Sow Good (SOWG) 10-Q 14 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	13-May-15
Document And Entity Information
Entity Registrant Name	Black Ridge Oil & Gas, Inc.
Entity Central Index Key	1490161
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		47,979,990
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2015

CONDENSED_BALANCE_SHEETS

CONDENSED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
ASSETS
Cash and cash equivalents	$97,781	$94,682
Derivative instruments	3,863,912	3,571,803
Accounts receivable	3,420,230	5,740,171
Prepaid expenses	38,243	41,387
Total current assets	7,420,166	9,448,043
Property and equipment:
Proved properties	118,421,670	112,418,105
Unproved properties	2,168,117	591,121
Other property and equipment	139,004	139,004
Total property and equipment	120,728,791	113,148,230
Less, accumulated depreciation, amortization, depletion and allowance for impairment	-21,536,823	-18,902,524
Total property and equipment, net	99,191,968	94,245,706
Derivative instruments	4,083,162	4,007,942
Debt issuance costs, net	604,697	701,019
Total assets	111,299,993	108,402,710
Current liabilities:
Accounts payable	11,014,273	10,291,262
Accrued expenses	68,416	57,435
Total current liabilities	11,082,689	10,348,697
Asset retirement obligations	330,557	286,804
Revolving credit facility and long term debt, net of discounts of $1,869,656 and $2,072,483, respectively	55,701,544	51,834,603
Deferred tax liability	5,957,649	6,593,040
Total liabilities	73,072,439	69,063,144
Commitments and contingencies (See note 14)
Stockholders' equity:
Preferred stock, $0.001 par value, 20,000,000 shares authorized, no shares issued and outstanding	0	0
Common stock, $0.001 par value, 500,000,000 shares authorized, 47,979,990 shares issued and outstanding	47,980	47,980
Additional paid-in capital	33,812,638	33,651,714
Retained earnings	4,366,936	5,639,872
Total stockholders' equity	38,227,554	39,339,566
Total liabilities and stockholders' equity	$111,299,993	$108,402,710

CONDENSED_BALANCE_SHEETS_Paren

CONDENSED BALANCE SHEETS (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Stockholders' equity:
Discounts on long term debt	$1,869,656	$2,072,483
Preferred stock, par value (in Dollars per share)	$0.00	$0.00
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value (in Dollars per share)	$0.00	$0.00
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	47,979,990	47,979,990
Common stock, shares outstanding	47,979,990	47,979,990

CONDENSED_STATEMENTS_OF_OPERAT

CONDENSED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Statement [Abstract]
Oil and gas sales	$2,886,456	$4,030,420
Gain (loss) on settled derivatives	1,133,421	-116,163
Gain (loss) on the mark-to-market of derivatives	367,329	-214,035
Total revenues	4,387,206	3,700,222
Operating expenses:
Production expenses	989,857	507,463
Production taxes	286,192	405,307
General and administrative	810,008	770,773
Depletion of oil and gas properties	2,630,032	1,586,932
Accretion of discount on asset retirement obligations	7,929	4,505
Depreciation and amortization	4,267	7,925
Total operating expenses	4,728,285	3,282,905
Net operating income (loss)	-341,079	417,317
Other income (expense):
Interest (expense)	-1,567,248	-1,082,900
Loss before provision for income taxes	-1,908,327	-665,583
Provision for income taxes	635,391	284,023
Net loss	($1,272,936)	($381,560)
Weighted average common shares outstanding - basic	47,979,990	47,979,990
Weighted average common shares outstanding - fully diluted	47,979,990	47,979,990
Net loss per common share - basic	($0.03)	($0.01)
Net loss per common share - fully diluted	($0.03)	($0.01)

CONDENSED_STATEMENTS_OF_CASH_F

CONDENSED STATEMENTS OF CASH FLOWS (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	($1,272,936)	($381,560)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion of oil and gas properties	2,630,032	1,586,932
Depreciation and amortization	4,267	7,925
Amortization of debt issuance costs	96,322	70,653
Accretion of discount on asset retirement obligations	7,929	4,505
(Gain) loss on the mark-to-market of derivatives	-367,329	214,035
Accrued payment in kind interest applied to long term debt	314,114	208,803
Amortization of original issue discount on debt	42,399	26,316
Amortization of debt discounts, warrants	160,428	153,522
Common stock options issued to employees and directors	160,924	144,240
Deferred income taxes	-635,391	-284,023
Decrease (increase) in current assets:
Accounts receivable	2,319,941	-1,160,467
Prepaid expenses	3,144	-8,444
Increase (decrease) in current liabilities:
Accounts payable	110,460	252,259
Accrued expenses	10,981	42,271
Net cash provided by operating activities	3,585,285	876,967
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of oil and gas properties	99,000	1,234,740
Purchases of oil and gas properties and development capital expenditures	-7,031,186	-7,582,458
Advances to operators	0	-1,410,896
Purchases of other property and equipment	0	-8,094
Net cash used in investing activities	-6,932,186	-7,766,708
CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt	5,700,000	9,350,000
Repayments on revolving credit facilities	-2,350,000	-3,550,000
Net cash provided by financing activities	3,350,000	5,800,000
NET CHANGE IN CASH	3,099	-1,089,741
CASH AT BEGINNING OF PERIOD	94,682	1,150,347
CASH AT END OF PERIOD	97,781	60,606
SUPPLEMENTAL INFORMATION:
Interest paid	1,110,083	640,978
Income taxes paid	0	0
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	612,551	-846,354
Advances to operators applied to development of oil and gas properties	0	321,904
Capitalized asset retirement costs, net of revision in estimate	$35,824	$23,259

1_Organization_and_Nature_of_B

1. Organization and Nature of Business	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Note 1 - Organization and Nature of Business	Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to be quoted on the OTCQB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010. We became a publicly traded company when our shares began trading on July 1, 2010. Since October 2010, we have been engaged in the business of acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana. Our strategy is to participate in the exploration, development and production of oil and gas reserves as a non-operating working interest owner with a growing, diversified portfolio of oil and gas wells. We aggressively seek to accumulate mineral rights and participate in the drilling of new wells on a continuous basis. Occasionally, we also purchase working interests in producing wells.
	The Company’s focus is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. We believe that our prospective success revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners.
	As a non-operating working interest partner, we participate in drilling activities primarily on a heads-up basis. Before a well is spud, an operator is required to offer all mineral lease owners in the designated well spacing unit the right to participate in the drilling and production of the well. Drilling costs and revenues from oil and gas sales are split pro-rata based on acreage ownership in the designated drilling unit. We rely on our operator partners to identify specific drilling sites, permit wells, and engage in the drilling process. As a non-operator we are focused on maintaining a low overhead structure.

2_Basis_of_Presentation_and_Si

2. Basis of Presentation and Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Note 2 - Basis of Presentation and Significant Accounting Policies	The interim condensed financial statements included herein, presented in accordance with United States generally accepted accounting principles and stated in US dollars, have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to not make the information presented misleading.
	These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2014, which were included in our Annual Report on Form 10-K filed with the SEC. The Company follows the same accounting policies in the preparation of interim reports.
	Use of Estimates
	The preparation of financial statements in conformity with generally accepted accounting principles 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 amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Environmental Liabilities
	The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company.
	Cash and Cash Equivalents
	Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at March 31, 2015 and December 31, 2014.
	Cash in Excess of FDIC Insured Limits
	The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at March 31, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts.
	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 the drilling operations within 120 days from when the advance is paid.
	Debt Issuance Costs
	Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at March 31, 2015, and December 31, 2014, was $604,697 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $96,322 and $70,653 for the three months ended March 31, 2015 and 2014, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense.
	Website Development Costs
	The Company accounts for website development costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein website development costs are segregated into three activities:
		1)	Initial stage (planning), whereby the related costs are expensed.
		2)	Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures.
		3)	Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality.
	We have capitalized a total of $56,660 of website development costs from inception through March 31, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $4,722 for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015, all website development costs have been fully depreciated.
	Income Taxes
	The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.
	Basic and Diluted Loss Per Share
	The basic net loss per share is computed by dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted net loss per common share is computed by dividing the net loss by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. For the periods presented, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.
	Fair Value of Financial Instruments
	Under FASB ASC 820-10-05, the Financial Accounting Standards Board establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement reaffirms that fair value is the relevant measurement attribute. The adoption of this standard did not have a material effect on the Company’s financial statements as reflected herein. The carrying amounts of cash, accounts payable and accrued expenses reported on the balance sheets are estimated by management to approximate fair value primarily due to the short term nature of the instruments. The Company had no items that required fair value measurement on a recurring basis.
	Non-Oil & Gas Property and Equipment
	Property and equipment that are not oil and 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 oil and 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-oil and gas long-lived assets. Depreciation expense was $4,267 and $7,925 for the three months ended March 31, 2015 and 2014, respectively.
	Revenue Recognition
	The Company recognizes oil and 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 gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover an imbalance situation.
	Asset Retirement Obligations
	The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
	Full Cost Method
	The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially 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		$	–	$	23,944
	Capitalized Interest Costs			155,991		53,774
	Total		$	155,991	$	77,718
	Proceeds from sales of proved properties 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 20% or more of the proved reserves related to a single full cost pool. The Company assesses all items classified as unevaluated property on a quarterly basis 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 amortization.
	Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 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.
	Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense.
	Stock-Based Compensation
	The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common stock and stock options issued for services and compensation totaled $160,924 and $144,240 for the three months ended March 31, 2015 and 2014, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $160,428 and $153,522 of warrant related debt discounts were amortized during the three months ended March 31, 2015 and 2014, respectively, and treated as interest expense. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility.
	Uncertain Tax Positions
	Effective upon inception at April 9, 2010, the Company adopted standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
	Various taxing authorities may periodically audit the Company’s income tax returns. These audits include questions regarding the Company’s tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. Black Ridge Oil & Gas, Inc. has not yet undergone an examination by any taxing authorities.
	The assessment of the Company’s tax position relies on the judgment of management to estimate the exposures associated with the Company’s various filing positions.
	Derivative Instruments and Price Risk Management
	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 a portion of the 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.
	Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations are recorded to gain (loss) on the mark-to-market of derivatives on the statements of operations.
	Recent Accounting Pronouncements
	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 below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.
	In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Interest–Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which changes the presentation of debt issuance costs in financial statements. ASU 2015-03 requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. It is effective for annual reporting periods beginning after December 15, 2016. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. The Company is currently in the process of evaluating the impact of adoption of ASU 2015-03 on its balance sheets.
	In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) (“ASU 2014-15”), which 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 ASU 2014-15 will have a material impact on its financial statements.
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration that is expected to be received for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted. ASU 2014-09 allows for either full retrospective or modified retrospective adoption. We do not expect the adoption of the new provisions to have a material impact on our financial condition or results of operations.

3_Property_and_Equipment

3. Property and Equipment	3 Months Ended
	Mar. 31, 2015
Property and equipment:
Note 3 - Property and Equipment	Property and equipment at March 31, 2015 and December 31, 2014, consisted of the following:
		March 31,			December 31,
		2015			2014
	Oil and gas properties, full cost method:
	Evaluated costs	$	118,421,670		$	112,418,105
	Unevaluated costs, not subject to amortization or ceiling test		2,168,117			591,121
			120,589,787			113,009,226
	Other property and equipment		139,004			139,004
			120,728,791			113,148,230
	Less: Accumulated depreciation, amortization, depletion and impairments		(21,536,823	)		(18,902,524	)
	Total property and equipment, net	$	99,191,968		$	94,245,706
	The following table shows depreciation, depletion, and amortization expense by type of asset:
		Three Months Ended
		March 31,
		2015			2014
	Depletion of costs for evaluated oil and gas properties	$	2,630,032		$	1,586,932
	Depreciation and amortization of other property and equipment		4,267			7,925
	Total depreciation, amortization and depletion	$	2,634,299		$	1,594,857

4_Oil_and_Gas_Properties

4. Oil and Gas Properties	3 Months Ended
	Mar. 31, 2015
Extractive Industries [Abstract]
Note 4 - Oil and Gas Properties	The following table summarizes gross and net productive oil wells by state at March 31, 2015 and 2014. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.
		31-Mar-15						31-Mar-14
		Gross			Net			Gross		Net
	North Dakota		281			8.42			187		5.43
	Montana		5			0.37			1		0.08
	Total		286			8.79			188		5.51
	The Company’s oil and gas properties consist of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. As of March 31, 2015 and 2014, our principal oil and gas assets included approximately 9,401 and 10,370 net acres, respectively, located in North Dakota and Montana.
	The following table summarizes our capitalized costs for the purchase and development of our oil and gas properties for the three months ended March 31, 2015 and 2014, respectively:
		Three Months Ended
		March 31,
		2015			2014
	Purchases of oil and gas properties and development costs for cash	$	7,031,186		$	7,582,458
	Purchase of oil and gas properties accrued at period-end		9,977,347			7,107,447
	Purchase of oil and gas properties accrued at beginning of period		(9,364,796	)		(7,953,801	)
	Advances to operators applied to purchase of oil and gas properties		–			321,904
	Capitalized asset retirement costs, net of revision in estimate		35,824			23,259
	Total purchase and development costs, oil and gas properties	$	7,679,561		$	7,081,267
	2015 Acquisitions
	During the three months ended March 31, 2015, we purchased approximately 9 net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $102,928.
	2015 Divestitures
	During the three months ended March 31, 2015, we sold a total of approximately 9 net leasehold acres of oil and gas properties for total proceeds of $99,000. No gain or loss was recorded pursuant to the sales.
	2014 Acquisitions
	During the three months ended March 31, 2014, we purchased approximately 199 net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,650,474.
	2014 Divestitures
	During the three months ended March 31, 2014, we sold a total of approximately 468 net leasehold acres of oil and gas properties for total proceeds of $1,234,740. No gain or loss was recorded pursuant to the sales.
	Undeveloped Acreage Expirations
	During the three months ended March 31, 2015, we had leases encompassing 567 net acres expire with carrying costs of $1,120,278 that had been reserved and transferred to the full cost pool subject to depletion in 2014. We estimate that approximately 537 additional net acres with carrying costs of approximately $769,778 will expire prior to the commencement of production activities on the related leased property during 2015. The carrying costs of leases we estimate will expire during the remainder of 2015 had been reserved and transferred to the full cost pool subject to depletion in 2014.

5_Asset_Retirement_Obligation

5. Asset Retirement Obligation	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Note 5 - Asset Retirement Obligation
	The Company has asset retirement obligations (ARO) associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling ARO.
	The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the three months ended March 31, 2015 and 2014:
		Three Months Ended
		March 31,
		2015		2014
	Beginning ARO	$	286,804	$	160,665
	Liabilities incurred for new wells placed in production		35,824		23,259
	Accretion of discount on ARO		7,929		4,505
	Ending ARO	$	330,557	$	188,429

6_Related_Party

6. Related Party	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Note 6 - Related Party
	We currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. Pursuant to the lease, we occupy approximately 2,813 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide ninety (90) day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent three year periods. We have paid a total of $17,958 and $18,719 to this entity during the three months ended March 31, 2015 and 2014, respectively.

7_Derivative_Instruments

7. Derivative Instruments	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Note 7 - Derivative Instruments	The Company is required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as cash flow hedges for accounting purposes and, as such, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in its statements of operations under the captions “Loss on settled derivatives” and “Loss on the mark-to-market of derivatives.”
	The Company has utilized swap and collar derivative contracts. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits the upside revenue potential of upward price movements.
	For a fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price and the Company is required to make a payment to the counterparty if the settlement price for any period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price and no payment is required by either party if the settlement price for any settlement period is between the floor price and the ceiling price.
	The Company’s derivative contracts are settled based on reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate (“WTI”) pricing.
	As of March 31, 2015, the Company had outstanding derivative contracts with respect to future production as follows:
	Crude Oil Swaps
	Settlement Period	Oil (Barrels)		Fixed Price
	April 1, 2015 – December 31, 2015	18,000		$	88.28
	April 1, 2015 – December 31, 2015	15,750		$	89.7
	April 1, 2015 – December 31, 2015	9,000		$	92.38
	April 1, 2015 – December 31, 2015	22,500		$	90.16
	January 1, 2016 – December 31, 2016	60,000		$	90.36
	January 1, 2016 – December 31, 2016	24,000		$	88.15
	January 1, 2017 – December 31, 2017	78,000		$	87.18
	Crude Oil Costless Collars
				Floor/Ceiling
	Settlement Period	Oil (Barrels)		Price		Basis
	April 1, 2015 – December 31, 2015	27,000		$75.00/$95.60		NYMEX
	January 1, 2016 – June 30, 2016	10,002		$80.00/$89.50		NYMEX
	As of March 31, 2015, the Company had total volume on open commodity swaps of 227,250 barrels at a weighted average price of approximately $88.88 per barrel.
	Derivative Gains and Losses
	The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented:
		Three Months Ended
		March 31,
		2015				2014
	Realized gain (loss) on derivatives:
	Crude oil fixed price swaps	$	896,133			$	(116,163	)
	Crude oil collars		237,288				–
	Realized loss on derivatives, net	$	1,133,421			$	(116,163	)
	Gain (loss) on the mark-to-market of derivatives:
	Crude oil fixed price swaps	$	405,779			$	(220,722	)
	Crude oil collars		(38,450	)			6,687
	Gain (loss) on the mark-to-market of derivatives, net	$	367,329			$	(214,035	)
	Balance Sheet Offsetting of Derivative Assets and Liabilities
	In accordance with FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities, all of the Company’s derivative contracts are carried at their fair value in the condensed balance sheets under the captions “Derivative instruments” and “Noncurrent derivative instruments”. Derivative instruments from the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed balance sheets. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under the netting arrangements with counterparties, and the resulting net amounts presented in the condensed balance sheets for the periods presented, all at fair value.
		31-Mar-15									31-Dec-14
		Gross amounts of recognized assets				Gross amounts offset on balance sheet			Net amounts of assets on balance sheet		Gross amounts of recognized assets		Gross amounts offset on balance sheet			Net amounts of assets on balance sheet
	Commodity derivative assets	$	7,955,592			$	(8,518	)	$	7,947,074	$	7,620,896	$	(41,151	)	$	7,579,745
		31-Mar-15									31-Dec-14
		Gross amounts of recognized liabilities				Gross amounts offset on balance sheet			Net amounts of liabilities on balance sheet		Gross amounts of recognized liabilities		Gross amounts offset on balance sheet			Net amounts of liabilities on balance sheet
	Commodity derivative liabilities	$	–			$	–		$	–	$	–	$	–		$	–
	The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed balance sheets:
		March 31,				December 31,
		2015				2014
	Derivative assets	$	3,863,912			$	3,571,803
	Noncurrent derivative assets		4,083,162				4,007,942
	Net amount of assets on the balance sheet		7,947,074				7,579,745
	Current portion of derivative liabilities		–				–
	Derivative liabilities		–				–
	Net amounts of liabilities on the balance sheet		–				–
	Total derivative assets (liabilities), net	$	7,947,074			$	7,579,745

8_Fair_Value_of_Financial_Inst

8. Fair Value of Financial Instruments	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Note 8 - Fair Value of Financial Instruments
	The Company adopted FASB ASC 820-10 upon inception at April 9, 2010. Under FASB ASC 820-10-5, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). The standard outlines a valuation framework and creates a fair value hierarchy in order to increase the consistency and comparability of fair value measurements and the related disclosures. Under GAAP, certain assets and liabilities must be measured at fair value, and FASB ASC 820-10-50 details the disclosures that are required for items measured at fair value.
	The Company has revolving credit facilities that must be measured under the new fair value standard. The Company’s financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy. The three levels are as follows:
	Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
	Level 2 - Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates, yield curves, etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
	Level 3 - Unobservable inputs that reflect our assumptions about the assumptions that market participants would use in pricing the asset or liability.
	The following schedule summarizes the valuation of financial instruments at fair value on a recurring basis in the balance sheets as of March 31, 2015 and December 31, 2014:
			Fair Value Measurements at March 31, 2015
			Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	97,781	$	–		$	–
	Derivative Instruments (crude oil swaps and collars)		–		7,947,074			–
	Total assets		97,781		7,947,074			–
	Liabilities
	Revolving credit facilities and long term debt, net of discounts		–		55,701,544			–
	Total Liabilities		–		55,701,544			–
		$	97,781	$	(47,754,470	)	$	–
		Fair Value Measurements at December 31, 2014
		Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	94,682	$	–		$	–
	Derivative Instruments (crude oil swaps and collars)		–		7,579,745			–
	Total assets		94,682		7,579,745			–
	Liabilities
	Revolving credit facilities and long term debt, net of discounts		–		51,834,603			–
	Total Liabilities		–		51,834,603			–
		$	94,682	$	(44,254,858	)	$	–
	There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the three months ended March 31, 2015 and 2014.
	Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the three months ended March 31, 2015 and 2014.

9_Revolving_Credit_Facilities_

9. Revolving Credit Facilities and Long Term Debt	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Note 9 - Revolving Credit Facilities and Long Term Debt	The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, and March 30, 2015 (as amended, the “Senior Credit Agreement”) with Cadence Bank, N.A. (“Cadence”), as lender (the “Senior Credit Facility”). Under the terms of the Senior Credit Agreement, a senior secured revolving line of credit in the maximum aggregate principal amount of $50 million is available from time to time (i) for direct investment in oil and gas properties, (ii) for general working capital purposes, including the issuance of letters of credit, and (iii) to refinance the then existing debt under the Company’s former credit facility with Dougherty Funding LLC.
	Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability was $35 million as of December 31, 2014, and subsequently amended to $34 million on March 30, 2015. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base.
	The Senior Credit Facility’s maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Company’s assets, including but not limited to the Company’s mineral interests in North Dakota and Montana.
	The Company had borrowings of $25.95 million and $22.6 million outstanding under the Senior Credit Agreement as of March 31, 2015 and December 31, 2014, respectively.
	Subordinated Credit Facility
	The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, and March 30, 2015 (as amended, the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders named therein (the “Subordinated Credit Facility”). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the “Credit Facilities”), and (iii) general corporate purposes.
	The Subordinated Credit Agreement provided initial commitment availability of $25 million, which was subsequently amended to the current availability of $30 million, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw was at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment.
	The Subordinated Credit Facility matures on June 30, 2017. Upon at least three business days’ written notice, the Company may prepay the entire amount under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined in the Subordinated Credit Facility, shall be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement. Prepayments made on or after the second anniversary of the funding date shall be accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility is secured by second priority interests on substantially all of the Company’s assets, including but not limited to second priority mortgages on the Company’s mineral interests in North Dakota and Montana.
	The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14.7 million, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate a previously outstanding revolving credit facility. We have drawn an additional $14.7 million, net of $300,000 original issue discounts, through March 31, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of March 31, 2015 and December 31, 2014, respectively.
	Intercreditor Agreements and Covenants
	Cadence and Chambers have entered into an Intercreditor Agreement dated August 8, 2013 (the “Intercreditor Agreement”). The Intercreditor Agreement provides that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility are subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and sets forth the respective rights, obligations and remedies of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated Credit Facility with respect to their second priority liens.
	The Credit Facilities, as amended, require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain (i) as of the last day of each fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarter ending March 31, 2015, and 0.80 to 1.00 for the quarter ending June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a ratio of current assets, including debt facility available to be drawn, to current liabilities of a minimum of 1.0 to 1.0, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014, 4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended December 31, 2014, was waived for the quarter ended March 31, 2015, and 3.50 to 1.00 for the quarters ending June 30, 2015 and September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, in each case calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain (i) as of the last day of each fiscal quarter of the Company, a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarter ending March 31, 2015, and 0.80 to 1.00 for the quarter ending June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) as of the last day of each fiscal quarter of the Company, a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014, 4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending December 31, 2014, was waived for the quarter ending March 31, 2015, and 3.50 to 1.00 for the quarters ending June 30, 2015 and September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, calculated on a modified trailing four quarter basis, (iii) as of the last day of any fiscal quarter of the Company, a consolidated cash interest coverage ratio (consolidated EBITDA to consolidated cash interest expense) of no less than 2.5 to 1.0, calculated on a modified trailing four quarter basis and (iv) as of the last day of any period of four consecutive fiscal quarters of the Company, a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements based on anticipated oil production from currently producing wells as agreed to by the lenders. The Company is in compliance with all covenants, as amended, for the period ending March 31, 2015.
	Debt Discount, Detachable Warrants
	In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $160,428 and $153,522 was amortized during the three months ended March 31, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the warrants is $1,485,321 as of March 31, 2015.
	Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of March 31, 2015 and December 31, 2014, respectively:
		March 31,			December 31,
		2015			2014
	Senior Revolving Credit Facility, Cadence Bank, N.A.	$	25,950,000		$	22,600,000
	Subordinated Credit Agreement, Chambers		30,000,000			30,000,000
	PIK Interest on Subordinated Credit Agreement, Chambers		1,621,200			1,307,086
	Total credit facilities and long term debts		57,571,200			53,907,086
	Less: Unamortized OID		(384,335	)		(426,734	)
	Less: Unamortized debt discount attributable to warrants		(1,485,321	)		(1,645,749	)
	Total credit facilities and long term debts, net of discounts		55,701,544			51,834,603
	Less: current maturities		–			–
	Long term portion of credit facilities and long term debts	$	57,701,544		$	51,834,603
	Net proceeds of $29.4 million was received from our $30 million in advances due to $600,000 of OID pursuant to the Subordinated Credit Agreement at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $42,399 and $26,316 was amortized during the three months ended March 31, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $384,335 as of March 31, 2015.
	The following presents components of interest expense for the three months ended March 31, 2015 and 2014, respectively:
		Three Months Ended
		March 31,
		2015			2014
	Accrued PIK interest	$	314,114		$	208,803
	Amortization of OID		42,399			26,316
	Interest and commitment fees		1,109,976			677,380
	Amortization of debt issuance costs		96,322			70,653
	Amortization of warrant costs		160,428			153,522
	Less interest capitalized to the full cost pool of our proved oil & gas properties		(155,991	)		(53,774	)
		$	1,567,248		$	1,082,900

10_Changes_in_Stockholders_Equ

10. Changes in Stockholders' Equity	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Note 10 - Changes in Stockholders' Equity	Preferred Stock
	The Company has 20,000,000 authorized shares of $0.001 par value preferred stock. No shares have been issued to date.
	Common Stock
	The Company has 500,000,000 authorized shares of $0.001 par value common stock.

11_Options

11. Options	3 Months Ended
	Mar. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Note 11 - Options
	Options Granted
	No options were granted during the three months ended March 31, 2015.
	The Company recognized a total of $160,924, and $144,240 of compensation expense during the three months ended March 31, 2015 and 2014, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,811,617 as of March 31, 2015.
	Options Exercised
	No options were exercised during the three months ended March 31, 2015 and 2014.
	Options Forfeited
	No options were forfeited during the three months ended March 31, 2015 and 2014.

12_Warrants

12. Warrants	3 Months Ended
	Mar. 31, 2015
Warrants and Rights Note Disclosure [Abstract]
Note 12 - Warrants	Warrants Granted
	No warrants were granted during the three months ended March 31, 2015 and 2014.
	We recognized a total of $160,428 and $153,522 of finance expense during the three months ended March 31, 2015 and 2014, respectively, on common stock warrants issued to lenders, respectively. All warrants granted pursuant to debt financings are amortized over the remaining life of the respective loan.
	Warrants Exercised
	No warrants were exercised during the three months ended March 31, 2015 and 2014.

13_Income_Taxes

13. Income Taxes	3 Months Ended
	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Note 13 - Income Taxes	The Company accounts for income taxes under ASC Topic 740, Income Taxes, which provides for an asset and liability approach of accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributed to temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes.
	We currently estimate that our effective tax rate for the year ending December 31, 2015 will be approximately 33%. Losses incurred during the period from April 9, 2011 (inception) to March 31, 2015 could be used to offset future tax liabilities. 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. As of March 31, 2015, net deferred tax assets were $14,763,123 after a valuation allowance applied to net deferred tax assets of approximately $592,944. This valuation allowance reflects an allowance on only a portion of the Company’s deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. We have not provided any valuation allowance against our deferred tax liabilities. As of March 31, 2015, the Company recognized deferred tax liabilities totaling $20,720,772 primarily related to differences in the book and tax basis amounts of the Company’s oil and gas properties resulting from the expensing of intangible drilling costs and the accelerated depreciation utilized for tax purposes.
	The tax benefit for the three months ended March 31, 2015 of $635,391 was primarily driven by the Company’s loss before provision for income taxes.
	In accordance with FASB ASC 740, the Company has evaluated its tax positions and determined there are no significant uncertain tax positions as of any date on, or before March 31, 2015.

14_Commitments_and_Contingenci

14. Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Note 14 - Commitments and Contingencies	The Company from time to time may be involved in various inquiries, administrative proceedings and litigation relating to matters arising in the normal course of business. The Company is not aware of any inquiries or administrative proceedings and is not currently a defendant in any material litigation and is not aware of any threatened litigation that could have a material effect on the Company.
	The Company periodically maintains cash balances at banks in excess of federally insured amounts. The extent of loss, if any, to be sustained as a result of any future failure of a bank or other financial institution is not subject to estimation at this time.
	The Company commits to its participation in upcoming well development by signing an Authorization for Expenditure (“AFE”). As of March 31, 2015, the Company had committed to AFE’s of approximately $9.4 million beyond amounts previously paid or accrued. Additionally, the Company acquired a lease for mineral rights from the State of North Dakota on February 14, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal 2-15H well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there is currently third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage. We have signed an AFE for the well and the operator has agreed to retroactively honor the AFE if the state is successful in defending its ownership claim. As a result we have not capitalized any of the AFE costs or recognized any sales from this well. Our proportion of the well costs, based on the AFE and our working interest, is approximately $800,000. The well started production on May 21, 2012. Had we recognized the revenue and expenses from this well, we would have recorded approximately an additional $1,171,000 in oil and gas sales and $307,000 of production taxes and operating expenses to date of which $22,000 of oil and gas revenue and $10,000 of production expenses and taxes would relate to the three months ended March 31, 2015. In the event the state is not successful in defending its ownership claim, the state is required to refund the Company the cost to purchase the lease. Recently, the State of North Dakota has engaged with multiple operators requesting payment of royalties under similar circumstances in other wells. The Company will continue to monitor these developments, which may result in the recognition of a portion of our interest in the Dahl Federal 2-15H in an upcoming financial period.

15_Subsequent_Events

15. Subsequent Events	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Note 15 - Subsequent Events	Debt Facilities
	During the period from April 1, 2015 to May 12, 2015, the Company drew an additional $0.9 million, net of repayments, on the senior secured facility.
	Crude Oil Swaps
	Between April 1, 2015 and May 14, 2015, the Company entered into crude oil swap contracts with crude oil settlements based on NYMEX WTI pricing as follows:
	Settlement Period	Oil (Barrels)	Fixed Price
	October 1, 2015 – December 31, 2015	36,000	$	61.87
	January 1, 2016 – June 30, 2016	45,000	$	62.88

2_Basis_of_Presentation_and_Si1

2. Basis of Presentation and Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with generally accepted accounting principles 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 amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Environmental Liabilities	Environmental Liabilities
	The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company.
Cash and Cash Equivalents	Cash and Cash Equivalents
	Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at March 31, 2015 and December 31, 2014.
Cash in Excess of FDIC Insured Limits	Cash in Excess of FDIC Insured Limits
	The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at March 31, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts.
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 the drilling operations within 120 days from when the advance is paid.
Debt Issuance Costs	Debt Issuance Costs
	Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at March 31, 2015, and December 31, 2014, was $604,697 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $96,322 and $70,653 for the three months ended March 31, 2015 and 2014, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense.
Website Development Costs	Website Development Costs
	The Company accounts for website development costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein website development costs are segregated into three activities:
		1)	Initial stage (planning), whereby the related costs are expensed.
		2)	Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures.
		3)	Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality.
	We have capitalized a total of $56,660 of website development costs from inception through March 31, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $4,722 for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015, all website development costs have been fully depreciated.
Income Taxes	Income Taxes
	The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.
Basic and Diluted Loss Per Share	Basic and Diluted Loss Per Share
	The basic net loss per share is computed by dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted net loss per common share is computed by dividing the net loss by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. For the periods presented, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.
Fair Value of Financial Instruments	Fair Value of Financial Instruments
	Under FASB ASC 820-10-05, the Financial Accounting Standards Board establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement reaffirms that fair value is the relevant measurement attribute. The adoption of this standard did not have a material effect on the Company’s financial statements as reflected herein. The carrying amounts of cash, accounts payable and accrued expenses reported on the balance sheets are estimated by management to approximate fair value primarily due to the short term nature of the instruments. The Company had no items that required fair value measurement on a recurring basis.
Non-Oil and Gas Property and Equipment	Non-Oil & Gas Property and Equipment
	Property and equipment that are not oil and 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 oil and 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-oil and gas long-lived assets. Depreciation expense was $4,267 and $7,925 for the three months ended March 31, 2015 and 2014, respectively.
Revenue Recognition	Revenue Recognition
	The Company recognizes oil and 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 gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover an imbalance situation.
Asset Retirement Obligations	Asset Retirement Obligations
	The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Full Cost Method	Full Cost Method
	The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially 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		$	–	$	23,944
	Capitalized Interest Costs			155,991		53,774
	Total		$	155,991	$	77,718
	Proceeds from sales of proved properties 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 20% or more of the proved reserves related to a single full cost pool. The Company assesses all items classified as unevaluated property on a quarterly basis 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 amortization.
	Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under FASB ASC 410-20-25 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.
	Capitalized costs of oil and gas properties (net of related deferred income taxes) may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and gas reserves plus the cost of unproved properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the arithmetic average first day price of oil and natural gas for the preceding twelve months to estimated future production of proved oil and gas reserves as of the end of the period, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense.
Stock-Based Compensation
	Stock-Based Compensation
	The Company adopted FASB guidance on stock based compensation upon inception at April 9, 2010. Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are recognized in the income statement based on their fair values. Expense related to common stock and stock options issued for services and compensation totaled $160,924 and $144,240 for the three months ended March 31, 2015 and 2014, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $160,428 and $153,522 of warrant related debt discounts were amortized during the three months ended March 31, 2015 and 2014, respectively, and treated as interest expense. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility.
Uncertain Tax Positions	Uncertain Tax Positions
	Effective upon inception at April 9, 2010, the Company adopted standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition.
	Various taxing authorities may periodically audit the Company’s income tax returns. These audits include questions regarding the Company’s tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. Black Ridge Oil & Gas, Inc. has not yet undergone an examination by any taxing authorities.
	The assessment of the Company’s tax position relies on the judgment of management to estimate the exposures associated with the Company’s various filing positions.
Derivative Instruments and Price Risk Management	Derivative Instruments and Price Risk Management
	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 a portion of the 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.
	Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations are recorded to gain (loss) on the mark-to-market of derivatives on the statements of operations.
Recent Accounting Pronouncements
	Recent Accounting Pronouncements
	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 below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.
	In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Interest–Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which changes the presentation of debt issuance costs in financial statements. ASU 2015-03 requires an entity to present such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. It is effective for annual reporting periods beginning after December 15, 2016. Early adoption is permitted. The new guidance will be applied retrospectively to each prior period presented. The Company is currently in the process of evaluating the impact of adoption of ASU 2015-03 on its balance sheets.
	In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) (“ASU 2014-15”), which 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 ASU 2014-15 will have a material impact on its financial statements.
	In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration that is expected to be received for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted. ASU 2014-09 allows for either full retrospective or modified retrospective adoption. We do not expect the adoption of the new provisions to have a material impact on our financial condition or results of operations.

2_Basis_of_Presentation_and_Si2

2. Basis of Presentation and Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Schedule of Capitalized Costs		Three Months Ended
		March 31,
		2015		2014
	Capitalized Certain Payroll and Other Internal Costs	$	–	$	23,944
	Capitalized Interest Costs		155,991		53,774
	Total	$	155,991	$	77,718

3_Property_and_Equipment_Table

3. Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 2015
Property and equipment:
Property and equipment		March 31,			December 31,
		2015			2014
	Oil and gas properties, full cost method:
	Evaluated costs	$	118,421,670		$	112,418,105
	Unevaluated costs, not subject to amortization or ceiling test		2,168,117			591,121
			120,589,787			113,009,226
	Other property and equipment		139,004			139,004
			120,728,791			113,148,230
	Less: Accumulated depreciation, amortization, depletion and impairments		(21,536,823	)		(18,902,524	)
	Total property and equipment, net	$	99,191,968		$	94,245,706
Depreciation, depletion, and amortization expense		Three Months Ended
		March 31,
		2015			2014
	Depletion of costs for evaluated oil and gas properties	$	2,630,032		$	1,586,932
	Depreciation and amortization of other property and equipment		4,267			7,925
	Total depreciation, amortization and depletion	$	2,634,299		$	1,594,857

4_Oil_and_Gas_Properties_Table

4. Oil and Gas Properties (Tables)	3 Months Ended
	Mar. 31, 2015
Extractive Industries [Abstract]
Gross and net productive oil wells		31-Mar-15						31-Mar-14
		Gross			Net			Gross		Net
	North Dakota		281			8.42			187		5.43
	Montana		5			0.37			1		0.08
	Total		286			8.79			188		5.51
Capitalized costs		Three Months Ended
		March 31,
		2015			2014
	Purchases of oil and gas properties and development costs for cash	$	7,031,186		$	7,582,458
	Purchase of oil and gas properties accrued at period-end		9,977,347			7,107,447
	Purchase of oil and gas properties accrued at beginning of period		(9,364,796	)		(7,953,801	)
	Advances to operators applied to purchase of oil and gas properties		–			321,904
	Capitalized asset retirement costs, net of revision in estimate		35,824			23,259
	Total purchase and development costs, oil and gas properties	$	7,679,561		$	7,081,267

5_Asset_Retirement_Obligation_

5. Asset Retirement Obligation (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation		Three Months Ended
		March 31,
		2015		2014
	Beginning ARO	$	286,804	$	160,665
	Liabilities incurred for new wells placed in production		35,824		23,259
	Accretion of discount on ARO		7,929		4,505
	Ending ARO	$	330,557	$	188,429

7_Derivative_Instruments_Table

7. Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding derivative contracts with respect to future production	Crude Oil Swaps
	Settlement Period	Oil (Barrels)		Fixed Price
	April 1, 2015 – December 31, 2015	18,000		$	88.28
	April 1, 2015 – December 31, 2015	15,750		$	89.7
	April 1, 2015 – December 31, 2015	9,000		$	92.38
	April 1, 2015 – December 31, 2015	22,500		$	90.16
	January 1, 2016 – December 31, 2016	60,000		$	90.36
	January 1, 2016 – December 31, 2016	24,000		$	88.15
	January 1, 2017 – December 31, 2017	78,000		$	87.18
	Crude Oil Costless Collars
				Floor/Ceiling
	Settlement Period	Oil (Barrels)		Price		Basis
	April 1, 2015 – December 31, 2015	27,000		$75.00/$95.60		NYMEX
	January 1, 2016 – June 30, 2016	10,002		$80.00/$89.50		NYMEX
Realized and unrealized gains and losses on derivative instruments		Three Months Ended
		March 31,
		2015				2014
	Realized gain (loss) on derivatives:
	Crude oil fixed price swaps	$	896,133			$	(116,163	)
	Crude oil collars		237,288				–
	Realized loss on derivatives, net	$	1,133,421			$	(116,163	)
	Gain (loss) on the mark-to-market of derivatives:
	Crude oil fixed price swaps	$	405,779			$	(220,722	)
	Crude oil collars		(38,450	)			6,687
	Gain (loss) on the mark-to-market of derivatives, net	$	367,329			$	(214,035	)
Gross amounts of recognized derivative assets and liabilities		31-Mar-15									31-Dec-14
		Gross amounts of recognized assets				Gross amounts offset on balance sheet			Net amounts of assets on balance sheet		Gross amounts of recognized assets		Gross amounts offset on balance sheet			Net amounts of assets on balance sheet
	Commodity derivative assets	$	7,955,592			$	(8,518	)	$	7,947,074	$	7,620,896	$	(41,151	)	$	7,579,745
		31-Mar-15									31-Dec-14
		Gross amounts of recognized liabilities				Gross amounts offset on balance sheet			Net amounts of liabilities on balance sheet		Gross amounts of recognized liabilities		Gross amounts offset on balance sheet			Net amounts of liabilities on balance sheet
	Commodity derivative liabilities	$	–			$	–		$	–	$	–	$	–		$	–
Reconciliation of derivative assets and liabilities		March 31,				December 31,
		2015				2014
	Derivative assets	$	3,863,912			$	3,571,803
	Noncurrent derivative assets		4,083,162				4,007,942
	Net amount of assets on the balance sheet		7,947,074				7,579,745
	Current portion of derivative liabilities		–				–
	Derivative liabilities		–				–
	Net amounts of liabilities on the balance sheet		–				–
	Total derivative assets (liabilities), net	$	7,947,074			$	7,579,745

8_Fair_Value_of_Financial_Inst1

8. Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Valuation of financial instruments at fair value			Fair Value Measurements at March 31, 2015
			Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	97,781	$	–		$	–
	Derivative Instruments (crude oil swaps and collars)		–		7,947,074			–
	Total assets		97,781		7,947,074			–
	Liabilities
	Revolving credit facilities and long term debt, net of discounts		–		55,701,544			–
	Total Liabilities		–		55,701,544			–
		$	97,781	$	(47,754,470	)	$	–
		Fair Value Measurements at December 31, 2014
		Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	94,682	$	–		$	–
	Derivative Instruments (crude oil swaps and collars)		–		7,579,745			–
	Total assets		94,682		7,579,745			–
	Liabilities
	Revolving credit facilities and long term debt, net of discounts		–		51,834,603			–
	Total Liabilities		–		51,834,603			–
		$	94,682	$	(44,254,858	)	$	–

9_Revolving_Credit_Facilities_1

9. Revolving Credit Facilities and Long Term Debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Revolving credit facility		March 31,			December 31,
		2015			2014
	Senior Revolving Credit Facility, Cadence Bank, N.A.	$	25,950,000		$	22,600,000
	Subordinated Credit Agreement, Chambers		30,000,000			30,000,000
	PIK Interest on Subordinated Credit Agreement, Chambers		1,621,200			1,307,086
	Total credit facilities and long term debts		57,571,200			53,907,086
	Less: Unamortized OID		(384,335	)		(426,734	)
	Less: Unamortized debt discount attributable to warrants		(1,485,321	)		(1,645,749	)
	Total credit facilities and long term debts, net of discounts		55,701,544			51,834,603
	Less: current maturities		–			–
	Long term portion of credit facilities and long term debts	$	57,701,544		$	51,834,603
Components of interest expense		Three Months Ended
		March 31,
		2015			2014
	Accrued PIK interest	$	314,114		$	208,803
	Amortization of OID		42,399			26,316
	Interest and commitment fees		1,109,976			677,380
	Amortization of debt issuance costs		96,322			70,653
	Amortization of warrant costs		160,428			153,522
	Less interest capitalized to the full cost pool of our proved oil & gas properties		(155,991	)		(53,774	)
		$	1,567,248		$	1,082,900

2_Basis_of_Presentation_and_Si3

2. Basis of Presentation and Significant Accounting Policies (Details-Capitalized costs) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Total capitalized costs	$155,991	$77,718
Certain Payroll and Other Internal Costs
Total capitalized costs	0	23,944
Capitalized Interest Costs
Total capitalized costs	$155,991	$53,774

2_Basis_of_Presentation_and_Si4

2. Basis of Presentation and Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Accounting Policies [Abstract]
Cash in excess of insured limits	$0		$0
Unamortized balance of debt issuance costs	604,697		701,019
Amortization of debt issuance costs charged to interest expense	96,322	70,653
Website development costs capitalized	56,660
Depreciation expense on website development costs	257	4,722
Depreciation of Non-Oil and Gas Property and Equipment	4,267	7,925
Share-based compensation expense	160,924	144,240
Amortization of warrant costs	$160,428	$153,522

3_Property_and_Equipment_Detai

3. Property and Equipment (Details-Property and equipment) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Oil and gas properties, full cost method:
Evaluated costs	$118,421,670	$112,418,105
Unevaluated costs, not subject to amortization or ceiling test	2,168,117	591,121
Total Oil and Gas properties full cost method	120,589,787	113,009,226
Other property and equipment	139,004	139,004
Total property plant and equipment gross	120,728,791	113,148,230
Less: Accumulated depreciation, amortization and depletion	-21,536,823	-18,902,524
Total property and equipment, net	$99,191,968	$94,245,706

3_Property_and_Equipment_Detai1

3. Property and Equipment (Details-Depreciation) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Property and equipment:
Depletion of costs for evaluated oil and gas properties	$2,630,032	$1,586,932
Depreciation and amortization of other property and equipment	4,267	7,925
Total depreciation, amortization and depletion	$2,634,299	$1,594,857

4_Oil_and_Gas_Properties_Detai

4. Oil and Gas Properties (Details-Wells)	Mar. 31, 2015	Mar. 31, 2014
	Wells	Wells
Productive oil wells, gross	286	188
Productive oil wells, net	8.79	5.51
North Dakota
Productive oil wells, gross	281	187
Productive oil wells, net	8.42	5.43
Montana
Productive oil wells, gross	5	1
Productive oil wells, net	0.37	0.08

4_Oil_and_Gas_Properties_Detai1

4. Oil and Gas Properties (Details-Development costs) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Extractive Industries [Abstract]
Purchases of oil and gas properties and development costs for cash	$7,031,186	$7,582,458
Purchase of oil and gas properties accrued at year-end	9,977,347	7,107,447
Purchase of oil and gas properties accrued at the beginning of the year	-9,364,796	-7,953,801
Advances to operators applied to development of oil and gas properties	0	321,904
Capitalized asset retirement obligations	35,824	23,259
Total purchase and development costs, oil and gas properties	$7,679,561	$7,081,267

4_Oil_and_Gas_Properties_Detai2

4. Oil and Gas Properties (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
	acre	acre
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and gas acreage acquired	9	199
Oil and gas properties acquired, cost	$102,928	$1,650,474
Oil and gas acreage sold	9	468
Proceeds from oil and gas diverstitures	99,000	1,234,740
Undeveloped acreage expirations	567
Undeveloped agreage expirations carrying costs	$1,120,278

5_Asset_Retirement_Obligation_1

5. Asset Retirement Obligation (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Asset retirement rollforward
Beginning Asset Retirement Obligation	$286,804	$160,665
Liabilities incurred for new wells placed in production	35,824	23,259
Accretion of discount on asset retirement obligations	7,929	4,505
Ending asset retirement obligation	$330,557	$188,429

6_Related_Party_Details_Narrat

6. Related Party (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Related Party Transactions [Abstract]
Rent expense	$17,958	$18,719

7_Derivative_Instruments_Detai

7. Derivative Instruments (Details-Outstanding derivative contracts)	3 Months Ended
	Mar. 31, 2015
	bbl
Crude Oil Swaps 1 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2015 B December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	18,000
Outstanding derivative contract, fixed price	88.28
Crude Oil Swaps 2 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2015 B December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	15,750
Outstanding derivative contract, fixed price	89.7
Crude Oil Swaps 3 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2015 B December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	9,000
Outstanding derivative contract, fixed price	92.38
Crude Oil Swaps 4 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	22,500
Outstanding derivative contract, fixed price	90.16
Crude Oil Swaps 5 [Member]
Outstanding derivative contracts Settlement Period	January 1, 2016 - December 31, 2016
Outstanding derivative contracts, amount of oil (in Barrels)	60,000
Outstanding derivative contract, fixed price	90.36
Crude Oil Swaps 6 [Member]
Outstanding derivative contracts Settlement Period	January 1, 2016 - December 31, 2016
Outstanding derivative contracts, amount of oil (in Barrels)	24,000
Outstanding derivative contract, fixed price	88.15
Crude Oil Swaps 7 [Member]
Outstanding derivative contracts Settlement Period	January 1, 2016 - December 31, 2016
Outstanding derivative contracts, amount of oil (in Barrels)	78,000
Outstanding derivative contract, fixed price	87.18
Crude Oil Costless Collars1 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	27,000
Outstanding derivative contracts Floor/Ceiling basis	NYMEX
Crude Oil Costless Collars1 [Member] | Minimum [Member]
Outstanding derivative contract, fixed price	75
Crude Oil Costless Collars1 [Member] | Maximum [Member]
Outstanding derivative contract, fixed price	95.6
Crude Oil Costless Collars2 [Member]
Outstanding derivative contracts Settlement Period	January 1, 2016 B June 30, 2016
Outstanding derivative contracts, amount of oil (in Barrels)	10,002
Outstanding derivative contracts Floor/Ceiling basis	NYMEX
Crude Oil Costless Collars2 [Member] | Minimum [Member]
Outstanding derivative contract, fixed price	80
Crude Oil Costless Collars2 [Member] | Maximum [Member]
Outstanding derivative contract, fixed price	89.5

7_Derivative_Instruments_Detai1

7. Derivative Instruments (Details-Derivative Gains and Losses) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Realized loss on derivatives, net	$1,133,421	($116,163)
Gain (loss) on the mark-to-market of derivatives, net	367,329	-214,035
Crude Oil Fixed Price Swap [Member]
Realized loss on derivatives, net	896,133	-116,163
Gain (loss) on the mark-to-market of derivatives, net	405,779	-220,722
Crude Oil Collars [Member]
Realized loss on derivatives, net	237,288	0
Gain (loss) on the mark-to-market of derivatives, net	($38,450)	$6,687

7_Derivative_Instruments_Detai2

7. Derivative Instruments (Details-Balance sheet derivatives) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Commodity derivative assets	$7,947,074	$7,579,745
Commodity derivative liabilities	0	0
Gross amounts recognized
Commodity derivative assets	7,955,592	7,620,896
Commodity derivative liabilities	0	0
Gross amounts offset on balance sheet
Commodity derivative assets	-8,518	-41,151
Commodity derivative liabilities	$0	$0

7_Derivative_Instruments_Detai3

7. Derivative Instruments (Details-Reconciliation of derivatives) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$3,863,912	$3,571,803
Noncurrent derivative assets	4,083,162	4,007,942
Net amount of assets on the balance sheet	7,947,074	7,579,745
Derivative liabilities	0	0
Noncurrent derivative liabilities	0	0
Net amounts of liabilities on the balance sheet	0	0
Total derivative liabilities, net	$7,947,074	$7,579,745

7_Derivative_Instruments_Detai4

7. Derivative Instruments (Details Narrative)	3 Months Ended
	Mar. 31, 2015
	bbl
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Total volume on open commodity swaps, barrels	227,250
Weighted average price per barrel	88.88

8_Fair_Value_of_Financial_Inst2

8. Fair Value of Financial Instruments (Details-Recurring basis) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Assets
Derivative Instruments	$7,947,074	$7,579,745
Fair Value Inputs Level1 [Member]
Assets
Cash and cash Equivalents		94,682
Derivative Instruments		0
Total assets		94,682
Liabilities
Revolving credit facilities		0
Total Liabilities		0
Total Assets and Liablilties		94,682
Fair Value Inputs Level2 [Member]
Assets
Cash and cash Equivalents		0
Derivative Instruments		7,579,745
Total assets		7,579,745
Liabilities
Revolving credit facilities		51,834,603
Total Liabilities		51,834,603
Total Assets and Liablilties		-44,254,858
Fair Value Inputs Level3 [Member]
Assets
Cash and cash Equivalents		0
Derivative Instruments		0
Total assets		0
Liabilities
Revolving credit facilities		0
Total Liabilities		0
Total Assets and Liablilties		0
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level1 [Member]
Assets
Cash and cash Equivalents	97,781
Derivative Instruments	0
Total assets	97,781
Liabilities
Revolving credit facilities	0
Total Liabilities	0
Total Assets and Liablilties	97,781
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level2 [Member]
Assets
Cash and cash Equivalents	0
Derivative Instruments	7,947,074
Total assets	7,947,074
Liabilities
Revolving credit facilities	55,701,544
Total Liabilities	55,701,544
Total Assets and Liablilties	-47,754,470
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level3 [Member]
Assets
Cash and cash Equivalents	0
Derivative Instruments	0
Total assets	0
Liabilities
Revolving credit facilities	0
Total Liabilities	0
Total Assets and Liablilties	$0

9_Revolving_Credit_Facilities_2

9. Revolving Credit Facilities and Long Term Debt (Details-Debt outstanding) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Credit facilities outstanding	$57,571,200	$53,907,086
Less: Unamortized OID	-384,335	-426,734
Less: Unamortized debt discount attributable to warrants	-1,485,321	-1,645,749
Total credit facilities and long term debts, net of discounts	55,701,544	51,834,603
Less: current maturities	0	0
Long term portion of credit facilities and long term debts	55,701,544	51,834,603
Senior Revolving Credit Facility, Cadence Bank
Credit facilities outstanding	25,950,000	22,600,000
Subordinated Credit Agreement, Chambers
Credit facilities outstanding	30,000,000	30,000,000
PIK Interest on Subordinated Credit Agreement, Chambers
Credit facilities outstanding	$1,621,200	$1,307,086

9_Revolving_Credit_Facilities_3

9. Revolving Credit Facilities and Long Term Debt (Details-Interest expense) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Revolving Credit Facilities, interest	$1,567,248	$1,082,900
Accrued PIK interest
Revolving Credit Facilities, interest	314,114	208,803
Amortization of OID
Revolving Credit Facilities, interest	42,399	26,316
Interest and commitment fees
Revolving Credit Facilities, interest	1,109,976	677,380
Amortization of debt issuance costs
Revolving Credit Facilities, interest	96,322	70,653
Amortization of warrant costs
Revolving Credit Facilities, interest	160,428	153,522
Interest capitalized
Revolving Credit Facilities, interest	($155,991)	($53,774)

9_Revolving_Credit_Facilities_4

9. Revolving Credit Facilities and Long Term Debt (Details Narrative) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Amortization of debt discount attributable to warrants	$160,428	$153,522
Amortization of debt discount	42,399	26,316
Unamortized balance of debt discount	1,869,656		2,072,483
Unamortized balance of debt discount attributable to OID	384,335		426,734
Subordinated Credit Facility
Amortization of debt discount attributable to warrants	160,428	153,522
Amortization of debt discount	42,399	26,316
Unamortized balance of debt discount	1,485,321
Unamortized balance of debt discount attributable to OID	384,335
Proceeds received from credit facility	29,400,000
Senior Revolving Credit Facility, Cadence Bank
Proceeds received from credit facility	$25,950,000		$22,600,000

10_Changes_in_Stockholders_Equ1

10. Changes in Stockholders' Equity (Details Narrative) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Preferred stock, par value (in Dollars per share)	$0.00	$0.00
Preferred stock, shares authorized	20,000,000	20,000,000
Common stock, par value (in Dollars per share)	$0.00	$0.00
Common stock, shares authorized	500,000,000	500,000,000

11_Options_Details_Narrative

11. Options (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Compensation expense	$160,924	$144,240
Unamortized fair value of options	$1,811,617
Options exercised	0
Options forfeited	0
Options
Options granted	0	0

12_Warrants_Details_Narrative

12. Warrants (Details Narrative) (Warrants, USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Warrants
Finance expense related to warrants	$160,428	$153,522
Warrants granted	0
Warrants exercised	0

13_Income_Taxes_Details_Narrat

13. Income Taxes (Details Narrative) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Tax Disclosure [Abstract]
Deferred tax assets	$14,763,123
Deferred tax assets, Valuation allowance	592,944
Deferred tax liabilities	20,720,772
Tax benefit	635,391	284,023
Uncertain tax positions	$0

14_Commitments_and_Contingenci1

14. Commitments and Contingencies (Details Narrative) (USD $)	3 Months Ended	37 Months Ended
	Mar. 31, 2015	Mar. 31, 2015
Commitment to AFE (approximately)	$9,400,000	$9,400,000
Dahl Federal
Proforma sales		1,171,000
Proforma expenses		307,000
Proforma oil and gas revenue	22,000
Proforma oil and gas expenses	$10,000