result of additional proved undeveloped locations. • Revisions to previous estimates . In 2017 , revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 2.4 MMBOE. Included in these revisions were 1.8 MMBOE of upward adjustments caused by higher crude oil and natural gas prices and a 3.1 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2017 to December 31, 2016 which was partially offset by 2.5 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule. Notable changes in proved reserves for the year ended December 31, 2016 included the following: • Extensions and discoveries . In 2016 , total extensions and discoveries of 8.4 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Purchases of minerals in place . In 2016 , total purchases of minerals in place of 0.8 MMBOE were primarily attributable to an acquisition with a third party (See Note 3). • Revisions to previous estimates . In 2016 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 15.4 MMBOE. Included in these revisions were 15.7 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 3.4 MMBOE of downward adjustments related to the removal of undeveloped drilling locations related to the 5 year rule which was partially offset by a 3.6 MMBOE upward adjustment attributable to well performance when comparing the Company’s reserve estimates at December 31, 2016 to December 31, 2015 . Notable changes in proved reserves for the year ended December 31, 2015 included the following: • Extensions and discoveries . In 2015 , total extensions and discoveries of 10.7 MMBOE were primarily attributable to successful drilling in the Williston Basin. Both the new wells drilled in these areas as well as the proved undeveloped locations added as a result of drilling increased the Company’s proved reserves. • Revisions to previous estimates . In 2015 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 40.2 MMBOE. Included in these revisions were 52.6 MMBOE of downward adjustments caused by lower crude oil and natural gas prices and 12.4 MMBOE of net upward adjustments attributable to reservoir analysis and well performance when comparing the Company’s reserve estimates at December 31, 2015 to December 31, 2014. Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas . Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves. Years Ended December 31, 2017 2016 2015 Future Cash Inflows $ 3,143,603,968 $ 1,708,870,912 $ 2,470,707,712 Future Production Costs (1,265,524,800 ) (775,534,832 ) (981,256,096 ) Future Development Costs (409,360,320 ) (220,869,664 ) (356,401,888 ) Future Income Tax Expense (27,476,230 ) (2,477,353 ) (5,740,623 ) Future Net Cash Inflows $ 1,441,242,618 $ 709,989,063 $ 1,127,309,105 10% Annual Discount for Estimated Timing of Cash Flows (687,256,521 ) (330,963,050 ) (552,510,342 ) Standardized Measure of Discounted Future Net Cash Flows $ 753,986,097 $ 379,026,013 $ 574,798,763 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2017 $ 3.34 $ 45.90 December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03 The expected tax benefits to be realized from utilization of the net operating loss and tax credit carryforwards are used in the computation of future income tax cash flows. As a result of available net operating loss carryforwards and the remaining tax basis of its assets at December 31, 2017 , the Company’s future income taxes were significantly reduced. Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: Years Ended December 31, 2017 2016 2015 Beginning of Period $ 379,026,013 $ 574,798,763 $ 1,405,379,543 Sales of Oil and Natural Gas Produced, Net of Production Costs (153,625,893 ) (98,497,165 ) (128,964,023 ) Extensions and Discoveries 217,145,871 59,542,911 96,770,078 Previously Estimated Development Cost Incurred During the Period 46,833,826 23,271,960 114,208,095 Net Change of Prices and Production Costs 216,216,656 (174,656,448 ) (1,384,474,928 ) Change in Future Development Costs (34,753,469 ) 57,481,060 235,578,690 Revisions of Quantity and Timing Estimates 28,914,878 (130,664,183 ) (363,975,445 ) Accretion of Discount 37,942,243 57,569,313 170,222,344 Change in Income Taxes (3,617,100 ) 497,950 295,949,531 Purchases of Minerals in Place — 9,576,760 — Other 19,903,072 105,092 134,104,878 End of Period $ 753,986,097 $ 379,026,013 $ 574,798,763

QUARTERLY RESULTS OF OPERATIONS

QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)	QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) Quarterly data for the years end December 31, 2017 and 2016 is as follows: Quarter Ended March 31, June 30, September 30, December 31, 2017 Total Revenues $ 65,816,847 $ 64,901,882 $ 41,598,659 $ 37,002,281 Gains (Losses) on Derivative Instruments, Net 16,960,883 16,513,032 (12,663,253 ) (35,477,317 ) Total Operating Expenses 32,572,699 34,576,905 41,013,678 40,661,791 Income (Loss) from Operations 33,244,148 30,324,977 584,981 (3,659,510 ) Other Income (Expense) (16,303,805 ) (16,523,118 ) (16,672,448 ) (21,759,013 ) Income Tax Benefit — — — (1,570,016 ) Net Income (Loss) 16,940,523 13,801,859 (16,087,467 ) (23,848,687 ) Net Income (Loss) Per Common Share – Basic 0.28 0.22 (0.26 ) (0.37 ) Net Income (Loss) Per Common Share – Diluted 0.27 0.22 (0.26 ) (0.37 ) Quarter Ended March 31, June 30, September 30, December 31, 2016 Total Revenues $ 31,836,236 $ 32,014,226 $ 45,109,408 $ 35,943,626 Gains (Losses) on Derivative Instruments, Net 3,463,883 (10,522,948 ) 3,381,564 (11,141,233 ) Total Operating Expenses 141,220,772 124,946,744 74,583,046 33,457,789 Impairment 104,311,122 88,880,921 43,820,791 — Income (Loss) from Operations (109,384,536 ) (92,932,518 ) (29,473,638 ) 2,485,837 Other Income (Expense) (17,181,218 ) (16,046,144 ) (16,145,257 ) (16,218,413 ) Income Tax Benefit — — — (1,402,179 ) Net Loss (126,565,754 ) (108,978,662 ) (45,618,895 ) (12,330,397 ) Net Loss Per Common Share – Basic (2.08 ) (1.78 ) (0.74 ) (0.20 ) Net Loss Per Common Share – Diluted (2.08 ) (1.78 ) (0.74 ) (0.20 )

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Exchange Agreement On January 31, 2018, the Company entered into an agreement (the “Exchange Agreement”) with holders (the “Supporting Noteholders”) of approximately $497 million , or 71% , of the aggregate principal amount of the Company’s outstanding 8.000% senior unsecured notes due 2020 (the “Outstanding Notes”), pursuant to which the Supporting Noteholders have agreed to exchange all of the Outstanding Notes held by each such Supporting Noteholder for approximately $155 million of the Company’s common stock, par value $0.001 (the “Common Stock”), and approximately $344 million in aggregate principal amount of new senior secured second lien notes due 2023 (the “Second Lien Notes”) (such proposed exchange, the “Exchange Transaction”). For each $1,000 principal amount of Outstanding Notes exchanged pursuant to the Exchange Agreement, (i) TRT Holdings, Inc. and its affiliates will receive $612 in principal amount of Second Lien Notes and approximately 133.3 shares of Common Stock and (ii) all other Supporting Noteholders will receive $750 in principal amount of Second Lien Notes and approximately 83.3 shares of Common Stock. The number of shares of Common Stock issuable to the Supporting Noteholders is subject to adjustment in the event the Company issues or sells Common Stock in connection with the Equity Raise (as defined below) at a price less than $3.00 per share. The obligations of the Supporting Noteholders under the Exchange Agreement, including their obligation to exchange their Outstanding Notes, are subject to the conditions set forth in the Exchange Agreement, including: (a) the Company raising at least $156.0 million in total value (the “Equity Raise”), comprised of (i) at least 50% in new cash contributions from the sale of Common Stock, including the funding of up to $40.0 million of commitments received under the Subscription Agreements (as defined below); and (ii) no more than 50% from the fair market value of additional assets acquired, which assets will represent non-operating interests in the Williston Basin shale play; (b) reincorporation of the Company in the State of Delaware; (c) the Company having received the requisite shareholder approvals for (i) the issuance of the Common Stock and (ii) the reincorporation; (d) the Company obtaining the requisite consent of the lenders under the Company’s first lien term loan credit agreement; and (e) entry into a customary intercreditor agreement between the agent for the first lien term loan and the trustee for the Second Lien Notes. The Exchange Agreement will terminate upon written notice of termination by the Company or the Supporting Noteholders if the Exchange Transaction has not closed on or before May 31, 2018. The Exchange Agreement contains certain representations, warranties and other agreements by the Company and the Supporting Noteholders. The Company’s and the Supporting Noteholders’ obligations under the Exchange Agreement are subject to various customary conditions set forth in the Exchange Agreement, including the negotiation, execution and delivery of an indenture for the Second Lien Notes and other definitive documentation for the Exchange Transaction. Accordingly, there can be no assurance if or when the Company will consummate the Exchange Transaction and the other transactions contemplated by the Exchange Agreement. The Company will not receive any cash proceeds from the issuance of the Second Lien Notes or the Common Stock to be issued in the Exchange Transaction. Subscription Agreements Also on January 31, 2018, and in connection with the Exchange Transaction, the Company and certain investors entered into subscription agreements (the “Subscription Agreements”) whereby such investors agreed to purchase up to $40.0 million of Common Stock at $3.00 per share (subject to adjustment based on the pricing of the Equity Raise), subject to the closing of the Exchange Transaction.

SIGNIFICANT ACCOUNTING POLICI26

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements under GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved crude oil and natural gas reserve volumes, future development costs, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of derivative instruments, impairment of oil and natural gas properties, and deferred income taxes. Actual results may differ from those estimates.
Reclassifications	Reclassifications Certain prior period balances in the balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net loss, cash flows or stockholders’ deficit previously reported.
Cash and Cash Equivalents	Cash and Cash Equivalents Northern considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available on a daily or weekly basis and are highly liquid in nature. Due to the balances being greater than $250,000 , the Company does not have FDIC coverage on the entire amount of bank deposits. The Company believes this risk is minimal. In addition, the Company is subject to Security Investor Protection Corporation (“SIPC”) protection on a vast majority of its financial assets.
Accounts Receivable	Accounts Receivable Accounts receivable are carried on a gross basis, with no discounting. The Company regularly reviews all aged accounts receivable for collectability and establishes an allowance as necessary for individual customer balances. Accounts receivable not expected to be collected within the next twelve months are included within Other Noncurrent Assets, Net on the balance sheets.
Advances to Operators	Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid.
Other Property and Equipment	Other Property and Equipment Property and equipment that are not crude oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than crude oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-crude oil and natural gas long-lived assets.
Oil and Gas Properties	Oil and Gas Properties Northern follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2017 , 2016 and 2015 , respectively: Years Ended December 31, 2017 2016 2015 Capitalized Certain Payroll and Other Internal Costs $ 930,289 $ 1,890,480 $ 2,717,913 Capitalized Interest Costs 147,775 356,196 1,506,172 Total $ 1,078,064 $ 2,246,676 $ 4,224,085 As of December 31, 2017 , the Company held leasehold interests in the Williston Basin on acreage located in North Dakota and Montana targeting the Bakken and Three Forks formations. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. In the years ended December 31, 2017 , 2016 and 2015 , there were no property sales that resulted in a significant alteration. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing twelve-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives designated as hedges for accounting purposes, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. The Company did not have any ceiling test impairment for the year ended December 31, 2017 . As a result of low commodity prices and their effect on the proved reserve values of properties, the Company recorded non-cash ceiling test impairments for the years ended December 31, 2016 and 2015 of $237.0 million , and $1.2 billion , respectively. The impairment charges affected the Company’s reported net income but did not reduce the Company’s cash flow. If a significantly lower pricing environment reoccurs, the Company expects it could be required to further writedown the value of its oil and natural gas properties. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine the Company’s actual ceiling test calculation and impairment analyses in future periods. Capitalized costs associated with impaired properties and capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the period. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations.
Asset Retirement Obligations	Asset Retirement Obligations The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards Board (“FASB”) ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
Business Combinations	Business Combinations The Company accounts for its acquisitions that qualify as a business using the acquisition method under FASB ASC Topic 805, “Business Combinations.” Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs include origination, legal and other fees to issue debt in connection with the Company’s term loan credit agreement, senior unsecured notes and prior Revolving Credit Facility. These debt issuance costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method (see Note 4).
Bond Premium/Discount on Senior Notes	Bond Premium/Discount on Senior Notes On May 13, 2013, the Company recorded a bond premium of $10.5 million in connection with the “ 8.000% Senior Notes Due 2020” (see Note 4). This bond premium is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization of the bond premium was $1.5 million for each of the years ended December 31, 2017 , 2016 and 2015 . On May 18, 2015, the Company recorded a bond discount of $10.0 million in connection with the “ 8.000% Senior Notes Due 2020” (see Note 4). This bond discount is being amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
Revenue Recognition	Revenue Recognition The Company recognizes crude oil and natural gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for natural gas balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2017 , 2016 and 2015 , the Company’s natural gas production was in balance, meaning its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled its entitled interest in natural gas production from those wells.
Concentrations of Market and Credit Risk	Concentrations of Market and Credit Risk The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The Company operates in the exploration, development and production sector of the crude oil and natural gas industry. The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its counterparties is generally high. In the normal course of business, letters of credit or parent guarantees may be required for counterparties which management perceives to have a higher credit risk.
Restructuring Costs	Restructuring Costs The Company accounts for restructuring costs in accordance with FASB ASC Topic 420, “Exit or Disposal Cost Obligations.” Under these standards, the costs associated with restructuring are recorded during the period in which the liability is incurred.
Stock-Based Compensation	Stock-Based Compensation The Company records expense associated with the fair value of stock-based compensation. For fully vested stock and restricted stock grants, the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant. In determining the fair value of performance-based share awards subject to market conditions, the Company utilizes a Monte Carlo simulation prepared by an independent third party. For stock options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.
Stock Issuance	Stock Issuance The Company records any stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable.
Income Taxes	Income Taxes The Company’s income tax expense, deferred tax assets and deferred tax liabilities reflect management’s best assessment of estimated current and future taxes to be paid. The Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The Company’s only taxing jurisdiction is the United States (federal and state). Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements, which will result in taxable or deductible amounts in the future. In evaluating the Company’s ability to recover its deferred tax assets, the Company considers all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, the Company begins with historical results and incorporates assumptions about the amount of future state and federal pretax operating income adjusted for items that do not have tax consequences. The assumptions about future taxable income require significant judgment and are consistent with the plans and estimates the Company is using to manage the underlying businesses. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. In assessing the need for a valuation allowance for the Company’s deferred tax assets, a significant item of negative evidence considered was the cumulative book loss over the three-year period ended December 31, 2017 , driven primarily by the full cost ceiling impairments over that period. Additionally, the Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flows. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control. Due to these factors, management has placed a lower weight on the prospect of future earnings in its overall analysis of the valuation allowance. In determining whether to establish a valuation allowance on the Company’s deferred tax assets, management concluded that the objectively verifiable evidence of cumulative negative earnings for the three-year period ended December 31, 2017 , is difficult to overcome with any forms of positive evidence that may exist.
Net Income Per Common Share	Net Income Per Common Share Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options and restricted stock. The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
Derivative Instruments and Price Risk Management	Derivative Instruments and Price Risk Management The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil. The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company may also use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. The Company follows the provisions of FASB ASC 815, “Derivatives and Hedging” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value and marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations. See Note 13 for a description of the derivative contracts into which the Company has entered.
Impairment	Impairment Long-lived assets to be held and used are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Crude oil and natural gas properties accounted for using the full cost method of accounting are excluded from this requirement but continue to be subject to the full cost method’s impairment rules.
New Accounting Pronouncements	New Accounting Pronouncements From time to time, new accounting pronouncements are issued by the FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. The Company has completed the process of evaluating the effect of the adoption and determined there were no changes required to our reported revenues as a result of the adoption. The majority of our revenue arrangements generally consist of a single performance obligation to transfer promised goods or services. Based on our evaluation process and review of our contracts with customers, the timing and amount of revenue recognized based on the standard is consistent with our revenue recognition policy under previous guidance. The Company adopted the new standard effective January 1, 2018, using the modified retrospective approach, and will expand our financial statement disclosures in order to comply with the standard. We have determined the adoption of the standard will not have a material impact on our results of operations, cash flows, or financial position. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The standard requires lessees to recognize the assets and liabilities that arise from leases on the balance sheet. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact of the new guidance on its financial statements, however, based on its current operating leases, it is not expected to have a material impact. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments . This guidance provides guidance of eight specific cash flow issues. This amendment is effective for periods beginning after December 15, 2017, with early adoption permitted. The Company adopted this standard on January 1, 2018 and anticipates it will not have a material impact on its financial statements and related disclosures. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business to provide guidance in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 provides a screen to determine when a set of assets is not a business, requiring that when substantially all fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set of assets is not a business. A framework is provided to assist in evaluating whether both an input and a substantive process are present for the set to be a business. ASU 2017-01 is effective for periods beginning after December 15, 2017, including interim periods within those annual periods. No disclosures are required at transition and early adoption is permitted. The Company adopted this standard on January 1, 2018 and will apply this guidance to its next business combination.

SIGNIFICANT ACCOUNTING POLICI27

SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Capitalized costs related to the exploration and development of crude oil and natural gas properties	Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2017 , 2016 and 2015 , respectively: Years Ended December 31, 2017 2016 2015 Capitalized Certain Payroll and Other Internal Costs $ 930,289 $ 1,890,480 $ 2,717,913 Capitalized Interest Costs 147,775 356,196 1,506,172 Total $ 1,078,064 $ 2,246,676 $ 4,224,085 The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2017 2016 2015 Costs Incurred for the Year: Proved Property Acquisition and Other $ 15,722,378 $ 18,531,518 $ 9,068,139 Unproved Property Acquisition 716,681 2,301,285 3,346,214 Development 139,531,567 63,621,429 116,255,535 Total $ 155,970,626 $ 84,454,232 $ 128,669,888
Defined prices for each quarter	SEC defined prices for each quarter-end in 2017 were as follows: SEC Defined Prices for 12-Months Ended NYMEX Oil Price (per Bbl) Henry Hub Gas Price (per MMBtu) December 31, 2017 $ 51.34 $ 2.98 September 30, 2017 49.81 3.01 June 30, 2017 48.95 3.01 March 31, 2017 47.61 2.74 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2017 $ 3.34 $ 45.90 December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03
Reconciliation of denominators used to calculate basic and diluted EPS	The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2017 , 2016 and 2015 are as follows: Years Ended December 31, 2017 2016 2015 Weighted Average Common Shares Outstanding – Basic 62,408,855 61,173,547 60,652,447 Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock — — — Weighted Average Common Shares Outstanding – Diluted 62,408,855 61,173,547 60,652,447 Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect 1,109,511 829,313 322,393

CRUDE OIL AND NATURAL GAS PRO28

CRUDE OIL AND NATURAL GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Summary of capitalized costs excluded from depletion	The following is a summary of capitalized costs excluded from depletion at December 31, 2017 by year incurred. Years Ended December 31, 2017 2016 2015 Prior Years Property Acquisition $ 565,352 $ 509,877 $ 502,794 $ 121,321 Development — — — — Total $ 565,352 $ 509,877 $ 502,794 $ 121,321

LONG TERM DEBT (Tables)

LONG TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of long term debt	The Company’s long-term debt consists of the following: December 31, 2017 Principal Balance Unamortized Net Discount Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 700,000,000 $ (1,197,954 ) $ (6,847,557 ) $ 691,954,489 Term Loan Credit Agreement 300,000,000 — (12,630,267 ) $ 287,369,733 Total $ 1,000,000,000 $ (1,197,954 ) $ (19,477,824 ) $ 979,324,222 December 31, 2016 Principal Balance Unamortized Net Discount Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 700,000,000 $ (1,693,847 ) $ (9,681,028 ) $ 688,625,125 Revolving Credit Facility (1) 144,000,000 — — $ 144,000,000 Total $ 844,000,000 $ (1,693,847 ) $ (9,681,028 ) $ 832,625,125 ____________ (1) Debt issuance costs related to our revolving credit facility were $1.6 million and are recorded in “Other Noncurrent Assets, Net” on the balance sheet as of December 31, 2016

COMMON AND PREFERRED STOCK (Tab

COMMON AND PREFERRED STOCK (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of changes in the number of common stock shares	The following is a schedule of changes in the number of shares of common stock outstanding since the beginning of 2015 : Years Ended December 31, 2017 2016 2015 Beginning Balance 63,259,781 63,120,384 61,066,712 Restricted Stock Grants (Note 6) 911,355 2,109,814 2,112,998 Legal Settlement 3,000,000 — — Surrenders - Tax Obligations (270,510 ) (375,875 ) (57,929 ) Other Forfeitures (108,993 ) (1,594,542 ) (1,397 ) Ending Balance 66,791,633 63,259,781 63,120,384

STOCK OPTIONS_STOCK-BASED COM31

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Restricted stock activity	The following table reflects the outstanding restricted stock awards and activity related thereto for the years ended December 31, 2017 , 2016 and 2015 : Year Ended Year Ended Year Ended Number of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Number Of Shares Weighted- Average Price Restricted Stock Awards: Restricted Shares Outstanding at the Beginning of the Year 1,905,104 $ 4.59 2,365,396 $ 7.15 538,499 $ 13.54 Shares Granted 911,355 2.10 2,109,814 3.83 2,112,998 6.29 Shares Forfeited (108,993 ) 3.59 (1,594,542 ) 4.67 (1,397 ) 14.79 Lapse of Restrictions (985,933 ) 4.05 (975,564 ) 7.34 (284,704 ) 12.24 Restricted Shares Outstanding at the End of the Year 1,721,533 $ 3.65 1,905,104 $ 4.59 2,365,396 $ 7.15
Stock option activity	Changes in stock option awards for the years ended December 31, 2017 , 2016 , and 2015 were as follows: Stock Option Awards Weighted-Average Price Weighted Average Contractual Term Intrinsic Value Outstanding as of December 31, 2014 (1) 141,872 $ 5.18 2.8 $ 66,680 Granted — — Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2015 (1) 141,872 $ 5.18 1.8 $ — Granted 250,000 $ 2.79 Exercised — — Expired or canceled — — Forfeited — — Outstanding as of December 31, 2016 (1) 391,872 $ 3.66 2.9 $ — Granted — — Exercised — — Expired or canceled (141,872) — Outstanding as of December 31, 2017 (1) 250,000 $ 2.79 1.0 $ — ____________ (1) All of the stock options outstanding were vested and exercisable at the end of the period.

ASSET RETIREMENT OBLIGATION (Ta

ASSET RETIREMENT OBLIGATION (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation [Abstract]
Asset retirement obligation transactions	The following table summarizes the Company’s asset retirement obligation transactions recorded during the year ended December 31, 2017 and 2016 . Years Ended December 31, 2017 2016 Beginning Asset Retirement Obligation $ 7,508,300 $ 5,816,356 Liabilities Acquired or Incurred During the Period 578,441 585,729 Liabilities Removed Due to Divestitures — (21,426 ) Revision of Estimates 609,351 789,003 Accretion of Discount on Asset Retirement Obligations 536,732 405,991 Liabilities Settled During the Period (104,696 ) (67,353 ) Ending Asset Retirement Obligation $ 9,128,128 $ 7,508,300

(Tables)

(Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income tax expense provision (benefit)	The income tax provision (benefit) for the year ended December 31, 2017 , 2016 , and 2015 consists of the following: 2017 2016 2015 Current Federal $ (785,016 ) $ (1,402,179 ) $ (73,649 ) State — — — Deferred Federal 126,501,000 (99,298,900 ) (398,002,555 ) State (12,983,000 ) (9,707,000 ) (36,608,000 ) Valuation Allowance (114,303,000 ) 109,005,900 232,260,000 Total Expense (Benefit) $ (1,570,016 ) $ (1,402,179 ) $ (202,424,204 )
Reconciliation of reported amount of income tax expense (benefit)	The following is a reconciliation of the reported amount of income tax benefit for the years ended December 31, 2017 , 2016 , and 2015 to the amount of income tax expenses that would result from applying the statutory rate to pretax loss. 2017 2016 2015 Income (Loss) Before Taxes and NOL $ (10,763,788 ) $ (294,895,887 ) $ (1,177,778,745 ) Federal Statutory Rate 35.00 % 35.00 % 35.00 % Taxes Computed at Federal Statutory Rates (3,767,000 ) (103,214,000 ) (412,223,000 ) State Taxes, Net of Federal Taxes (8,476,000 ) (6,306,000 ) (23,825,000 ) Non-Deductible Compensation 22,000 82,000 470,000 Share Based Compensation Tax Deficiency — (834,900 ) 307,000 Federal Rate Reduction 124,493,000 — — Other 460,984 (135,179 ) 586,796 Valuation Allowance (114,303,000 ) 109,005,900 232,260,000 Reported Provision (Benefit) $ (1,570,016 ) $ (1,402,179 ) $ (202,424,204 )
Components of deferred tax asset (liability)	The significant components of the Company’s deferred tax assets (liabilities) were as follows: Years Ended December 31, 2017 2016 Net Operating Loss (NOLs) and Tax Credit Carryforwards $ 174,864,900 $ 224,679,900 Share Based Compensation 797,000 1,032,000 Accrued Interest 1,144,000 1,727,000 Allowance for Doubtful Accounts 1,360,000 1,795,000 Crude Oil and Natural Gas Properties and Other Properties 42,329,000 107,642,000 Derivative Instruments 7,393,000 4,341,000 Other (140,000 ) 49,000 Total Net Deferred Tax Assets (Liabilities) Before Valuation Allowance 227,747,900 341,265,900 Valuation Allowance (226,962,900 ) (341,265,900 ) Total Net Deferred Tax Assets $ 785,000 $ —

OPERATING LEASES (Tables)

OPERATING LEASES (Tables)	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
Minimum future lease payments	Minimum future annual lease payments for the calendar years presented are as follows: Amount 2018 $ 342,000 2019 352,000 2020 361,000 2021 340,000 Total $ 1,395,000
Schedule of Rent Expense	The following has been recorded to rent expense for the periods presented: Years Ended December 31, 2017 2016 2015 Rent Expense $ 369,000 $ 320,000 $ 287,000

FAIR VALUE (Tables)

FAIR VALUE (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Financial instruments measured at fair value on recurring basis	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016 . Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Asset (crude oil swaps) $ — $ — $ — Commodity Derivatives – Current Liabilities (crude oil swaps) — (18,681,891 ) — Commodity Derivatives – Non-Current Asset (crude oil swaps) — — — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — (11,496,929 ) — Total $ — $ (30,178,820 ) $ — Fair Value Measurements at Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Asset (crude oil swaps) $ — $ 4,517 $ — Commodity Derivatives – Current Liabilities (crude oil swaps and collars) — (10,001,564 ) — Commodity Derivatives – Non-Current Asset (crude oil swaps) — — — Commodity Derivatives – Non-Current Liabilities (crude oil swaps) — (1,738,329 ) — Total $ — $ (11,735,376 ) $ —

DERIVATIVE INSTRUMENTS AND PR36

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of non-cash gains or losses on derivative contracts	The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period-end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period. Years Ended 2017 2016 2015 Cash Received (Paid) on Derivatives (1) $ 3,776,788 $ 61,528,201 $ 161,098,510 Non-Cash Gain (Loss) on Derivatives (18,443,443 ) (76,346,935 ) (88,715,603 ) Gain (Loss) on Derivative Instruments, Net $ (14,666,655 ) $ (14,818,734 ) $ 72,382,907 _____________ (1) Net cash paid for crude oil swaps for the year ended December 31, 2017 include approximately $0.7 million of payments from crude oil derivative contracts that were settled prior to their contractual maturities as a result of the termination of the Company’s revolving credit facility. Net cash receipts for the year ended December 31, 2015 includes approximately $0.2 million of proceeds received from crude oil derivative contracts that were settled prior to their contractual maturities.
Open commodity swap contracts	The following table reflects open commodity swap contracts as of December 31, 2017 , the associated volumes and the corresponding fixed price. Settlement Period Oil (Barrels) Fixed Price ($) Swaps-Crude Oil 01/01/18 – 08/31/18 160,000 49.99 01/01/18 – 08/31/18 160,000 50.04 01/01/18 – 08/31/18 160,000 49.99 01/01/18 – 08/31/18 160,000 50.17 01/01/18 – 09/30/18 270,000 53.99 01/01/18 – 09/30/18 270,000 53.99 01/01/18 – 09/30/18 273,000 55.19 01/01/18 – 12/31/18 180,000 53.30 01/01/18 – 12/31/18 365,000 54.80 01/01/18 – 12/31/18 365,000 54.09 01/01/18 – 12/31/18 365,000 54.42 10/01/18 – 12/31/18 92,000 52.50 10/01/18 – 12/31/18 92,000 52.55 10/01/18 – 12/31/18 46,000 54.50 10/01/18 – 12/31/18 92,000 52.50 01/01/19 – 03/31/19 45,000 54.22 01/01/19 – 03/31/19 63,000 53.65 01/01/19 – 12/31/19 365,000 51.05 01/01/19 – 12/31/19 365,000 51.05 01/01/19 – 12/31/19 182,500 52.70 01/01/19 – 12/31/19 365,000 51.05 01/01/19 – 12/31/19 182,500 52.15 01/01/19 – 12/31/19 182,500 52.75 04/01/19 – 06/30/19 45,500 53.59 04/01/19 – 06/30/19 36,400 53.10 07/01/19 – 09/30/19 46,000 53.07 07/01/19 – 09/30/19 9,200 52.65 01/01/20 – 03/31/20 27,300 51.81 01/01/20 – 12/31/20 366,000 49.77 01/01/20 – 12/31/20 183,000 51.30 01/01/20 – 12/31/20 109,800 51.70 01/01/20 – 12/31/20 366,000 49.75 01/01/20 – 12/31/20 183,000 51.10 04/01/20 – 06/30/20 9,100 51.50
Schedule of weighted average price of open commodity derivative contracts	The following table reflects the weighted average price of open commodity swap derivative contracts as of December 31, 2017 , by year with associated volumes. Weighted Average Price Year Volumes (Bbl) Weighted 2018 3,050,000 53.26 2019 1,887,600 51.80 2020 1,244,200 50.41
Derivatives instruments balance sheet location	The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at December 31, 2017 and 2016 , respectively. Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement: December 31, Type of Crude Oil Contract Balance Sheet Location 2017 2016 Derivative Assets: Swap Contracts Current Assets $ — $ 4,517 Total Derivative Assets $ — $ 4,517 Derivative Liabilities: Swap Contracts Current Liabilities $ (18,681,891 ) $ (9,512,724 ) Swap Contracts Non-Current Liabilities (11,496,929 ) (1,738,329 ) Swaption Contracts Current Liabilities — (333,046 ) Costless Collars Current Liabilities — (155,794 ) Total Derivative Liabilities $ (30,178,820 ) $ (11,739,893 )
Reconciliation between gross assets and liabilities and the amounts reflected on balance sheet	The tables presented below provide reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet. The amounts presented exclude derivative settlement receivables and payables as of the balance sheet dates. Estimated Fair Value at December 31, 2017 Gross Amounts of Recognized Assets (Liabilities) Gross Amounts Offset in the Net Amounts of Assets (Liabilities) Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ — $ — $ — Non-Current Assets — — — Total Derivative Assets $ — $ — $ — Offsetting of Derivative Liabilities: Current Liabilities $ (18,681,891 ) $ — $ (18,681,891 ) Non-Current Liabilities (11,496,929 ) — (11,496,929 ) Total Derivative Liabilities $ (30,178,820 ) $ — $ (30,178,820 ) Estimated Fair Value at December 31, 2016 Gross Amounts of Recognized Assets (Liabilities) Gross Amounts Offset in the Net Amounts of Assets (Liabilities) Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 20,962 $ (16,445 ) $ 4,517 Non-Current Assets — — — Total Derivative Assets $ 20,962 $ (16,445 ) $ 4,517 Offsetting of Derivative Liabilities: Current Liabilities $ (10,018,009 ) $ 16,445 $ (10,001,564 ) Non-Current Liabilities (1,738,329 ) — (1,738,329 ) Total Derivative Liabilities $ (11,756,338 ) $ 16,445 $ (11,739,893 )

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Calculation of earnings per share	The following is a reconciliation of the numerator and denominator used to calculate basic earnings per share and diluted earnings per share for the years ended December 31, 2017 , 2016 , and 2015 : 2017 2016 2015 Net Loss Shares Per Share Net Loss Shares Per Share Net Income Shares Per Share Basic EPS $ (9,193,772 ) 62,408,855 $ (0.15 ) $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 ) Dilutive Effect of Options — — — — — — — — — Diluted EPS $ (9,193,772 ) 62,408,855 $ (0.15 ) $ (293,493,708 ) 61,173,547 $ (4.80 ) $ (975,354,541 ) 60,652,447 $ (16.08 )

SUPPLEMENTAL OIL AND GAS INFO38

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Schedule of costs incurred in crude oil and natural gas acquisition, exploration and development activities	Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the years ended December 31, 2017 , 2016 and 2015 , respectively: Years Ended December 31, 2017 2016 2015 Capitalized Certain Payroll and Other Internal Costs $ 930,289 $ 1,890,480 $ 2,717,913 Capitalized Interest Costs 147,775 356,196 1,506,172 Total $ 1,078,064 $ 2,246,676 $ 4,224,085 The costs incurred in crude oil and natural gas acquisition, exploration and development activities are highlighted in the table below. Years Ended December 31, 2017 2016 2015 Costs Incurred for the Year: Proved Property Acquisition and Other $ 15,722,378 $ 18,531,518 $ 9,068,139 Unproved Property Acquisition 716,681 2,301,285 3,346,214 Development 139,531,567 63,621,429 116,255,535 Total $ 155,970,626 $ 84,454,232 $ 128,669,888
Summary of capitalized costs excluded from depletion	The following is a summary of capitalized costs excluded from depletion at December 31, 2017 by year incurred. Years Ended December 31, 2017 2016 2015 Prior Years Property Acquisition $ 565,352 $ 509,877 $ 502,794 $ 121,321 Development — — — — Total $ 565,352 $ 509,877 $ 502,794 $ 121,321
Schedule of estimates of its proved crude oil and natural gas reserves	The following tables present the Company’s independent petroleum consultants’ estimates of its proved crude oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Natural Gas Oil BOE Proved Developed and Undeveloped Reserves at December 31, 2014 70,935,117 88,913,305 100,735,825 Revisions of Previous Estimates (23,552,809 ) (36,277,018 ) (40,202,486 ) Extensions, Discoveries and Other Additions 8,170,259 9,346,864 10,708,574 Production (4,651,583 ) (5,168,687 ) (5,943,951 ) Proved Developed and Undeveloped Reserves at December 31, 2015 50,900,984 56,814,464 65,297,962 Revisions of Previous Estimates (8,697,825 ) (13,995,801 ) (15,445,439 ) Extensions, Discoveries and Other Additions 7,695,309 7,142,439 8,424,991 Purchases of Minerals in Place 960,758 640,108 800,234 Production (4,026,899 ) (4,325,919 ) (4,997,069 ) Proved Developed and Undeveloped Reserves at December 31, 2016 46,832,327 46,275,291 54,080,679 Revisions of Previous Estimates 8,838,976 889,814 2,362,977 Extensions, Discoveries and Other Additions 27,637,350 20,184,388 24,790,613 Production (5,187,886 ) (4,537,295 ) (5,401,943 ) Proved Developed and Undeveloped Reserves at December 31, 2017 78,120,767 62,812,198 75,832,326 Proved Developed Reserves: December 31, 2014 38,277,770 44,666,408 51,046,037 December 31, 2015 33,619,954 36,573,821 42,177,147 December 31, 2016 32,808,111 32,245,139 37,713,158 December 31, 2017 46,518,005 38,592,506 46,345,507 Proved Undeveloped Reserves: December 31, 2014 32,657,347 44,246,897 49,689,788 December 31, 2015 17,281,030 20,240,643 23,120,815 December 31, 2016 14,024,216 14,030,152 16,367,521 December 31, 2017 31,602,762 24,219,692 29,486,819
Summary of standardized measure of discounted future net cash flows	The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas . Future cash inflows were computed by applying average prices of crude oil and natural gas for the last 12 months to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year end tax rates to future pretax cash flows relating to proved crude oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carry forwards relating to crude oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s crude oil and natural gas reserves. Years Ended December 31, 2017 2016 2015 Future Cash Inflows $ 3,143,603,968 $ 1,708,870,912 $ 2,470,707,712 Future Production Costs (1,265,524,800 ) (775,534,832 ) (981,256,096 ) Future Development Costs (409,360,320 ) (220,869,664 ) (356,401,888 ) Future Income Tax Expense (27,476,230 ) (2,477,353 ) (5,740,623 ) Future Net Cash Inflows $ 1,441,242,618 $ 709,989,063 $ 1,127,309,105 10% Annual Discount for Estimated Timing of Cash Flows (687,256,521 ) (330,963,050 ) (552,510,342 ) Standardized Measure of Discounted Future Net Cash Flows $ 753,986,097 $ 379,026,013 $ 574,798,763
Schedule of average sales prices	SEC defined prices for each quarter-end in 2017 were as follows: SEC Defined Prices for 12-Months Ended NYMEX Oil Price (per Bbl) Henry Hub Gas Price (per MMBtu) December 31, 2017 $ 51.34 $ 2.98 September 30, 2017 49.81 3.01 June 30, 2017 48.95 3.01 March 31, 2017 47.61 2.74 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The price of other liquids is included in natural gas. The prices for the Company’s reserve estimates were as follows: Natural Gas MCF Oil Bbl December 31, 2017 $ 3.34 $ 45.90 December 31, 2016 $ 1.67 $ 35.24 December 31, 2015 $ 1.63 $ 42.03
Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10%	Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum follow: Years Ended December 31, 2017 2016 2015 Beginning of Period $ 379,026,013 $ 574,798,763 $ 1,405,379,543 Sales of Oil and Natural Gas Produced, Net of Production Costs (153,625,893 ) (98,497,165 ) (128,964,023 ) Extensions and Discoveries 217,145,871 59,542,911 96,770,078 Previously Estimated Development Cost Incurred During the Period 46,833,826 23,271,960 114,208,095 Net Change of Prices and Production Costs 216,216,656 (174,656,448 ) (1,384,474,928 ) Change in Future Development Costs (34,753,469 ) 57,481,060 235,578,690 Revisions of Quantity and Timing Estimates 28,914,878 (130,664,183 ) (363,975,445 ) Accretion of Discount 37,942,243 57,569,313 170,222,344 Change in Income Taxes (3,617,100 ) 497,950 295,949,531 Purchases of Minerals in Place — 9,576,760 — Other 19,903,072 105,092 134,104,878 End of Period $ 753,986,097 $ 379,026,013 $ 574,798,763

QUARTERLY RESULTS OF OPERATIO39

QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of quarterly financial information	Quarterly data for the years end December 31, 2017 and 2016 is as follows: Quarter Ended March 31, June 30, September 30, December 31, 2017 Total Revenues $ 65,816,847 $ 64,901,882 $ 41,598,659 $ 37,002,281 Gains (Losses) on Derivative Instruments, Net 16,960,883 16,513,032 (12,663,253 ) (35,477,317 ) Total Operating Expenses 32,572,699 34,576,905 41,013,678 40,661,791 Income (Loss) from Operations 33,244,148 30,324,977 584,981 (3,659,510 ) Other Income (Expense) (16,303,805 ) (16,523,118 ) (16,672,448 ) (21,759,013 ) Income Tax Benefit — — — (1,570,016 ) Net Income (Loss) 16,940,523 13,801,859 (16,087,467 ) (23,848,687 ) Net Income (Loss) Per Common Share – Basic 0.28 0.22 (0.26 ) (0.37 ) Net Income (Loss) Per Common Share – Diluted 0.27 0.22 (0.26 ) (0.37 ) Quarter Ended March 31, June 30, September 30, December 31, 2016 Total Revenues $ 31,836,236 $ 32,014,226 $ 45,109,408 $ 35,943,626 Gains (Losses) on Derivative Instruments, Net 3,463,883 (10,522,948 ) 3,381,564 (11,141,233 ) Total Operating Expenses 141,220,772 124,946,744 74,583,046 33,457,789 Impairment 104,311,122 88,880,921 43,820,791 — Income (Loss) from Operations (109,384,536 ) (92,932,518 ) (29,473,638 ) 2,485,837 Other Income (Expense) (17,181,218 ) (16,046,144 ) (16,145,257 ) (16,218,413 ) Income Tax Benefit — — — (1,402,179 ) Net Loss (126,565,754 ) (108,978,662 ) (45,618,895 ) (12,330,397 ) Net Loss Per Common Share – Basic (2.08 ) (1.78 ) (0.74 ) (0.20 ) Net Loss Per Common Share – Diluted (2.08 ) (1.78 ) (0.74 ) (0.20 )

ORGANIZATION AND NATURE OF BU40

ORGANIZATION AND NATURE OF BUSINESS (Details)	12 Months Ended
	Dec. 31, 2017a
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Percentage of mineral rights developed	87.00%
Gas and oil acreage net mineral rights (in acres)	143,253

SIGNIFICANT ACCOUNTING POLICI41

SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 18, 2015	Dec. 31, 2014	May 13, 2013
Accounts Receivable & Advances to Operations
Allowance for doubtful accounts	$ 4,900,000				$ 5,600,000	$ 4,900,000
Provision for doubtful accounts					700,000	800,000	$ 6,200,000
Charged against the allowance for doubtful accounts					$ 0	400,000
Period for advance payments to be applied against joint interest billings					90 days
Other Property and Equipment
Depreciation expense					$ 200,000	200,000	300,000
Oil and Gas Properties
Minimum percentage of proved reserves sold to be considered a significant alteration					25.00%
Proceeds from sale of oil and gas properties					$ 0	0	0
Discount rate					10.00%
Impairment of Oil and Natural Gas Properties	0	$ 43,820,791	$ 88,880,921	$ 104,311,122	$ 0	237,012,834	1,163,959,246
Capitalized costs related to expired leases subject to depletion					18,700,000	13,400,000	19,000,000
Amortization of debt issuance costs					4,122,226	3,822,967	3,696,532
Debt Issuance Costs & Bond Premium/Discount
Write-off of Debt Issuance Costs					95,135	1,089,507	0
Loss on the Extinguishment of Debt					(992,950)	0	$ 0
Restructuring Costs, Income Taxes, Net Income Per Common Share, & Impairment
Valuation Allowance	$ 341,265,900				$ 226,962,900	$ 341,265,900
Potentially dilutive stock options (in shares)	391,872				250,000	391,872	141,872		141,872
Asset impairment charges					$ 0	$ 0	$ 0
Minimum [Member]
Other Property and Equipment
Property and equipment, estimated useful lives					3 years
Maximum [Member]
Other Property and Equipment
Property and equipment, estimated useful lives					7 years
Other Noncurrent Assets [Member]
Accounts Receivable & Advances to Operations
Accounts receivable	$ 6,800,000				$ 5,500,000	$ 6,800,000
Restricted Common Stock [Member]
Restructuring Costs, Income Taxes, Net Income Per Common Share, & Impairment
Potentially dilutive shares (in shares)	1,905,104				1,721,533	1,905,104	2,365,396		538,499
Senior Notes Due 2020 [Member]
Debt Issuance Costs & Bond Premium/Discount
Amortization of bond premium					$ 1,500,000	$ 1,500,000	$ 1,500,000
Amortization of bond discount					2,000,000	2,000,000	1,200,000
Unsecured Debt [Member] | Senior Notes Due 2020 [Member]
Debt Issuance Costs & Bond Premium/Discount
Unamortized debt issuance costs								$ 10,000,000		$ 10,500,000
Interest rate percentage								8.00%		8.00%
Severance and Benefit Costs [Member]
Restructuring Costs, Income Taxes, Net Income Per Common Share, & Impairment
Restructuring costs					$ 0	$ 0	500,000
2013 Equity Incentive Plan [Member]
Restructuring Costs, Income Taxes, Net Income Per Common Share, & Impairment
Non-cash expense related to acceleration of certain equity awards previously granted							$ 100,000

SIGNIFICANT ACCOUNTING POLICI42

SIGNIFICANT ACCOUNTING POLICIES - Oil and Gas Properties (Details)	3 Months Ended				12 Months Ended
	Dec. 31, 2016$ / bbl$ / MMBTU	Sep. 30, 2016$ / bbl$ / MMBTU	Jun. 30, 2016$ / bbl$ / MMBTU	Mar. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Defined Price Per Unit [Line Items]
Capitalized Certain Payroll and Other Internal Costs					$ 930,289	$ 1,890,480	$ 2,717,913
Capitalized Interest Costs					147,775	356,196	1,506,172
Total					$ 1,078,064	$ 2,246,676	$ 4,224,085
NYMEX [Member]
Defined Price Per Unit [Line Items]
Defined price for each quarter | $ / bbl	51.34	49.81	48.95	47.61
Henry Hub [Member]
Defined Price Per Unit [Line Items]
Defined price for each quarter | $ / MMBTU	2.98	3.01	3.01	2.74

SIGNIFICANT ACCOUNTING POLICI43

SIGNIFICANT ACCOUNTING POLICIES - Earnings Per Share (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Weighted Average Shares Outstanding - Basic (in shares)	62,408,855	61,173,547	60,652,447
Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock (in shares)	0	0	0
Weighted Average Common Shares Outstanding - Diluted (in shares)	62,408,855	61,173,547	60,652,447
Restricted Stock Excluded From EPS Due To The Anti-Dilutive Effect (in shares)	1,109,511	829,313	322,393

CRUDE OIL AND NATURAL GAS PRO44

CRUDE OIL AND NATURAL GAS PROPERTIES (Details)	Oct. 06, 2016USD ($)awell	Dec. 31, 2016USD ($)a$ / a	Dec. 31, 2017USD ($)a$ / a	Dec. 31, 2016USD ($)a$ / a	Dec. 31, 2015USD ($)a$ / a
Business Acquisition [Line Items]
Capital expenditures incurred but not yet paid			$ 85,000,000	$ 50,700,000
Mineral acres acquired, net (in acres) | a			1,934	3,399	4,355
Average acquisition cost per net acre (in dollars per acre) | $ / a		1,515	2,352	1,515	1,314
Unproven Leasehold Interests | a		26,432	14,377	26,432
Anticipated future period over which excluded costs will become subject to depletion			5 years
Impairment costs related to expired leases subject to depletion			$ 600,000	$ 7,000,000	$ 37,600,000
Definitive Purchase and Sale Agreement with Third Party [Member]
Business Acquisition [Line Items]
Mineral acres acquired, net (in acres) | a	3.8
Producing oil and gas wells, gross (in wells) | well	144
Cash consideration	$ 9,400,000
Payments to acquire producing properties	8,900,000
Reimbursement of drilling costs in process wells	$ 500,000
Revenue since acquisition		$ 1,200,000
Operating expenses since acquisition		500,000
Transaction costs		0
Goodwill		$ 0		$ 0

CRUDE OIL AND NATURAL GAS PRO45

CRUDE OIL AND NATURAL GAS PROPERTIES - Capitalized Costs (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition	$ 565,352	$ 509,877	$ 502,794	$ 121,321
Development	0	0	0	0
Total	$ 565,352	$ 509,877	$ 502,794	$ 121,321

LONG TERM DEBT - Schedule of Lo

LONG TERM DEBT - Schedule of Long Term Debt (Details) - USD ($)	Dec. 31, 2017	Nov. 01, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Principal Balance	$ 1,000,000,000		$ 844,000,000
Unamortized Net Discount	(1,197,954)		(1,693,847)
Debt Issuance Costs, Net	(19,477,824)		(9,681,028)
Long-term Debt, Net	979,324,222		832,625,125
Term Loan [Member]
Line of Credit Facility [Line Items]
Interest rate percentage		3.00%
Line of Credit [Member] | Term Loan [Member]
Line of Credit Facility [Line Items]
Principal Balance	300,000,000
Unamortized Net Discount	0
Debt Issuance Costs, Net	(12,630,267)
Long-term Debt, Net	$ 287,369,733
Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Principal Balance			144,000,000
Unamortized Net Discount			0
Debt Issuance Costs, Net			0
Long-term Debt, Net			144,000,000
8% Senior Notes [Member] | Senior Notes [Member]
Line of Credit Facility [Line Items]
Interest rate percentage	8.00%
Principal Balance	$ 700,000,000		700,000,000
Unamortized Net Discount	(1,197,954)		(1,693,847)
Debt Issuance Costs, Net	(6,847,557)		(9,681,028)
Long-term Debt, Net	$ 691,954,489		688,625,125
Other Noncurrent Assets [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Issuance Costs, Net			$ (1,600,000)

LONG TERM DEBT - Narrative (Det

LONG TERM DEBT - Narrative (Details) - USD ($)	Nov. 01, 2017	Dec. 31, 2017	Dec. 31, 2016	May 18, 2015	May 13, 2013	May 18, 2012
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 1,000,000,000	$ 844,000,000
Senior Notes [Member] | 8% Senior Notes [Member]
Line of Credit Facility [Line Items]
Interest rate percentage		8.00%
Long-term debt, gross		$ 700,000,000	$ 700,000,000
Senior Notes [Member] | 8% Senior Notes [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 30,000,000
8% Senior Notes Due 2020 [Member]
Line of Credit Facility [Line Items]
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2016		104.00%
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2017		102.00%
Percentage of notes at redemption prices for beginning on June 1, 2018		100.00%
Number of days in default payment of interest		30 days
Payment of certain final judgments		$ 25,000,000
Number of days related to payment certain final judgments		60 days
8% Senior Notes Due 2020 [Member] | The "Original Notes" [Member]
Line of Credit Facility [Line Items]
Principal amount of senior unsecured notes						$ 300,000,000
Maturity date		Jun. 1, 2020
Net proceeds from issuance of senior unsecured notes		$ 291,200,000
8% Senior Notes Due 2020 [Member] | The "2013 Follow-on Notes" [Member]
Line of Credit Facility [Line Items]
Interest rate percentage					8.00%
Maturity date		Jun. 1, 2020
Price of senior unsecured notes					105.25%
Additional amount of senior unsecured notes					$ 200,000,000
Net proceeds from issuance of senior unsecured notes		$ 200,100,000
8% Senior Notes Due 2020 [Member] | The "2015 Mirror Notes" [Member]
Line of Credit Facility [Line Items]
Interest rate percentage				8.00%
Maturity date		Jun. 1, 2020
Price of senior unsecured notes				95.00%
Additional amount of senior unsecured notes				$ 200,000,000
Net proceeds from issuance of senior unsecured notes		$ 184,900,000
Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Commitment fee percentage		0.375%
Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Commitment fee percentage		0.50%
Revolving Credit Facility [Member] | LIBOR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		2.00%
Revolving Credit Facility [Member] | LIBOR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		3.00%
Revolving Credit Facility [Member] | Alternate Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		1.00%
Revolving Credit Facility [Member] | Alternate Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		2.00%
Term Loan [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing	$ 500,000,000
Interest rate percentage	3.00%
Prepayment rate requirement	100.00%
Yield maintenance, outstanding balance period	1 year
Call protection, multiplier interest rate	7.00%
Call protection, multiplier interest rate if occurring within eighteen months of funding	7.00%
Call protection, multiplier interest rate if occurring within eighteen months of funding, term	18 months
Call protection, multiplier interest rate if occurring after eighteen months but prior to thirty months of funding	3.00%
Call protection, multiplier interest rate if occurring after thirty months but prior to forty two months of funding	1.00%
Term Loan [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Call protection, multiplier interest rate if occurring after eighteen months but prior to thirty months of funding, term	18 months
Call protection, multiplier interest rate if occurring after thirty months but prior to forty two months of funding, term	30 months
Covenant compliance, cash to debt ratio	1.3
Covenant compliance, cash and cash equivalents including undrawn credit commitments threshold	$ 20,000,000
Term Loan [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Call protection, multiplier interest rate if occurring after eighteen months but prior to thirty months of funding, term	30 months
Call protection, multiplier interest rate if occurring after thirty months but prior to forty two months of funding, term	42 months
Covenant compliance, debt to EBITDAX ratio	3.75
Term Loan [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Interest rate percentage	1.00%
Interest rate margin in effect during period	7.75%
Term Loan, Initial Loans [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing	$ 300,000,000
Term Loan, Delayed Draw Loans [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing	$ 100,000,000
Debt instrument, term	18 months
Unused capacity, commitment fee percentage	2.00%
Term Loan, Incremental Loans [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing	$ 100,000,000

COMMON AND PREFERRED STOCK - Na

COMMON AND PREFERRED STOCK - Narrative (Details)	Sep. 25, 2017shares	Dec. 31, 2017USD ($)Class$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)shares	May 31, 2016shares	May 31, 2011USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shares of preferred and common stock authorized for issuance (in shares)		147,500,000
Number of classes of shares | Class		2
Common stock, shares authorized (in shares)		142,500,000	142,500,000		142,500,000
Common stock, par value (in dollars per share) | $ / shares		$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)		5,000,000	5,000,000
Preferred stock, par value (in dollars per share) | $ / shares		$ 0.001	$ 0.001
Common stock surrendered by certain employees to cover tax obligations (in shares)		270,510	375,875	57,929
Fair value of common stock surrendered by certain employees to cover tax obligations | $		$ 700,000	$ 1,400,000	$ 300,000
Legal Settlement (in shares)		3,000,000	0	0
Shares forfeited (in shares)		108,993	1,594,542	1,397
Stock repurchase program, amount approved | $						$ 150,000,000
Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Legal Settlement (in shares)	3,000,000
Common stock surrendered by certain employees related to termination of employment (in shares)				1,400,000
Restricted Common Stock [Member] | Chief Executive Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares forfeited (in shares)		1,500,000
Reversal of compensation expense | $		$ 1,800,000

COMMON AND PREFERRED STOCK - Co

COMMON AND PREFERRED STOCK - Common Stock Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in number of common stock shares [Roll forward]
Beginning Balance (in shares)	63,259,781	63,120,384	61,066,712
Restricted Stock Grants (in shares)	911,355	2,109,814	2,112,998
Legal settlement (in shares)	3,000,000	0	0
Surrenders - Tax Obligations (in shares)	(270,510)	(375,875)	(57,929)
Other Forfeitures (in shares)	(108,993)	(1,594,542)	(1,397)
Ending balance (in shares)	66,791,633	63,259,781	63,120,384

STOCK OPTIONS_STOCK-BASED COM50

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 12, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
2013 Equity Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future awards (in shares)		2,900,000
Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued (in shares)		911,355	2,109,814	2,112,998
Unrecognized compensation expense		$ 3.1
Unrecognized compensation expense, recognized period		1 year 9 months 18 days
Percent of forfeiture rate assumed for restricted stock		0.00%
Stock Option Awards [Member] | 2006 Incentive Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		560,000
Grant price per share (in dollars per share)		$ 5.18
Stock Option Awards [Member] | 2013 Equity Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant price per share (in dollars per share)		$ 2.79
Share-based compensation expense		$ 0.4
Stock Option Awards [Member] | Directors [Member] | 2006 Incentive Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		500,000
Stock Option Awards [Member] | Directors [Member] | 2013 Equity Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)	250,000
Stock Option Awards [Member] | Employee [Member] | 2006 Incentive Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		60,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		$ 0.1
Vesting period		3 years
Risk-free interest rate		0.97%
Maximum dollar amount of performance shares issuable		$ 1.3
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants earning percentage		0.00%
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants earning percentage		150.00%
Risk-free interest rate		80.00%

STOCK OPTIONS_STOCK-BASED COM51

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Restricted Stock Activity (Details) - Restricted Stock Awards [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Number of Shares
Beginning of the Year (in shares)	1,905,104	2,365,396	538,499
Shares Granted (in shares)	911,355	2,109,814	2,112,998
Shares Forfeited (in shares)	(108,993)	(1,594,542)	(1,397)
Lapse of Restrictions (in shares)	(985,933)	(975,564)	(284,704)
End of the Year (in shares)	1,721,533	1,905,104	2,365,396
Weighted- Average Price
Beginning of the Year (in dollars per share)	$ 4.59	$ 7.15	$ 13.54
Shares Granted (in dollars per share)	2.10	3.83	6.29
Shares Forfeited (in dollars per share)	3.59	4.67	14.79
Lapse of Restrictions (in dollars per share)	4.05	7.34	12.24
End of the Year (in dollars per share)	$ 3.65	$ 4.59	$ 7.15

STOCK OPTIONS_STOCK-BASED COM52

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Stock Option Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock Option Awards
Beginning Balance (in shares)	391,872	141,872	141,872
Granted (in shares)	0	250,000	0
Exercised (in shares)	0	0	0
Expired or canceled (in shares)	(141,872)	0	0
Forfeited (in shares)		0	0
Ending Balance (in shares)	250,000	391,872	141,872	141,872
Weighted-Average Price
Beginning Balance (in dollars per share)	$ 3.66	$ 5.18	$ 5.18
Granted (in dollars per share)	0	2.79	0
Exercised (in dollars per share)	0	0	0
Expired or canceled (in dollars per share)	0	0	0
Forfeited (in dollars per share)		0	0
Ending Balance (in dollars per share)	$ 2.79	$ 3.66	$ 5.18	$ 5.18
Weighted Average Contractual Term	1 year	2 years 10 months 24 days	1 year 9 months 18 days	2 years 9 months 18 days
Intrinsic Value	$ 0	$ 0	$ 0	$ 66,680

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - 8% Senior Unsecured Notes Due 2020 [Member] $ in Millions	Dec. 31, 2017USD ($)
Related Party Transaction [Line Items]
Interest rate percentage	8.00%
Investments of TRT Holdings, Inc. and Affiliates [Member]
Related Party Transaction [Line Items]
Notes payable	$ 200

COMMITMENTS & CONTINGENCIES (De

COMMITMENTS & CONTINGENCIES (Details) - USD ($)	Sep. 25, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Legal settlement (in shares)		3,000,000	0	0
Chief Executive Officer [Member]
Loss Contingencies [Line Items]
Legal settlement, cash paid	$ 750,000
Legal settlement (in shares)	3,000,000
Other Noncurrent Assets [Member]
Loss Contingencies [Line Items]
Possible revenue to be reversed due to pending litigation		$ 5,500,000	$ 6,800,000

ASSET RETIREMENT OBLIGATION (De

ASSET RETIREMENT OBLIGATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset retirement obligation [Roll Forward]
Beginning Asset Retirement Obligation	$ 7,508,300	$ 5,816,356
Liabilities Acquired or Incurred During the Period	578,441	585,729
Liabilities Removed Due to Divestitures	0	(21,426)
Revision of Estimates	609,351	789,003
Accretion of Discount on Asset Retirement Obligations	536,732	405,991
Liabilities Settled During the Period	(104,696)	(67,353)
Ending Asset Retirement Obligation	$ 9,128,128	$ 7,508,300

INCOME TAXES - Income Tax Expen

INCOME TAXES - Income Tax Expense (Benefit) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current
Federal									$ (785,016)	$ (1,402,179)	$ (73,649)
State									0	0	0
Deferred
Federal									126,501,000	(99,298,900)	(398,002,555)
State									(12,983,000)	(9,707,000)	(36,608,000)
Valuation Allowance									(114,303,000)	109,005,900	232,260,000
Total Expense (Benefit)	$ (1,570,016)	$ 0	$ 0	$ 0	$ (1,402,179)	$ 0	$ 0	$ 0	$ (1,570,016)	$ (1,402,179)	$ (202,424,204)

INCOME TAXES - Effective Income

INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of reported amount of income tax expense (benefit) [Abstract]
Income (Loss) Before Taxes and NOL									$ (10,763,788)	$ (294,895,887)	$ (1,177,778,745)
Federal Statutory Rate									35.00%	35.00%	35.00%
Taxes Computed at Federal Statutory Rates									$ (3,767,000)	$ (103,214,000)	$ (412,223,000)
State Taxes, Net of Federal Taxes									(8,476,000)	(6,306,000)	(23,825,000)
Non-Deductible Compensation									22,000	82,000	470,000
Share Based Compensation Tax Deficiency									0	(834,900)	307,000
Federal Rate Reduction									124,493,000	0	0
Other									460,984	(135,179)	586,796
Valuation Allowance									(114,303,000)	109,005,900	232,260,000
Total Expense (Benefit)	$ (1,570,016)	$ 0	$ 0	$ 0	$ (1,402,179)	$ 0	$ 0	$ 0	(1,570,016)	(1,402,179)	(202,424,204)
Alternative minimum tax credit	800,000				1,400,000				800,000	1,400,000
Interest or penalties expense									0	0	$ 0
Interest or penalties accrued	0				$ 0				0	$ 0
Federal [Member]
Reconciliation of reported amount of income tax expense (benefit) [Abstract]
Net operating loss carryforward	714,500,000								714,500,000
Alternative minimum tax credit	$ 800,000								$ 800,000

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Valuation Allowance	$ 226,962,900	$ 341,265,900
Alternative minimum tax credit	800,000	$ 1,400,000
Tax reform, net reduction in deferred tax assets	124,500,000
Tax reform, reduction in valuation allowance	125,300,000
Income tax benefit as result of the Tax Cuts and Jobs Act	800,000
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	714,500,000
Alternative minimum tax credit	$ 800,000

INCOME TAXES - Deferred Tax Ass

INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Net Operating Loss (NOLs) and Tax Credit Carryforwards	$ 174,864,900	$ 224,679,900
Share Based Compensation	797,000	1,032,000
Accrued Interest	1,144,000	1,727,000
Allowance for Doubtful Accounts	1,360,000	1,795,000
Crude Oil and Natural Gas Properties and Other Properties	42,329,000	107,642,000
Derivative Instruments	7,393,000	4,341,000
Other	(140,000)	49,000
Total Net Deferred Tax Assets (Liabilities) Before Valuation Allowance	227,747,900	341,265,900
Valuation Allowance	(226,962,900)	(341,265,900)
Total Net Deferred Tax Assets	$ 785,000	$ 0

OPERATING LEASES (Details)

OPERATING LEASES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	$ 342
2,019	352
2,020	361
2,021	340
Total	1,395
Rent expense	$ 369	$ 320	$ 287

FAIR VALUE - Financial Instrume

FAIR VALUE - Financial Instruments Measured at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring [Member] - Significant Other Observable Inputs (Level 2) [Member] - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivatives – Current Asset (crude oil swaps)	$ 0	$ 4,517
Commodity Derivatives – Current Liabilities (crude oil swaps)	(18,681,891)	(10,001,564)
Commodity Derivatives – Non-Current Liabilities (crude oil swaps)	(11,496,929)	(1,738,329)
Total	$ (30,178,820)	$ (11,735,376)

FAIR VALUE - Additional Informa

FAIR VALUE - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 979,324,222	$ 832,625,125
Unamortized net discount	1,197,954	1,693,847
Asset retirement obligations	578,441	585,729
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior unsecured notes	528,000,000
Senior Notes [Member] | 8% Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	691,954,489	688,625,125
Unamortized net discount	1,197,954	$ 1,693,847
Term Loan [Member] | Line of Credit [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	287,369,733
Unamortized net discount	$ 0

DERIVATIVE INSTRUMENTS AND PR63

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Gains/Losses on Derivatives (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash Received (Paid) on Derivatives									$ 3,776,788	$ 61,528,201	$ 161,098,510
Non-Cash Gain (Loss) on Derivatives									(18,443,443)	(76,346,935)	(88,715,603)
Gain (Loss) on Derivative Instruments, Net	$ (35,477,317)	$ (12,663,253)	$ 16,513,032	$ 16,960,883	$ (11,141,233)	$ 3,381,564	$ (10,522,948)	$ 3,463,883	(14,666,655)	$ (14,818,734)	72,382,907
Net cash receipts (payments) for crude oil contracts									$ 700,000		$ 200,000

DERIVATIVE INSTRUMENTS AND PR64

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Open Commodity Swap Contracts (Details)	12 Months Ended
	Dec. 31, 2017bbl$ / bbl
Derivative Instruments, Gain (Loss) [Line Items]
Volumes (in bbl) | bbl	6,200,000
Weighted Average Price (in dollar per bbl) | $ / bbl	52.24
Oil Swap 1 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	160,000
Fixed Price (in dollars per bbl) | $ / bbl	49.99
Oil Swap 2 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	160,000
Fixed Price (in dollars per bbl) | $ / bbl	50.04
Oil Swap 3 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	160,000
Fixed Price (in dollars per bbl) | $ / bbl	49.99
Oil Swap 4 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	160,000
Fixed Price (in dollars per bbl) | $ / bbl	50.17
Oil Swap 5 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	270,000
Fixed Price (in dollars per bbl) | $ / bbl	53.99
Oil Swap 6 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	270,000
Fixed Price (in dollars per bbl) | $ / bbl	53.99
Oil Swap 7 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	273,000
Fixed Price (in dollars per bbl) | $ / bbl	55.19
Oil Swap 8 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	180,000
Fixed Price (in dollars per bbl) | $ / bbl	53.30
Oil Swap 9 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	365,000
Fixed Price (in dollars per bbl) | $ / bbl	54.80
Oil Swap 10 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	365,000
Fixed Price (in dollars per bbl) | $ / bbl	54.09
Oil Swap 11 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	365,000
Fixed Price (in dollars per bbl) | $ / bbl	54.42
Oil Swap 12 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	92,000
Fixed Price (in dollars per bbl) | $ / bbl	52.50
Oil Swap 13 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	92,000
Fixed Price (in dollars per bbl) | $ / bbl	52.55
Oil Swap 14 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	46,000
Fixed Price (in dollars per bbl) | $ / bbl	54.50
Oil Swap 15 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	92,000
Fixed Price (in dollars per bbl) | $ / bbl	52.50
Oil Swap 16 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	45,000
Fixed Price (in dollars per bbl) | $ / bbl	54.22
Oil Swap 17 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	63,000
Fixed Price (in dollars per bbl) | $ / bbl	53.65
Oil Swap 18 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	365,000
Fixed Price (in dollars per bbl) | $ / bbl	51.05
Oil Swap 19 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	365,000
Fixed Price (in dollars per bbl) | $ / bbl	51.05
Oil Swap 20 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	182,500
Fixed Price (in dollars per bbl) | $ / bbl	52.70
Oil Swap 21 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	365,000
Fixed Price (in dollars per bbl) | $ / bbl	51.05
Oil Swap 22 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	182,500
Fixed Price (in dollars per bbl) | $ / bbl	52.15
Oil Swap 23 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	182,500
Fixed Price (in dollars per bbl) | $ / bbl	52.75
Oil Swap 24 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	45,500
Fixed Price (in dollars per bbl) | $ / bbl	53.59
Oil Swap 25 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	36,400
Fixed Price (in dollars per bbl) | $ / bbl	53.10
Oil Swap 26 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	46,000
Fixed Price (in dollars per bbl) | $ / bbl	53.07
Oil Swap 27 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	9,200
Fixed Price (in dollars per bbl) | $ / bbl	52.65
Oil Swap 28 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	27,300
Fixed Price (in dollars per bbl) | $ / bbl	51.81
Oil Swap 29 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	366,000
Fixed Price (in dollars per bbl) | $ / bbl	49.77
Oil Swap 30 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	183,000
Fixed Price (in dollars per bbl) | $ / bbl	51.30
Oil Swap 31 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	109,800
Fixed Price (in dollars per bbl) | $ / bbl	51.70
Oil Swap 32 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	366,000
Fixed Price (in dollars per bbl) | $ / bbl	49.75
Oil Swap 33 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	183,000
Fixed Price (in dollars per bbl) | $ / bbl	51.10
Oil Swap 34 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in bbl) | bbl	9,100
Fixed Price (in dollars per bbl) | $ / bbl	51.50
Open Commodity Swap 1 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes (in bbl) | bbl	3,050,000
Weighted Average Price (in dollar per bbl) | $ / bbl	53.26
Open Commodity Swap 2 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes (in bbl) | bbl	1,887,600
Weighted Average Price (in dollar per bbl) | $ / bbl	51.80
Open Commodity Swap 3 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes (in bbl) | bbl	1,244,200
Weighted Average Price (in dollar per bbl) | $ / bbl	50.41

DERIVATIVE INSTRUMENTS AND PR65

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Classification of outstanding financial instruments (Details) - Not Designated as Hedging Instrument [Member] - Cash Flow Hedging [Member] - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Total Derivatives Assets	$ 0	$ 4,517
Total Derivatives Liabilities	(30,178,820)	(11,739,893)
Swap Contracts [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Assets	0	4,517
Swap Contracts [Member] | Current Assets/Liabilities [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Liabilities	(18,681,891)	(9,512,724)
Swap Contracts [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Liabilities	(11,496,929)	(1,738,329)
Swaption Contracts [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Liabilities	0	(333,046)
Costless Collars [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Total Derivatives Liabilities	$ 0	$ (155,794)

DERIVATIVE INSTRUMENTS AND PR66

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets (Liabilities), Offsetting of Derivative Assets	$ 0	$ 20,962
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	0	(16,445)
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	0	4,517
Gross Amounts of Recognized Assets (Liabilities), Offsetting of Derivative Liabilities	(30,178,820)	(11,756,338)
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	0	16,445
Net Amount of Assets (Liabilities) Presented in Balance Sheet, Offsetting of Derivative Liabilities	(30,178,820)	(11,739,893)
Current Assets [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets (Liabilities), Offsetting of Derivative Assets	0	20,962
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	0	(16,445)
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	0	4,517
Non Current Assets [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets (Liabilities), Offsetting of Derivative Assets	0	0
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	0	0
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	0	0
Current Liabilities [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets (Liabilities), Offsetting of Derivative Liabilities	(18,681,891)	(10,018,009)
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	0	16,445
Net Amount of Assets (Liabilities) Presented in Balance Sheet, Offsetting of Derivative Liabilities	(18,681,891)	(10,001,564)
Non Current Liabilities [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets (Liabilities), Offsetting of Derivative Liabilities	(11,496,929)	(1,738,329)
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	0	0
Net Amount of Assets (Liabilities) Presented in Balance Sheet, Offsetting of Derivative Liabilities	$ (11,496,929)	$ (1,738,329)

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic EPS [Abstract]
Net Income (Loss)	$ (23,848,687)	$ (16,087,467)	$ 13,801,859	$ 16,940,523	$ (12,330,397)	$ (45,618,895)	$ (108,978,662)	$ (126,565,754)	$ (9,193,772)	$ (293,493,708)	$ (975,354,541)
Shares-Basic (in shares)									62,408,855	61,173,547	60,652,447
Net Income (Loss) Per Common Share - Common (in dollars per share)		$ (0.26)	$ 0.22	$ 0.28	$ (0.20)	$ (0.74)	$ (1.78)	$ (2.08)	$ (0.15)	$ (4.80)	$ (16.08)
Diluted EPS [Abstract]
Dilutive Effect of Options (in shares)									0	0	0
Dilutive Effect of Options (in dollars per share)									$ 0	$ 0	$ 0
Net Income (Loss) available to common shareholders, diluted									$ (9,193,772)	$ (293,493,708)	$ (975,354,541)
Weighted Average Common Shares Outstanding - Diluted (in shares)									62,408,855	61,173,547	60,652,447
Net Income (Loss) Per Common Share - Diluted (in dollars per share)	$ (0.37)	$ (0.26)	$ 0.22	$ 0.27	$ (0.20)	$ (0.74)	$ (1.78)	$ (2.08)	$ (0.15)	$ (4.80)	$ (16.08)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares excluded from EPS due to the anti-dilutive effect (in shares)									1,109,511	829,313	322,393
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares excluded from EPS due to the anti-dilutive effect (in shares)									1,109,511	829,313	322,393

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Compensation Related Costs [Abstract]
Percentage match of eligible employee's deferral contribution	100.00%	100.00%	100.00%
Maximum percentage of eligible employee's deferral contribution matched	8.00%	8.00%	8.00%
Matching contributions to the Plans	$ 178	$ 238	$ 279

SUPPLEMENTAL OIL AND GAS INFO69

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Costs Incurred (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Proved Property Acquisition and Other	$ 15,722,378	$ 18,531,518	$ 9,068,139
Unproved Property Acquisition	716,681	2,301,285	3,346,214
Development	139,531,567	63,621,429	116,255,535
Total	$ 155,970,626	$ 84,454,232	$ 128,669,888

SUPPLEMENTAL OIL AND GAS INFO70

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Capitalized Costs (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Property Acquisition	$ 565,352	$ 509,877	$ 502,794	$ 121,321
Development	0	0	0	0
Total	$ 565,352	$ 509,877	$ 502,794	$ 121,321

SUPPLEMENTAL OIL AND GAS INFO71

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Proved Reserve Data (Details)	12 Months Ended
	Dec. 31, 2017BoeMcfbbl	Dec. 31, 2016BoeMcfbbl	Dec. 31, 2016BoeMcfbbl	Dec. 31, 2016BoeMcfbbl	Dec. 31, 2016BoeMMBoeMcfbbl	Dec. 31, 2015BoeMcfbbl	Dec. 31, 2015BoeMcfbbl	Dec. 31, 2015BoeMcfbbl	Dec. 31, 2015BoeMMBoeMcfbbl	Dec. 31, 2014BoeMcfbbl
Natural Gas
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning Balance | Mcf	46,832,327	50,900,984				70,935,117
Revisions of Previous Estimates | Mcf	8,838,976	(8,697,825)				(23,552,809)
Extensions, Discoveries and Other Additions | Mcf	27,637,350	7,695,309				8,170,259
Purchases of Minerals in Place | Mcf		960,758
Production | Mcf	(5,187,886)	(4,026,899)				(4,651,583)
Proved Developed and Undeveloped Reserves, Ending Balance | Mcf	78,120,767	46,832,327				50,900,984
Proved Developed Reserves | Mcf	46,518,005	32,808,111	32,808,111	32,808,111	32,808,111	33,619,954	33,619,954	33,619,954	33,619,954	38,277,770
Proved Undeveloped Reserve | Mcf	31,602,762	14,024,216	14,024,216	14,024,216	14,024,216	17,281,030	17,281,030	17,281,030	17,281,030	32,657,347
Oil
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning Balance | bbl	46,275,291		56,814,464				88,913,305
Revisions of Previous Estimates | bbl	889,814		(13,995,801)				(36,277,018)
Extensions, Discoveries and Other Additions | bbl	20,184,388		7,142,439				9,346,864
Purchases of Minerals in Place | bbl			640,108
Production | bbl	(4,537,295)		(4,325,919)				(5,168,687)
Proved Developed and Undeveloped Reserves, Ending Balance | bbl	62,812,198		46,275,291				56,814,464
Proved Developed Reserves | bbl	38,592,506	32,245,139	32,245,139	32,245,139	32,245,139	36,573,821	36,573,821	36,573,821	36,573,821	44,666,408
Proved Undeveloped Reserve | bbl	24,219,692	14,030,152	14,030,152	14,030,152	14,030,152	20,240,643	20,240,643	20,240,643	20,240,643	44,246,897
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning Balance | Boe	54,080,679			65,297,962				100,735,825
Revisions of Previous Estimates	2,362,977			(15,445,439)	(15.4)			(40,202,486)	(40.2)
Extensions, Discoveries and Other Additions | Boe	24,790,613			8,424,991				10,708,574
Purchases of Minerals in Place | Boe				800,234
Production | Boe	(5,401,943)			(4,997,069)				(5,943,951)
Proved Developed and Undeveloped Reserves, Ending Balance | Boe	75,832,326			54,080,679				65,297,962
Proved Developed Reserves | Boe	46,345,507	37,713,158	37,713,158	37,713,158	37,713,158	42,177,147	42,177,147	42,177,147	42,177,147	51,046,037
Proved Undeveloped Reserves | Boe	29,486,819	16,367,521	16,367,521	16,367,521	16,367,521	23,120,815	23,120,815	23,120,815	23,120,815	49,689,788

SUPPLEMENTAL OIL AND GAS INFO72

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Additional Information (Details)	12 Months Ended
	Dec. 31, 2017BoeMMBoe	Dec. 31, 2016Boe	Dec. 31, 2016MMBoe	Dec. 31, 2015Boe	Dec. 31, 2015MMBoe
Oil
Reserve Quantities [Line Items]
Extension and discoveries attributable to successful drilling (in MMBOE) | Boe	24,790,613	8,424,991		10,708,574
Purchase of mineral in place attributable to acquisitions (in MMBOE)			0.8
Decrease to reserves due to revisions of previous estimates	(2,362,977)	15,445,439	15.4	40,202,486	40.2
Upward (downward) adjustment attributable to lower crude oil and natural gas prices (in MMBOE)			15.7		(52.6)
Downward adjustment attributable to removal of undeveloped drilling locations (in MMBOE)			3.4
Upward adjustment attributable to well performance (in MMBOE)			3.6
Downward adjustments attributable to reservoir analysis (in MMBOE)					12.4
Williston Basin
Reserve Quantities [Line Items]
Extension and discoveries attributable to successful drilling (in MMBOE)					10.7
Williston Basin | Oil
Reserve Quantities [Line Items]
Extension and discoveries attributable to successful drilling (in MMBOE)	24.8		8.4

SUPPLEMENTAL OIL AND GAS INFO73

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Future Net Cash Flows of Proved Reserves (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Future Cash Inflows	$ 3,143,603,968	$ 1,708,870,912	$ 2,470,707,712
Future Production Costs	(1,265,524,800)	(775,534,832)	(981,256,096)
Future Development Costs	(409,360,320)	(220,869,664)	(356,401,888)
Future Income Tax Expense	(27,476,230)	(2,477,353)	(5,740,623)
Future Net Cash Inflows	1,441,242,618	709,989,063	1,127,309,105
10% Annual Discount for Estimated Timing of Cash Flows	(687,256,521)	(330,963,050)	(552,510,342)
Standardized Measure of Discounted Future Net Cash Flows	$ 753,986,097	$ 379,026,013	$ 574,798,763	$ 1,405,379,543

SUPPLEMENTAL OIL AND GAS INFO74

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Average Sales Prices (Details)	12 Months Ended
	Dec. 31, 2017$ / bbl$ / Mcf	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf
Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sale price (in dollars per volume unit) | $ / Mcf	3.34	1.67	1.63
Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sale price (in dollars per volume unit) | $ / bbl	45.90	35.24	42.03

SUPPLEMENTAL OIL AND GAS INFO75

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Beginning of Period	$ 379,026,013	$ 574,798,763	$ 1,405,379,543
Sales of Oil and Natural Gas Produced, Net of Production Costs	(153,625,893)	(98,497,165)	(128,964,023)
Extensions and Discoveries	217,145,871	59,542,911	96,770,078
Previously Estimated Development Cost Incurred During the Period	46,833,826	23,271,960	114,208,095
Net Change of Prices and Production Costs	216,216,656	(174,656,448)	(1,384,474,928)
Change in Future Development Costs	(34,753,469)	57,481,060	235,578,690
Revisions of Quantity and Timing Estimates	28,914,878	(130,664,183)	(363,975,445)
Accretion of Discount	37,942,243	57,569,313	170,222,344
Change in Income Taxes	(3,617,100)	497,950	295,949,531
Purchases of Minerals in Place	0	9,576,760	0
Other	19,903,072	105,092	134,104,878
End of Period	$ 753,986,097	$ 379,026,013	$ 574,798,763

QUARTERLY RESULTS OF OPERATIO76

QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Total Revenues	$ 37,002,281	$ 41,598,659	$ 64,901,882	$ 65,816,847	$ 35,943,626	$ 45,109,408	$ 32,014,226	$ 31,836,236	$ 209,319,669	$ 144,903,496	$ 275,057,413
Gain (Loss) on Derivative Instruments, Net	(35,477,317)	(12,663,253)	16,513,032	16,960,883	(11,141,233)	3,381,564	(10,522,948)	3,463,883	(14,666,655)	(14,818,734)	72,382,907
Total Operating Expenses	40,661,791	41,013,678	34,576,905	32,572,699	33,457,789	74,583,046	124,946,744	141,220,772	148,825,073	374,208,351	1,394,445,680
Impairment					0	43,820,791	88,880,921	104,311,122	0	237,012,834	1,163,959,246
Income (Loss) from Operations	(3,659,510)	584,981	30,324,977	33,244,148	2,485,837	(29,473,638)	(92,932,518)	(109,384,536)	60,494,596	(229,304,855)	(1,119,388,267)
Other Income (Expense)	(21,759,013)	(16,672,448)	(16,523,118)	(16,303,805)	(16,218,413)	(16,145,257)	(16,046,144)	(17,181,218)	116,042	(15,902)	(30,091)
Income Tax Benefit	(1,570,016)	0	0	0	(1,402,179)	0	0	0	(1,570,016)	(1,402,179)	(202,424,204)
Net Loss	$ (23,848,687)	$ (16,087,467)	$ 13,801,859	$ 16,940,523	$ (12,330,397)	$ (45,618,895)	$ (108,978,662)	$ (126,565,754)	$ (9,193,772)	$ (293,493,708)	$ (975,354,541)
Net Loss Per Common Share – Basic (in dollars per share)		$ (0.26)	$ 0.22	$ 0.28	$ (0.20)	$ (0.74)	$ (1.78)	$ (2.08)	$ (0.15)	$ (4.80)	$ (16.08)
Net Loss Per Common Share – Diluted (in dollars per share)	$ (0.37)	$ (0.26)	$ 0.22	$ 0.27	$ (0.20)	$ (0.74)	$ (1.78)	$ (2.08)	$ (0.15)	$ (4.80)	$ (16.08)

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($)	Jan. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsequent Event [Line Items]
Common stock, par value (in dollars per share)		$ 0.001	$ 0.001
Long-term debt		$ 979,324,222	$ 832,625,125
Subsequent Event [Member]
Subsequent Event [Line Items]
Subscription agreement, purchase agreement amount	$ 40,000,000
Subscription agreement, purchase agreement price per share (in dollars per share)	$ 3
Exchange Agreement [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Common stock, par value (in dollars per share)	$ 0.001
Exchange Agreement [Member] | Unsecured Debt [Member] | 8.00% Senior Notes Due 2020 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Converted debt amount	$ 497,000,000
Converted debt percent	71.00%
Converted debt stated interest rate	8.00%
Exchange Agreement [Member] | Secured Debt [Member] | Senior Second Lien Notes Due 2023 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Long-term debt	$ 344,000,000
Common Stock [Member] | Exchange Agreement [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Common shares issued upon conversion amount	$ 155,000,000
TRTH Holdings And Affiliates [Member] | Exchange Agreement [Member] | Secured Debt [Member] | Senior Second Lien Notes Due 2023 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Debt to debt conversion ratio	0.6120
TRTH Holdings And Affiliates [Member] | Common Stock [Member] | Exchange Agreement [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Debt to shares conversion ratio	0.1333
Other Supporting Noteholders [Member] | Exchange Agreement [Member] | Secured Debt [Member] | Senior Second Lien Notes Due 2023 [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Debt to debt conversion ratio	0.7500
Other Supporting Noteholders [Member] | Common Stock [Member] | Exchange Agreement [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Debt to shares conversion ratio	0.0833
Shares issued in equity raising price per share conversion ratio threshold (in dollars per share)	$ 3
Debt conversion ratio adjustment, minimum equity raised threshold	$ 156,000,000
Debt conversion ratio adjustment, minimum cash contribution from sale of common stock threshold	50.00%
Debt conversion ratio adjustment, commitments received under subscription agreements threshold	$ 40,000,000
Debt conversion ratio adjustment, maximum additional assets acquired percent threshold	50.00%