Northern Oil and Gas (NOG) 10-Q 9 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 01, 2016
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 Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		63,029,971
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016

CONDENSED BALANCE SHEETS

CONDENSED BALANCE SHEETS - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Current Assets:
Cash and Cash Equivalents	$ 3,319,021	$ 3,390,389
Trade Receivables, Net	32,856,099	51,445,026
Advances to Operators	1,733,051	1,689,879
Prepaid and Other Expenses	1,200,717	892,867
Derivative Instruments	7,212,947	64,611,558
Total Current Assets	46,321,835	122,029,719
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved	2,392,372,802	2,336,757,089
Unproved	4,822,789	10,007,529
Other Property and Equipment	1,871,314	1,837,469
Total Property and Equipment	2,399,066,905	2,348,602,087
Less – Accumulated Depreciation, Depletion and Impairment	(2,043,702,564)	(1,759,281,704)
Total Property and Equipment, Net	355,364,341	589,320,383
Derivative Instruments	20,166	0
Deferred Income Taxes (Note 9)	0	0
Other Noncurrent Assets, Net	8,665,794	10,080,846
Total Assets	410,372,136	721,430,948
Current Liabilities:
Accounts Payable	47,759,558	65,319,170
Accrued Expenses	5,201,185	7,893,975
Accrued Interest	18,670,814	4,713,232
Derivative Instruments	707,703	0
Asset Retirement Obligations	243,698	188,770
Total Current Liabilities	72,582,958	78,115,147
Long-term Debt, Net	807,788,710	835,290,329
Derivative Instruments	49,153	0
Asset Retirement Obligations	6,011,773	5,627,586
Total Liabilities	886,432,594	919,033,062
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 (9/30/2016 – 63,029,971 Shares Outstanding and 12/31/2015 – 63,120,384 Shares Outstanding)	63,030	63,120
Additional Paid-In Capital	442,926,076	440,221,018
Retained Deficit	(919,049,564)	(637,886,252)
Total Stockholders’ Deficit	(476,060,458)	(197,602,114)
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$ 410,372,136	$ 721,430,948

CONDENSED BALANCE SHEETS (Paren

CONDENSED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
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)	63,029,971	63,120,384

CONDENSED STATEMENTS OF OPERATI

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
REVENUES
Oil and Gas Sales	$ 41,719,194	$ 49,779,903	$ 112,614,382	$ 163,298,384
Gain (Loss) on Derivative Instruments, Net	3,381,564	51,366,762	(3,677,502)	54,818,997
Other Revenue	8,650	9,887	22,989	27,004
Total Revenues	45,109,408	101,156,552	108,959,869	218,144,385
OPERATING EXPENSES
Production Expenses	10,920,651	12,567,423	33,961,883	40,331,314
Production Taxes	4,045,291	5,048,227	11,032,903	17,333,123
General and Administrative Expense	2,098,293	4,614,771	11,021,970	13,224,012
Depletion, Depreciation, Amortization and Accretion	13,698,020	31,670,479	47,720,972	113,629,323
Impairment of Oil and Natural Gas Properties	43,820,791	354,422,654	237,012,834	996,815,713
Total Expenses	74,583,046	408,323,554	340,750,562	1,181,333,485
LOSS FROM OPERATIONS	(29,473,638)	(307,167,002)	(231,790,693)	(963,189,100)
OTHER INCOME (EXPENSE)
Interest Expense, Net of Capitalization	(16,145,440)	(16,154,160)	(48,290,447)	(42,278,400)
Write-off of Debt Issuance Costs	0	0	(1,089,507)	0
Other Income	183	1,586	7,337	2,128
Total Other Income (Expense)	(16,145,257)	(16,152,574)	(49,372,617)	(42,276,272)
LOSS BEFORE INCOME TAXES	(45,618,895)	(323,319,576)	(281,163,310)	(1,005,465,372)
INCOME TAX BENEFIT	0	(77,544)	0	(202,424,154)
NET LOSS	$ (45,618,895)	$ (323,242,032)	$ (281,163,310)	$ (803,041,218)
Net Loss Per Common Share - Basic (in dollars per share)	$ (0.74)	$ (5.33)	$ (4.60)	$ (13.25)
Net Loss Per Common Share - Diluted (in dollars per share)	$ (0.74)	$ (5.33)	$ (4.60)	$ (13.25)
Weighted Average Shares Outstanding - Basic (in shares)	61,237,627	60,679,257	61,127,577	60,627,142
Weighted Average Shares Outstanding - Diluted (in shares)	61,237,627	60,679,257	61,127,577	60,627,142

CONDENSED STATEMENTS OF CASH FL

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$ (281,163,310)	$ (803,041,218)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities:
Depletion, Depreciation, Amortization and Accretion	47,720,972	113,629,323
Amortization of Debt Issuance Costs	2,879,164	2,674,927
Write-off of Debt Issuance Costs	1,089,507	0
Amortization/Accretion of 8% Senior Notes Premium/Discount	373,277	(376,315)
Deferred Income Taxes	0	(202,350,555)
Loss on the Mark-to-Market of Derivative Instruments	58,135,302	59,115,913
Amortization of Deferred Rent	0	(8,548)
Share-Based Compensation Expense	2,508,003	2,911,715
Impairment of Oil and Natural Gas Properties	237,012,834	996,815,713
Other	442,848	975,556
Changes in Working Capital and Other Items:
Trade Receivables, Net	18,588,927	(5,361,872)
Prepaid Expenses and Other	(307,849)	24,395
Accounts Payable	(873,647)	(4,450,439)
Accrued Interest	13,835,754	15,007,861
Accrued Expenses	(2,493,580)	(688,101)
Asset Retirement Obligations	(29,498)	(57,345)
Net Cash Provided by Operating Activities	97,718,704	174,821,010
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Oil and Natural Gas Properties and Development Capital Expenditures, Net	(66,931,194)	(233,364,628)
Proceeds from Sale of Oil, Natural Gas, and Other Properties	955,448	160,944
Purchases of Other Property and Equipment	(58,480)	(20,859)
Net Cash Used for Investing Activities	(66,034,226)	(233,224,543)
CASH FLOWS FROM FINANCING ACTIVITIES
Advances on Revolving Credit Facility	29,000,000	140,000,000
Repayments on Revolving Credit Facility	(59,000,000)	(268,000,000)
Debt Issuance Costs Paid	(428,515)	(5,687,108)
Issuance of Senior Unsecured Notes	0	190,000,000
Repurchase of Common Stock – Tax Obligations	(1,327,331)	(204,613)
Net Cash (Used for) Provided by Financing Activities	(31,755,846)	56,108,279
NET DECREASE IN CASH AND CASH EQUIVALENTS	(71,368)	(2,295,254)
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD	3,390,389	9,337,512
CASH AND CASH EQUIVALENTS – END OF PERIOD	3,319,021	7,042,258
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	31,320,249	25,412,729
Cash Paid During the Period for Income Taxes	0	3,303,945
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable	42,834,450	92,962,284
Capitalized Asset Retirement Obligations	180,302	364,913
Non-Cash Compensation Capitalized on Oil and Gas Properties	$ 882,234	$ 465,198

CONDENSED STATEMENTS OF CASH F6

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) (Parenthetical)	Sep. 30, 2016	Dec. 31, 2015
Statement of Cash Flows [Abstract]
Rate of Senior notes	8.00%	8.00%

ORGANIZATION AND NATURE OF BUSI

ORGANIZATION AND NATURE OF BUSINESS	9 Months Ended
	Sep. 30, 2016
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 MKT 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 September 30, 2016 , approximately 77% of Northern’s 156,074 total net acres were developed.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	SIGNIFICANT ACCOUNTING POLICIES The financial information included herein is unaudited, except for the balance sheet as of December 31, 2015 , which has been derived from the Company’s audited financial statements for the year ended December 31, 2015 . However, such information includes all adjustments (consisting of normal recurring adjustments and change in accounting principles) that are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year. Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2015 , which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015 . 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 condensed 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 condensed balance sheets. As of September 30, 2016 and December 31, 2015 , the Company included accounts receivable of $6.8 million in Other Noncurrent Assets, Net due to their long-term nature. The allowance for doubtful accounts at September 30, 2016 and December 31, 2015 was $4.9 million and $4.5 million , respectively. 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 $50,652 and $74,469 for the three months ended September 30, 2016 and 2015 , respectively. Depreciation expense was $155,813 and $229,694 for the nine months ended September 30, 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 three and nine months ended September 30, 2016 and 2015 , respectively. Three Months Ended Nine Months Ended 2016 2015 2016 2015 Capitalized Certain Payroll and Other Internal Costs $ 239,132 $ 520,046 $ 1,674,015 $ 1,500,734 Capitalized Interest Costs 79,805 311,739 289,409 1,270,420 Total $ 318,937 $ 831,785 $ 1,963,424 $ 2,771,154 As of September 30, 2016 , 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. There were no property sales in the nine months ended September 30, 2016 and 2015 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. As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties, the Company recorded non-cash ceiling test impairments for the three months ended September 30, 2016 and 2015 of $43.8 million and $354.4 million , respectively. The Company recorded non-cash ceiling test impairments for the nine months ended September 30, 2016 and 2015 of $237.0 million and $996.8 million , respectively. The impairment charges affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have stabilized or recovered long enough to stabilize or increase the trailing twelve-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our 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 three months ended September 30, 2016 and 2015 , the Company transferred into the full cost pool costs related to expired leases of $5.2 million and $6.4 million , respectively. For the nine months ended September 30, 2016 and 2015 , the Company transferred into the full cost pool costs related to expired leases of $10.5 million and $15.3 million , respectively. Asset Retirement Obligations The Company accounts for its abandonment and restoration liabilities under the 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. Debt Issuance Costs Deferred financing costs include origination, legal and other fees to issue debt in connection with the Company’s credit facility and senior unsecured notes. These debt issuance costs are being 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 three months ended September 30, 2016 and 2015 was $0.9 million and $1.0 million , respectively. The amortization of debt issuance costs for the nine months ended September 30, 2016 and 2015 was $2.9 million and $2.7 million , respectively. During the three and nine months ended September 30, 2016 , $0 and $1.1 million , respectively, of debt issuance costs were written-off as a result of a reduction in the borrowing base of the Revolving Credit Facility, which became effective in May 2016 and was due to the impact that lower commodity prices had on our oil and gas reserve valuation. There were no debt issuance costs written-off during the three and nine months ended September 30, 2015 . As a result of the adoption of ASU No. 2015-03 , “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”), the Company reclassified unamortized debt issuance costs associated with its 8% Senior Notes, which totaled $12.5 million as of December 31, 2015 , from "Debt Issuance Costs, Net" to a reduction of "Long-term Debt" on the balance sheets. Adoption of ASU 2015-03 had no impact on the Company's current and previously reported stockholders' deficit, results of operations, or cash flows. Unamortized debt issuance costs associated with the Company's revolving credit facility, which amounted to $1.9 million and $3.3 million as of September 30, 2016 and December 31, 2015 , respectively, were not reclassified and remain reflected in "Other Noncurrent Assets, Net" on the condensed balance sheets. 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 for the three and nine months ended September 30, 2016 and 2015 was $0.4 million and $1.1 million in each period. 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 three months ended September 30, 2016 and 2015 was $0.5 million and $0.5 million , respectively. The amortization of the bond discount for the nine months ended September 30, 2016 and 2015 was $1.5 million and $0.7 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. For the three and nine months ended September 30, 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 customers 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 three and nine months ended September 30, 2015, we 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 our Denver office, which includes $0.1 million of non-cash expense related to acceleration of certain equity awards previously granted under our 2013 Incentive Plan. 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. 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 the 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 September 30, 2016 , 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 September 30, 2016 , 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 September 30, 2016 and December 31, 2015 was $336.3 million and $232.3 million , respectively. Net Income (Loss) Per Common Share Basic earnings per share (“EPS”) are computed by dividing net income (loss) (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income (loss) 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 three and nine months ended September 30, 2016 and 2015 are as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 Weighted Average Common Shares Outstanding – Basic 61,237,627 60,679,257 61,127,577 60,627,142 Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock — — — — Weighted Average Common Shares Outstanding – Diluted 61,237,627 60,679,257 61,127,577 60,627,142 Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect 574,862 150,428 885,200 173,763 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 has, and may continue to 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 condensed statements of operations. See Note 11 for a description of the derivative contracts into which the Company has entered. New Accounting Pronouncements From time to time, new accounting pronouncements are issued by 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 August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) . The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period beginning after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU 2014-09 for all entities by one year. This update is effective for public business entities for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements. In February 2016, the FASB issued ASU 2016-02, Leases , which introduces the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous guidance. The guidance will be effective for annual reporting periods beginning after December 15, 2018 and interim periods within those fiscal years with early adoption permitted. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation: Improvements to Employee Share-Based Payment Accounting, which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. This standard will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements.

CRUDE OIL AND NATURAL GAS PROPE

CRUDE OIL AND NATURAL GAS PROPERTIES	9 Months Ended
	Sep. 30, 2016
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 condensed 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 September 30, 2016 and December 31, 2015 were approximately $42.8 million and $59.5 million , respectively. Acquisitions For the nine months ended September 30, 2016 , the Company acquired approximately 1,645 net acres, for an average cost of approximately $2,965 per net acre, in its key prospect areas in the form of effective leases. For the nine months ended September 30, 2015 , the Company acquired approximately 3,157 net acres, for an average cost of approximately $1,065 per net acre, in its key prospect areas in the form of effective leases. Unproved Properties Unproved properties not subject to depletion comprise approximately 28,858 net acres and 38,003 net acres of undeveloped leasehold interests at September 30, 2016 and December 31, 2015 , 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. 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 historically have not been subject to specified drilling projects. The Company generally participates in drilling activities on a heads-up basis by electing whether to participate 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 drilling 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 nine months ended September 30, 2016 and 2015 , the Company included in the pool of cost subject to depletion $6.4 million and $32.4 million , respectively, for unproved property costs related to expiring leases.

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT The Company's long-term debt consists of the following: September 30, 2016 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 698,178,106 $ (10,389,396 ) $ 687,788,710 Revolving Credit Facility (1) 120,000,000 — 120,000,000 Total $ 818,178,106 $ (10,389,396 ) $ 807,788,710 December 31, 2015 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 697,804,829 $ (12,514,500 ) $ 685,290,329 Revolving Credit Facility (1) 150,000,000 — 150,000,000 Total $ 847,804,829 $ (12,514,500 ) $ 835,290,329 _____________ (1) Debt issuance costs related to our revolving credit facility are recorded in "Other Noncurrent Assets, Net" on the condensed balance sheets Revolving Credit Facility 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, which is secured by substantially all of the Company’s assets, provides for a commitment equal to the lesser of the facility amount or the borrowing base. At September 30, 2016 , the facility amount was $750 million , the borrowing base was $350 million and there was a $120 million outstanding balance, leaving $230 million of borrowing capacity available under the facility. The Revolving Credit Facility matures on September 30, 2018 and provides for a borrowing base subject to redetermination semi-annually each April and October and for unscheduled event-driven redeterminations. Borrowings under the Revolving Credit Facility can either be at the Alternate Base Rate (as defined in the credit agreement) plus a spread ranging from 1.0% to 2.0% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined in the credit agreement) plus a spread ranging from 2.0% to 3.0% . The applicable spread at any time is dependent upon the amount of borrowings relative to the borrowing base at such time. The Company may 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 is paid on the undrawn balance based on an annual rate of either 0.375% or 0.50% . At September 30, 2016 , the commitment fee was 0.375% and the interest rate margin was 2.25% on LIBOR loans and 1.25% on base rate loans. At September 30, 2016 , the Company had a borrowing base of $350 million with $120.0 million of LIBOR loans issued under the Revolving Credit Facility at a weighted average interest rate of 2.78% . The Revolving Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay any cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of its business or operations, merge, consolidate, make investments, or maintain excess cash liquidity. In addition, the Company is required to maintain a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0 , a ratio of secured debt to EBITDAX (as defined in the credit agreement) of no greater than 2.5 to 1.0 and a ratio of EBITDAX (as defined in the credit agreement) to interest expense (as defined in the credit agreement) of no less than 2.5 to 1.0 (through September 30, 2016). The Company was in compliance with the financial covenants of the Revolving Credit Facility at September 30, 2016 . The minimum ratio of EBITDAX to interest expense that the Company is required to maintain begins stepping down with the quarter ending December 31, 2016, through the quarter ending March 31, 2018. The schedule of the minimum ratio of EBITDAX to interest expense the Company is required to maintain is as follows: Measurement Period Minimum ratio of EBITDAX to Interest Expense 12 months ending December 31, 2016 1.75 to 1.00 12 months ending March 31, 2017 1.50 to 1.00 12 months ending June 30, 2017 1.25 to 1.00 12 months ending September 30, 2017 1.25 to 1.00 12 months ending December 31, 2017 1.00 to 1.00 12 months ending March 31, 2018 1.00 to 1.00 12 months ending June 30, 2018 and beyond 2.50 to 1.00 All of the Company’s obligations under the Revolving Credit Facility are 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	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
COMMON AND PREFERRED STOCK	COMMON AND PREFERRED STOCK In May 2016, the Company’s shareholders approved an amendment to the Company's Articles of Incorporation to increase the number of authorized shares of common stock by 50% , from 95,000,000 to 142,500,000 . As a result, 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 $.001 per share, and 5,000,000 shares of preferred stock, par value $.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 during the nine months ended September 30, 2016 and the year ended December 31, 2015 : Nine Months Ended September 30, 2016 Year Ended December 31, 2015 Beginning Balance 63,120,384 61,066,712 Restricted Stock Grants (Note 6) 1,846,777 2,112,998 Other Surrenders (342,648 ) (57,929 ) Other (1,594,542 ) (1,397 ) Ending Balance 63,029,971 63,120,384 2016 Activity During the nine months ended September 30, 2016 , 342,648 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 $1.3 million , which is based on the market prices on the dates the shares were surrendered. On August 15, 2016, 1,530,796 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 . 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. During the three and nine months ended September 30, 2016 and September 30, 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	9 Months Ended
	Sep. 30, 2016
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. In May 2016, the Company’s shareholders approved an amendment to the 2013 Plan to increase the number of shares available for awards under the 2013 Plan by 1.6 million shares. As of September 30, 2016 , there were 3,479,245 shares available for future awards under the 2013 Plan. Restricted Stock Awards During the nine months ended September 30, 2016 , the Company issued 1,846,777 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 March 2019. As of September 30, 2016 , there was approximately $5.1 million of total unrecognized compensation expense related to unvested restricted stock that will be recognized over a weighted-average period of approximately 2.3 years. The Company has assumed a zero percent forfeiture rate 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 nine months ended September 30, 2016 : Nine Months Ended Number of Shares Weighted-Average Price Restricted Stock Awards: Restricted Shares Outstanding at Beginning of Period 2,365,396 $ 7.15 Shares Granted 1,846,777 4.03 Lapse of Restrictions (827,014 ) 7.56 Shares Forfeited (1,594,542 ) 4.67 Restricted Shares Outstanding at End of Period 1,790,617 $ 5.03 Stock Option Awards 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 nine months ended September 30, 2016 . Stock Option Awards Weighted-Average Exercise Price Weighted Average Contractual Term Outstanding as of December 31, 2015 141,872 $ 5.18 1.8 Granted 250,000 2.79 Exercised — — Expired or canceled — — Forfeited — — Outstanding as of September 30, 2016 (1) 391,872 $ 3.66 3.2 ____________ (1) All of the stock options outstanding were vested and exercisable at the end of the period. The Company used 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. The Company used the simplified method to determine the expected term of the options due to the lack of sufficient historical data. Changes in these assumptions can materially affect the fair value estimate. The total fair value of the options is recognized as compensation over the vesting period. The assumptions used to estimate the fair value of stock option awards granted are as follows: February 12, 2016 Risk-free interest rate 1.15 % Expected term 5.0 Expected volatility 61.89 % Fair value per option $ 1.47 Performance Equity Awards The Company has granted performance equity awards under its 2016 Long Term Incentive Program to certain officers. The awards are subject to a market condition, which is based on a comparison of the Company versus a defined peer group with respect to year-over-year change in average stock price from 2015 to 2016. Depending on the Company’s stock price performance relative to the defined peer group, the award recipients will earn between 0% and 150% of their 2016 base salaries in the form of awards 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 2017. 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 relative 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 actuals for the three months ended March 31, 2016 and a forecast period for the remaining nine months of 2016 , a risk-free interest rate of 0.49% and 83.3% for Northern’s stock price volatility. The maximum value of the awards issuable if all participants earned the maximum award would total $1.7 million . For the three and nine months ended September 30, 2016 and 2015 , the Company recorded $0.0 million and $0.2 million , respectively, and $0.2 million and $0.3 million , respectively, of compensation expense in connection with these performance awards.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	9 Months Ended
	Sep. 30, 2016
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. 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 of the Notes at September 30, 2016. 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	9 Months Ended
	Sep. 30, 2016
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 $6.8 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 $6.8 million in accounts receivable is included in “Other Noncurrent Assets, Net” on the condensed 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. Mr. Reger's complaint alleges that the Company breached his employment agreement by, among other things, purporting to terminate him for cause, removing him from the Company's board of directors based on such termination, and denying him payments and other benefits to which he alleges that he is entitled under the employment agreement (including payments and benefits in connection with a termination without cause). Mr. Reger is seeking unspecified damages, an order reinstating him to the Company's board of directors, and other equitable relief. Among other damages that Mr. Reger may seek, including damages for defamation, the Company expects him to seek benefits to which he alleges he should have been entitled for a termination without cause, which may have included at least $1.6 million in cash severance and the immediate vesting of 1,530,796 shares of restricted stock held by Mr. Reger at the time of his termination. 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 our Company, Michael Reger (our former chief executive officer), and Thomas Stoelk (our chief financial officer and interim chief executive officer) as defendants. The complaint purports to bring a federal securities class action on behalf of the 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 federal securities laws and to pursue remedies under Sections 10(a) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder.

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates . A valuation allowance for the Company’s deferred tax assets is established if, in management’s opinion, it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. At September 30, 2016 , a valuation allowance of $336.3 million had been provided for our net deferred tax assets based on the uncertainty regarding whether these assets may be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. The income tax provision (benefit) for the three and nine months ended September 30, 2016 and 2015 consists of the following: Three Months Ended Nine Months Ended 2016 2015 2016 2015 Current Income Tax Benefit $ — $ (77,544 ) $ — $ (73,599 ) Deferred Income Tax Benefit Federal (16,252,000 ) (116,171,555 ) (95,001,000 ) (360,106,555 ) State (1,466,000 ) (3,964,000 ) (9,005,000 ) (12,287,000 ) Valuation Allowance 17,718,000 120,135,555 104,006,000 170,043,000 Total Income Tax Benefit $ — $ (77,544 ) $ — $ (202,424,154 ) Income tax provision (benefit) during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income (loss), plus any unusual or infrequently occurring items that are recorded in the interim period. The provision for the three and nine month periods ended September 30, 2016 , presented above, differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to income before income taxes. The lower effective tax rate in 2016 relates to the valuation allowance placed on the net deferred tax assets in the second quarter of 2015 , in addition to state income taxes and estimated permanent differences. The higher effective tax rate in 2015 relates to the addition of state income taxes and estimated permanent differences. 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 nine months ended September 30, 2016 and 2015 , the Company did not recognize any interest or penalties in its condensed statements of operations, nor did it have any interest or penalties accrued in its condensed balance sheet at September 30, 2016 and December 31, 2015 relating to unrecognized benefits. The tax years 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.

FAIR VALUE

FAIR VALUE	9 Months Ended
	Sep. 30, 2016
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: Fair Value Measurements at September 30, 2016 Using Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Asset (crude oil swaps and swaptions) $ — $ 7,212,947 $ — Commodity Derivatives – Non-Current Asset (crude oil swaps) — 20,166 — Commodity Derivatives – Current Liability (crude oil swaps) — (707,703 ) — Commodity Derivatives – Non-Current Liability (crude oil swaps) (49,153 ) Total $ — $ 6,476,257 $ — Fair Value Measurements at December 31, 2015 Using Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives – Current Asset (crude oil swaps) $ — $ 64,611,558 $ — The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include crude oil swaps (see Note 11). 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 condensed 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 condensed balance sheet at September 30, 2016 is $807.8 million , which includes $687.8 million of senior unsecured notes including a net discount of $1.8 million and $120.0 million of borrowings under the Company’s revolving credit facility (see Note 4). The fair value of the Company’s senior unsecured notes, which are publicly traded, is $532.8 million at September 30, 2016 . The Company’s revolving credit facility 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 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 during the nine months ended September 30, 2016 were approximately $0.2 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 nine months ended September 30, 2016 .

DERIVATIVE INSTRUMENTS AND PRIC

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT	9 Months Ended
	Sep. 30, 2016
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 10). 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 condensed 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. Three Months Ended Nine Months Ended 2016 2015 2016 2015 Cash Received on Derivatives (1) $ 9,027,150 $ 42,958,080 $ 54,457,800 $ 113,934,910 Non-Cash Gain (Loss) on Derivatives (5,645,586 ) 8,408,682 (58,135,302 ) (59,115,913 ) Gain (Loss) on Derivative Instruments, Net $ 3,381,564 $ 51,366,762 $ (3,677,502 ) $ 54,818,997 ___________________ (1) Net cash receipts for crude oil collars for the nine month periods ended September 30, 2015 include approximately $202,000 of proceeds received from crude oil derivative contracts that were settled in the second quarter of 2015 prior to their contractual maturities. The Company has master netting agreements on individual crude oil contracts with certain counterparties and therefore the current asset and liability are netted on the balance sheet and the non-current asset and liability are netted on the balance sheet for contracts with these counterparties. The following table reflects open commodity swap contracts as of September 30, 2016 , the associated volumes and the corresponding fixed price. Settlement Period Oil (Barrels) Fixed Price ($) Swaps-Crude Oil 10/01/16 – 12/31/16 90,000 65.00 10/01/16 – 12/31/16 90,000 64.93 10/01/16 – 12/31/16 45,000 65.00 10/01/16 – 12/31/16 90,000 65.00 10/01/16 – 12/31/16 90,000 64.93 10/01/16 – 12/31/16 45,000 65.30 01/01/17 – 06/30/17 360,000 50.00 01/01/17 – 06/30/17 180,000 50.01 01/01/17 – 06/30/17 180,000 49.99 01/01/17 – 06/30/17 (1) 60,000 55.20 07/01/17 – 12/31/17 240,000 52.75 07/01/17 – 12/31/17 120,000 51.75 (1) The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 10,000 barrels per month are exercisable on or about June 30, 2017. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 10,000 barrels per month at an average price of $55.20 per barrel for each month during the period July 1, 2017 through December 31, 2017. The following table reflects the weighted average price of open commodity swap derivative contracts as of September 30, 2016 , by year with associated volumes. Year Volumes (Bbl) Weighted Average Price ($) 2016 450,000 65.00 2017 1,140,000 51.04 2018 and beyond — — The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at September 30, 2016 and December 31, 2015 , respectively. Certain amounts may be presented on a net basis on the condensed financial statements when such amounts are with the same counterparty and subject to a master netting arrangement: Type of Crude Oil Contract Balance Sheet Location September 30, 2016 Estimated Fair Value December 31, 2015 Estimated Fair Value Derivative Assets: Swap and Swaption Contracts Current Assets $ 7,212,947 $ 64,611,558 Swap Contracts Non-Current Assets 20,166 — Total Derivative Assets $ 7,233,113 $ 64,611,558 Derivative Liabilities: Swap Contracts Current Liabilities $ (707,703 ) $ — Swap Contracts Non-Current Liabilities (49,153 ) — Total Derivative Liabilities $ (756,856 ) $ — 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 September 30, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 7,528,105 $ (315,158 ) $ 7,212,947 Non-Current Assets 20,166 — 20,166 Total Derivative Assets $ 7,548,271 $ (315,158 ) $ 7,233,113 Offsetting of Derivative Liabilities: Current Liabilities $ (1,022,861 ) $ 315,158 $ (707,703 ) Non-Current Liabilities (49,153 ) — (49,153 ) Total Derivative Liabilities $ (1,072,014 ) $ 315,158 $ (756,856 ) Estimated Fair Value at December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 64,611,558 $ — $ 64,611,558 All of the Company’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDAs”) entered into with counterparties that are also lenders under the Company’s Revolving Credit Facility. The Company’s obligations under the derivative instruments are secured pursuant to the Revolving Credit Facility, and no additional collateral had been posted by the Company as of September 30, 2016 . 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 10 for the aggregate fair value of all derivative instruments that were in a net liability position at September 30, 2016 and December 31, 2015 .

RESTRUCTURING COSTS

RESTRUCTURING COSTS	9 Months Ended
	Sep. 30, 2016
Restructuring and Related Activities [Abstract]
RESTRUCTURING COSTS	RESTRUCTURING COSTS In September 2015, we restructured certain of our operations in response to the current oil and gas commodity environment. These changes, which included a reduction in workforce, are expected to result in better utilization of our resources and improved cost efficiencies. At September 30, 2016 , there were no unpaid restructuring costs. Type of Location in the Three Months Ended Nine Months Ended September 30, 2016 2015 2016 2015 Severance and Benefit Costs Operating Expenses – General and Administrative $ — $ 523,487 $ — $ 523,487 The following table summarizes our restructuring costs: Restructuring Liability at January 1, 2016 $ 32,493 Additions — Settlements (32,493 ) Revisions — Restructuring Liability at September 30, 2016 $ —

SIGNIFICANT ACCOUNTING POLICI19

SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2016
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 condensed 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 condensed balance sheets. As of September 30, 2016 and December 31, 2015 , the Company included accounts receivable of $6.8 million in Other Noncurrent Assets, Net due to their long-term nature. The allowance for doubtful accounts at September 30, 2016 and December 31, 2015 was $4.9 million and $4.5 million , respectively.
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. Depreciation expense was $50,652 and $74,469 for the three months ended September 30, 2016 and 2015 , respectively. Depreciation expense was $155,813 and $229,694 for the nine months ended September 30, 2016 and 2015 , respectively.
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 three and nine months ended September 30, 2016 and 2015 , respectively. Three Months Ended Nine Months Ended 2016 2015 2016 2015 Capitalized Certain Payroll and Other Internal Costs $ 239,132 $ 520,046 $ 1,674,015 $ 1,500,734 Capitalized Interest Costs 79,805 311,739 289,409 1,270,420 Total $ 318,937 $ 831,785 $ 1,963,424 $ 2,771,154 As of September 30, 2016 , 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. There were no property sales in the nine months ended September 30, 2016 and 2015 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. As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties, the Company recorded non-cash ceiling test impairments for the three months ended September 30, 2016 and 2015 of $43.8 million and $354.4 million , respectively. The Company recorded non-cash ceiling test impairments for the nine months ended September 30, 2016 and 2015 of $237.0 million and $996.8 million , respectively. The impairment charges affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have stabilized or recovered long enough to stabilize or increase the trailing twelve-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our 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 three months ended September 30, 2016 and 2015 , the Company transferred into the full cost pool costs related to expired leases of $5.2 million and $6.4 million , respectively. For the nine months ended September 30, 2016 and 2015 , the Company transferred into the full cost pool costs related to expired leases of $10.5 million and $15.3 million , respectively.
Asset Retirement Obligations	Asset Retirement Obligations The Company accounts for its abandonment and restoration liabilities under the 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.
Debt Issuance Costs	Debt Issuance Costs Deferred financing costs include origination, legal and other fees to issue debt in connection with the Company’s credit facility and senior unsecured notes. These debt issuance costs are being 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 three months ended September 30, 2016 and 2015 was $0.9 million and $1.0 million , respectively. The amortization of debt issuance costs for the nine months ended September 30, 2016 and 2015 was $2.9 million and $2.7 million , respectively. During the three and nine months ended September 30, 2016 , $0 and $1.1 million , respectively, of debt issuance costs were written-off as a result of a reduction in the borrowing base of the Revolving Credit Facility, which became effective in May 2016 and was due to the impact that lower commodity prices had on our oil and gas reserve valuation. There were no debt issuance costs written-off during the three and nine months ended September 30, 2015 . As a result of the adoption of ASU No. 2015-03 , “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”), the Company reclassified unamortized debt issuance costs associated with its 8% Senior Notes, which totaled $12.5 million as of December 31, 2015 , from "Debt Issuance Costs, Net" to a reduction of "Long-term Debt" on the balance sheets. Adoption of ASU 2015-03 had no impact on the Company's current and previously reported stockholders' deficit, results of operations, or cash flows. Unamortized debt issuance costs associated with the Company's revolving credit facility, which amounted to $1.9 million and $3.3 million as of September 30, 2016 and December 31, 2015 , respectively, were not reclassified and remain reflected in "Other Noncurrent Assets, Net" on the condensed balance sheets.
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 for the three and nine months ended September 30, 2016 and 2015 was $0.4 million and $1.1 million in each period. 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 three months ended September 30, 2016 and 2015 was $0.5 million and $0.5 million , respectively. The amortization of the bond discount for the nine months ended September 30, 2016 and 2015 was $1.5 million and $0.7 million , respectively.
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. For the three and nine months ended September 30, 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 customers 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. During the three and nine months ended September 30, 2015, we 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 our Denver office, which includes $0.1 million of non-cash expense related to acceleration of certain equity awards previously granted under our 2013 Incentive Plan.
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. 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 the 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 September 30, 2016 , 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 September 30, 2016 , 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 September 30, 2016 and December 31, 2015 was $336.3 million and $232.3 million , respectively.
Net Income (Loss) Per Common Share	Net Income (Loss) Per Common Share Basic earnings per share (“EPS”) are computed by dividing net income (loss) (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income (loss) 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 three and nine months ended September 30, 2016 and 2015 are as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 Weighted Average Common Shares Outstanding – Basic 61,237,627 60,679,257 61,127,577 60,627,142 Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock — — — — Weighted Average Common Shares Outstanding – Diluted 61,237,627 60,679,257 61,127,577 60,627,142 Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect 574,862 150,428 885,200 173,763
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 has, and may continue to 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 condensed statements of operations. See Note 11 for a description of the derivative contracts into which the Company has entered.
New Accounting Pronouncements	New Accounting Pronouncements From time to time, new accounting pronouncements are issued by 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 August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) . The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period beginning after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU 2014-09 for all entities by one year. This update is effective for public business entities for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements. In February 2016, the FASB issued ASU 2016-02, Leases , which introduces the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous guidance. The guidance will be effective for annual reporting periods beginning after December 15, 2018 and interim periods within those fiscal years with early adoption permitted. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements. In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation: Improvements to Employee Share-Based Payment Accounting, which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. This standard will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company is evaluating the impact of the future adoption of this standard on its condensed financial statements.

SIGNIFICANT ACCOUNTING POLICI20

SIGNIFICANT ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Capitalized costs related to the exploration and development of crude oil and natural gas properties	Capitalized costs are summarized as follows for the three and nine months ended September 30, 2016 and 2015 , respectively. Three Months Ended Nine Months Ended 2016 2015 2016 2015 Capitalized Certain Payroll and Other Internal Costs $ 239,132 $ 520,046 $ 1,674,015 $ 1,500,734 Capitalized Interest Costs 79,805 311,739 289,409 1,270,420 Total $ 318,937 $ 831,785 $ 1,963,424 $ 2,771,154
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 three and nine months ended September 30, 2016 and 2015 are as follows: Three Months Ended Nine Months Ended 2016 2015 2016 2015 Weighted Average Common Shares Outstanding – Basic 61,237,627 60,679,257 61,127,577 60,627,142 Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock — — — — Weighted Average Common Shares Outstanding – Diluted 61,237,627 60,679,257 61,127,577 60,627,142 Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect 574,862 150,428 885,200 173,763

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company's long-term debt consists of the following: September 30, 2016 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 698,178,106 $ (10,389,396 ) $ 687,788,710 Revolving Credit Facility (1) 120,000,000 — 120,000,000 Total $ 818,178,106 $ (10,389,396 ) $ 807,788,710 December 31, 2015 Long-term Debt Debt Issuance Costs, Net Long-term Debt, Net 8% Senior Notes $ 697,804,829 $ (12,514,500 ) $ 685,290,329 Revolving Credit Facility (1) 150,000,000 — 150,000,000 Total $ 847,804,829 $ (12,514,500 ) $ 835,290,329 _____________ (1) Debt issuance costs related to our revolving credit facility are recorded in "Other Noncurrent Assets, Net" on the condensed balance sheets
Schedule of Debt Covenants	The schedule of the minimum ratio of EBITDAX to interest expense the Company is required to maintain is as follows: Measurement Period Minimum ratio of EBITDAX to Interest Expense 12 months ending December 31, 2016 1.75 to 1.00 12 months ending March 31, 2017 1.50 to 1.00 12 months ending June 30, 2017 1.25 to 1.00 12 months ending September 30, 2017 1.25 to 1.00 12 months ending December 31, 2017 1.00 to 1.00 12 months ending March 31, 2018 1.00 to 1.00 12 months ending June 30, 2018 and beyond 2.50 to 1.00

COMMON AND PREFERRED STOCK (Tab

COMMON AND PREFERRED STOCK (Tables)	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Schedule of changes in the number of shares of common stock outstanding	The following is a schedule of changes in the number of shares of common stock outstanding during the nine months ended September 30, 2016 and the year ended December 31, 2015 : Nine Months Ended September 30, 2016 Year Ended December 31, 2015 Beginning Balance 63,120,384 61,066,712 Restricted Stock Grants (Note 6) 1,846,777 2,112,998 Other Surrenders (342,648 ) (57,929 ) Other (1,594,542 ) (1,397 ) Ending Balance 63,029,971 63,120,384

STOCK OPTIONS_STOCK-BASED COM23

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Tables)	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Outstanding restricted stock awards and activity	The following table reflects the outstanding restricted stock awards and activity related thereto for the nine months ended September 30, 2016 : Nine Months Ended Number of Shares Weighted-Average Price Restricted Stock Awards: Restricted Shares Outstanding at Beginning of Period 2,365,396 $ 7.15 Shares Granted 1,846,777 4.03 Lapse of Restrictions (827,014 ) 7.56 Shares Forfeited (1,594,542 ) 4.67 Restricted Shares Outstanding at End of Period 1,790,617 $ 5.03
Outstanding stock option activity	Stock Option Awards Weighted-Average Exercise Price Weighted Average Contractual Term Outstanding as of December 31, 2015 141,872 $ 5.18 1.8 Granted 250,000 2.79 Exercised — — Expired or canceled — — Forfeited — — Outstanding as of September 30, 2016 (1) 391,872 $ 3.66 3.2 ____________ (1) All of the stock options outstanding were vested and exercisable at the end of the period.
Stock option valuation assumptions	The assumptions used to estimate the fair value of stock option awards granted are as follows: February 12, 2016 Risk-free interest rate 1.15 % Expected term 5.0 Expected volatility 61.89 % Fair value per option $ 1.47

INCOME TAXES (Tables)

INCOME TAXES (Tables)	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income tax provision (benefit)	The income tax provision (benefit) for the three and nine months ended September 30, 2016 and 2015 consists of the following: Three Months Ended Nine Months Ended 2016 2015 2016 2015 Current Income Tax Benefit $ — $ (77,544 ) $ — $ (73,599 ) Deferred Income Tax Benefit Federal (16,252,000 ) (116,171,555 ) (95,001,000 ) (360,106,555 ) State (1,466,000 ) (3,964,000 ) (9,005,000 ) (12,287,000 ) Valuation Allowance 17,718,000 120,135,555 104,006,000 170,043,000 Total Income Tax Benefit $ — $ (77,544 ) $ — $ (202,424,154 )

FAIR VALUE (Tables)

FAIR VALUE (Tables)	9 Months Ended
	Sep. 30, 2016
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: Fair Value Measurements at September 30, 2016 Using Quoted Prices In Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity Derivatives – Current Asset (crude oil swaps and swaptions) $ — $ 7,212,947 $ — Commodity Derivatives – Non-Current Asset (crude oil swaps) — 20,166 — Commodity Derivatives – Current Liability (crude oil swaps) — (707,703 ) — Commodity Derivatives – Non-Current Liability (crude oil swaps) (49,153 ) Total $ — $ 6,476,257 $ — Fair Value Measurements at December 31, 2015 Using Quoted Prices In Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity Derivatives – Current Asset (crude oil swaps) $ — $ 64,611,558 $ —

DERIVATIVE INSTRUMENTS AND PR26

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables)	9 Months Ended
	Sep. 30, 2016
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. Three Months Ended Nine Months Ended 2016 2015 2016 2015 Cash Received on Derivatives (1) $ 9,027,150 $ 42,958,080 $ 54,457,800 $ 113,934,910 Non-Cash Gain (Loss) on Derivatives (5,645,586 ) 8,408,682 (58,135,302 ) (59,115,913 ) Gain (Loss) on Derivative Instruments, Net $ 3,381,564 $ 51,366,762 $ (3,677,502 ) $ 54,818,997 ___________________ (1) Net cash receipts for crude oil collars for the nine month periods ended September 30, 2015 include approximately $202,000 of proceeds received from crude oil derivative contracts that were settled in the second quarter of 2015 prior to their contractual maturities.
Open commodity swap contracts	The following table reflects open commodity swap contracts as of September 30, 2016 , the associated volumes and the corresponding fixed price. Settlement Period Oil (Barrels) Fixed Price ($) Swaps-Crude Oil 10/01/16 – 12/31/16 90,000 65.00 10/01/16 – 12/31/16 90,000 64.93 10/01/16 – 12/31/16 45,000 65.00 10/01/16 – 12/31/16 90,000 65.00 10/01/16 – 12/31/16 90,000 64.93 10/01/16 – 12/31/16 45,000 65.30 01/01/17 – 06/30/17 360,000 50.00 01/01/17 – 06/30/17 180,000 50.01 01/01/17 – 06/30/17 180,000 49.99 01/01/17 – 06/30/17 (1) 60,000 55.20 07/01/17 – 12/31/17 240,000 52.75 07/01/17 – 12/31/17 120,000 51.75 (1) The Company has entered into crude oil derivative contracts that give counterparties the option to extend certain current derivative contracts for an additional six-month period. Options covering a notional volume of 10,000 barrels per month are exercisable on or about June 30, 2017. If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 10,000 barrels per month at an average price of $55.20 per barrel for each month during the period July 1, 2017 through December 31, 2017.
Schedule of weighted average price of open commodity derivative contracts	The following table reflects the weighted average price of open commodity swap derivative contracts as of September 30, 2016 , by year with associated volumes. Year Volumes (Bbl) Weighted Average Price ($) 2016 450,000 65.00 2017 1,140,000 51.04 2018 and beyond — —
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 September 30, 2016 and December 31, 2015 , respectively. Certain amounts may be presented on a net basis on the condensed financial statements when such amounts are with the same counterparty and subject to a master netting arrangement: Type of Crude Oil Contract Balance Sheet Location September 30, 2016 Estimated Fair Value December 31, 2015 Estimated Fair Value Derivative Assets: Swap and Swaption Contracts Current Assets $ 7,212,947 $ 64,611,558 Swap Contracts Non-Current Assets 20,166 — Total Derivative Assets $ 7,233,113 $ 64,611,558 Derivative Liabilities: Swap Contracts Current Liabilities $ (707,703 ) $ — Swap Contracts Non-Current Liabilities (49,153 ) — Total Derivative Liabilities $ (756,856 ) $ —
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 September 30, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 7,528,105 $ (315,158 ) $ 7,212,947 Non-Current Assets 20,166 — 20,166 Total Derivative Assets $ 7,548,271 $ (315,158 ) $ 7,233,113 Offsetting of Derivative Liabilities: Current Liabilities $ (1,022,861 ) $ 315,158 $ (707,703 ) Non-Current Liabilities (49,153 ) — (49,153 ) Total Derivative Liabilities $ (1,072,014 ) $ 315,158 $ (756,856 ) Estimated Fair Value at December 31, 2015 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Offsetting of Derivative Assets: Current Assets $ 64,611,558 $ — $ 64,611,558

RESTRUCTURING COSTS (Tables)

RESTRUCTURING COSTS (Tables)	9 Months Ended
	Sep. 30, 2016
Restructuring and Related Activities [Abstract]
Restructuring and Related Costs	The following table summarizes our restructuring costs: Restructuring Liability at January 1, 2016 $ 32,493 Additions — Settlements (32,493 ) Revisions — Restructuring Liability at September 30, 2016 $ — At September 30, 2016 , there were no unpaid restructuring costs. Type of Location in the Three Months Ended Nine Months Ended September 30, 2016 2015 2016 2015 Severance and Benefit Costs Operating Expenses – General and Administrative $ — $ 523,487 $ — $ 523,487

ORGANIZATION AND NATURE OF BU28

ORGANIZATION AND NATURE OF BUSINESS (Details)	9 Months Ended
	Sep. 30, 2016a
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Percentage of mineral rights developed	77.00%
Gas and oil acreage net mineral rights (in acres)	156,074

SIGNIFICANT ACCOUNTING POLICI29

SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	May 18, 2015	May 13, 2013
Cash and Cash Equivalents [Abstract]
Threshold amount of FDIC coverage	$ 250,000		$ 250,000
Accounts Receivable, Net [Abstract]
Allowance for doubtful accounts	4,900,000		$ 4,900,000		$ 4,500,000
Advance to Operators [Abstract]
Period for advance payments to be applied against joint interest billings			90 days
Property, Plant and Equipment [Abstract]
Depreciation expense	50,652	$ 74,469	$ 155,813	$ 229,694
Debt Issuance Costs [Abstract]
Amortization of debt issuance costs	900,000	1,000,000	2,879,164	2,674,927
Write-off of Debt Issuance Costs	$ 0	0	$ 1,089,507	0
Bond Premium/Discount on Senior Notes [Abstract]
Rate of Senior notes	8.00%		8.00%		8.00%
Income Taxes [Abstract]
Valuation allowance	$ 336,300,000		$ 336,300,000		$ 232,300,000
Employee Severance and Related Benefit Costs [Member]
Restructuring Costs [Abstract]
Restructuring costs		500,000		500,000
Senior Notes Due 2020 [Member]
Bond Premium/Discount on Senior Notes [Abstract]
Amortization of bond premium	400,000	400,000	1,100,000	1,100,000
Amortization of bond discount	$ 500,000	500,000	$ 1,500,000	700,000
Senior Unsecured Notes [Member]
Bond Premium/Discount on Senior Notes [Abstract]
Rate of Senior notes	8.00%		8.00%
Senior Unsecured Notes [Member] | Senior Notes Due 2020 [Member]
Debt Issuance Costs [Abstract]
Increase (decrease) of unamortized debt issuance costs						$ 10,000,000	$ 10,500,000
Bond Premium/Discount on Senior Notes [Abstract]
Capitalized costs associated with bond premium/discount						$ 10,000,000	$ 10,500,000
Rate of Senior notes						8.00%	8.00%
Minimum [Member]
Property, Plant and Equipment [Abstract]
Property and equipment, estimated useful lives			3 years
Maximum [Member]
Property, Plant and Equipment [Abstract]
Property and equipment, estimated useful lives			7 years
Other Noncurrent Assets, Net [Member]
Accounts Receivable, Net [Abstract]
Accounts receivable	$ 6,800,000		$ 6,800,000		6,800,000
Other Noncurrent Assets, Net [Member] | Revolving Credit Facility [Member]
Debt Issuance Costs [Abstract]
Increase (decrease) of unamortized debt issuance costs	1,900,000		1,900,000		3,300,000
Bond Premium/Discount on Senior Notes [Abstract]
Capitalized costs associated with bond premium/discount	$ 1,900,000		$ 1,900,000		3,300,000
Debt Issuance Costs, Net [Member]
Debt Issuance Costs [Abstract]
Increase (decrease) of unamortized debt issuance costs					(12,500,000)
Bond Premium/Discount on Senior Notes [Abstract]
Capitalized costs associated with bond premium/discount					(12,500,000)
Long-term Debt [Member]
Debt Issuance Costs [Abstract]
Increase (decrease) of unamortized debt issuance costs					12,500,000
Bond Premium/Discount on Senior Notes [Abstract]
Capitalized costs associated with bond premium/discount					$ 12,500,000
2013 Equity Incentive Plan [Member]
Restructuring Costs [Abstract]
Non-cash expense related to acceleration of certain equity awards previously granted		$ 100,000		$ 100,000

SIGNIFICANT ACCOUNTING POLICI30

SIGNIFICANT ACCOUNTING POLICIES - Capitalized Costs (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Full Cost Method [Abstract]
Capitalized Certain Payroll and Other Internal Costs	$ 239,132	$ 520,046	$ 1,674,015	$ 1,500,734
Capitalized Interest Costs	79,805	311,739	289,409	1,270,420
Total	318,937	831,785	$ 1,963,424	2,771,154
Minimum percentage of proved reserves sold to be considered a significant alteration			25.00%
Discount rate			10.00%
Impairment of Oil and Natural Gas Properties	43,820,791	354,422,654	$ 237,012,834	996,815,713
Capitalized costs related to expired leases subject to depletion	$ 5,200,000	$ 6,400,000	$ 10,500,000	$ 15,300,000

SIGNIFICANT ACCOUNTING POLICI31

SIGNIFICANT ACCOUNTING POLICIES - Reconciliation of EPS (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accounting Policies [Abstract]
Weighted Average Common Shares Outstanding - Basic (in shares)	61,237,627	60,679,257	61,127,577	60,627,142
Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock (in shares)	0	0	0	0
Weighted Average Common Shares Outstanding - Diluted (in shares)	61,237,627	60,679,257	61,127,577	60,627,142
Restricted Stock and Stock Options Excluded From EPS Due To The Anti-Dilutive Effect (in shares)	574,862	150,428	885,200	173,763

CRUDE OIL AND NATURAL GAS PRO32

CRUDE OIL AND NATURAL GAS PROPERTIES (Details) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2016USD ($)a$ / a	Sep. 30, 2015USD ($)a$ / a	Dec. 31, 2015USD ($)a
Acquisitions [Abstract]
Capital expenditures incurred but not yet paid | $	$ 42.8		$ 59.5
Mineral acres acquired, net (in acres) | a	1,645	3,157
Average acquisition cost per net acre (in dollars per acre) | $ / a	2,965	1,065
Unproved Properties [Abstract]
Unproven leasehold interests (in acres) | a	28,858		38,003
Anticipated future period over which excluded costs will become subject to depletion (in years)	5 years
Impairment costs related to expired leases subject to depletion | $	$ 6.4	$ 32.4

LONG-TERM DEBT - Schedule of Lo

LONG-TERM DEBT - Schedule of Long Term Debt (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt	$ 818,178,106	$ 847,804,829
Debt Issuance Costs, Net	(10,389,396)	(12,514,500)
Long-term Debt, Net	807,788,710	835,290,329
Senior Notes [Member] | 8% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt	698,178,106	697,804,829
Debt Issuance Costs, Net	(10,389,396)	(12,514,500)
Long-term Debt, Net	687,788,710	685,290,329
Line of Credit [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt	120,000,000	150,000,000
Debt Issuance Costs, Net	0	0
Long-term Debt, Net	$ 120,000,000	$ 150,000,000

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details)	3 Months Ended	9 Months Ended
	Dec. 31, 2016	Sep. 30, 2016USD ($)	Dec. 31, 2015	May 18, 2015USD ($)	May 13, 2013USD ($)	May 18, 2012USD ($)
Line of Credit Facility [Line Items]
Rate of senior unsecured notes		8.00%	8.00%
8% Senior Notes Due 2020 [Member]
Line of Credit Facility [Line Items]
Rate of senior unsecured notes		8.00%
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 (in days)		60 days
8% Senior Notes Due 2020 [Member] | The "2015 Mirror Notes" [Member]
Line of Credit Facility [Line Items]
Rate of senior unsecured notes				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
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
Rate of senior unsecured notes						8.00%
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]
Rate of senior unsecured notes					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
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing		750,000,000
Borrowing base		350,000,000
Borrowings under Credit Facility		120,000,000
Remaining borrowing capacity of Credit Facility		$ 230,000,000
Revolving credit facility, maturity date		Sep. 30, 2018
Loans issued under revolving credit facility		$ 120,000,000
Weighted average interest rate		2.78%
Line of credit facility covenant terms current ratio		1
Line of credit facility ratio of debt to EBITDAX		2.5
Line of credit facility ratio of EBITDAX to interest expense		2.5
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 Loans [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		2.25%
Commitment fee percentage		0.375%
Revolving Credit Facility [Member] | LIBOR Loans [Member] | Forecast [Member]
Line of Credit Facility [Line Items]
Increase in variable basis spread percentage	0.50%
Revolving Credit Facility [Member] | LIBOR Loans [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		2.00%
Revolving Credit Facility [Member] | LIBOR Loans [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 Loans [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		1.25%
Revolving Credit Facility [Member] | Alternate Base Rate Loans [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 Loans [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period		2.00%

LONG-TERM DEBT - Debt Covenant

LONG-TERM DEBT - Debt Covenant (Details) - Revolving Credit Facility [Member]	Sep. 30, 2016
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	2.5
Measurement Period 1 [Member]
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	1.75
Measurement Period 2 [Member]
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	1.50
Measurement Period 3 [Member]
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	1.25
Measurement Period 4 [Member]
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	1.25
Measurement Period 5 [Member]
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	1
Measurement Period 6 [Member]
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	1
Measurement Period 7 [Member]
Debt Instrument [Line Items]
Line of credit facility ratio of EBITDAX to interest expense	2.50

COMMON AND PREFERRED STOCK (Det

COMMON AND PREFERRED STOCK (Details) $ / shares in Units, $ in Millions	Aug. 15, 2016USD ($)shares	May 31, 2016shares	Sep. 30, 2016USD ($)Class$ / sharesshares	Dec. 31, 2015$ / sharesshares	May 31, 2011USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage increase of authorized shares		50.00%
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
Stock Activity [Abstract]
Common stock surrendered by certain employees to cover tax obligations (in shares)			342,648
Fair value of common stock surrendered by certain employees to cover tax obligations | $			$ 1.3
Shares forfeited (in shares)			342,648	57,929
Stock Repurchase Program [Abstract]
Stock repurchase program, amount approved | $					$ 150
Common Stock [Member] | Chief Executive Officer [Member]
Stock Activity [Abstract]
Shares forfeited (in shares)	1,530,796
Share-based compensation expense reversed in connection with termination | $	$ 1.8

COMMON AND PREFERRED STOCK - Ch

COMMON AND PREFERRED STOCK - Changes in Equity (Details) - shares	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Changes in the number of shares of common stock outstanding [Roll forward]
Beginning Balance (in shares)	63,120,384	61,066,712
Restricted Stock Grants (in shares)	1,846,777	2,112,998
Other Surrenders (in shares)	(342,648)	(57,929)
Other (in shares)	(1,594,542)	(1,397)
Ending Balance (in shares)	63,029,971	63,120,384

STOCK OPTIONS_STOCK-BASED COM38

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 12, 2016	Jan. 31, 2016	Sep. 30, 2016	May 31, 2016
2013 Equity Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase in shares available for future issuance (in shares)				1,600,000
Shares available for future awards (in shares)			3,479,245
Restricted Stock Awards [Member]
Restricted Stock Awards [Abstract]
Unrecognized compensation expense			$ 5.1
Unrecognized compensation expense, recognized period			2 years 3 months 18 days
Percent of forfeiture rate assumed for restricted stock			0.00%
Stock Option Awards [Abstract]
Shares granted (in shares)			1,846,777
Stock Option Awards [Member] | 2013 Equity Incentive Plan [Member]
Stock Option Awards [Abstract]
Shares granted (in dollars per share)			$ 2.79
Share-based compensation expense			$ 0.4
Stock Option Awards [Member] | Directors [Member] | 2013 Equity Incentive Plan [Member]
Stock Option Awards [Abstract]
Shares granted (in shares)	250,000	250,000

STOCK OPTIONS_STOCK-BASED COM39

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Restricted Stock Awards (Details) - Restricted Stock [Member]	9 Months Ended
	Sep. 30, 2016$ / sharesshares
Number of Shares
Outstanding, beginning | shares	2,365,396
Shares Granted | shares	1,846,777
Lapse of Restrictions | shares	(827,014)
Shares Forfeited | shares	(1,594,542)
Outstanding, ending | shares	1,790,617
Weighted-Average Price
Outstanding, beginning (in dollars per share) | $ / shares	$ 7.15
Shares Granted (in dollars per share) | $ / shares	4.03
Lapse of Restrictions (in dollars per share) | $ / shares	7.56
Shares Forfeited (in dollars per share) | $ / shares	4.67
Outstanding, ending (in dollars per share) | $ / shares	$ 5.03

STOCK OPTIONS_STOCK-BASED COM40

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Stock Options Outstanding (Details) - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Stock Option Awards
Outstanding, beginning	141,872
Granted	250,000
Exercised	0
Expired or canceled	0
Forfeited	0
Outstanding, ending	391,872	141,872
Weighted-Average Exercise Price
Outstanding, beginning (in dollars per share)	$ 5.18
Granted (in dollars per share)	2.79
Exercised (in dollars per share)	0
Expired or canceled (in dollars per share)	0
Forfeited (in dollars per share)	0
Outstanding, ending (in dollars per share)	$ 3.66	$ 5.18
Weighted Average Contractual Term (in years)	3 years 2 months 12 days	1 year 9 months 18 days

STOCK OPTIONS_STOCK-BASED COM41

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Valuation Assumptions (Details) - Stock Option Awards [Member]	Feb. 12, 2016$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.15%
Expected term (in years)	5 years
Expected volatility	61.89%
Fair value per option (in dollars per share)	$ 1.47

STOCK OPTIONS_STOCK-BASED COM42

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS - Performance Equity Awards (Details) - Performance Equity Awards [Member] - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)				3 years
Maximum dollar amount of performance shares issuable	$ 1.7			$ 1.7
Share-based compensation expense	$ 0		$ 0.2	$ 0.2	$ 0.3
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants Earning Percentage	0.00%			0.00%
Risk-free interest rate		0.49%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Participants Earning Percentage	150.00%			150.00%
Risk-free interest rate		83.30%

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Rate of Senior notes	8.00%	8.00%
TRT and Affiliates [Member] | 8% Senior Unsecured Notes Due 2020 [Member]
Related Party Transaction [Line Items]
Notes payable to related parties	$ 200
Rate of Senior notes	8.00%

COMMITMENTS & CONTINGENCIES - L

COMMITMENTS & CONTINGENCIES - Litigation (Details) - USD ($) $ in Millions	Aug. 16, 2016	Aug. 15, 2016	Sep. 30, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Shares forfeited (in shares)			342,648	57,929
Quiet title action in North Dakota [Member]
Loss Contingencies [Line Items]
Possible revenue to be reversed due to pending litigation			$ 6.8
Quiet title action in North Dakota [Member] | Other Noncurrent Assets, Net [Member]
Loss Contingencies [Line Items]
Loss contingency accounts receivable			$ 6.8
Chief Executive Officer [Member] | Common Stock [Member]
Loss Contingencies [Line Items]
Shares forfeited (in shares)		1,530,796
Michael Reger [Member] | Chief Executive Officer [Member]
Loss Contingencies [Line Items]
Damages sought	$ 1.6

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Income tax provision [Abstract]
Current Income Tax Benefit	$ 0	$ (77,544)	$ 0	$ (73,599)
Deferred Income Tax Benefit
Federal	(16,252,000)	(116,171,555)	(95,001,000)	(360,106,555)
State	(1,466,000)	(3,964,000)	(9,005,000)	(12,287,000)
Valuation Allowance	17,718,000	120,135,555	104,006,000	170,043,000
Total Income Tax Benefit	0	$ (77,544)	0	$ (202,424,154)
Valuation allowance for net deferred tax assets	$ 336,300,000		$ 336,300,000		$ 232,300,000
Statutory U.S. federal income tax rate			35.00%
Minimum amount tax benefits likely realized upon settlement percentage	50.00%		50.00%
Unrecognized tax benefits	$ 0		$ 0

FAIR VALUE (Details)

FAIR VALUE (Details) - Fair Value, Measurements, Recurring [Member] - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Quoted Prices In Active Markets for Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivatives – Current Asset (crude oil swaps and swaptions)	$ 0	$ 0
Commodity Derivatives – Non-Current Asset (crude oil swaps)	0
Commodity Derivatives – Current Liability (crude oil swaps)	0
Total	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivatives – Current Asset (crude oil swaps and swaptions)	7,212,947	64,611,558
Commodity Derivatives – Non-Current Asset (crude oil swaps)	20,166
Commodity Derivatives – Current Liability (crude oil swaps)	(707,703)
Commodity Derivatives – Non-Current Liability (crude oil swaps)	(49,153)
Total	6,476,257
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivatives – Current Asset (crude oil swaps and swaptions)	0	$ 0
Commodity Derivatives – Non-Current Asset (crude oil swaps)	0
Commodity Derivatives – Current Liability (crude oil swaps)	0
Total	$ 0

FAIR VALUE - Fair Value of Othe

FAIR VALUE - Fair Value of Other Financial Instruments (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 807,788,710	$ 835,290,329
Debt instrument, unamortized discount	1,800,000
Asset retirement obligations	200,000
Transfers between Level 1, Level 2 or Level 3	0
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior unsecured notes	687,800,000
Revolving credit facility	120,000,000
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior unsecured notes	$ 532,800,000

DERIVATIVE INSTRUMENTS AND PR48

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Details)	Jun. 30, 2017bbl	Sep. 30, 2016USD ($)bbl$ / bbl	Sep. 30, 2015USD ($)	Dec. 31, 2017$ / bblbbl	Sep. 30, 2016USD ($)bbl$ / bbl	Sep. 30, 2015USD ($)
Non-cash gains or losses on derivative contracts [Abstract]
Cash Received on Derivatives | $		$ 9,027,150	$ 42,958,080		$ 54,457,800	$ 113,934,910
Non-Cash Gain (Loss) on Derivatives | $		(5,645,586)	8,408,682		(58,135,302)	(59,115,913)
Gain (Loss) on Derivative Instruments, Net | $		$ 3,381,564	$ 51,366,762		$ (3,677,502)	54,818,997
Crude Oil Commodity Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Proceeds from settled contracts | $						$ 202,000
Oil Swap 1 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					90,000
Fixed Price (in dollars per barrel) | $ / bbl		65			65
Oil Swap 2 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					90,000
Fixed Price (in dollars per barrel) | $ / bbl		64.93			64.93
Oil Swap 3 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					45,000
Fixed Price (in dollars per barrel) | $ / bbl		65			65
Oil Swap 4 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					90,000
Fixed Price (in dollars per barrel) | $ / bbl		65			65
Oil Swap 5 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					90,000
Fixed Price (in dollars per barrel) | $ / bbl		64.93			64.93
Oil Swap 6 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					45,000
Fixed Price (in dollars per barrel) | $ / bbl		65.30			65.30
Oil Swap 7 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					360,000
Fixed Price (in dollars per barrel) | $ / bbl		50			50
Oil Swap 8 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					180,000
Fixed Price (in dollars per barrel) | $ / bbl		50.01			50.01
Oil Swap 9 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					180,000
Fixed Price (in dollars per barrel) | $ / bbl		49.99			49.99
Oil Swap 10 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					60,000
Fixed Price (in dollars per barrel) | $ / bbl		55.20			55.20
Oil Swap 11 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					240,000
Fixed Price (in dollars per barrel) | $ / bbl		52.75			52.75
Oil Swap 12 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)					120,000
Fixed Price (in dollars per barrel) | $ / bbl		51.75			51.75
Open Commodity Swap 1 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes		450,000			450,000
Weighted Average Price (in dollars per barrel) | $ / bbl		65			65
Open Commodity Swap 2 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes		1,140,000			1,140,000
Weighted Average Price (in dollars per barrel) | $ / bbl		51.04			51.04
Open Commodity Swap 3 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes		0			0
Weighted Average Price (in dollars per barrel) | $ / bbl		0			0
Forecast [Member] | Oil Swap 10 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil exercisable upon extension (in barrels)	10,000
Additional oil (in barrels)				10,000
Average Fixed Price (in dollars per barrel) | $ / bbl				55.20

DERIVATIVE INSTRUMENTS AND PR49

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT - Reconciliation between the gross assets and liabilities and the amounts reflected on the balance sheet (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Offsetting Assets [Line Items]
Current assets	$ 7,212,947	$ 64,611,558
Noncurrent assets	20,166	0
Total derivative assets	7,233,113	64,611,558
Current liabilities	(707,703)	0
Noncurrent liabilities	49,153	0
Total derivative liabilities	756,856	0
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets	7,548,271
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	(315,158)
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	7,233,113
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities	(1,072,014)
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	315,158
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Liabilities	(756,856)
Current Assets [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets	7,528,105	64,611,558
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	(315,158)	0
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	7,212,947	64,611,558
Non Current Assets [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets	20,166
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	0
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	20,166
Current Liabilities [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities	(1,022,861)
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	315,158
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Liabilities	(707,703)
Non Current Liabilities [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities	(49,153)
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	0
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Liabilities	(49,153)
Swap Contracts [Member] | Current Assets [Member]
Offsetting Assets [Line Items]
Current assets	7,212,947	64,611,558
Swap Contracts [Member] | Non Current Assets [Member]
Offsetting Assets [Line Items]
Noncurrent assets	20,166	0
Swap Contracts [Member] | Current Liabilities [Member]
Offsetting Assets [Line Items]
Current liabilities	(707,703)	0
Swap Contracts [Member] | Non Current Liabilities [Member]
Offsetting Assets [Line Items]
Noncurrent liabilities	$ 49,153	$ 0

RESTRUCTURING COSTS - Related C

RESTRUCTURING COSTS - Related Costs (Details) - Severance and Benefit Costs [Member] - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Restructuring Cost and Reserve [Line Items]
Restructuring costs		$ 500,000		$ 500,000
General and Administrative [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	$ 0	$ 523,487	$ 0	$ 523,487

RESTRUCTURING COSTS (Details)

RESTRUCTURING COSTS (Details)	9 Months Ended
	Sep. 30, 2016USD ($)
Restructuring Reserve [Roll Forward]
Beginning Balance	$ 32,493
Additions	0
Settlements	(32,493)
Revisions	0
Ending Balance	$ 0