Sow Good (SOWG) 10-Q 12 Aug 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Aug. 08, 2014
Document And Entity Information	'	'
Entity Registrant Name	'Black Ridge Oil & Gas, Inc.	'
Entity Central Index Key	'0001490161	'
Document Type	'10-Q	'
Document Period End Date	30-Jun-14	'
Amendment Flag	'false	'
Current Fiscal Year End Date	'--12-31	'
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	'Q2	'
Document Fiscal Year Focus	'2014	'

CONDENSED_BALANCE_SHEETS

CONDENSED BALANCE SHEETS (USD $)	Jun. 30, 2014	Dec. 31, 2013
ASSETS	'	'
Cash and cash equivalents	$84,415	$1,150,347
Accounts receivable	4,740,795	1,905,467
Advances to operators	2,560,046	1,214,662
Prepaid expenses	41,954	26,142
Total current assets	7,427,210	4,296,618
Property and equipment:	'	'
Proved properties	91,749,159	79,361,432
Unproved properties	2,855,106	2,798,795
Other property and equipment	126,613	115,482
Total property and equipment	94,730,878	82,275,709
Less, accumulated depreciation, amortization, depletion and allowance for impairment	-13,248,024	-9,513,434
Total property and equipment, net	81,482,854	72,762,275
Debt issuance costs, net	682,358	772,883
Total assets	89,592,422	77,831,776
Current liabilities:	'	'
Accounts payable	8,543,446	8,453,709
Accrued expenses	62,853	4,813
Current portion of derivative instruments	940,926	139,065
Total current liabilities	9,547,225	8,597,587
Derivative instruments	367,909	74,611
Asset retirement obligations	211,030	160,665
Revolving credit facilities and long term debt, net of discounts of $2,475,252 and $2,645,582, respectively	42,249,343	30,556,301
Deferred tax liability	3,444,107	4,033,845
Total liabilities	55,819,614	43,423,009
Commitments and contingencies	'	'
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	33,361,756	33,072,795
Retained earnings	363,072	1,287,992
Total stockholders' equity	33,772,808	34,408,767
Total liabilities and stockholders' equity	$89,592,422	$77,831,776

CONDENSED_BALANCE_SHEETS_Paren

CONDENSED BALANCE SHEETS (Parenthetical) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Stockholders' equity:	'	'
Long term debt, net of discounts	$2,475,252	$2,645,582
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		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Statement [Abstract]	'	'	'	'
Oil and gas sales	$5,553,997	$2,151,001	$9,584,417	$4,062,300
Loss on settled derivatives	-262,719	0	-378,882	0
Losses on the mark-to-market of derivatives	-881,124	0	-1,095,159	0
Total revenues	4,410,154	2,151,001	8,110,376	4,062,300
Operating expenses:	'	'	'	'
Production expenses	595,591	269,461	1,103,054	538,267
Production taxes	591,525	232,528	996,832	451,870
General and administrative	634,109	586,860	1,404,882	1,190,438
Depletion of oil and gas properties	2,131,545	868,663	3,718,477	1,568,388
Accretion of discount on asset retirement obligations	5,148	1,811	9,653	2,963
Depreciation and amortization	8,188	5,811	16,113	11,622
Total operating expenses	3,966,106	1,965,134	7,249,011	3,763,548
Net operating income (loss)	444,048	185,867	861,365	298,752
Other income (expense):	'	'	'	'
Interest income	0	73	0	193
Interest (expense)	-1,293,123	-576,153	-2,376,023	-809,133
Total other income (expense)	-1,293,123	-576,080	-2,376,023	-808,940
Loss before provision for income taxes	-849,075	-390,213	-1,514,658	-510,188
Provision for income taxes	305,715	92,913	589,738	526,701
Net income (loss)	($543,360)	($297,300)	($924,920)	$16,513
Weighted average common shares outstanding - basic	47,979,990	47,979,990	47,979,990	47,979,990
Weighted average common shares outstanding - fully diluted	47,979,990	47,979,990	47,979,990	48,540,032
Net income (loss) per common share - basic	($0.01)	($0.01)	($0.02)	$0
Net income (loss) per common share - fully diluted	($0.01)	($0.01)	($0.02)	$0

CONDENSED_STATEMENTS_OF_CASH_F

CONDENSED STATEMENTS OF CASH FLOWS (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net income (loss)	($924,920)	$16,513
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'
Depletion of oil and gas properties	3,718,477	1,568,388
Depreciation and amortization	16,113	11,622
Amortization of debt issuance costs	145,307	399,654
Accretion of discount on asset retirement obligations	9,653	2,963
Losses on the mark-to-market of derivatives	1,095,159	0
Accrued payment in kind interest applied to long term debt	472,712	0
Amortization of original issue discount on debt	60,288	0
Amortization of debt discounts, warrants	310,042	0
Common stock warrants granted as financing costs	0	65,884
Common stock options issued to employees and directors	288,961	329,714
Deferred income taxes	-589,738	-526,701
Decrease (increase) in current assets:	'	'
Accounts receivable	-2,835,328	-911,092
Prepaid expenses	-15,812	17,798
Increase (decrease) in current liabilities:	'	'
Accounts payable	203,177	-14,833
Accrued expenses	58,040	52,517
Net cash provided by operating activities	2,012,131	1,012,427
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Proceeds from sale or swap of oil and gas properties	1,360,920	343,486
Purchases of oil and gas properties and development capital expenditures	-11,731,981	-2,675,398
Advances to operators	-3,491,089	-615,370
Purchases of other property and equipment	-11,131	0
Net cash used in investing activities	-13,873,281	-2,947,282
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Advances from revolving credit facilities and long term debt	18,700,000	4,300,000
Repayments on revolving credit facilities	-7,850,000	-2,185,006
Debt issuance costs	-54,782	-25,000
Net cash provided by financing activities	10,795,218	2,089,994
NET CHANGE IN CASH	-1,065,932	155,139
CASH AT BEGINNING OF PERIOD	1,150,347	1,417,340
CASH AT END OF PERIOD	84,415	1,572,479
SUPPLEMENTAL INFORMATION:	'	'
Interest paid	1,457,540	275,920
Income taxes paid	0	0
NON-CASH INVESTING AND FINANCING ACTIVITIES:	'	'
Net change in accounts payable for purchase of oil and gas properties	-98,778	2,198,196
Advances to operators received in swap for oil and gas properties	0	-1,200,000
Advances to operators applied to development of oil and gas properties	2,131,043	1,592,306
Capitalized asset retirement costs, net of revision in estimate	$40,712	$2,494

1_Organization_and_Nature_of_B

1. Organization and Nature of Business	6 Months Ended
	Jun. 30, 2014
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 trade its common stock 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	6 Months Ended
	Jun. 30, 2014
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. 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, 2013, which were included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013. 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. Cash and cash equivalents consist of the following:
			June 30,		December 31,
			2014		2013
	Cash		$	84,415	$	1,112,356
	Money market funds			–		37,991
	Total		$	84,415	$	1,150,347
	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 $862,356 in excess of FDIC and SIPC insured limits at June 30, 2014 and December 31, 2013, 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 June 30, 2014, and December 31, 2013, was $682,358 and $772,883, respectively. Amortization of debt issuance costs charged to interest expense were $145,307 and $399,654 for the six months ended June 30, 2014 and 2013, 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 June 30, 2014. 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 $9,443 and $9,443 for the six months ended June 30, 2014 and 2013, respectively.
	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.
	Net Income (Loss) Per Common Share
	Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, 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.
	The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2014 and 2013 are as follows:
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
	Weighted average common shares outstanding – basic			47,979,990		47,979,990		47,979,990		47,979,990
	Plus: Potentially dilutive common shares:
	Stock options and warrants			–		–		–		560,042
	Weighted average common shares outstanding – diluted			47,979,990		47,979,990		47,979,990		48,540,032
	Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 16,135,709 and 9,374,876 for the three months ended June 30, 2014 and 2013, respectively, and 16,135,709 and 8,176,209 for the six months ended June 30, 2014 and 2013, respectively.
	Segment Reporting
	Under FASB ASC 280-10-50, the Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations.
	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 $16,113 and $11,622 for the six months ended June 30, 2014 and 2013, 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 six months ended June 30, 2014 and 2013, respectively:
			Six Months Ended
			June 30,
			2014		2013
	Capitalized Certain Payroll and Other Internal Costs		$	23,944	$	10,540
	Capitalized Interest Costs			105,555		–
	Total		$	129,499	$	10,540
	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 $288,961 and $329,714 for the six months ended June 30, 2014 and 2013, 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, $310,042 and $65,884 of warrant related costs were amortized during the six months ended June 30, 2014 and 2013, respectively, pursuant to warrants granted in consideration for credit facilities, of which $310,042 and $-0- was amortized pursuant to debt discounts during the six months ended June 30, 2014 and 2013, respectively. 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, 2013.

3_Acquisition

3. Acquisition	6 Months Ended
	Jun. 30, 2014
Business Combinations [Abstract]	'
Note 3 - Acquisition	'
	On December 13, 2013, the Company acquired oil and natural gas properties from CP Exploration, LP (“CPX”) for approximately $20.6 million, net of purchase price adjustments (“the CPX Acquisition”). The properties acquired in the CPX Acquisition are comprised of leasehold interests in approximately 2,040 net leasehold acres in the Williston Basin of North Dakota and interests in 43 gross (0.92 net) producing wells on the acquired leases.
	The Company completed its valuation of the properties acquired in the CPX Acquisition which is summarized as follows:
	Purchase price of Acquired Properties	$	20,680,032
	Allocation of Purchase Price:
	Proved Oil and Gas Properties	$	20,517,903
	Unproved Oil and gas Properties		195,780
	Total fair value of oil and gas properties		20,713,683
	Asset retirement obligations(1)		(33,651	)
	Fair value of net assets acquired	$	20,680,032
	(1) The estimated fair value of the acquired asset retirement obligation was determined using the Company’s credit adjusted risk-free rate.
	The following unaudited pro forma combined results of operations for the six months ended June 30, 2014 and 2013 are presented as though the CPX Acquisition had been completed as of January 1, 2013. The pro forma combined results of operations for the six months ended June 30, 2014 and 2013 have been prepared by adjusting the historical results of the Company to include the historical results of the properties acquired in the CPX Acquisition. The supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented. The pro forma results of operations do not include any cost savings or other synergies that resulted from the CPX Acquisition or any estimated costs incurred to integrate the CPX Acquisition assets.
		Six Months Ended
		June 30,
		2014			2013
		(Unaudited)
	Boe Produced		112,270			72,057
	Revenues	$	8,110,376		$	6,144,500
	Net operating income	$	861,365		$	1,171,004
	Net income (loss)	$	(924,920	)	$	108,358
	Income (loss) per common share
	Basic	$	(0.02	)	$	0
	Diluted	$	(0.02	)	$	0

4_Property_and_Equipment

4. Property and Equipment	6 Months Ended
	Jun. 30, 2014
Property and equipment:	'
Note 4 - Property and Equipment	'
	Property and equipment at June 30, 2014 and December 31, 2013, consisted of the following:
		June 30,			December 31,
		2014			2013
	Oil and gas properties, full cost method:
	Evaluated costs	$	91,749,159		$	79,361,432
	Unevaluated costs, not subject to amortization or ceiling test		2,855,106			2,798,795
			94,604,265			82,160,227
	Other property and equipment		126,613			115,482
			94,730,878			82,275,709
	Less: Accumulated depreciation, amortization, depletion and impairments		(13,248,024	)		(9,513,434	)
	Total property and equipment, net	$	81,482,854		$	72,762,275
	The following table shows depreciation, depletion, and amortization expense by type of asset:
		Six Months Ended
		June 30,
		2014			2013
	Depletion of costs for evaluated oil and gas properties	$	3,718,477		$	1,568,388
	Depreciation and amortization of other property and equipment		16,113			11,622
	Total depreciation, amortization and depletion	$	3,734,590		$	1,580,010

5_Oil_and_Gas_Properties

5. Oil and Gas Properties	6 Months Ended
	Jun. 30, 2014
Extractive Industries [Abstract]	'
Note 5 - Oil and Gas Properties	'
	The following table summarizes gross and net productive oil wells by state at June 30, 2014 and 2013. 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.
		30-Jun-14						30-Jun-13
		Gross			Net			Gross		Net
	North Dakota		206			6.2			80		2.74
	Montana		1			0.08			1		0.08
	Total		207			6.28			81		2.82
	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 June 30, 2014 and 2013, our principal oil and gas assets included approximately 9,800 and 11,891 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 six months ended June 30, 2014 and 2013, respectively:
		Six Months Ended
		June 30,
		2014			2013
	Purchases of oil and gas properties and development costs for cash	$	11,731,981		$	2,675,398
	Purchase of oil and gas properties accrued at period-end		7,855,023			4,816,341
	Purchase of oil and gas properties accrued at beginning of period		(7,953,801	)		(2,618,145	)
	Advances to operators applied to purchase of oil and gas properties		2,131,043			1,592,306
	Capitalized asset retirement costs, net of revision in estimate		40,712			2,494
	Total purchase and development costs, oil and gas properties	$	13,804,958		$	6,468,394
	2014 Acquisitions
	During the six months ended June 30, 2014, we purchased approximately 200 net leasehold acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $1,652,551.
	2014 Divestitures
	During the six months ended June 30, 2014, we sold a total of approximately 490 net leasehold acres of oil and gas properties for total proceeds of $1,340,920. No gain or loss was recorded pursuant to the sales.
	2014 Swap Transactions
	During the six months ended June 30, 2014, we traded a total of approximately 52 net mineral acres of oil and gas properties for 40 net mineral acres and $20,000 in cash. No gain or loss was recorded pursuant to the transaction.
	2013 Acquisitions
	During the six months ended June 30, 2013, we purchased approximately 800 net leasehold acres of oil and gas properties in North Dakota. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $416,283.
	2013 Divestitures
	During the six months ended June 30, 2013, we sold a total of approximately 105 net leasehold acres of oil and gas properties for total proceeds of $343,486. No gain or loss was recorded pursuant to the sales.
	2013 Swap Transactions
	During the six months ended June 30, 2013, we traded a total of approximately 950 net mineral acres of oil and gas properties for 160 net mineral acres and approximately $1.2 million in prepaid well development costs. No gain or loss was recorded pursuant to the transaction.
	Undeveloped Acreage Expirations
	During the six months ended June 30, 2014, we had leases encompassing 4,196 net acres expire with carrying costs of $6,187,557 that had been reserved and transferred to the full cost pool subject to depletion in 2013. We estimate that approximately 6 additional net acres with carrying costs of approximately $10,002 will expire prior to the commencement of production activities on the related leased property during 2014. The carrying costs of leases we estimate will expire in 2015 have also been reserved and transferred to the full cost pool and are subject to depletion.

6_Asset_Retirement_Obligation

6. Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Note 6 - Asset Retirement Obligation	'
	The Company has asset retirement obligations 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 asset retirement obligations.
	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 six months ended June 30, 2014 and 2013:
		Six Months Ended
		June 30,
		2014		2013
	Beginning asset retirement obligation	$	160,665	$	67,145
	Revision in estimate of asset retirement obligation		–		(20,123	)
	Liabilities incurred for new wells placed in production		40,712		22,617
	Accretion of discount on asset retirement obligation		9,653		2,963
	Ending asset retirement obligation	$	211,030	$	72,602

7_Related_Party

7. Related Party	6 Months Ended
	Jun. 30, 2014
Related Party Transactions [Abstract]	'
Note 7 - Related Party	'
	We have subleased and 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. The sublease agreement was cancelled and we entered into a direct lease on April 30, 2012 to expand and occupy approximately 1,142 square feet of office space. The 2012 lease was amended effective November 15, 2013 to 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 $35,501 and $15,765 to this entity during the six months ended June 30, 2014 and 2013, respectively.

8_Derivative_Instruments

8. Derivative Instruments

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

'

Note 8 - 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 June 30, 2014, the Company had outstanding derivative contracts with respect to future production as follows:

Crude Oil Swaps

Settlement Period

Oil (Barrels)

Fixed Price

July 1, 2014 – December 31, 2014

22,002

$

94.45

July 1, 2014 – December 31, 2014

19,998

$

93.4

July 1, 2014 – December 31, 2014

18,000

$

94.9

July 1, 2014 – December 31, 2014

12,000

$

100.12

January 1, 2015 – December 31, 2015

24,000

$

88.28

January 1, 2015 – December 31, 2015

21,000

$

89.7

January 1, 2015 – December 31, 2015

12,000

$

92.37

January 1, 2016 – December 31, 2016

60,000

$

90.36

Crude Oil Costless Collars

Floor/Ceiling

Settlement Period

Oil (Barrels)

Price

Basis

January 1, 2015 – December 31, 2015

36,000

$75.00/$95.60

NYMEX

January 1, 2016 – June 30, 2016

10,002

$80.00/$89.50

NYMEX

As of June 30, 2014 the Company had total volume on open commodity swaps of 189,000 barrels at a weighted average price of approximately $92 per barrel.

Derivative Gains and Losses

The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented:

Six Months Ended

June 30,

2014

2013

Realized loss on derivatives:

Crude oil fixed price swaps

$

(378,882

)

$

–

Crude oil collars

–

–

Realized loss on derivatives, net

$

(378,882

)

$

–

Unrealized gain (loss) on derivatives:

Crude oil fixed price swaps

$

(912,071

)

$

–

Crude oil collars

(183,088

)

–

Unrealized loss on derivatives, net

$

(1,095,159

)

$

–

Balance Sheet Offsetting of Derivative Assets and Liabilities

In December 2011, the FASB issued ASU No2011-11, Balance Sheet (Topic210)-Disclosures about Offsetting Assets and Liabilities, which requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effects of netting arrangements on an entity’s financial position. The Company adopted the provision of the standard upon entering into our first derivative contract and has provided the applicable disclosures below with respect to its derivative instruments.

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.

30-Jun-14

31-Dec-13

Gross

Net

Gross

Net

Gross

amounts

amounts of

Gross

amounts

amounts of

amounts of

offset

liabilities

amounts of

offset

liabilities

recognized

on balance

on balance

recognized

on balance

on balance

liabilities

sheet

sheet

liabilities

sheet

sheet

Commodity derivative assets

$

–

$

–

$

–

$

–

$

–

$

–

30-Jun-14

31-Dec-13

Gross

Net

Gross

Net

Gross

amounts

amounts of

Gross

amounts

amounts of

amounts of

offset

liabilities

amounts of

offset

liabilities

recognized

on balance

on balance

recognized

on balance

on balance

liabilities

sheet

sheet

liabilities

sheet

sheet

Commodity derivative liabilities

$

-1,360,074

$

51,239

$

-1,308,835

$

-396,573

$

182,897

$

-213,676

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed balance sheets:

June 30,

December 31,

2014

2013

Derivative assets

$

–

$

–

Noncurrent derivative assets

–

–

Net amount of assets on the balance sheet

–

–

Current portion of derivative instruments

(940,926

)

(139,065

)

Derivative instruments

(367,909

)

(74,611

)

Net amounts of liabilities on the balance sheet

(1,308,835

)

(213,676

)

Total derivative liabilities, net

$

(1,308,835

)

$

(213,676

)

9_Fair_Value_of_Financial_Inst

9. Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
Note 9 - 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 June 30, 2014 and December 31, 2013:
		Fair Value Measurements at June 30, 2014
		Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	84,415	$	–		$	–
	Total assets		84,415		–			–
	Liabilities
	Derivative instruments (crude oil swaps and collars)		–		1,308,835			–
	Revolving credit facilities and long term debt, net of discounts		–		42,249,343			–
	Total Liabilities		–		43,558,178			–
		$	84,415	$	(43,558,178	)	$	–
		Fair Value Measurements at December 31, 2013
		Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	1,150,347	$	–		$	–
	Total assets		1,150,347		–			–
	Liabilities
	Derivative instruments (crude oil swaps and collars)		–		213,676			–
	Revolving credit facilities and long term debt, net of discounts		–		30,556,301			–
	Total Liabilities		–		30,769,977			–
		$	1,150,347	$	(30,769,977	)	$	–
	There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the six months ended June 30, 2014 and 2013.
	Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the six months ended June 30, 2014 and 2013.

10_Revolving_Credit_Facilities

10. Revolving Credit Facilities and Long Term Debt	6 Months Ended
	Jun. 30, 2014
Debt Disclosure [Abstract]	'
Note 10 - Revolving Credit Facilities and Long Term Debt	'
	Senior Credit Facility and Subordinated Credit Facilities
	The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013 and March 24, 2014 (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 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 has been increased to $20 million as a result of redeterminations. 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 will mature on August 8, 2016. 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.
	As of June 30, 2014, the Company had borrowings of $14.05 million outstanding under the Senior Credit Agreement.
	The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013 and March 24, 2014 (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 former 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 provides for initial commitment availability of $25 million, subject to customary conditions, 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 $14,700,000, 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 the Dougherty revolving credit facility. We have drawn an additional $14,700,000, net of $300,000 original issue discount through June 30, 2014. Availability under the facility is $35 million as of June 30, 2014.
	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, and 0.80 to 1.00 for the quarter ending March 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, and 3.50 to 1.00 for the quarter ended March 31, 2015 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, and 0.80 to 1.00 for the quarter ending March 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, and 3.50 to 1.00 for the quarter ending March 31, 2015 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 prior to funding with regard to no less than 50% and no greater than 75% of its future oil production on currently producing wells. The Company is in compliance with all covenants, as amended, for the period ending June 30, 2014.
	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 $310,042 was amortized during the six months ended June 30, 2014. The remaining unamortized balance of the debt discount attributable to the warrants is $1,963,902 as of June 30, 2014.
	Dougherty Revolving Credit Facility (former credit facility)
	On April 4, 2012, the Company entered into a Secured Revolving Credit Agreement with Dougherty Funding, LLC (“Dougherty”) as Lender which was subsequently amended on September 5, 2012 and December 14, 2012 with an Amended and Restated Secured Revolving Credit Agreement (collectively the “Dougherty Credit Facility”).
	The Dougherty Credit Facility provided for a maximum available amount of $20 million, of which $16.5 million was available prior to termination of the facility, with interest payable on the outstanding balance at a rate of 9.25% per year and a maturity date of August 1, 2015. In connection with the amended financing, the Company issued Dougherty Funding, LLC warrants to purchase 585,000 shares of the Company’s common stock at an exercise price of $0.38 per share. The warrants expire on August 31, 2015.
	We took our first draw on April 12, 2012 of $2,450,000, and used $2,051,722 of the proceeds to repay and terminate our predecessor PrenAnte5 revolving credit facility, including interest of $51,722.
	On September 9, 2013, we repaid the Dougherty Credit Facility with proceeds from the Subordinated Credit Facility.
	Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of June 30, 2014 and December 31, 2013, respectively:
		June 30,			December 31,
		2014			2013
	Senior Revolving Credit Facility, Cadence Bank, N.A.	$	14,050,000		$	13,000,000
	Subordinated Credit Agreement, Chambers		30,000,000			20,000,000
	PIK Interest on Subordinated Credit Agreement, Chambers		674,595			201,883
	Total credit facilities and long term debts		44,724,595			33,201,883
	Less: Unamortized OID		(511,350	)		(371,638	)
	Less: Unamortized debt discount attributable to warrants		(1,963,902	)		(2,273,944	)
	Total credit facilities and long term debts, net of discounts		42,249,343			30,556,301
	Less: current maturities		–			–
	Long term portion of credit facilities and long term debts	$	42,249,343		$	30,556,301
	Net proceeds of $29,400,000 were received from our $30,000,000 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 $60,288 was amortized during the six months ended June 30, 2014. The remaining unamortized balance of the debt discount attributable to the OID is $511,350 as of June 30, 2014.
	The following presents components of interest expense for the six months ended June 30, 2014 and 2013, respectively:
		Six Months Ended
		June 30,
		2014			2013
	Accrued PIK interest	$	472,712		$	–
	Amortization of OID		60,288			–
	Interest and commitment fees		1,493,229			343,595
	Amortization of debt issuance costs		145,307			399,654
	Amortization of warrant costs		310,042			65,884
	Less interest capitalized to the full cost pool of our proved oil & gas properties		(105,555	)		–
		$	2,376,023		$	809,133

11_Changes_in_Stockholders_Equ

11. Changes in Stockholders' Equity	6 Months Ended
	Jun. 30, 2014
Equity [Abstract]	'
Note 11 - 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.

12_Options

12. Options	6 Months Ended
	Jun. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Note 12 - Options	'
	Options Granted
	On February 10, 2014, the Company granted 27,500 options to purchase its common stock to an employee. The options vest annually over five years beginning on the first anniversary of the grant and are exercisable until the tenth anniversary of the date of grant at exercise prices of $0.782 per share. The total estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 116% and a call option value of $0.6778 was $18,639 and is being amortized over the vesting period.
	On January 30, 2014, the Company granted 5,000 options to purchase its common stock to an employee. The options vest annually over five years beginning on the first anniversary of the grant and are exercisable until the tenth anniversary of the date of grant at exercise prices of $0.63 per share. The total estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 115% and a call option value of $0.5471 was $2,735 and is being amortized over the vesting period.
	The Company recognized a total of $288,961, and $329,714 of compensation expense during the six months ended June 30, 2014 and 2013, 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 $2,115,749 as of June 30, 2014.
	Options Exercised
	No options were exercised during the six months ended June 30, 2014 and 2013.
	Options Forfeited
	No options were forfeited during the six months ended June 30, 2014 and 2013.

13_Warrants

13. Warrants	6 Months Ended
	Jun. 30, 2014
Warrants and Rights Note Disclosure [Abstract]	'
Note 13 - Warrants	'
	Warrants Granted
	No warrants were granted during the six months ended June 30, 2014 and 2013.
	We recognized a total of $310,042 and $65,884 of finance expense during the six months ended June 30, 2014 and 2013, 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 six months ended June 30, 2014 and 2013.

14_Income_Taxes

14. Income Taxes	6 Months Ended
	Jun. 30, 2014
Income Tax Disclosure [Abstract]	'
Note 14 - 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, 2014 will be approximately 37%. Losses incurred during the period from April 9, 2011 (inception) to June 30, 2014 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 June 30, 2014, net deferred tax assets were $13,453,500 after a valuation allowance applied to net deferred tax assets of approximately $567,688. 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 June 30, 2014, the Company recognized deferred tax liabilities totaling $16,897,607 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 six months ended June 30, 2014 of $589,738 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 June 30, 2014.

15_Commitments_and_Contingenci

15. Commitments and Contingencies	6 Months Ended
	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Note 15 - 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 June 30, 2014, the Company had committed to AFE’s of approximately $10.7 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 $1,057,000 in oil and gas sales and $271,000 of production taxes and operating expenses to date of which $138,000 of oil and gas revenue and $37,000 of production expenses and taxes would relate to the six months ended June 30, 2014. 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.

16_Subsequent_Events

16. Subsequent Events	6 Months Ended
	Jun. 30, 2014
Subsequent Events [Abstract]	'
Note 16 - Subsequent Events	'
	Debt Facilities
	During the period from June 30, 2014 to August 12, 2014, the Company drew an additional $1.25 million on the senior secured facility.

2_Basis_of_Presentation_and_Si1

2. Basis of Presentation and Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2014
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. Cash and cash equivalents consist of the following:
			June 30,		December 31,
			2014		2013
	Cash		$	84,415	$	1,112,356
	Money market funds			–		37,991
	Total		$	84,415	$	1,150,347
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 $862,356 in excess of FDIC and SIPC insured limits at June 30, 2014 and December 31, 2013, 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 June 30, 2014, and December 31, 2013, was $682,358 and $772,883, respectively. Amortization of debt issuance costs charged to interest expense were $145,307 and $399,654 for the six months ended June 30, 2014 and 2013, 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 June 30, 2014. 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 $9,443 and $9,443 for the six months ended June 30, 2014 and 2013, respectively.
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.
Net Income (Loss) Per Common Share	'
	Net Income (Loss) Per Common Share
	Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, 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.
	The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and six months ended June 30, 2014 and 2013 are as follows:
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
	Weighted average common shares outstanding – basic			47,979,990		47,979,990		47,979,990		47,979,990
	Plus: Potentially dilutive common shares:
	Stock options and warrants			–		–		–		560,042
	Weighted average common shares outstanding – diluted			47,979,990		47,979,990		47,979,990		48,540,032
	Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 16,135,709 and 9,374,876 for the three months ended June 30, 2014 and 2013, respectively, and 16,135,709 and 8,176,209 for the six months ended June 30, 2014 and 2013, respectively.
Segment Reporting	'
	Segment Reporting
	Under FASB ASC 280-10-50, the Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations.
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 $16,113 and $11,622 for the six months ended June 30, 2014 and 2013, 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 six months ended June 30, 2014 and 2013, respectively:
			Six Months Ended
			June 30,
			2014		2013
	Capitalized Certain Payroll and Other Internal Costs		$	23,944	$	10,540
	Capitalized Interest Costs			105,555		–
	Total		$	129,499	$	10,540
	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 $288,961 and $329,714 for the six months ended June 30, 2014 and 2013, 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, $310,042 and $65,884 of warrant related costs were amortized during the six months ended June 30, 2014 and 2013, respectively, pursuant to warrants granted in consideration for credit facilities, of which $310,042 and $-0- was amortized pursuant to debt discounts during the six months ended June 30, 2014 and 2013, respectively. 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, 2013.

2_Basis_of_Presentation_and_Si2

2. Basis of Presentation and Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2014
Accounting Policies [Abstract]	'
Cash and Cash Equivalents	'
		June 30,		December 31,
		2014		2013
	Cash	$	84,415	$	1,112,356
	Money market funds		–		37,991
	Total	$	84,415	$	1,150,347
Net Income (Loss) Per Common Share	'
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2014		2013		2014		2013
	Weighted average common shares outstanding – basic		47,979,990		47,979,990		47,979,990		47,979,990
	Plus: Potentially dilutive common shares:
	Stock options and warrants		–		–		–		560,042
	Weighted average common shares outstanding – diluted		47,979,990		47,979,990		47,979,990		48,540,032
Schedule of Capitalized Costs	'
		Six Months Ended
		June 30,
		2014		2013
	Capitalized Certain Payroll and Other Internal Costs	$	23,944	$	10,540
	Capitalized Interest Costs		105,555		–
	Total	$	129,499	$	10,540

3_Acquisition_Tables

3. Acquisition (Tables)	6 Months Ended
	Jun. 30, 2014
Business Combinations [Abstract]	'
Valuation of the properties acquired in the CPX Acquisition	'
	Purchase price of Acquired Properties	$	20,680,032
	Allocation of Purchase Price:
	Proved Oil and Gas Properties	$	20,517,903
	Unproved Oil and gas Properties		195,780
	Total fair value of oil and gas properties		20,713,683
	Asset retirement obligations(1)		(33,651	)
	Fair value of net assets acquired	$	20,680,032
Pro forma combined results of operations	'
		Six Months Ended
		June 30,
		2014			2013
		(Unaudited)
	Boe Produced		112,270			72,057
	Revenues	$	8,110,376		$	6,144,500
	Net operating income	$	861,365		$	1,171,004
	Net income (loss)	$	(924,920	)	$	108,358
	Income (loss) per common share
	Basic	$	(0.02	)	$	0
	Diluted	$	(0.02	)	$	0

4_Property_and_Equipment_Table

4. Property and Equipment (Tables)	6 Months Ended
	Jun. 30, 2014
Property and equipment:	'
Property and equipment	'
		June 30,			December 31,
		2014			2013
	Oil and gas properties, full cost method:
	Evaluated costs	$	91,749,159		$	79,361,432
	Unevaluated costs, not subject to amortization or ceiling test		2,855,106			2,798,795
			94,604,265			82,160,227
	Other property and equipment		126,613			115,482
			94,730,878			82,275,709
	Less: Accumulated depreciation, amortization, depletion and impairments		(13,248,024	)		(9,513,434	)
	Total property and equipment, net	$	81,482,854		$	72,762,275
Depreciation, depletion, and amortization expense	'
		Six Months Ended
		June 30,
		2014			2013
	Depletion of costs for evaluated oil and gas properties	$	3,718,477		$	1,568,388
	Depreciation and amortization of other property and equipment		16,113			11,622
	Total depreciation, amortization and depletion	$	3,734,590		$	1,580,010

5_Oil_and_Gas_Properties_Table

5. Oil and Gas Properties (Tables)	6 Months Ended
	Jun. 30, 2014
Extractive Industries [Abstract]	'
Gross and net productive oil wells	'
		30-Jun-14						30-Jun-13
		Gross			Net			Gross		Net
	North Dakota		206			6.2			80		2.74
	Montana		1			0.08			1		0.08
	Total		207			6.28			81		2.82
Capitalized costs	'
		Six Months Ended
		June 30,
		2014			2013
	Purchases of oil and gas properties and development costs for cash	$	11,731,981		$	2,675,398
	Purchase of oil and gas properties accrued at period-end		7,855,023			4,816,341
	Purchase of oil and gas properties accrued at beginning of period		(7,953,801	)		(2,618,145	)
	Advances to operators applied to purchase of oil and gas properties		2,131,043			1,592,306
	Capitalized asset retirement costs, net of revision in estimate		40,712			2,494
	Total purchase and development costs, oil and gas properties	$	13,804,958		$	6,468,394

6_Asset_Retirement_Obligation_

6. Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Asset retirement obligation	'
		Six Months Ended
		June 30,
		2014		2013
	Beginning asset retirement obligation	$	160,665	$	67,145
	Revision in estimate of asset retirement obligation		–		(20,123	)
	Liabilities incurred for new wells placed in production		40,712		22,617
	Accretion of discount on asset retirement obligation		9,653		2,963
	Ending asset retirement obligation	$	211,030	$	72,602

8_Derivative_Instruments_Table

8. Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

'

Outstanding derivative contracts with respect to future production

'

Crude Oil Swaps

Settlement Period

Oil (Barrels)

Fixed Price

July 1, 2014 – December 31, 2014

22,002

$

94.45

July 1, 2014 – December 31, 2014

19,998

$

93.4

July 1, 2014 – December 31, 2014

18,000

$

94.9

July 1, 2014 – December 31, 2014

12,000

$

100.12

January 1, 2015 – December 31, 2015

24,000

$

88.28

January 1, 2015 – December 31, 2015

21,000

$

89.7

January 1, 2015 – December 31, 2015

12,000

$

92.37

January 1, 2016 – December 31, 2016

60,000

$

90.36

Crude Oil Costless Collars

Floor/Ceiling

Settlement Period

Oil (Barrels)

Price

Basis

January 1, 2015 – December 31, 2015

36,000

$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

'

Six Months Ended

June 30,

2014

2013

Realized loss on derivatives:

Crude oil fixed price swaps

$

(378,882

)

$

–

Crude oil collars

–

–

Realized loss on derivatives, net

$

(378,882

)

$

–

Unrealized gain (loss) on derivatives:

Crude oil fixed price swaps

$

(912,071

)

$

–

Crude oil collars

(183,088

)

–

Unrealized loss on derivatives, net

$

(1,095,159

)

$

–

Gross amounts of recognized derivative assets and liabilities

'

30-Jun-14

31-Dec-13

Gross

Net

Gross

Net

Gross

amounts

amounts of

Gross

amounts

amounts of

amounts of

offset

liabilities

amounts of

offset

liabilities

recognized

on balance

on balance

recognized

on balance

on balance

liabilities

sheet

sheet

liabilities

sheet

sheet

Commodity derivative assets

$

–

$

–

$

–

$

–

$

–

$

–

30-Jun-14

31-Dec-13

Gross

Net

Gross

Net

Gross

amounts

amounts of

Gross

amounts

amounts of

amounts of

offset

liabilities

amounts of

offset

liabilities

recognized

on balance

on balance

recognized

on balance

on balance

liabilities

sheet

sheet

liabilities

sheet

sheet

Commodity derivative liabilities

$

-1,360,074

$

51,239

$

-1,308,835

$

-396,573

$

182,897

$

-213,676

Reconciliation of derivative assets and liabilities

'

June 30,

December 31,

2014

2013

Derivative assets

$

–

$

–

Noncurrent derivative assets

–

–

Net amount of assets on the balance sheet

–

–

Current portion of derivative instruments

(940,926

)

(139,065

)

Derivative instruments

(367,909

)

(74,611

)

Net amounts of liabilities on the balance sheet

(1,308,835

)

(213,676

)

Total derivative liabilities, net

$

(1,308,835

)

$

(213,676

)

9_Fair_Value_of_Financial_Inst1

9. Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2014
Fair Value Disclosures [Abstract]	'
Valuation of financial instruments at fair value	'
		Fair Value Measurements at June 30, 2014
		Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	84,415	$	–		$	–
	Total assets		84,415		–			–
	Liabilities
	Derivative instruments (crude oil swaps and collars)		–		1,308,835			–
	Revolving credit facilities and long term debt, net of discounts		–		42,249,343			–
	Total Liabilities		–		43,558,178			–
		$	84,415	$	(43,558,178	)	$	–
		Fair Value Measurements at December 31, 2013
		Level 1		Level 2			Level 3
	Assets
	Cash and cash equivalents	$	1,150,347	$	–		$	–
	Total assets		1,150,347		–			–
	Liabilities
	Derivative instruments (crude oil swaps and collars)		–		213,676			–
	Revolving credit facilities and long term debt, net of discounts		–		30,556,301			–
	Total Liabilities		–		30,769,977			–
		$	1,150,347	$	(30,769,977	)	$	–

10_Revolving_Credit_Facilities1

10. Revolving Credit Facilities and Long Term Debt (Tables)	6 Months Ended
	Jun. 30, 2014
Debt Disclosure [Abstract]	'
Revolving credit facility	'
		June 30,			December 31,
		2014			2013
	Senior Revolving Credit Facility, Cadence Bank, N.A.	$	14,050,000		$	13,000,000
	Subordinated Credit Agreement, Chambers		30,000,000			20,000,000
	PIK Interest on Subordinated Credit Agreement, Chambers		674,595			201,883
	Total credit facilities and long term debts		44,724,595			33,201,883
	Less: Unamortized OID		(511,350	)		(371,638	)
	Less: Unamortized debt discount attributable to warrants		(1,963,902	)		(2,273,944	)
	Total credit facilities and long term debts, net of discounts		42,249,343			30,556,301
	Less: current maturities		–			–
	Long term portion of credit facilities and long term debts	$	42,249,343		$	30,556,301
Components of interest expense	'
		Six Months Ended
		June 30,
		2014			2013
	Accrued PIK interest	$	472,712		$	–
	Amortization of OID		60,288			–
	Interest and commitment fees		1,493,229			343,595
	Amortization of debt issuance costs		145,307			399,654
	Amortization of warrant costs		310,042			65,884
	Less interest capitalized to the full cost pool of our proved oil & gas properties		(105,555	)		–
		$	2,376,023		$	809,133

2_Basis_of_Presentation_and_Si3

2. Basis of Presentation and Significant Accounting Policies (Details-Cash) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'	'	'
Cash	$84,415	$1,112,356	'	'
Money market funds	0	37,991	'	'
Total cash and cash equivalents	$84,415	$1,150,347	$1,572,479	$1,417,340

2_Basis_of_Presentation_and_Si4

2. Basis of Presentation and Significant Accounting Policies (Details-Weighted average shares)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Accounting Policies [Abstract]	'	'	'	'
Weighted average common shares outstanding basic	47,979,990	47,979,990	47,979,990	47,979,990
Stock options and warrants	0	0	0	560,042
Weighted average common shares outstanding diluted	47,979,990	47,979,990	47,979,990	48,540,032

2_Basis_of_Presentation_and_Si5

2. Basis of Presentation and Significant Accounting Policies (Details-Capitalized costs) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Total capitalized costs	$129,499	$10,540
Certain Payroll and Other Internal Costs	'	'
Total capitalized costs	23,944	10,540
Capitalized Interest Costs	'	'
Total capitalized costs	$105,555	$0

2_Basis_of_Presentation_and_Si6

2. Basis of Presentation and Significant Accounting Policies (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Accounting Policies [Abstract]	'	'	'	'	'
Cash in excess of insured limits	$0	'	$0	'	$862,356
Unamortized balance of debt issuance costs	682,358	'	682,358	'	772,883
Amortization of debt issuance costs charged to interest expense	'	'	145,307	399,654	'
Website development costs capitalized	56,660	'	56,660	'	'
Depreciation expense on website development costs	'	'	9,443	9,443	'
Depreciation of NON-Oil & Gas Property and Equipment	'	'	16,113	11,622	'
Antidilutive shares excluded from earnings per share calculation	16,135,709	9,374,876	16,135,709	8,176,209	'
Share-based compensation expense	'	'	288,961	329,714	'
Amortization of warrant costs	'	'	310,042	65,884	'
Amortization of warrant costs pursuant to debt discounts	'	'	$310,042	$0	'

3_Acquisition_DetailsPurchase_

3. Acquisition (Details-Purchase price of acquired properties) (USD $)	6 Months Ended
	Jun. 30, 2014
Purchase price of Acquired Properties	$20,680,032
Allocation of Purchase Price	'
Total fair value of oil and gas properties	20,713,683
Asset retirement obligations(1)	-33,651
Fair value of net assets acquired	20,680,032
Proved Oil and Gas Properties	'
Allocation of Purchase Price	'
Total fair value of oil and gas properties	20,517,903
Unproved Oil and Gas Properties	'
Allocation of Purchase Price	'
Total fair value of oil and gas properties	$195,780

3_Acquisition_DetailsPro_forma

3. Acquisition (Details-Pro forma results) (Boe [Member], USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
	Wells	Wells
Boe [Member]	'	'
Boe Produced	112,270	72,057
Revenues	$8,110,376	$6,144,500
Net operating income	861,365	1,171,004
Net income (loss)	($924,920)	$108,358
Income (loss) per common share	'	'
Basic	($0.02)	$0
Diluted	($0.02)	$0

4_Property_and_Equipment_Detai

4. Property and Equipment (Details-Property and equipment) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Oil and gas properties, full cost method:	'	'
Evaluated costs	$91,749,159	$79,361,432
Unevaluated costs, not subject to amortization or ceiling test	2,855,106	2,798,795
Total Oil and Gas properties full cost method	94,604,265	82,160,227
Other property and equipment	126,613	115,482
Total property plant and equipment gross	94,730,878	82,275,709
Less: Accumulated depreciation, amortization and depletion	-13,248,024	-9,513,434
Total property and equipment, net	$81,482,854	$72,762,275

4_Property_and_Equipment_Detai1

4. Property and Equipment (Details-Depreciation) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Property and equipment:	'	'	'	'
Depletion of costs for evaluated oil and gas properties	$2,131,545	$868,663	$3,718,477	$1,568,388
Depreciation and amortization of other property and equipment	8,188	5,811	16,113	11,622
Total depreciation, amortization and depletion	'	'	$3,734,590	$1,580,010

5_Oil_and_Gas_Properties_Detai

5. Oil and Gas Properties (Details-Wells)	Jun. 30, 2014	Jun. 30, 2013
	Wells	Wells
Productive oil wells, gross	207	81
Productive oil wells, net	6.28	2.82
North Dakota	'	'
Productive oil wells, gross	206	80
Productive oil wells, net	6.2	2.74
Montana	'	'
Productive oil wells, gross	1	1
Productive oil wells, net	0.08	0.08

5_Oil_and_Gas_Properties_Detai1

5. Oil and Gas Properties (Details-Development costs) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Extractive Industries [Abstract]	'	'
Purchases of oil and gas properties and development costs for cash	$11,731,981	$2,675,398
Purchase of oil and gas properties accrued at period-end	7,855,023	4,816,341
Purchase of oil and gas properties accrued at beginning of period	-7,953,801	-2,618,145
Advances to operators applied to purchase of oil and gas properties	2,131,043	1,592,306
Capitalized asset retirement costs, net of revision in estimate	40,712	2,494
Total purchase and development costs, oil and gas properties	$13,804,958	$6,468,394

5_Oil_and_Gas_Properties_Detai2

5. Oil and Gas Properties (Details Narrative) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
	acre	acre
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'	'
Oil and gas assets in acres	9,800	11,891
Oil and gas acreage purchased	200	800
Oil and gas acreage purchased - value	$1,652,551	$416,283
Oil and gas acreage sold	490	105
Oil and gas acreage sold - value	1,340,920	343,486
Oil and gas acreage traded in	52	950
Mineral acres received in swap	40	160
Other consideration received in swap	'$20,000 cash	'$1.2 million in prepaid well development costs
Net acres expired	4,196	'
Carrying cost of expired acres	$6,187,557	'

6_Asset_Retirement_Obligation_1

6. Asset Retirement Obligation (Details) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]	'	'
Beginning Asset Retirement Obligation	$160,665	$67,145
Revision in estimate of asset retirement obligation	0	-20,123
Liabilities Incurred for New Wells Placed in Production	40,712	22,617
Accretion of Discount on Asset Retirement Obligations	9,653	2,963
Ending Asset Retirement Obligation	$211,030	$72,602

7_Related_Party_Details_Narrat

7. Related Party ( Details Narrative) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Related Party Transactions [Abstract]	'	'
Rent expense	$35,501	$15,765

8_Derivative_Instruments_Detai

8. Derivative Instruments (Details-Outstanding derivative contracts)	6 Months Ended
	Jun. 30, 2014
	bbl
Crude Oil Swaps1 [Member]	'
Outstanding derivative contracts Settlement Period	'July 1, 2014 - December 31, 2014
Outstanding derivative contracts, amount of oil (in Barrels)	22,002
Outstanding derivative contract, fixed price	94.45
Crude Oil Swaps2 [Member]	'
Outstanding derivative contracts Settlement Period	'July 1, 2014 - December 31, 2014
Outstanding derivative contracts, amount of oil (in Barrels)	19,998
Outstanding derivative contract, fixed price	93.4
Crude Oil Swaps3 [Member]	'
Outstanding derivative contracts Settlement Period	'July 1, 2014 - December 31, 2014
Outstanding derivative contracts, amount of oil (in Barrels)	18,000
Outstanding derivative contract, fixed price	94.9
Crude Oil Swaps4 [Member]	'
Outstanding derivative contracts Settlement Period	'July 1, 2014 - December 31, 2014
Outstanding derivative contracts, amount of oil (in Barrels)	12,000
Outstanding derivative contract, fixed price	100.12
Crude Oil Swaps5 [Member]	'
Outstanding derivative contracts Settlement Period	'January 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	24,000
Outstanding derivative contract, fixed price	88.28
Crude Oil Swaps6 [Member]	'
Outstanding derivative contracts Settlement Period	'January 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	21,000
Outstanding derivative contract, fixed price	89.7
Crude Oil Swaps7 [Member]	'
Outstanding derivative contracts Settlement Period	'January 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	12,000
Outstanding derivative contract, fixed price	92.37
Crude Oil Swaps8 [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 Costless Collars1 [Member]	'
Outstanding derivative contracts Settlement Period	'January 1, 2015 B December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels)	36,000
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

8_Derivative_Instruments_Detai1

8. Derivative Instruments (Details-Derivative gains and losses) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Realized gain (loss) on derivatives:	'	'	'	'
Crude oil fixed price swaps	'	'	($378,882)	$0
Crude oil collars	'	'	0	0
Realized loss on derivatives, net	-262,719	0	-378,882	0
Unrealized loss on derivatives:	'	'	'	'
Crude oil fixed price swaps	'	'	-912,071	0
Crude oil collars	'	'	-183,088	0
Unrealized loss on derivatives	($881,124)	$0	($1,095,159)	$0

8_Derivative_Instruments_Detai2

8. Derivative Instruments (Details-Balance sheet derivatives) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Commodity derivative assets	$0	$0
Commodity derivative liabilities	-1,308,835	-213,676
Gross amounts recognized	'	'
Commodity derivative assets	0	0
Commodity derivative liabilities	-1,360,074	-396,573
Gross amounts offset on balance sheet	'	'
Commodity derivative assets	0	0
Commodity derivative liabilities	$51,239	$182,897

8_Derivative_Instruments_Detai3

8. Derivative Instruments (Details-Financial statement disclosure) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Derivative assets	$0	$0
Noncurrent derivative assets	0	0
Net amount of assets on the balance sheet	0	0
Current portion of derivative instruments	-940,926	-139,065
Derivative instruments	-367,909	-74,611
Net amounts of liabilities on the balance sheet	-1,308,835	-213,676
Total derivative liabilities, net	($1,308,835)	($213,676)

8_Derivative_Instruments_Detai4

8. Derivative Instruments (Details Narrative)	Jun. 30, 2014
	bbl
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Total volume on open commodity swaps, barrels	189,000
Weighted average price per barrel	92

9_Fair_Value_of_Financial_Inst2

9. Fair Value of Financial Instruments (Details-Recurring basis) (Fair Value, Measurements, Recurring [Member], USD $)	Jun. 30, 2014	Dec. 31, 2013
Fair Value Inputs Level1 [Member]	'	'
Assets	'	'
Cash and cash Equivalents	$84,415	$1,150,347
Total assets	84,415	1,150,347
Liabilities	'	'
Derivative Instruments (crude oil swaps and collars)	0	0
Revolving credit facilities	0	0
Total Liabilities	0	0
Total Assets and Liablilties	84,415	1,150,347
Fair Value Inputs Level2 [Member]	'	'
Assets	'	'
Cash and cash Equivalents	0	0
Total assets	0	0
Liabilities	'	'
Derivative Instruments (crude oil swaps and collars)	1,308,835	213,676
Revolving credit facilities	42,249,343	30,556,301
Total Liabilities	43,558,178	30,769,977
Total Assets and Liablilties	-43,558,178	-30,769,977
Fair Value Inputs Level3 [Member]	'	'
Assets	'	'
Cash and cash Equivalents	0	0
Total assets	0	0
Liabilities	'	'
Derivative Instruments (crude oil swaps and collars)	0	0
Revolving credit facilities	0	0
Total Liabilities	0	0
Total Assets and Liablilties	$0	$0

10_Revolving_Credit_Facilities2

10. Revolving Credit Facilities and Long Term Debt (Details-Debt outstanding) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Total credit facilities and long term debts	$44,724,595	$33,201,883
Less: Unamortized OID	-511,350	-371,638
Less: Unamortized debt discount attributable to warrants	-1,963,902	-2,273,944
Total credit facilities and long term debts, net of discounts	42,249,343	30,556,301
Less: current maturities	0	0
Long term portion of credit facilities and long term debts	42,249,343	30,556,301
Senior Revolving Credit Facility, Cadence Bank	'	'
Total credit facilities and long term debts	14,050,000	13,000,000
Subordinated Credit Agreement, Chambers	'	'
Total credit facilities and long term debts	30,000,000	20,000,000
PIK Interest on Subordinated Credit Agreement, Chambers	'	'
Total credit facilities and long term debts	$674,595	$201,883

10_Revolving_Credit_Facilities3

10. Revolving Credit Facilities and Long Term Debt (Details-Interest expense) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Revolving Credit Facilities, interest	$2,376,023	$809,133
Accrued PIK interest	'	'
Revolving Credit Facilities, interest	472,712	0
Amortization of OID	'	'
Revolving Credit Facilities, interest	60,288	0
Interest and commitment fees	'	'
Revolving Credit Facilities, interest	1,493,229	343,595
Amortization of debt issuance costs	'	'
Revolving Credit Facilities, interest	145,307	399,654
Amortization of warrant costs	'	'
Revolving Credit Facilities, interest	310,042	65,884
Interest capitalized	'	'
Revolving Credit Facilities, interest	($105,555)	$0

10_Revolving_Credit_Facilities4

10. Revolving Credit Facilities and Long Term Debt (Details Narrative) (USD $)	6 Months Ended
	Jun. 30, 2014
Subordinated Credit Facility	'
Amortization of debt discount	$310,042
Unamortized balance of debt discount	1,963,902
Dougherty Revolving Credit Facility	'
Amortization of debt discount	60,288
Unamortized balance of debt discount	511,350
Proceeds received from credit facility	$29,400,000

11_Changes_in_Stockholders_Equ1

11. Changes in Stockholders' Equity (Details Narrative) (USD $)	Jun. 30, 2014	Dec. 31, 2013
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

12_Options_Details_Narrative

12. Options (Details Narrative) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Feb. 10, 2014	Jan. 30, 2014
Compensation expense	$288,961	$329,714	'	'
Unamortized fair value of options	2,115,749	'	'	'
Fair value of options granted	'	'	$18,639	$2,735
Options exercised	0	'	'	'
Options forfeited	0	'	'	'
10-Feb-14	'	'	'	'
Options granted	27,500	'	'	'
30-Jan-14	'	'	'	'
Options granted	5,000	'	'	'

13_Warrants_Details_Narrative

13. Warrants (Details Narrative) (Warrants, USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Warrants	'	'
Finance expense related to warrants	$310,042	$65,884
Warrants granted	0	'
Warrants exercised	0	'

14_Income_Taxes_Details_Narrat

14. Income Taxes (Details Narrative) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Tax Disclosure [Abstract]	'	'	'	'
Deferred tax assets	$13,453,500	'	$13,453,500	'
Deferred tax assets, Valuation allowance	567,688	'	567,688	'
Deferred tax liabilities	16,897,607	'	16,897,607	'
Tax benefit	$305,715	$92,913	$589,738	$526,701
Tax rate	'	'	37.00%	'

15_Commitments_and_Contingenci1

15. Commitments and Contingencies (Details Narrative) (USD $)	6 Months Ended
	Jun. 30, 2014
Commitment to AFE (approximately)	$10,700,000
State of North Dakota	'
Proforma oil and gas revenue	138,000
Proforma oil and gas expenses	$37,000