Northern Oil and Gas (NOG) 10-Q 8 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	1-May-15
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN OIL & GAS, INC.
Entity Central Index Key	1104485
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		61,613,968
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15

BALANCE_SHEETS_UNAUDITED

BALANCE SHEETS (UNAUDITED) (USD $)	Mar. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and Cash Equivalents	$5,741,083	$9,337,512
Trade Receivables	78,591,692	85,931,719
Advances to Operators	1,875,149	930,034
Prepaid and Other Expenses	1,268,652	895,088
Derivative Instruments	124,698,923	128,893,220
Total Current Assets	212,175,499	225,987,573
Oil and Natural Gas Properties, Full Cost Method of Accounting
Proved	2,235,833,943	2,167,452,297
Unproved	26,854,820	50,642,433
Other Property and Equipment	1,879,928	1,870,369
Total Property and Equipment	2,264,568,691	2,219,965,099
Less - Accumulated Depreciation, Depletion and Impairment	-863,573,953	-458,038,546
Total Property and Equipment, Net	1,400,994,738	1,761,926,553
DERIVATIVE INSTRUMENTS	14,397,517	25,013,011
DEBT ISSUANCE COSTS	13,097,051	13,819,195
TOTAL ASSETS	1,640,664,805	2,026,746,332
CURRENT LIABILITIES
Accounts Payable	161,546,866	231,557,547
Accrued Expenses	4,663,999	6,653,124
Accrued Interest	13,615,052	3,585,536
Derivative Instruments	100,646	0
Deferred Tax Liability	41,679,000	43,938,000
Asset Retirement Obligations	212,771	0
Total Current Liabilities	221,818,334	285,734,207
LONG-TERM LIABILITIES
Revolving Credit Facility	338,000,000	298,000,000
8% Senior Notes	507,681,416	508,053,097
Derivative Instruments	0	579,070
Asset Retirement Obligations	5,096,882	5,105,762
Deferred Tax Liability	25,191,555	158,412,555
Total Long-Term Liabilities	875,969,853	970,150,484
TOTAL LIABILITIES	1,097,788,187	1,255,884,691
COMMITMENTS AND CONTINGENCIES (NOTE 8)
STOCKHOLDERS' EQUITY
Preferred Stock, Par Value $.001; 5,000,000 Authorized, No Shares Outstanding	0	0
Common Stock Par Value $.001 95,000,000 Authorized (3/31/2015 - 61,553,309 Shares Outstanding and 12/31/2014 - 61,066,712 Shares Outstanding)	61,553	61,067
Additional Paid-In Capital	435,085,349	433,332,285
Retained Earnings	107,729,716	337,468,289
Total Stockholders' Equity	542,876,618	770,861,641
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$1,640,664,805	$2,026,746,332

BALANCE_SHEETS_UNAUDITED_Paren

BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
LONG-TERM LIABILITIES
Rate of Senior notes (in hundredths)	8.00%	8.00%
STOCKHOLDERS' EQUITY
Preferred Stock, par value (in dollars per share)	$0.00	$0.00
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)	$0.00	$0.00
Common Stock, shares authorized (in shares)	95,000,000	95,000,000
Common Stock, shares outstanding (in shares)	61,553,309	61,066,712

STATEMENTS_OF_OPERATIONS_UNAUD

STATEMENTS OF OPERATIONS (UNAUDITED) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
REVENUES
Oil and Gas Sales	$50,454,148	$96,802,970
Gain (Loss) on Settled Derivatives	39,994,650	-6,817,980
Losses on the Mark-to-Market of Derivative Instruments	-14,331,367	-7,859,683
Other Revenue	7,207	0
Total Revenues	76,124,638	82,125,307
OPERATING EXPENSES
Production Expenses	14,199,090	11,677,429
Production Taxes	5,413,108	9,791,201
General and Administrative Expense	4,352,806	3,997,690
Depletion, Depreciation, Amortization and Accretion	45,213,039	36,100,921
Impairment of Oil and Natural Gas Properties	360,428,962	0
Total Expenses	429,607,005	61,567,241
(LOSS) INCOME FROM OPERATIONS	-353,482,367	20,558,066
OTHER INCOME (EXPENSE)
Interest Expense, Net of Capitalization	-11,736,547	-9,898,968
Other Income	342	30,665
Total Other Income (Expense)	-11,736,205	-9,868,303
(LOSS) INCOME BEFORE INCOME TAXES	-365,218,572	10,689,763
INCOME TAX PROVISION	-135,480,000	4,100,000
NET (LOSS) INCOME	($229,738,572)	$6,589,763
Net (Loss) Income Per Common Share - Basic (in dollars per share)	($3.79)	$0.11
Net (Loss) Income Per Common Share - Diluted (in dollars per share)	($3.79)	$0.11
Weighted Average Shares Outstanding - Basic (in shares)	60,556,180	61,203,725
Weighted Average Shares Outstanding - Diluted (in shares)	60,556,180	61,446,274

STATEMENTS_OF_CASH_FLOWS_UNAUD

STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income	($229,738,572)	$6,589,763
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities:
Depletion, Depreciation, Amortization and Accretion	45,213,039	36,100,921
Amortization of Debt Issuance Costs	722,144	634,592
Amortization of 8% Senior Notes Premium	-371,681	-371,681
Deferred Income Taxes	-135,480,000	4,100,000
Loss on the Mark-to-Market of Derivative Instruments	14,331,367	7,859,683
Amortization of Deferred Rent	-3,664	-3,664
Share - Based Compensation Expense	1,695,873	557,865
Impairment of Oil and Natural Gas Properties	360,428,962	0
Changes in Working Capital and Other Items:
Trade Receivables	7,340,027	4,615,349
Prepaid Expenses and Other	-333,009	-292,994
Accounts Payable	-4,302,624	4,139,303
Accrued Interest	9,417,583	8,984,260
Accrued Expenses	-1,985,461	-165,777
Asset Retirement Obligations	-57,532	0
Net Cash Provided By Operating Activities	66,876,452	72,747,620
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of Oil and Gas Properties and Development Capital Expenditures	-110,547,904	-119,186,402
Proceeds from Sale, Net of Oil and Natural Gas Properties	160,944	0
Purchases of Other Property and Equipment	-9,559	-14,052
Net Cash Used For Investing Activities	-110,396,519	-119,200,454
CASH FLOWS FROM FINANCING ACTIVITIES
Advances on Revolving Credit Facility	50,000,000	63,000,000
Repayments on Revolving Credit Facility	-10,000,000	0
Debt Issuance Costs Paid	0	-225,000
Repurchase of Common Stock	-76,362	-13,900,382
Net Cash Provided by Financing Activities	39,923,638	48,874,618
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	-3,596,429	2,421,784
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD	9,337,512	5,687,166
CASH AND CASH EQUIVALENTS - END OF PERIOD	5,741,083	8,108,950
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Period for Interest	2,062,136	714,658
Cash Paid During the Period for Income Taxes	3,300,000	0
Non-Cash Financing and Investing Activities:
Oil and Natural Gas Properties Included in Accounts Payable	155,548,338	158,428,005
Capitalized Asset Retirement Obligations	154,830	91,869
Non-Cash Compensation Capitalized on Oil and Gas Properties	$134,039	$152,557

STATEMENTS_OF_CASH_FLOWS_UNAUD1

STATEMENTS OF CASH FLOWS (UNAUDITED) (Parenthetical)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities:
Rate of Senior notes (in hundredths)	8.00%	8.00%	8.00%

ORGANIZATION_AND_NATURE_OF_BUS

ORGANIZATION AND NATURE OF BUSINESS	3 Months Ended
	Mar. 31, 2015
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
ORGANIZATION AND NATURE OF BUSINESS	NOTE 1     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 March 31, 2015, approximately 65% of Northern’s 180,633 total net acres were developed.

SIGNIFICANT_ACCOUNTING_POLICIE

SIGNIFICANT ACCOUNTING POLICIES	3 Months Ended
	Mar. 31, 2015
SIGNIFICANT ACCOUNTING POLICIES [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	NOTE 2     SIGNIFICANT ACCOUNTING POLICIES
	The financial information included herein is unaudited, except for the balance sheet as of December 31, 2014, which has been derived from the Company’s audited financial statements for the year ended December 31, 2014.  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 omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”).  The financial statements should be read in conjunction with the audited financial statements for the year ended December 31, 2014, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.
	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.
	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.
	The allowance for doubtful accounts at March 31, 2015 and December 31, 2014 was $2,340,000 and $1,840,000, 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 $79,775 and $79,668 for the three months ended March 31, 2015 and 2014, 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 months ended March 31, 2015 and 2014, respectively:
		Three Months Ended
		March 31,
		2015		2014
	Capitalized Certain Payroll and Other Internal Costs	$	425,428	$	648,876
	Capitalized Interest Costs		737,750		1,197,410
		$	1,163,178	$	1,846,286
	As of March 31, 2015, 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 three months ended March 31, 2015 and 2014 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 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, 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 in 2015, we recorded a non-cash ceiling test impairment of $360.4 million in the three-month period ended March 31, 2015.  The Company did not have any impairment of its proved oil and gas properties for the three-month period ended March 31, 2014.  The impairment charge 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 recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-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 based on the estimated gross proved reserves as determined by independent petroleum engineers.  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 March 31, 2015 and 2014, the Company transferred into the full cost pool costs related to expired leases of $5.5 million and $7.3 million, respectively.
	Asset Retirement Obligations
	The Company accounts for its abandonment and restoration liabilities under 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 included in capitalized costs and 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 March 31, 2015 and 2014 was $722,144 and $634,592, respectively.
	Bond Premium on Senior Notes
	At March 31, 2015, the Company had recorded a bond premium of $10.5 million in connection with the “8% 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 months ended March 31, 2015 and 2014 was $371,681, in each period.
	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 months ended March 31, 2015 and 2014, 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.
	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
	Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  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.  No valuation allowance has been recorded as of March 31, 2015 and December 31, 2014.
	Net Income Per Common Share
	Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).  Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period.  Potential common shares include stock options and restricted stock.  The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
	The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2015 and 2014 are as follows:
		Three Months Ended
		March 31,
		2015		2014
	Weighted Average Common Shares Outstanding – Basic		60,556,180		61,203,725
	Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock		-		242,549
	Weighted Average Common Shares Outstanding – Diluted		60,556,180		61,446,274
	Restricted Stock Excluded From EPS Due To The Anti-Dilutive Effect		144,420		5,213
	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” (“FASB ASC 815”) 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 are recorded to gain (loss) on settled derivatives and mark-to-market gains or losses are recorded to gains (losses) on the mark-to-market of derivative instruments on the statements of operations.  See Note 11 for a description of the derivative contracts which the Company has entered into.
	New Accounting Pronouncements
	From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date.  If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
	In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition.  The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This guidance will be effective for the Company in the annual period beginning after December 15, 2016.  The Company is evaluating the effect of adopting this new accounting guidance but does not expect adoption will have a material impact on the Company’s statements of operations, balance sheets, cash flows or disclosures.
	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 does not believe that the adoption of this guidance will have a material impact on its financial statements.
In April 2015, the FASB issued ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30):  Simplifying the Presentation of Debt Issuance Costs,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.  An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.  An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.  Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle.  These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items.  We are evaluating the impact that this new guidance will have on our financial statements.

CRUDE_OIL_AND_NATURAL_GAS_PROP

CRUDE OIL AND NATURAL GAS PROPERTIES	3 Months Ended
	Mar. 31, 2015
CRUDE OIL AND NATURAL GAS PROPERTIES [Abstract]
CRUDE OIL AND NATURAL GAS PROPERTIES	NOTE 3     CRUDE OIL AND NATURAL GAS PROPERTIES
	The value of the Company’s crude oil and natural gas properties consists of all acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs.  Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition.  Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition.  Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.  Development capital expenditures and purchases of properties that were in accounts payable and not yet paid in cash at March 31, 2015 and December 31, 2014 were approximately $155.5 million and $221.3 million, respectively.
	Acquisitions
	For the three months ended March 31, 2015, the Company acquired approximately 899 net acres, for an average cost of approximately $1,363 per net acre, in its key prospect areas in the form of effective leases.
	Divestitures
	In the first quarter of 2015, the Company sold its interest in certain North Dakota and Montana properties covering 383 net acres for $0.2 million in consideration.
	From time-to-time the Company may also trade leasehold interests with operators to balance working interests in spacing units to facilitate and encourage a more expedited development of the Company’s acreage.
	Unproved Properties
	Unproved properties not being amortized comprise approximately 52,631 net acres and 55,743 net acres of undeveloped leasehold interests at March 31, 2015 and December 31, 2014, 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.
	All properties that are not classified as proved properties are considered unproved properties and, thus, the costs associated with such properties are not subject to depletion.  Once a property is classified as proved, all associated acreage and drilling costs are subject to depletion.
	The Company historically has acquired its properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators.  The Company generally participates in drilling activities on a heads up basis by electing whether to participate 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 three months ended March 31, 2015 and 2014, the Company included $23.6 million and $0, respectively, related to expiring leases and other costs within costs subject to the depletion calculation.

REVOLVING_CREDIT_FACILITY_AND_

REVOLVING CREDIT FACILITY AND LONG TERM DEBT	3 Months Ended
	Mar. 31, 2015
REVOLVING CREDIT FACILITY AND LONG TERM DEBT [Abstract]
REVOLVING CREDIT FACILITY AND LONG TERM DEBT	NOTE 4     REVOLVING CREDIT FACILITY AND LONG TERM DEBT
	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 March 31, 2015, the facility amount was $750 million, the borrowing base was $550 million and there was a $338 million outstanding balance, leaving $212 million of borrowing capacity available under the facility.  Under the terms of the Revolving Credit Facility, the Company may issue an unlimited amount of permitted additional indebtedness, as defined, provided that the borrowing base will be reduced by 25% of the stated amount of any such permitted additional indebtedness.  The $500 million in Notes described below is “permitted additional indebtedness” as defined in the Revolving Credit 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 event-driven unscheduled redeterminations.  Borrowings under the Revolving Credit Facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.5% to 1.5% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined) plus a spread ranging from 1.5% to 2.5%.  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 March 31, 2015, the commitment fee was 0.5% and the interest rate margin was 2.0% on LIBOR loans and 1.0% on base rate loans.  At March 31, 2015, the Company had $338.0 million of LIBOR loans issued under the Revolving Credit Facility at a weighted average interest rate of 2.17%.  The Company was in compliance with the financial covenants of the Revolving Credit Facility at March 31, 2015.
	In April 2015, the $550 million borrowing base on the Revolving Credit Facility was reaffirmed.  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, or make investments.  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) of no greater than 2.5 to 1.0 and a ratio of EBITDAX (as defined) to interest expense (as defined) of no less than 2.5 to 1.0.
	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% an additional $200 million aggregate principal amount of 8.000% senior unsecured notes due June 1, 2020 (the “Follow-on Notes” and, together with the Original 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 and the issuance of the Follow-on Notes resulted in net proceeds to the Company of approximately $200.1 million, which 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).
	At any time prior to June 1, 2015, the Company may redeem up to 35% of the Notes at a redemption price of 108% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption.  Prior to June 1, 2016, the Company may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date.  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 Notes are governed by an Indenture (the “Indenture”), dated as of May 18, 2012, by and among the Company and Wilmington Trust, National Association, as trustee.
	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 important 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 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 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	3 Months Ended
	Mar. 31, 2015
COMMON AND PREFERRED STOCK [Abstract]
COMMON AND PREFERRED STOCK	NOTE 5    COMMON AND PREFERRED STOCK
	The Company’s Articles of Incorporation authorize the issuance of up to 100,000,000 shares.  The shares are classified in two classes, consisting of 95,000,000 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 three months ended March 31, 2015 and the year ended December 31, 2014:
		Three Months Ended			Year Ended
		31-Mar-15			31-Dec-14
	Beginning Balance		61,066,712			61,858,199
	Stock Options Exercised		-			100,000
	Restricted Stock Grants (Note 6)		497,854			299,416
	Stock Repurchased		-			(1,153,885	)
	Other Surrenders		(11,257	)		(79,461	)
	Other		-			42,443
	Ending balance		61,553,309			61,066,712
	2015 Activity
	In the three months ended March 31, 2015, 11,257 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 $76,379, which was based on the market price on the date the shares were surrendered.
	Stock Repurchase Program
	In May 2011, the Company’s board of directors approved a stock repurchase program to acquire up to $150 million of the Company’s outstanding common stock.  The stock repurchase program allows the Company to repurchase its shares from time to time in the open market, block transactions and in negotiated transactions.
	During the first quarter of 2015, the Company did not repurchase shares of its common stock under the stock repurchase program.  During the first quarter of 2014, the Company repurchased 1,018,897 shares of its common stock under the stock repurchase program.  This stock had a cost of approximately $13.7 million.  All repurchased shares are included in the Company’s pool of authorized but unissued shares.  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.
	Performance Equity Awards
	At the end of the first quarter of 2015, certain of the Company’s executive officers were granted performance equity awards under the 2015 long-term equity incentive program adopted by the compensation committee.  Entitlement to the performance shares will be based on the Company’s 2015 performance relative to established performance goals for year-over-year change in average stock price relative to a selected peer group.  Participants may earn from zero to 150 percent of their 2015 base salaries and the amounts earned will be settled in restricted shares of common stock that will vest annually over a subsequent three-year service-based vesting period beginning in 2016.  The maximum dollar amount of the performance shares issuable if all participants earned the maximum award would total $3.3 million.  For the three-month period ended March 31, 2015, the Company did not record compensation expense in connection with these performance equity awards.  No such performance equity awards have vested.

STOCK_OPTIONSSTOCKBASED_COMPEN

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS	3 Months Ended
	Mar. 31, 2015
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS [Abstract]
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS	NOTE 6     STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS
	On April 5, 2013, the board of directors approved the Company’s 2013 Incentive Plan (the “2013 Plan”), which was subsequently approved at the 2013 annual meeting of shareholders.  1,500,000 shares were authorized for grant under the 2013 Plan, plus the number of shares remaining available for future grants under the Company’s predecessor 2009 Equity Incentive Plan on the date the shareholders approved the 2013 Plan.  The 2013 Plan is intended 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.
	Restricted Stock Awards
	During the three months ended March 31, 2015, the Company issued 497,854 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 October 2018.  As of March 31, 2015, there was approximately $8.2 million of total unrecognized compensation expense related to unvested restricted stock that will be recognized over a weighted-average period of approximately 2.4 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 three months ended March 31, 2015:
			Three Months Ended
			31-Mar-15
			Number of			Weighted-Average
			Shares			Price
	Restricted Stock Awards:
	Restricted Shares Outstanding at the Beginning of Period			538,499		$	13.54
	Shares Granted			497,854			8.61
	Lapse of Restrictions			(64,759	)		14.67
	Restricted Shares Outstanding at End of Period			971,594		$	10.94
	Stock Option Awards
	On November 1, 2007, the board of directors granted options to purchase 560,000 shares of the Company’s common stock under the Company’s 2006 Incentive Stock Option Plan.  The Company granted options to purchase 500,000 shares of the Company’s common stock to members of the board and options to purchase 60,000 shares of the Company’s common stock to one employee pursuant to an employment agreement.  These options were granted at a price of $5.18 per share and the optionees were fully vested on the grant date.  As of March 31, 2015, options to purchase a total of 141,872 shares of the Company’s common stock remain outstanding but unexercised.  The board of directors determined that no future grants will be made pursuant to the 2006 Incentive Stock Option Plan.
	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.  There were no stock options granted by the Company in the three months ended March 31, 2015.
	Currently Outstanding Options
		·	No options were forfeited during the three months ended March 31, 2015.
		·	No options expired during the three months ended March 31, 2015.
		·	Options covering 141,872 shares were exercisable and outstanding at March 31, 2015.
		·	The Company recorded no compensation expense related to these options for the three months ended March 31, 2015.  There is no further compensation expense that will be recognized in future periods relative to any options that had been granted as of March 31, 2015, because the Company recognized the entire fair value of such compensation upon vesting of the options.
		·	There were no unvested options at March 31, 2015.

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2015
RELATED PARTY TRANSACTIONS [Abstract]
RELATED PARTY TRANSACTIONS	NOTE 7     RELATED PARTY TRANSACTIONS
	The Company is a non-operating participant in a number of wells in North Dakota that are operated by Emerald Oil, Inc. (“Emerald”), by virtue of leased acreage or working interests held by the Company in drilling units operated by Emerald.  As of March 31, 2015, such wells included 43 gross (7.8 net) producing wells, and an additional 5 gross (0.3 net) wells that were drilling or awaiting completion.  Based on authorizations for expenditure (or AFEs) provided by Emerald with respect to each of the wells, the total drilling and completion costs for these 48 gross wells was estimated at approximately $492.4 million, approximately $82.2 million of which is attributable to Northern Oil’s working interest in the wells.  James Russell (J.R.) Reger is a current director (and until March 2014 was an executive officer) of Emerald, which is a publicly-traded company.  J.R. Reger is also the brother of Northern Oil’s Chairman and Chief Executive Officer, Michael Reger.  At March 31, 2015, the Company’s accounts receivable and accounts payable balances with Emerald were $1.2 million and $7.6 million, respectively.  At December 31, 2014, the Company’s accounts receivable and accounts payable balances with Emerald were $2.9 million and $8.4 million.  The Company recorded total revenues of $2.0 million and $5.3 million from Emerald for the three months ended March 31, 2015 and 2014, respectively.
	All transactions involving related parties are approved or ratified by the Company’s Audit Committee.

COMMITMENTS_CONTINGENCIES

COMMITMENTS & CONTINGENCIES	3 Months Ended
	Mar. 31, 2015
COMMITMENTS & CONTINGENCIES [Abstract]
COMMITMENTS & CONTINGENCIES	NOTE 8     COMMITMENTS & CONTINGENCIES
	Litigation
	The Company is engaged in 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 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 is party to a quiet title action in North Dakota that relates to its interest in certain crude oil and natural gas leases.  In the event the action results in a final judgment that is adverse to the Company, the Company would be required to reverse approximately $1.7 million in revenue (net of accrued taxes) that has been accrued since the second quarter of 2008 based on the Company’s purported interest in the crude oil and natural gas leases at issue, approximately $16,000 of which relates to the three-month period ended March 31, 2015.  The Company fully maintains the validity of its interest in the crude oil and natural gas leases, and is vigorously defending such interest.

INCOME_TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2015
INCOME TAXES [Abstract]
INCOME TAXES	NOTE 9     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.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not 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 for the three months ended March 31, 2015 and 2014 consists of the following:
		Three Months
		Ended March 31,
		2015			2014
	Current Income Taxes	$	-		$	-
	Deferred Income Taxes
	Federal		(123,429,000	)		3,741,000
	State		(12,051,000	)		359,000
	Total Provision	$	(135,480,000	)	$	4,100,000
	Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities.  The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement.  Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards.
	The Company has no liabilities for unrecognized tax benefits.
	The Company’s policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expense.  For the three months ended March 31, 2015 and 2014, the Company did not recognize any interest or penalties in its statements of operations, nor did it have any interest or penalties accrued in its balance sheet at March 31, 2015 and December 31, 2014 relating to unrecognized benefits.
	The tax years 2014, 2013, 2012 and 2011 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	3 Months Ended
	Mar. 31, 2015
FAIR VALUE [Abstract]
FAIR VALUE	NOTE 10     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 of 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
		March 31, 2015 Using
		Quoted Prices		Significant Other Observable Inputs			Significant
		In Active Markets		(Level 2)			Unobservable Inputs
		for Identical Assets					(Level 3)
		(Level 1)
	Commodity Derivatives – Current Asset (crude oil swaps)	$	-	$	124,698,923		$	-
	Commodity Derivatives – Non-Current Asset (crude oil swaps)		-		14,397,517			-
	Commodity Derivatives – Current Liability (crude oil swaptions)		-		(100,646	)		-
	Total	$	-	$	138,995,794		$	-
		Fair Value Measurements at
		December 31, 2014 Using
		Quoted Prices		Significant Other Observable Inputs			Significant
		In Active Markets		(Level 2)			Unobservable Inputs
		for Identical Assets					(Level 3)
		(Level 1)
	Commodity Derivatives – Current Asset (crude oil swaps)	$	-	$	128,893,220		$	-
	Commodity Derivatives – Non-Current Asset (crude oil swaps)		-		25,013,011			-
	Commodity Derivatives – Non-Current Liability (crude oil swaptions)		-		(579,070	)		-
	Total	$	-	$	153,327,161		$	-
	The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include crude oil swaps and crude oil swaptions (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 balance sheet.  The current derivative asset and liability amounts represent the fair values expected to be settled in the subsequent twelve months.
	Fair Value of Other Financial Instruments
	The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments.
	The carrying amount of the Company’s long-term debt reported in the balance sheet at March 31, 2015 is $845.7 million, which includes $507.7 million of senior unsecured notes including a premium of $7.7 million and $338.0 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 $453.8 million at March 31, 2015.  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 Topic 410, “Asset Retirement and Environmental Obligations” (“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 three months ended March 31, 2015 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 three-month period ended March 31, 2015.

DERIVATIVE_INSTRUMENTS_AND_PRI

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT	3 Months Ended
	Mar. 31, 2015
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT [Abstract]
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT	NOTE 11     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 statements of operations as a gain or loss on the mark-to-market of derivative instruments.  The Company recorded losses of $14.3 million and $7.9 million on the mark-to-market of derivative instruments in the statements of operations for three months ended March 31, 2015 and 2014, respectively.  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 Company recorded realized gains on settled derivatives of $40.0 million and realized losses on settled derivatives of $6.8 million in the statements of operations for three months ended March 31, 2015 and 2014, respectively.
	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 March 31, 2015, the associated volumes and the corresponding fixed price.
	Settlement Period		Oil (Barrels)				Fixed Price
	Swaps-Crude Oil
	04/01/15 – 06/30/15			180,000				89.15
	04/01/15 – 06/30/15			30,000				90.5
	04/01/15 – 06/30/15			90,000				88.55
	04/01/15 – 06/30/15			90,000				88
	04/01/15 – 06/30/15			30,000				90.75
	04/01/15 – 06/30/15			30,000				90.25
	04/01/15 – 06/30/15			45,000				89
	04/01/15 – 06/30/15			45,000				89
	04/01/15 – 12/31/15			540,000				89
	04/01/15 – 12/31/15			270,000				89
	04/01/15 – 12/31/15			270,000				89.02
	04/01/15 – 12/31/15			135,000				89
	04/01/15 – 12/31/15			135,000				89
	07/01/15 – 12/31/15(1)			180,000				90.75
	07/01/15 – 12/31/15(1)			180,000				91
	07/01/15 – 12/31/15(1)			180,000				91.25
	07/01/15 – 06/30/16			360,000				89
	07/01/15 – 06/30/16			360,000				90
	07/01/15 – 06/30/16			360,000				91
	01/01/16 – 06/30/16			180,000				90
	01/01/16 – 06/30/16			90,000				90
	01/01/16 – 06/30/16			90,000				90
	_________________
	-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 90,000 barrels per month are exercisable on or about December 31, 2015.  If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 90,000 barrels per month at an average price of $91.00 per barrel for each month during the period January 1, 2016 through June 30, 2016.
	As of March 31, 2015, the Company had a total volume on open commodity swaps of 3.9 million barrels at a weighted average price of approximately $89.66.
	The following table reflects the weighted average price of open commodity swap derivative contracts as of March 31, 2015, by year with associated volumes.
	Weighted Average Price
	Of Open Commodity Swap Contracts
	Year		Volumes (Bbl)				Weighted
							Average Price
	2015			2,970,000				89.56
	2016			900,000				90
	The following table sets forth the amounts, on a gross basis, and classification of the Company’s outstanding derivative financial instruments at March 31, 2015 and December 31, 2014, respectively.  Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement:
	Type of Crude Oil Contract		Balance Sheet Location		31-Mar-15				31-Dec-14
					Estimated				Estimated
					Fair Value				Fair Value
	Derivative Assets:
	Swap Contracts		Current Assets		$	124,698,923			$	128,893,220
	Swap Contracts		Non-Current Assets			14,397,517				25,013,011
	Total Derivative Assets				$	139,096,440			$	153,906,231
	Derivative Liabilities:
	Swaption Contracts		Current Liabilities		$	(100,646	)		$	-
	Swaption Contracts		Non-Current Liabilities			-				(579,070	)
	Total Derivative Liabilities				$	(100,646	)		$	(579,070	)
	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 March 31, 2015
			Gross Amounts of Recognized Assets				Gross Amounts				Net Amounts of
							Offset in the				Assets Presented
							Balance Sheet				in the
											Balance Sheet
	Offsetting of Derivative Assets:
	Current Assets		$	124,698,923			$	-			$	124,698,923
	Non-Current Assets			14,397,517				-				14,397,517
	Total Derivative Assets		$	139,096,440			$	-			$	139,096,440
	Offsetting of Derivative Liabilities:
	Current Liabilities		$	(100,646	)		$	-			$	(100,646	)
	Non-Current Liabilities			-				-				-
Total Derivative Liabilities		$	(100,646	)		$	-			$	(100,646	)
		Estimated Fair Value at December 31, 2014
		Gross Amounts of Recognized Assets				Gross Amounts				Net Amounts of
						Offset in the				Assets Presented
						Balance Sheet				in the
										Balance Sheet
Offsetting of Derivative Assets:
Current Assets		$	128,893,220			$	-			$	128,893,220
Non-Current Assets			25,013,011				-				25,013,011
Total Derivative Assets		$	153,906,231			$	-			$	153,906,231
Offsetting of Derivative Liabilities:
Current Liabilities		$	-			$	-			$	-
Non-Current Liabilities			(579,070	)			-				(579,070	)
Total Derivative Liabilities		$	(579,070	)		$	-			$	(579,070	)
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 March 31, 2015.  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 March 31, 2015 and December 31, 2014.

SIGNIFICANT_ACCOUNTING_POLICIE1

SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
	Mar. 31, 2015
SIGNIFICANT 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.
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.
	The allowance for doubtful accounts at March 31, 2015 and December 31, 2014 was $2,340,000 and $1,840,000, 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 $79,775 and $79,668 for the three months ended March 31, 2015 and 2014, 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 months ended March 31, 2015 and 2014, respectively:
		Three Months Ended
		March 31,
		2015		2014
	Capitalized Certain Payroll and Other Internal Costs	$	425,428	$	648,876
	Capitalized Interest Costs		737,750		1,197,410
		$	1,163,178	$	1,846,286
	As of March 31, 2015, 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 three months ended March 31, 2015 and 2014 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 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, 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 in 2015, we recorded a non-cash ceiling test impairment of $360.4 million in the three-month period ended March 31, 2015.  The Company did not have any impairment of its proved oil and gas properties for the three-month period ended March 31, 2014.  The impairment charge 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 recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-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 based on the estimated gross proved reserves as determined by independent petroleum engineers.  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 March 31, 2015 and 2014, the Company transferred into the full cost pool costs related to expired leases of $5.5 million and $7.3 million, respectively.
Asset Retirement Obligations	Asset Retirement Obligations
	The Company accounts for its abandonment and restoration liabilities under 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 included in capitalized costs and 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 March 31, 2015 and 2014 was $722,144 and $634,592, respectively.
Bond Premium on Senior Notes	Bond Premium on Senior Notes
	At March 31, 2015, the Company had recorded a bond premium of $10.5 million in connection with the “8% 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 months ended March 31, 2015 and 2014 was $371,681, in each period.
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 months ended March 31, 2015 and 2014, 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.
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
	Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.  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.  No valuation allowance has been recorded as of March 31, 2015 and December 31, 2014.
Net Income Per Common Share	Net Income Per Common Share
	Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator).  Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period.  Potential common shares include stock options and restricted stock.  The number of potential common shares outstanding relating to stock options and restricted stock is computed using the treasury stock method.
	The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three months ended March 31, 2015 and 2014 are as follows:
		Three Months Ended
		March 31,
		2015		2014
	Weighted Average Common Shares Outstanding – Basic		60,556,180		61,203,725
	Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock		-		242,549
	Weighted Average Common Shares Outstanding – Diluted		60,556,180		61,446,274
	Restricted Stock Excluded From EPS Due To The Anti-Dilutive Effect		144,420		5,213
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” (“FASB ASC 815”) 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 are recorded to gain (loss) on settled derivatives and mark-to-market gains or losses are recorded to gains (losses) on the mark-to-market of derivative instruments on the statements of operations.  See Note 11 for a description of the derivative contracts which the Company has entered into.
New Accounting Pronouncements	New Accounting Pronouncements
	From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date.  If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
	In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition.  The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This guidance will be effective for the Company in the annual period beginning after December 15, 2016.  The Company is evaluating the effect of adopting this new accounting guidance but does not expect adoption will have a material impact on the Company’s statements of operations, balance sheets, cash flows or disclosures.
	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 does not believe that the adoption of this guidance will have a material impact on its financial statements.
	In April 2015, the FASB issued ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30):  Simplifying the Presentation of Debt Issuance Costs,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.  The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.  An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.  An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance.  Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle.  These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items.  We are evaluating the impact that this new guidance will have on our financial statements.

SIGNIFICANT_ACCOUNTING_POLICIE2

SIGNIFICANT ACCOUNTING POLICIES (Tables)	3 Months Ended
	Mar. 31, 2015
SIGNIFICANT 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 months ended March 31, 2015 and 2014, respectively:
		Three Months Ended
		March 31,
		2015		2014
	Capitalized Certain Payroll and Other Internal Costs	$	425,428	$	648,876
	Capitalized Interest Costs		737,750		1,197,410
		$	1,163,178	$	1,846,286
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 months ended March 31, 2015 and 2014 are as follows:
		Three Months Ended
		March 31,
		2015		2014
	Weighted Average Common Shares Outstanding – Basic		60,556,180		61,203,725
	Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock		-		242,549
	Weighted Average Common Shares Outstanding – Diluted		60,556,180		61,446,274
	Restricted Stock Excluded From EPS Due To The Anti-Dilutive Effect		144,420		5,213

COMMON_AND_PREFERRED_STOCK_Tab

COMMON AND PREFERRED STOCK (Tables)	3 Months Ended
	Mar. 31, 2015
COMMON AND PREFERRED STOCK [Abstract]
Schedule of changes in the number of common stock shares	The following is a schedule of changes in the number of shares of common stock outstanding during the three months ended March 31, 2015 and the year ended December 31, 2014:
		Three Months Ended			Year Ended
		31-Mar-15			31-Dec-14
	Beginning Balance		61,066,712			61,858,199
	Stock Options Exercised		-			100,000
	Restricted Stock Grants (Note 6)		497,854			299,416
	Stock Repurchased		-			(1,153,885	)
	Other Surrenders		(11,257	)		(79,461	)
	Other		-			42,443
	Ending balance		61,553,309			61,066,712

STOCK_OPTIONSSTOCKBASED_COMPEN1

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Tables)	3 Months Ended
	Mar. 31, 2015
STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS [Abstract]
Restricted stock activity	The following table reflects the outstanding restricted stock awards and activity related thereto for the three months ended March 31, 2015:
		Three Months Ended
		31-Mar-15
		Number of			Weighted-Average
		Shares			Price
	Restricted Stock Awards:
	Restricted Shares Outstanding at the Beginning of Period		538,499		$	13.54
	Shares Granted		497,854			8.61
	Lapse of Restrictions		(64,759	)		14.67
	Restricted Shares Outstanding at End of Period		971,594		$	10.94

INCOME_TAXES_Tables

INCOME TAXES (Tables)	3 Months Ended
	Mar. 31, 2015
INCOME TAXES [Abstract]
Income tax expense provision	The income tax provision for the three months ended March 31, 2015 and 2014 consists of the following:
		Three Months
		Ended March 31,
		2015			2014
	Current Income Taxes	$	-		$	-
	Deferred Income Taxes
	Federal		(123,429,000	)		3,741,000
	State		(12,051,000	)		359,000
	Total Provision	$	(135,480,000	)	$	4,100,000

FAIR_VALUE_Tables

FAIR VALUE (Tables)	3 Months Ended
	Mar. 31, 2015
FAIR VALUE [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
		March 31, 2015 Using
		Quoted Prices		Significant Other Observable Inputs			Significant
		In Active Markets		(Level 2)			Unobservable Inputs
		for Identical Assets					(Level 3)
		(Level 1)
	Commodity Derivatives – Current Asset (crude oil swaps)	$	-	$	124,698,923		$	-
	Commodity Derivatives – Non-Current Asset (crude oil swaps)		-		14,397,517			-
	Commodity Derivatives – Current Liability (crude oil swaptions)		-		(100,646	)		-
	Total	$	-	$	138,995,794		$	-
		Fair Value Measurements at
		December 31, 2014 Using
		Quoted Prices		Significant Other Observable Inputs			Significant
		In Active Markets		(Level 2)			Unobservable Inputs
		for Identical Assets					(Level 3)
		(Level 1)
	Commodity Derivatives – Current Asset (crude oil swaps)	$	-	$	128,893,220		$	-
	Commodity Derivatives – Non-Current Asset (crude oil swaps)		-		25,013,011			-
	Commodity Derivatives – Non-Current Liability (crude oil swaptions)		-		(579,070	)		-
	Total	$	-	$	153,327,161		$	-

DERIVATIVE_INSTRUMENTS_AND_PRI1

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Tables)	3 Months Ended
	Mar. 31, 2015
DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT [Abstract]
Open commodity swap contracts	The following table reflects open commodity swap contracts as of March 31, 2015, the associated volumes and the corresponding fixed price.
	Settlement Period		Oil (Barrels)				Fixed Price
	Swaps-Crude Oil
	04/01/15 – 06/30/15			180,000				89.15
	04/01/15 – 06/30/15			30,000				90.5
	04/01/15 – 06/30/15			90,000				88.55
	04/01/15 – 06/30/15			90,000				88
	04/01/15 – 06/30/15			30,000				90.75
	04/01/15 – 06/30/15			30,000				90.25
	04/01/15 – 06/30/15			45,000				89
	04/01/15 – 06/30/15			45,000				89
	04/01/15 – 12/31/15			540,000				89
	04/01/15 – 12/31/15			270,000				89
	04/01/15 – 12/31/15			270,000				89.02
	04/01/15 – 12/31/15			135,000				89
	04/01/15 – 12/31/15			135,000				89
	07/01/15 – 12/31/15(1)			180,000				90.75
	07/01/15 – 12/31/15(1)			180,000				91
	07/01/15 – 12/31/15(1)			180,000				91.25
	07/01/15 – 06/30/16			360,000				89
	07/01/15 – 06/30/16			360,000				90
	07/01/15 – 06/30/16			360,000				91
	01/01/16 – 06/30/16			180,000				90
	01/01/16 – 06/30/16			90,000				90
	01/01/16 – 06/30/16			90,000				90
	_________________
	-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 90,000 barrels per month are exercisable on or about December 31, 2015.  If the counterparties exercise all such options, the notional volume of the Company’s existing crude oil derivative contracts will increase by 90,000 barrels per month at an average price of $91.00 per barrel for each month during the period January 1, 2016 through June 30, 2016.
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 March 31, 2015, by year with associated volumes.
	Weighted Average Price
	Of Open Commodity Swap Contracts
	Year		Volumes (Bbl)				Weighted
							Average Price
	2015			2,970,000				89.56
	2016			900,000				90
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 March 31, 2015 and December 31, 2014, respectively.  Certain amounts may be presented on a net basis on the financial statements when such amounts are with the same counterparty and subject to a master netting arrangement:
	Type of Crude Oil Contract		Balance Sheet Location		31-Mar-15				31-Dec-14
					Estimated				Estimated
					Fair Value				Fair Value
	Derivative Assets:
	Swap Contracts		Current Assets		$	124,698,923			$	128,893,220
	Swap Contracts		Non-Current Assets			14,397,517				25,013,011
	Total Derivative Assets				$	139,096,440			$	153,906,231
	Derivative Liabilities:
	Swaption Contracts		Current Liabilities		$	(100,646	)		$	-
	Swaption Contracts		Non-Current Liabilities			-				(579,070	)
	Total Derivative Liabilities				$	(100,646	)		$	(579,070	)
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 March 31, 2015
			Gross Amounts of Recognized Assets				Gross Amounts				Net Amounts of
							Offset in the				Assets Presented
							Balance Sheet				in the
											Balance Sheet
	Offsetting of Derivative Assets:
	Current Assets		$	124,698,923			$	-			$	124,698,923
	Non-Current Assets			14,397,517				-				14,397,517
	Total Derivative Assets		$	139,096,440			$	-			$	139,096,440
	Offsetting of Derivative Liabilities:
	Current Liabilities		$	(100,646	)		$	-			$	(100,646	)
	Non-Current Liabilities			-				-				-
	Total Derivative Liabilities		$	(100,646	)		$	-			$	(100,646	)
			Estimated Fair Value at December 31, 2014
			Gross Amounts of Recognized Assets				Gross Amounts				Net Amounts of
							Offset in the				Assets Presented
							Balance Sheet				in the
											Balance Sheet
	Offsetting of Derivative Assets:
	Current Assets		$	128,893,220			$	-			$	128,893,220
	Non-Current Assets			25,013,011				-				25,013,011
	Total Derivative Assets		$	153,906,231			$	-			$	153,906,231
	Offsetting of Derivative Liabilities:
	Current Liabilities		$	-			$	-			$	-
	Non-Current Liabilities			(579,070	)			-				(579,070	)
	Total Derivative Liabilities		$	(579,070	)		$	-			$	(579,070	)

ORGANIZATION_AND_NATURE_OF_BUS1

ORGANIZATION AND NATURE OF BUSINESS (Details)	3 Months Ended
	Mar. 31, 2015
	acre
ORGANIZATION AND NATURE OF BUSINESS [Abstract]
Percentage of mineral rights developed (in hundredths)	65.00%
Gas and oil acreage net mineral rights (in acres)	180,633

SIGNIFICANT_ACCOUNTING_POLICIE3

SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Cash and Cash Equivalents [Abstract]
Threshold amount of FDIC coverage	$250,000
Accounts Receivable [Abstract]
Allowance for doubtful accounts	2,340,000		1,840,000
Advance to Operators [Abstract]
Period for advance payments to be applied against joint interest billings	90 days
Property, Plant and Equipment [Line Items]
Depreciation expense	79,775	79,668
Full Cost Method [Abstract]
Capitalized Certain Payroll and Other Internal Costs	425,428	648,876
Capitalized Interest Cost	737,750	1,197,410
Total	1,163,178	1,846,286
Minimum percentage of proved reserves sold to be considered a significant alteration (in hundredths)	25.00%
Impairment of Oil and Natural Gas Properties	360,428,962	0
Capitalized costs related to expired leases subject to depletion	5,500,000	7,300,000
Discount rate (in hundredths)	10.00%
Debt Issuance Costs [Abstract]
Amortization of debt issuance costs	722,144	634,592
Rate of Senior notes (in hundredths)	8.00%	8.00%	8.00%
Amortization of bond premium	371,681	371,681
Income Taxes [Abstract]
Valuation allowance	0		0
Net Income Per Common Share [Abstract]
Weighted Average Common Shares Outstanding - Basic (in shares)	60,556,180	61,203,725
Plus: Potentially Dilutive Common Shares Including Stock Options and Restricted Stock (in shares)	0	242,549
Weighted Average Common Shares Outstanding - Diluted (in shares)	60,556,180	61,446,274
Restricted Stock Excluded from EPS due to the Anti-Dilutive Effect (in shares)	144,420	5,213
Senior Unsecured Notes [Member]
Debt Issuance Costs [Abstract]
Capitalized costs in connection with debt	$10,500,000
Rate of Senior notes (in hundredths)	8.00%
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful lives	3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property and equipment, estimated useful lives	7 years

CRUDE_OIL_AND_NATURAL_GAS_PROP1

CRUDE OIL AND NATURAL GAS PROPERTIES (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
	acre		acre
Acquisitions [Abstract]
Capital expenditures incurred but not yet paid	$155,500,000		$221,300,000
Mineral acres acquired, net (in acres)	899
Average acquisition cost per net acre	1,363
Proceeds from sale of oil and gas properties	160,944	0
Unproved Properties [Abstract]
Unproven leasehold interests (in net acres)	52,631		55,743
Anticipated future period over which excluded costs will become subject to depletion	5 years
Impairment costs related to expired leases subject to depletion	23,600,000	0
North Dakota and Montana Properties [Member]
Acquisitions [Abstract]
Gas and Oil acreage, net acres sold	383
Proceeds from sale of oil and gas properties	$200,000

REVOLVING_CREDIT_FACILITY_AND_1

REVOLVING CREDIT FACILITY AND LONG TERM DEBT (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Apr. 30, 2015
Line of Credit Facility [Line Items]
Rate of senior unsecured notes (in hundredths)	8.00%	8.00%	8.00%
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing	$750
Borrowing base	550
Borrowings under Credit Facility	338
Remaining borrowing capacity of Credit Facility	212
Percent of total additional permitted borrowing (in hundredths)	25.00%
Permitted additional indebtedness	500
Revolving credit facility, maturity date	30-Sep-18
Credit Facility interest rate description	Borrowings under the Revolving Credit Facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.5% to 1.5% or LIBOR borrowings at the Adjusted LIBOR Rate (as defined) plus a spread ranging from 1.5% to 2.5%. 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 March 31, 2015, the commitment fee was 0.5% and the interest rate margin was 2.0% on LIBOR loans and 1.0% on base rate loans. At March 31, 2015, the Company had $338.0 million of LIBOR loans issued under the Revolving Credit Facility at a weighted average interest rate of 2.17%. The Company was in compliance with the financial covenants of the Revolving Credit Facility at March 31, 2015.
Commitment fee, description	A commitment fee is paid on the undrawn balance based on an annual rate of either 0.375% or 0.50%.
Loans issued under revolving credit facility	338
Weighted average interest rate (in hundredths)	2.17%
Credit facility covenants	The Revolving Credit Facility contains negative covenants that limit the Companybs 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, or make investments. 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) of no greater than 2.5 to 1.0 and a ratio of EBITDAX (as defined) to interest expense (as defined) of no less than 2.5 to 1.0.
Line of credit facility covenant terms current ratio	1
Revolving Credit Facility [Member] | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Borrowing base				550
Line of credit facility covenant terms current ratio				1
Line of credit facility ratio of debt to EBITDAX				2.5
Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Commitment fee percentage (in hundredths)	0.38%
Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Commitment fee percentage (in hundredths)	0.50%
8% Senior Notes Due 2020 [Member]
Line of Credit Facility [Line Items]
Principal amount of senior unsecured notes	300
Rate of senior unsecured notes (in hundredths)	8.00%
Maturity date	1-Jun-20
Price of senior unsecured notes (in hundredths)	105.25%
Additional amount of senior unsecured notes	200
Net proceeds from issuance of senior unsecured notes	291.2
Additional net proceeds from issuance of senior unsecured notes	200.1
Percentage of notes that can be redeemed (in hundredths)	35.00%
Rate of redemption price of notes (in hundredths)	108.00%
Limitation (in number of days) to redeemed the notes	180 days
Limitation (in percentage of aggregate principal amount of Notes) to redeemed the notes	65.00%
Percentage of notes at redemption prices for prior to June 1, 2016 (in hundredths)	100.00%
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2016 (in hundredths)	104.00%
Percentage of notes at redemption prices for the twelve-month period beginning on June 1, 2017 (in hundredths)	102.00%
Percentage of notes at redemption prices for beginning on June 1, 2018 (in hundredths)	100.00%
Number of days in default payment of interest	30 days
Payment of certain final judgments	$25
Number of days related to payment certain final judgments	60 days
LIBOR Loans [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Commitment fee percentage (in hundredths)	0.50%
Interest rate margin in effect during period (in hundredths)	2.00%
LIBOR Loans [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period (in hundredths)	1.50%
LIBOR Loans [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period (in hundredths)	2.50%
Alternate Base Rate Loans [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period (in hundredths)	1.00%
Alternate Base Rate Loans [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period (in hundredths)	0.50%
Alternate Base Rate Loans [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Interest rate margin in effect during period (in hundredths)	1.50%

COMMON_AND_PREFERRED_STOCK_Det

COMMON AND PREFERRED STOCK (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
	Class
COMMON AND PREFERRED STOCK [Abstract]
Total shares of preferred and common stock authorized for issuance (in shares)	100,000,000
Number of classes of shares	2
Common stock, shares authorized (in shares)	95,000,000		95,000,000
Common stock, par value (in dollars per share)	$0.00		$0.00
Preferred stock, shares authorized (in shares)	5,000,000		5,000,000
Preferred stock, par value (in dollars per share)	$0.00		$0.00
Changes in number of common stock shares [Roll forward]
Beginning Balance (in shares)	61,066,712	61,858,199	61,858,199
Stock Options Exercised (in shares)	0		100,000
Restricted Stock Grants (Note 6) (in shares)	497,854		299,416
Stock Repurchased (in shares)	0	-1,018,837	-1,153,885
Other Surrenders (in shares)	-11,257		-79,461
Other (in shares)	0		42,443
Ending Balance (in shares)	61,553,309		61,066,712
Stock Activity [Abstract]
Common stock surrendered by certain employees to cover tax obligations (in shares)	11,257
Fair value of common stock surrendered by certain employees to cover tax obligations	$76,379
Stock Repurchase Program [Abstract]
Stock repurchase program, amount approved	150,000,000
Treasury stock, repurchased and retired	13,700,000
Stock repurchase (in shares)	0	1,018,837	1,153,885
Performance Stock [Member]
Performance Stock [Abstract]
Vesting Period	3 years
Performance Stock [Member] | Minimum [Member]
Performance Stock [Abstract]
Participant's earning percentage (in hundredths)	0.00%
Performance Stock [Member] | Maximum [Member]
Performance Stock [Abstract]
Participant's earning percentage (in hundredths)	150.00%
Maximum dollar amount of performance shares issuable	$3,300,000

STOCK_OPTIONSSTOCKBASED_COMPEN2

STOCK OPTIONS/STOCK-BASED COMPENSATION AND WARRANTS (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
2006 Incentive Stock Option Plan [Member]
Stock Option Awards [Abstract]
Shares granted (in shares)	0
2013 Equity Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares were authorized for grant (in shares)	1,500,000
Restricted Stock Awards [Member]
Restricted Stock Awards [Abstract]
Unrecognized compensation expense	8,200,000
Unrecognized compensation expense, recognized period	2 years 4 months 24 days
Percent of forfeiture rate assumed for restricted stock (in hundredths)	0.00%
Restricted Stock Awards Activity [Roll forward]
Restricted Shares Outstanding at the Beginning of Period (in shares)	538,499
Shares Granted (in shares)	497,854
Lapse of Restrictions (in shares)	-64,759
Restricted Shares Outstanding at the End of Period (in shares)	971,594
Restricted Stock Awards, Additional Disclosures [Abstract]
Restricted Shares Outstanding, Weighted-Average Price at the Beginning of Period (in dollars per share)	13.54
Shares Granted, Weighted-Average Price (in dollars per share)	8.61
Lapse of Restrictions, Weighted-Average Price (in dollars per share)	14.67
Restricted Shares Outstanding, Weighted-Average Price at the End of Period (in dollars per share)	10.94
Currently Outstanding Options [Abstract]
Unvested options outstanding (in shares)	971,594
Stock Option Awards [Member]
Restricted Stock Awards Activity [Roll forward]
Restricted Shares Outstanding at the End of Period (in shares)	0
Stock Option Awards [Abstract]
Options remain outstanding but unexercised (in shares)	141,872
Currently Outstanding Options [Abstract]
Forfeited (in shares)	0
Options expired during period (in shares)	0
Exercisable (in shares)	141,872
Share-based compensation expense	0
Unvested options outstanding (in shares)	0
Stock Option Awards [Member] | 2006 Incentive Stock Option Plan [Member]
Stock Option Awards [Abstract]
Shares granted (in shares)	560,000
Shares granted (in dollars per share)	5.18
Stock Option Awards [Member] | Directors [Member] | 2006 Incentive Stock Option Plan [Member]
Stock Option Awards [Abstract]
Shares granted (in shares)	500,000
Stock Option Awards [Member] | Employee [Member] | 2006 Incentive Stock Option Plan [Member]
Stock Option Awards [Abstract]
Shares granted (in shares)	60,000

RELATED_PARTY_TRANSACTIONS_Det

RELATED PARTY TRANSACTIONS (Details) (Emerald [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
	Well
Emerald [Member]
Related Party Transaction [Line Items]
Number of producing wells, gross	43
Number of producing wells, net	7.8
Number of drilling or awaiting completion wells, gross	5
Number of drilling or awaiting completion wells, net	0.3
Number of producing and drilling wells, gross	48
Estimated total drilling and completion cost of wells	$492.40
Estimated total drilling and completion cost of wells attributable to entity	82.2
Accounts receivable from related parties	1.2		2.9
Accounts payable to related parties	7.6		8.4
Revenue from related party transactions	$2	$5.30

COMMITMENTS_CONTINGENCIES_Deta

COMMITMENTS & CONTINGENCIES (Details) (USD $)	3 Months Ended	81 Months Ended
	Mar. 31, 2015	Mar. 31, 2015
COMMITMENTS & CONTINGENCIES [Abstract]
Estimated reversal of revenue	$16,000	$1,700,000

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income tax provision [Abstract]
Current Income Taxes	$0	$0
Deferred Income Taxes [Abstract]
Federal	-123,429,000	3,741,000
State	-12,051,000	359,000
Total Provision	-135,480,000	4,100,000
Minimum amount tax benefits likely realized upon settlement percentage (in hundredths)	50.00%
Unrecognized tax benefits	0
Unrecognized tax benefits, income tax penalties and interest expense	0	0
Unrecognized tax benefits, interest and penalties accrued	$0		$0
Open tax years			2014	2013	2012	2011

FAIR_VALUE_Details

FAIR VALUE (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfers between Level 1 and Level 2	$0
Fair Value, Measurements, Recurring [Member] | 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)	0	0
Commodity Derivatives - Non - Current Asset (crude oil swaps)	0	0
Commodity Derivatives - Current Liability (crude oil swaptions)	0
Commodity Derivatives - Non-Current Liability (crude oil swaptions)		0
Total	0	0
Fair Value, Measurements, Recurring [Member] | 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)	124,698,923	128,893,220
Commodity Derivatives - Non - Current Asset (crude oil swaps)	14,397,517	25,013,011
Commodity Derivatives - Current Liability (crude oil swaptions)	-100,646
Commodity Derivatives - Non-Current Liability (crude oil swaptions)		-579,070
Total	138,995,794	153,327,161
Fair Value, Measurements, Recurring [Member] | 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)	0	0
Commodity Derivatives - Non - Current Asset (crude oil swaps)	0	0
Commodity Derivatives - Current Liability (crude oil swaptions)	0
Commodity Derivatives - Non-Current Liability (crude oil swaptions)		0
Total	$0	$0

FAIR_VALUE_Part_2_Details

FAIR VALUE, Part 2 (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$845.70
Debt Instrument, Unamortized Premium	7.7
Asset retirement obligations	0.2
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior unsecured notes	507.7
Revolving credit facility	338
Estimated Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior unsecured notes	$453.80

DERIVATIVE_INSTRUMENTS_AND_PRI2

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Volumes (Bbl)	3,900,000
Weighted Average Price (in dollars per barrel)	$89.66
Notional volume barrels per month (in barrels)	90,000
Increase in derivative contracts (in barrels)	90,000
Average price per barrel (in dollars per barrel)	91
Oil Swap 1 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	180,000
Fixed Price (in dollars per barrel)	89.15
Oil Swap 1 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 1 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 2 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	30,000
Fixed Price (in dollars per barrel)	90.5
Oil Swap 2 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 2 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 3 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	90,000
Fixed Price (in dollars per barrel)	88.55
Oil Swap 3 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 3 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 4 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	90,000
Fixed Price (in dollars per barrel)	88
Oil Swap 4 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 4 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 5 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	30,000
Fixed Price (in dollars per barrel)	90.75
Oil Swap 5 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 5 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 6 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	30,000
Fixed Price (in dollars per barrel)	90.25
Oil Swap 6 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 6 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 7 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	45,000
Fixed Price (in dollars per barrel)	89
Oil Swap 7 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 7 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 8 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	45,000
Fixed Price (in dollars per barrel)	89
Oil Swap 8 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 8 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-15
Oil Swap 9 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	540,000
Fixed Price (in dollars per barrel)	89
Oil Swap 9 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 9 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15
Oil Swap 10 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	270,000
Fixed Price (in dollars per barrel)	89
Oil Swap 10 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 10 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15
Oil Swap 11 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	270,000
Fixed Price (in dollars per barrel)	89.02
Oil Swap 11 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 11 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15
Oil Swap 12 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	135,000
Fixed Price (in dollars per barrel)	89
Oil Swap 12 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 12 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15
Oil Swap 13 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	135,000
Fixed Price (in dollars per barrel)	89
Oil Swap 13 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Apr-15
Oil Swap 13 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15
Oil Swap 14 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	180,000	[1]
Fixed Price (in dollars per barrel)	90.75	[1]
Oil Swap 14 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jul-15	[1]
Oil Swap 14 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15	[1]
Oil Swap 15 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	180,000	[1]
Fixed Price (in dollars per barrel)	91	[1]
Oil Swap 15 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jul-15	[1]
Oil Swap 15 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15	[1]
Oil Swap 16 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	180,000	[1]
Fixed Price (in dollars per barrel)	91.25	[1]
Oil Swap 16 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jul-15	[1]
Oil Swap 16 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	31-Dec-15	[1]
Oil Swap 17 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	360,000
Fixed Price (in dollars per barrel)	89
Oil Swap 17 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jul-15
Oil Swap 17 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-16
Oil Swap 18 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	360,000
Fixed Price (in dollars per barrel)	90
Oil Swap 18 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jul-15
Oil Swap 18 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-16
Oil Swap 19 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	360,000
Fixed Price (in dollars per barrel)	91
Oil Swap 19 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jul-15
Oil Swap 19 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-16
Oil Swap 20 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	180,000
Fixed Price (in dollars per barrel)	90
Oil Swap 20 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jan-16
Oil Swap 20 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-16
Oil Swap 21 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	90,000
Fixed Price (in dollars per barrel)	90
Oil Swap 21 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jan-16
Oil Swap 21 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-16
Oil Swap 22 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil (in barrels)	90,000
Fixed Price (in dollars per barrel)	90
Oil Swap 22 [Member] | Minimum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	1-Jan-16
Oil Swap 22 [Member] | Maximum [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Settlement Period	30-Jun-16
Open Commodity Swap 1 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes (Bbl)	2,970,000
Weighted Average Price (in dollars per barrel)	$89.56
Open Commodity Swap 2 [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Volumes (Bbl)	900,000
Weighted Average Price (in dollars per barrel)	$90
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss) on price risk derivatives not designated as hedges	$40		($6.80)
Unrealized gain (loss) on price risk derivatives not designated as hedges	($14.30)		($7.90)
[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 90,000 barrels per month are exercisable on or about December 31, 2015. If the counterparties exercise all such options, the notional volume of the Company's existing crude oil derivative contracts will increase by 90,000 barrels per month at an average price of $ 91.00 per barrel for each month during the period January 1, 2016 through June 30, 2016.

DERIVATIVE_INSTRUMENTS_AND_PRI3

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT, Part 2 (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Derivative Assets [Abstract]
Derivative Assets, Current	$124,698,923	$128,893,220
Derivative Assets, Noncurrent	14,397,517	25,013,011
Derivative Liabilities [Abstract]
Derivative Liabilities, Current	-100,646	0
Derivative Liabilities, Noncurrent	0	-579,070
Total Derivatives Liabilities	-100,646	-579,070
Total Assets [Member]
Derivative Assets [Abstract]
Total Derivatives Assets	139,096,440	153,906,231
Swap Contracts [Member] | Current Assets/Liabilities [Member]
Derivative Assets [Abstract]
Derivative Assets, Current	124,698,923	128,893,220
Swap Contracts [Member] | Non-Current Assets/Liabilities [Member]
Derivative Assets [Abstract]
Derivative Assets, Noncurrent	14,397,517	25,013,011
Swaption Contracts [Member] | Current Assets/Liabilities [Member]
Derivative Liabilities [Abstract]
Derivative Liabilities, Current	-100,646	0
Swaption Contracts [Member] | Non-Current Assets/Liabilities [Member]
Derivative Liabilities [Abstract]
Derivative Liabilities, Noncurrent	$0	($579,070)

DERIVATIVE_INSTRUMENTS_AND_PRI4

DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT, Part 3 (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets	$139,096,440	$153,906,231
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	0	0
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	139,096,440	153,906,231
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities	-100,646	-579,070
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	0	0
Net Amount of Assets Presented in the Balance Sheet, Offsetting of Derivative Liabilities	-100,646	-579,070
Current Assets [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets	124,698,923	128,893,220
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	0	0
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	124,698,923	128,893,220
Non Current Assets [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Assets	14,397,517	25,013,011
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Assets	0	0
Net Amounts of Assets Presented in the Balance Sheet, Offsetting of Derivative Assets	14,397,517	25,013,011
Current Liabilities [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities	-100,646	0
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	0	0
Net Amount of Assets Presented in the Balance Sheet, Offsetting of Derivative Liabilities	-100,646	0
Non Current Liabilities [Member]
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Assets, Offsetting of Derivative Liabilities	0	-579,070
Gross Amounts Offset in the Balance Sheet, Offsetting of Derivative Liabilities	0	0
Net Amount of Assets Presented in the Balance Sheet, Offsetting of Derivative Liabilities	$0	($579,070)