Sow Good (SOWG) 10-Q 12 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 10, 2015
Document And Entity Information
Entity Registrant Name	Black Ridge Oil & Gas, Inc.
Entity Central Index Key	1,490,161
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
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	Q3
Document Fiscal Year Focus	2,015

CONDENSED BALANCE SHEETS

CONDENSED BALANCE SHEETS - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 58,599	$ 94,682
Derivative instruments, current	2,693,561	3,571,803
Accounts receivable	3,861,923	5,740,171
Prepaid expenses	49,107	41,387
Total current assets	6,663,190	9,448,043
Oil and natural gas properties, full cost method of accounting:
Proved properties	128,083,460	112,418,105
Unproved properties	803,718	591,121
Other property and equipment	139,004	139,004
Total property and equipment	129,026,182	113,148,230
Less, accumulated depreciation, amortization, depletion and allowance for impairment	(78,895,166)	(18,902,524)
Total property and equipment, net	50,131,016	94,245,706
Derivative instruments, long-term	0	4,007,942
Debt issuance costs, net	463,792	701,019
Total assets	57,257,998	108,402,710
Current liabilities:
Accounts payable	8,438,772	10,291,262
Accrued expenses	65,207	57,435
Total current liabilities	8,503,979	10,348,697
Asset retirement obligations	353,095	286,804
Revolving credit facilities and long term debt, net of discounts of $1,461,093 and $2,072,483, respectively	57,458,543	51,834,603
Deferred tax liability	0	6,593,040
Total liabilities	$ 66,315,617	$ 69,063,144
Commitments and contingencies (See note 15)
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	34,117,590	33,651,714
Retained earnings (accumulated deficit)	(43,223,189)	5,639,872
Total stockholders' equity	(9,057,619)	39,339,566
Total liabilities and stockholders' equity	$ 57,257,998	$ 108,402,710

CONDENSED BALANCE SHEETS (Paren

CONDENSED BALANCE SHEETS (Parenthetical) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Stockholders' equity:
Discounts on long term debt	$ 1,461,093	$ 2,072,483
Preferred stock, par value (in Dollars per share)	$ 0.001	$ 0.001
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)	$ 0.001	$ 0.001
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 OPERATI

CONDENSED STATEMENTS OF OPERATIONS - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement [Abstract]
Oil and gas sales	$ 3,359,684	$ 5,492,326	$ 11,296,220	$ 15,076,743
Gain (loss) on settled derivatives	7,456,284	(70,253)	9,436,903	(449,135)
Gain (loss) on the mark-to-market of derivatives	(3,297,358)	2,147,798	(4,886,184)	1,052,639
Total revenues	7,518,610	7,569,871	15,846,939	15,680,247
Operating expenses:
Production expenses	887,187	670,404	3,030,707	1,773,458
Production taxes	330,186	588,923	1,171,530	1,585,755
General and administrative	754,788	690,189	2,295,241	2,095,071
Depletion of oil and gas properties	1,778,580	2,275,703	7,346,356	5,994,180
Impairment of oil and gas properties	30,995,000	0	52,634,000	0
Accretion of discount on asset retirement obligations	8,039	5,833	23,900	15,486
Depreciation and amortization	4,010	8,214	12,286	24,327
Total operating expenses	34,757,790	4,239,266	66,514,020	11,488,277
Net operating income (loss)	(27,239,180)	3,330,605	(50,667,081)	4,191,970
Other income (expense):
Other income	0	0	6,707	0
Interest income	0	972	0	972
Interest (expense)	(1,681,307)	(1,440,274)	(4,795,727)	(3,816,297)
Total other income (expense)	(1,681,307)	(1,439,302)	(4,789,020)	(3,815,325)
Income (loss) before provision for income taxes	(28,920,487)	1,891,303	(55,456,101)	376,645
Provision for income taxes	0	(700,587)	6,593,040	(110,849)
Net income (loss)	$ (28,920,487)	$ 1,190,716	$ (48,863,061)	$ 265,796
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	49,588,039	47,979,990	49,824,437
Net loss per common share - basic	$ (.60)	$ 0.02	$ (1.02)	$ 0.01
Net loss per common share - fully diluted	$ (.60)	$ 0.02	$ (1.02)	$ 0.01

CONDENSED STATEMENTS OF CASH FL

CONDENSED STATEMENTS OF CASH FLOWS - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (48,863,061)	$ 265,796
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties	7,346,356	5,994,180
Depreciation and amortization	12,286	24,327
Amortization of debt issuance costs	287,227	229,936
Accretion of discount on asset retirement obligations	23,900	15,486
Loss (gain) on the mark-to-market of derivatives	4,886,184	(1,052,639)
Accrued payment in kind interest applied to long term debt	962,550	787,344
Amortization of original issue discount on debt	127,378	102,566
Amortization of debt discounts, warrants	484,012	468,670
Common stock options issued to employees and directors	465,876	433,294
Deferred income taxes	(6,593,040)	110,849
Impairment of oil and natural gas properties	52,634,000	0
Decrease (increase) in current assets:
Accounts receivable	1,878,248	(1,233,582)
Prepaid expenses	(7,720)	(45,916)
Increase (decrease) in current liabilities:
Accounts payable	153,024	223,779
Accrued expenses	7,772	61,423
Net cash provided by operating activities	13,804,992	6,385,513
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties	127,348	1,360,920
Purchases of oil and gas properties and development capital expenditures	(17,968,423)	(17,410,744)
Advances to operators	0	(5,742,272)
Purchases of other property and equipment	0	(11,131)
Net cash used in investing activities	(17,841,075)	(21,803,227)
CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt	14,000,000	24,150,000
Repayments on revolving credit facilities	(9,950,000)	(9,600,000)
Debt issuance costs	(50,000)	(254,394)
Net cash provided by financing activities	4,000,000	14,295,606
NET CHANGE IN CASH	(36,083)	(1,122,108)
CASH AT BEGINNING OF PERIOD	94,682	1,150,347
CASH AT END OF PERIOD	58,599	28,239
SUPPLEMENTAL INFORMATION:
Interest paid	3,292,793	2,411,463
Income taxes paid	0	0
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	(2,005,514)	3,821,375
Advances to operators applied to development of oil and gas properties	0	4,285,575
Capitalized asset retirement costs, net of revision in estimate	$ 42,391	$ 61,815

1. Organization and Nature of B

1. Organization and Nature of Business	9 Months Ended
	Sep. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Business	Effective April 2, 2012, Ante5, Inc. changed its corporate name to Black Ridge Oil & Gas, Inc., and continues to be quoted on the OTCQB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010. We became a publicly traded company when our shares began trading on July 1, 2010. Since October 2010, we have been engaged in the business of acquiring oil and gas leases and participating in the drilling of wells in the Bakken and Three Forks trends in North Dakota and Montana. Our strategy is to participate in the exploration, development and production of oil and gas reserves as a non-operating working interest owner with a growing, diversified portfolio of oil and gas wells. We aggressively seek to accumulate mineral rights and participate in the drilling of new wells on a continuous basis. Occasionally, we also purchase working interests in producing wells. The Company’s focus is the acquisition, exploration, development and production of crude oil and natural gas properties, primarily in the Bakken and Three Forks trends in North Dakota and Montana. We believe that our prospective success revolves around our ability to acquire mineral rights and participate in drilling activities by virtue of our ownership of such rights and through the relationships we have developed with our operating partners. As a non-operating working interest partner, we participate in drilling activities primarily on a heads-up basis. Before a well is spud, an operator is required to offer all mineral lease owners in the designated well spacing unit the right to participate in the drilling and production of the well. Drilling costs and revenues from oil and gas sales are split pro-rata based on acreage ownership in the designated drilling unit. We rely on our operator partners to identify specific drilling sites, permit wells, and engage in the drilling process. As a non-operator we are focused on maintaining a low overhead structure.

2. Basis of Presentation and Si

2. Basis of Presentation and Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Basis of Presentation and Significant Accounting Policies	The interim condensed financial statements included herein, presented in accordance with United States generally accepted accounting principles and stated in US dollars, have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to not make the information presented misleading. These statements reflect all adjustments, which in the opinion of management, are necessary for fair presentation of the information contained therein. Except as otherwise disclosed, all such adjustments are of a normal recurring nature. It is suggested that these interim condensed financial statements be read in conjunction with the audited financial statements for the year ended December 31, 2014, which were included in our Annual Report on Form 10-K filed with the SEC. The Company follows the same accounting policies in the preparation of interim reports. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. Environmental Liabilities The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company. Cash and Cash Equivalents Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at September 30, 2015 and December 31, 2014. Cash in Excess of FDIC Insured Limits The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at September 30, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts. Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of the drilling operations within 120 days from when the advance is paid. Debt Issuance Costs Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at September 30, 2015, and December 31, 2014, was $463,792 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $287,227 and $229,936 for the nine months ended September 30, 2015 and 2014, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense. Website Development Costs The Company accounts for website development costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein website development costs are segregated into three activities: 1) Initial stage (planning), whereby the related costs are expensed. 2) Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures. 3) Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality. We have capitalized a total of $56,660 of website development costs from inception through September 30, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $14,165 for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, all website development costs have been fully depreciated. Income Taxes The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not. Basic and Diluted Loss Per Share The basic net loss per share is computed by dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted net loss per common share is computed by dividing the net loss by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2015 and 2014 are as follows: Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 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 – 1,608,049 – 1,844,447 Weighted average common shares outstanding – diluted 47,979,990 49,588,039 47,979,990 49,824,437 Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 15,757,209 and 8,249,542 for the three months ended September 30, 2015 and 2014, respectively, and 15,757,209 and 8,249,542 for the nine months ended September 30, 2015 and 2014, respectively. 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 $12,286 and $24,327 for the nine months ended September 30, 2015 and 2014, respectively. Revenue Recognition The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover an imbalance situation. Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. Full Cost Method The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the nine months ended September 30, 2015 and 2014, respectively: Nine Months Ended September 30, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ – $ 54,820 Capitalized Interest Costs 352,572 216,895 Total $ 352,572 $ 271,715 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. As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded non-cash ceiling test impairments of $52,634,000 in the nine months ended September 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the nine months ended September 30, 2014. The impairment charges affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. 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 $465,876 and $433,294 for the nine months ended September 30, 2015 and 2014, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $484,012 and $468,670 of warrant related debt discounts were amortized during the nine months ended September 30, 2015 and 2014, respectively, and treated as interest expense. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility. Uncertain Tax Positions Effective upon inception at April 9, 2010, the Company adopted standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Various taxing authorities may periodically audit the Company’s income tax returns. These audits include questions regarding the Company’s tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. Black Ridge Oil & Gas, Inc. has not yet undergone an examination by any taxing authorities. The assessment of the Company’s tax position relies on the judgment of management to estimate the exposures associated with the Company’s various filing positions. Derivative Instruments and Price Risk Management The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on a portion of the expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations are recorded to gain (loss) on the mark-to-market of derivatives on the statements of operations. Recent Accounting Pronouncements New accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Interest–Imputation of Interest (Subtopic 835-30) In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers

3. Joint Venture

3. Joint Venture	9 Months Ended
	Sep. 30, 2015
Equity Method Investments and Joint Ventures [Abstract]
Joint Venture	On July 23, 2015, the Company signed a definitive agreement with an affiliate of Merced Capital (“Merced”) to form a joint venture that will acquire and develop Williston Basin non-operated assets. The joint venture will be funded by Merced with an initial investment target of $50 Million. Investments will be subject to Merced approval, and will be managed by the Company. The joint venture assets will be managed by the Company in exchange for a management fee and reimbursement of third party expenses, and, after certain investor hurdles are met, the Company will receive a share of profits in the joint venture. The Company will also have the option to co-invest up to 25% on acquisitions and capital expenditures alongside the venture and any such co-investments will reside directly with the Company. Upon the sale of joint venture assets, the Company will also have the option to bid and acquire the assets. We have not yet commenced operations pursuant this joint venture.

4. Dahl Federal Recognition

4. Dahl Federal Recognition	9 Months Ended
	Sep. 30, 2015
Dahl Federal Recognition
Dahl Federal Recognition	During the second quarter of 2015, we recognized well costs, revenues and expenses related to the Dahl Federal 2-15H (Dahl Federal) back to the inception of the well in 2012. The Company acquired the lease for mineral rights for the acreage related to the Dahl Federal from the State of North Dakota on February 7, 2012 for 110 acres or an 8.7% working interest in the Dahl Federal well that spud on January 6, 2012. The acreage we purchased lies within the riverbed of the Missouri River and there had been third-party litigation ongoing in the State of North Dakota pertaining to the state’s ownership claim to similar riparian acreage. We had signed an AFE for the well and the operator agreed to retroactively honor the AFE if the state was successful in defending its ownership claim. As the ownership of our acreage was not certain, we determined we could not recognize the well costs, revenues and expenses until the ownership questions were resolved. In April of 2015, after a North Dakota Supreme Court ruling in favor of the State and subsequent consensus by numerous parties as to the proper survey to be used in determining the high water mark of the Missouri River, the State of North Dakota began requesting payment of royalties for wells under similar circumstances from other operators. Because we believe the ownership questions have now been resolved, we capitalized all well costs since the well’s inception, and have recognized revenues and expenses from the Dahl Federal’s first production in May of 2012. We have capitalized $927,312 of well costs related to the original AFE and subsequent improvements. We recognized $1,241,214 of oil and gas revenues, $75,359 of operating expenses and $137,860 of production taxes during the nine months ended September 30, 2015 related to production prior to 2015 in addition to actual revenue and expenses for the period.

5. Property and Equipment

5. Property and Equipment	9 Months Ended
	Sep. 30, 2015
Property and equipment:
Property and Equipment	Property and equipment at September 30, 2015 and December 31, 2014, consisted of the following: September 30, December 31, 2015 2014 Oil and gas properties, full cost method: Evaluated costs $ 128,083,460 $ 112,418,105 Unevaluated costs, not subject to amortization or ceiling test 803,718 591,121 128,887,178 113,009,226 Other property and equipment 139,004 139,004 129,026,182 113,148,230 Less: Accumulated depreciation, amortization, depletion and impairments (78,895,166 ) (18,902,524 ) Total property and equipment, net $ 50,131,016 $ 94,245,706 The following table shows depreciation, depletion, and amortization expense by type of asset: Nine Months Ended September 30, 2015 2014 Depletion of costs for evaluated oil and gas properties $ 7,346,356 $ 5,994,180 Depreciation and amortization of other property and equipment 12,286 24,327 Total depreciation, amortization and depletion $ 7,358,642 $ 6,018,507 Impairment of Oil and Gas Properties As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded non-cash ceiling test impairments of $52,634,000 in the nine months ended September 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the nine months ended September 30, 2014. The impairment charges affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

6. Oil and Gas Properties

6. Oil and Gas Properties	9 Months Ended
	Sep. 30, 2015
Extractive Industries [Abstract]
Oil and Gas Properties	The following table summarizes gross and net productive oil wells by state at September 30, 2015 and 2014. A net well represents our percentage ownership of a gross well. The following table does not include wells in which our interest is limited to royalty and overriding royalty interests. The following table also does not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation. September 30, 2015 September 30, 2014 Gross Net Gross Net North Dakota 336 10.51 230 7.28 Montana 5 0.37 1 0.08 Total 341 10.88 231 7.36 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 September 30, 2015 and 2014, our principal oil and gas assets included approximately 8,509 and 9,919 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 nine months ended September 30, 2015 and 2014, respectively: Nine Months Ended September 30, 2015 2014 Purchases of oil and gas properties and development costs for cash $ 17,968,423 $ 17,410,744 Purchase of oil and gas properties accrued at period-end 7,359,282 11,775,176 Purchase of oil and gas properties accrued at beginning of period (9,364,796 ) (7,953,801 ) Advances to operators applied to purchase of oil and gas properties – 4,285,575 Capitalized asset retirement costs, net of revision in estimate 42,391 61,815 Total purchase and development costs, oil and gas properties $ 16,005,300 $ 25,579,509 2015 Acquisitions During the nine months ended September 30, 2015, we purchased approximately nine net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $102,928. 2015 Divestitures During the nine months ended September 30, 2015, we sold a total of approximately 14 net leasehold acres of oil and gas properties and three wellbores for total proceeds of $127,348. No gain or loss was recorded pursuant to the sales. 2014 Acquisitions During the nine months ended September 30, 2014, we purchased approximately 319 net leasehold acres of oil and gas properties. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $2,401,318. 2014 Divestitures During the nine months ended September 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 nine months ended September 30, 2014, we traded approximately 52 net leasehold 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. Undeveloped Acreage Expirations During the nine months ended September 30, 2015, we had leases encompassing 1,466 net acres expire with carrying costs of $1,443,848 that had been reserved and transferred to the full cost pool subject to depletion. We estimate that approximately 400 additional net acres with carrying costs of approximately $550,563 will expire prior to the commencement of production activities on the related leased property during 2015. The carrying costs of leases we estimate will expire during the remainder of 2015 had been reserved and transferred to the full cost pool subject to depletion in 2014.

7. Asset Retirement Obligation

7. Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	The Company has asset retirement obligations (ARO) associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling ARO. The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the nine months ended September 30, 2015 and 2014: Nine Months Ended September 30, 2015 2014 Beginning ARO $ 286,804 $ 160,665 Liabilities incurred for new wells placed in production 42,391 61,815 Accretion of discount on ARO 23,900 15,486 Ending ARO $ 353,095 $ 237,966

8. Related Party

8. Related Party	9 Months Ended
	Sep. 30, 2015
Related Party Transactions [Abstract]
Related Party	We currently lease office space on a month to month basis where the lessor is an entity owned by our former CEO and current Chairman of the Board of Directors, Bradley Berman. Pursuant to the lease, we occupy approximately 2,813 square feet of office space. In accordance with this lease, our lease term remains on a month-to-month basis, provided that either party may provide ninety (90) day notice to terminate the lease, with base rents of $2,110 per month, plus common area operations and maintenance charges, and monthly parking fees of $240 per month, for the period from November 15, 2013 to October 31, 2014, and subject to increases of $117 per month beginning November 1, 2014 and for each of the subsequent three year periods. We have paid a total of $52,298 and $52,284 to this entity during the nine months ended September 30, 2015 and 2014, respectively.

9. Derivative Instruments

9. Derivative Instruments	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
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 September 30, 2015, the Company had outstanding derivative contracts with respect to future production as follows: Crude Oil Swaps Settlement Period Oil (Barrels) Fixed Price October 1, 2015 – December 31, 2015 6,000 $ 88.28 October 1, 2015 – December 31, 2015 5,250 $ 89.70 October 1, 2015 – December 31, 2015 3,000 $ 92.38 October 1, 2015 – December 31, 2015 7,500 $ 90.16 October 1, 2015 – December 31, 2015 36,000 $ 61.87 April 1, 2016 – May 31, 2016 15,000 $ 62.88 April 1, 2016 – May 31, 2016 10,000 $ 90.36 April 1, 2016 – May 31, 2016 4,000 $ 88.15 Crude Oil Costless Collars Floor/Ceiling Settlement Period Oil (Barrels) Price Basis October 1, 2015 – December 31, 2015 9,000 $75.00/$95.60 NYMEX April 1, 2016 – May 31, 2016 3,334 $80.00/$89.50 NYMEX As of September 30, 2015, the Company had total volume on open commodity swaps of 86,750 barrels at a weighted average price of approximately $73.55 per barrel. Derivative Liquidations On September 24, 2015, the Company settled all its 2017 and 2018 derivative contracts and the majority of its 2016 derivative contracts prior to the expiration of their contractual maturities, resulting in the receipt of cash proceeds totaling $6,255,000. The resulting gain is included in gain (loss) on settled derivatives for the nine months ended September 30, 2015. Derivative Gains and Losses The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented: Nine Months Ended September 30, 2015 2014 Gain (loss) on settled derivatives: Crude oil fixed price swaps $ 8,579,756 $ (449,135 ) Crude oil collars 857,147 – Gain (loss) on settled derivatives, net $ 9,436,903 $ (449,135 ) Gain (loss) on the mark-to-market of derivatives: Crude oil fixed price swaps $ (4,366,810 ) $ 1,012,502 Crude oil collars (519,374 ) 40,137 Gain (loss) on the mark-to-market of derivatives, net $ (4,886,184 ) $ 1,052,639 Balance Sheet Offsetting of Derivative Assets and Liabilities In accordance with FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities, all of the Company’s derivative contracts are carried at their fair value in the condensed balance sheets under the captions “Derivative instruments” and “Noncurrent derivative instruments”. Derivative instruments from the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed balance sheets. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under the netting arrangements with counterparties, and the resulting net amounts presented in the condensed balance sheets for the periods presented, all at fair value. September 30, 2015 December 31, 2014 Gross Net Gross Net Gross amounts amounts of Gross amounts amounts of amounts of offset assets amounts of offset assets recognized on balance on balance recognized on balance on balance assets sheet sheet assets sheet sheet Commodity derivative assets $ 2,694,001 $ (440 ) $ 2,693,561 $ 7,620,896 $ (41,151 ) $ 7,579,745 September 30, 2015 December 31, 2014 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 $ – $ – $ – $ – $ – $ – The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed balance sheets: September 30, December 31, 2015 2014 Derivative assets $ 2,693,561 $ 3,571,803 Noncurrent derivative assets – 4,007,942 Net amount of assets on the balance sheet 2,693,561 7,579,745 Current portion of derivative liabilities – – Derivative liabilities – – Net amount of liabilities on the balance sheet – – Total derivative assets (liabilities), net $ 2,693,561 $ 7,579,745

10. Fair Value of Financial Ins

10. Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
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 September 30, 2015 and December 31, 2014: Fair Value Measurements at September 30, 2015 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 58,599 $ – $ – Derivative Instruments (crude oil swaps and collars) – 2,693,561 – Total assets 58,599 2,693,561 – Liabilities Revolving credit facilities and long term debt, net of discounts – 57,458,543 – Total Liabilities – 57,458,543 – $ 58,599 $ (54,764,982 ) $ – Fair Value Measurements at December 31, 2014 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 94,682 $ – $ – Derivative Instruments (crude oil swaps and collars) – 7,579,745 – Total assets 94,682 7,579,745 – Liabilities Revolving credit facilities and long term debt, net of discounts – 51,834,603 – Total Liabilities – 51,834,603 – $ 94,682 $ (44,254,858 ) $ – There were no transfers of financial assets or liabilities between Level 1 and Level 2 inputs for the nine months ended September 30, 2015 and 2014. Level 2 liabilities include Revolving credit facilities. No fair value adjustment was necessary during the nine months ended September 30, 2015 and 2014.

11. Revolving Credit Facilities

11. Revolving Credit Facilities and Long Term Debt	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Revolving Credit Facilities and Long Term Debt	The Company, as borrower, entered into a Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015 and August 10, 2015 (as amended, the “Senior Credit Agreement ” Availability under the Senior Credit Facility is at all times subject to the then-applicable borrowing base, determined by Cadence in a manner consistent with the normal and customary oil and gas lending practices of Cadence. Availability was initially set at $7 million and is subject to periodic redeterminations. The availability was $35 million as of December 31, 2014, and subsequently adjusted to $34 million on March 30, 2015. The availability remains at $34 million, of which $26.65 million was borrowed and outstanding as of September 30, 2015. Subject to availability under the borrowing base, the Company may borrow, repay and re-borrow funds in amounts of $250,000 or more. At the Company’s election, the unpaid principal balance of any borrowings under the Senior Credit Facility may bear interest at either (i) the Base Rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 1.00% to 1.50% or (ii) the LIBOR rate, as defined in the Senior Credit Facility, plus the applicable margin, which varies from 3.00% to 3.50%. Interest is payable for Base Rate loans on the last business day of the month and for LIBOR loans on the last LIBOR business day of each LIBOR interest period. The Company is also required to pay a quarterly fee of 0.50% on any unused portion of the borrowing base, as well as a facility fee of 0.90% of the initial and any subsequent additions to the borrowing base. The Senior Credit Facility’s maturity date of August 8, 2016, was subsequently amended to January 15, 2017 pursuant to the amendment on March 30, 2015. The Company may prepay the entire amount of Base Rate loans at any time, and may prepay the entire amount of LIBOR loans upon at least three business days’ notice to Cadence. The Senior Credit Facility is secured by first priority interests in mortgages on substantially all of the Company’s assets, including but not limited to the Company’s mineral interests in North Dakota and Montana. The Company had borrowings of $26.65 million and $22.6 million outstanding under the Senior Credit Agreement as of September 30, 2015 and December 31, 2014, respectively. Subordinated Credit Facility The Company, as borrower, entered into a Second Lien Credit Agreement dated August 8, 2013 and amendments thereto dated December 13, 2013, March 24, 2014, April 21, 2014, September 11, 2014, March 30, 2015, and August 10, 2015 (as amended, the “Subordinated Credit Agreement”) by and among the Company, as borrower, Chambers Energy Management, LP, as administrative agent (“Chambers”), and the several other lenders named therein (the “Subordinated Credit Facility”). Under the Subordinated Credit Facility, term loans in the aggregate principal amount of up to $75 million are available from time to time (i) to repay the Previous Credit Facility, (ii) for fees and closing costs in connection with both the Senior Credit Facility and the Subordinated Credit Facility (together, the “Credit Facilities”), and (iii) general corporate purposes. The Subordinated Credit Agreement provided initial commitment availability of $25 million, which was subsequently amended to the current availability of $30 million, with the remaining commitments subject to the approval of Chambers and other customary conditions. The Company may borrow the available commitments in amounts of $5 million or more and shall not request borrowings of such loans more than once a month, provided that the initial draw was at least $15 million. Loans under the Subordinated Credit Facility shall be funded net of a 2% OID. The unpaid principal balance of borrowings under the Subordinated Credit Facility bears interest at the Cash Interest Rate plus the PIK Interest Rate. The Cash Interest Rate is 9.00% per annum plus a rate per annum equal to the greater of (i) 1.00% and (ii) the offered rate for three-month deposits in U.S. dollars that appears on Reuters Screen LIBOR 01 as of 11:00 a.m. (London time) on the second full LIBOR business day preceding the first day of each calendar quarter. The PIK Interest Rate is equal to 4.00% per annum. Interest is payable on the last day of each month. The Company is also required to pay an annual nonrefundable administration fee of $50,000 and a monthly availability fee computed at a rate of 0.50% per annum on the average daily amount of any unused portion of the available amount under the commitment. The Subordinated Credit Facility matures on June 30, 2017. Upon at least three business days’ written notice, the Company may prepay the entire amount under the loans, together with accrued interest. Each prepayment made prior to the second anniversary of the funding date, as defined in the Subordinated Credit Facility, shall be accompanied by a make-whole amount, as defined in the Subordinated Credit Agreement. Prepayments made on or after the second anniversary of the funding date shall be accompanied by an applicable premium, as set forth in the Subordinated Credit Agreement. The Subordinated Credit Facility is secured by second priority interests on substantially all of the Company’s assets, including but not limited to second priority mortgages on the Company’s mineral interests in North Dakota and Montana. The first funding from the Subordinated Credit Facility occurred on September 9, 2013 at which time we drew $14.7 million, net of a $300,000 original issue discount, from the Subordinated Credit Agreement and used $10,226,057 of those proceeds to repay and terminate a previously outstanding revolving credit facility. We have drawn an additional $14.7 million, net of $300,000 original issue discounts, through September 30, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of September 30, 2015 and December 31, 2014, respectively. Intercreditor Agreements and Covenants Cadence and Chambers have entered into an Intercreditor Agreement dated August 8, 2013 (the “Intercreditor Agreement”). The Intercreditor Agreement provides that any liens on the assets of the Company securing indebtedness under the Subordinated Credit Facility are subordinate to liens on the assets securing indebtedness under the Senior Credit Facility and sets forth the respective rights, obligations and remedies of the lenders under the Senior Credit Facility with respect to their first priority liens and the lenders under the Subordinated Credit Facility with respect to their second priority liens. The Credit Facilities, as amended, require customary affirmative and negative covenants for credit facilities of the respective types and sizes for companies operating in the oil and gas industry, as well as customary events of default. Furthermore, the Credit Facilities contain financial covenants that require the Company to satisfy certain specified financial ratios. The Senior Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a ratio of current assets, including debt facility available to be drawn, to current liabilities of a minimum of 1.0 to 1.0, except for the quarter ending June 30, 2014, which was waived, (iii) a net debt to EBITDAX, as defined in the Senior Credit Agreement, ratio of 3.75 to 1.00 for the quarter ended March 31, 2014, 4.25 to 1.00 for the quarters ended June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ended December 31, 2014, was waived for the quarters ended March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, in each case calculated on a modified trailing four quarter basis, (iv) a maximum senior leverage ratio of not more than 2.5 to 1.0 calculated on a modified trailing four quarter basis, and (v) a minimum interest coverage ratio of not less than 3.0 to 1.0. The Subordinated Credit Agreement requires the Company to maintain, as of the last day of each fiscal quarter of the Company, (i) a collateral coverage ratio (reserve value plus consolidated working capital to adjusted indebtedness) of at least 0.65 to 1.00 through the quarter ending June 30, 2014, 0.70 to 1.00 for the quarters ending September 30, 2014 and December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 0.70 to 1.00 for the quarter ending September 30, 2015, and 0.80 to 1.00 for the quarter ending December 31, 2015 and thereafter, (ii) a consolidated net leverage ratio (adjusted total indebtedness less the amount of unrestricted cash equivalents to consolidated EBITDA) of no more than 3.75 to 1.00 for the quarter ending March 31, 2014, 4.25 to 1.00 for the quarters ending June 30, 2014 and September 30, 2014, 4.00 to 1.00 for the quarter ending December 31, 2014, was waived for the quarters ending March 31, 2015 and June 30, 2015, and 3.50 to 1.00 for the quarter ending September 30, 2015, and 3.65 to 1.00 for the quarter ending December 31, 2015, and 3.50 to 1.00 for the quarter ending March 31, 2016 and thereafter, calculated on a modified trailing four quarter basis, (iii) 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) a ratio of consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0, except for the quarter ending June 30, 2015 when the covenant was waived. In addition, each of the Credit Facilities requires that the Company enter into hedging agreements based on anticipated oil production from currently producing wells as agreed to by the lenders. The Company is in compliance with all covenants, as amended, for the period ending September 30, 2015. Debt Discount, Detachable Warrants In connection with the Subordinated Credit Facility, the Company agreed to issue to the lenders detachable warrants to purchase up to 5,000,000 shares of the Company’s common stock at an exercise price of $0.65 per share. The warrants expire on August 8, 2018. Proceeds from the loan were allocated between the debt and equity based on the relative fair values at the time of issuance, resulting in a debt discount of $2,473,576 at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $484,012 and $468,670 was amortized during the nine months ended September 30, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the warrants is $1,161,737 as of September 30, 2015. Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of September 30, 2015 and December 31, 2014, respectively: September 30, December 31, 2015 2014 Senior Revolving Credit Facility, Cadence Bank, N.A. $ 26,650,000 $ 22,600,000 Subordinated Credit Agreement, Chambers 30,000,000 30,000,000 PIK Interest on Subordinated Credit Agreement, Chambers 2,269,636 1,307,086 Total credit facilities and long term debts 58,919,636 53,907,086 Less: Unamortized OID (299,356 ) (426,734 ) Less: Unamortized debt discount attributable to warrants (1,161,737 ) (1,645,749 ) Total credit facilities and long term debts, net of discounts 57,458,543 51,834,603 Less: current maturities – – Long term portion of credit facilities and long term debts $ 57,458,543 $ 51,834,603 Net proceeds of $29.4 million were received from our $30 million in advances due to $600,000 of OID pursuant to the Subordinated Credit Agreement at issuance that is presented as a debt discount on the balance sheet and is being amortized using the effective interest method over the life of the credit facility, which matures on June 30, 2017. A total of $127,378 and $102,566 was amortized during the nine months ended September 30, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $299,356 as of September 30, 2015. The following presents components of interest expense for the nine months ended September 30, 2015 and 2014, respectively: Nine Months Ended September 30, 2015 2014 Accrued PIK interest $ 962,551 $ 787,344 Amortization of OID 127,378 102,566 Interest and commitment fees 3,287,131 2,444,676 Amortization of debt issuance costs 287,227 229,936 Amortization of warrant costs 484,012 468,670 Less interest capitalized to the full cost pool of our proved oil & gas properties (352,572 ) (216,895 ) $ 4,795,727 $ 3,816,297

12. Changes in Stockholders' Eq

12. Changes in Stockholders' Equity	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
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.

13. Options

13. Options	9 Months Ended
	Sep. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Options	Options Granted On September 30, 2015, the Company granted 1,000,000 options to purchase its common stock to its employees and certain of its directors. 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 an exercise price of $0.172 per share. The total estimated fair value using the Black-Scholes Pricing Model, based on a volatility rate of 106% and a call option value of $0.1434 was $143,379 and is being amortized over the vesting period. The Company recognized a total of $465,876, and $433,294 of compensation expense during the nine months ended September 30, 2015 and 2014, respectively, on common stock options issued to Employees and Directors that are being amortized over the implied service term, or vesting period, of the options. The remaining unamortized balance of these options is $1,650,044 as of September 30, 2015. Options Exercised No options were exercised during the nine months ended September 30, 2015 and 2014. Options Expired/Forfeited On September 30, 2015, 1,000,000 fully vested options with a strike price of $1.00 per share were voluntarily cancelled by a director of the Company. The fair market value of the options had been fully amortized prior to forfeiture. No options expired or were forfeited during the nine months ended September 30, 2014.

14. Warrants

14. Warrants	9 Months Ended
	Sep. 30, 2015
Warrants and Rights Note Disclosure [Abstract]
Warrants	Warrants Granted No warrants were granted during the nine months ended September 30, 2015 and 2014. We recognized a total of $484,012 and $468,670 of finance expense during the nine months ended September 30, 2015 and 2014, respectively, on common stock warrants issued to lenders, respectively. All warrants granted pursuant to debt financings are amortized over the remaining life of the respective loan. Warrants Exercised No warrants were exercised during the nine months ended September 30, 2015 and 2014.

15. Income Taxes

15. Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	The Company accounts for income taxes under ASC Topic 740, Income Taxes, We currently estimate that our effective tax rate for the year ending December 31, 2015 will be approximately 12%. Losses incurred during the period from April 9, 2011 (inception) to September 30, 2015 could be used to offset future tax liabilities. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized. As of September 30, 2015, net deferred tax assets were $15,417,147, after an offsetting reduction in deferred tax liabilities of $1,066,200, 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, was applied. A valuation allowance of approximately $15,417,147 was applied to the remaining net deferred tax assets. 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, which were netted against our deferred tax assets. The tax benefit for the nine months ended September 30, 2015 of $6,593,040 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 September 30, 2015.

16. Commitments and Contingenci

16. Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
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 September 30, 2015, the Company had committed to AFE’s of approximately $1.6 million beyond amounts previously paid or accrued.

17. Subsequent Events

17. Subsequent Events	9 Months Ended
	Sep. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	Debt Facilities During the period from October 1, 2015 to November 10, 2015, the Company drew an additional $0.25 million, net of repayments, on the senior secured facility. Borrowing Base Redetermination The borrowing base on our Senior Secured Facility was adjusted by our lender as part of a regularly scheduled redetermination from $34 million to $33 million effective October 1, 2015. The borrowing base will adjust down to $32 million on November 16, 2015 if certain commodity hedging is not put in place. The next scheduled borrowing base amount determination date is April 1, 2016.

2. Basis of Presentation and 23

2. Basis of Presentation and Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Environmental Liabilities	Environmental Liabilities The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial losses from environmental accidents or events which would have a material effect on the Company.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash equivalents include money market accounts which have maturities of three months or less. For the purpose of the statements of cash flows, all highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. Cash equivalents are stated at cost plus accrued interest, which approximates market value. No cash equivalents were on hand at September 30, 2015 and December 31, 2014.
Cash in Excess of FDIC Insured Limits	Cash in Excess of FDIC Insured Limits The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) and the Securities Investor Protection Corporation (SIPC) up to $250,000 and $500,000, respectively, under current regulations. The Company had approximately $-0- and $-0- in excess of FDIC and SIPC insured limits at September 30, 2015 and December 31, 2014, respectively. The Company has not experienced any losses in such accounts.
Advances to Operators	Advances to Operators The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of the drilling operations within 120 days from when the advance is paid.
Debt Issuance Costs	Debt Issuance Costs Costs relating to obtaining our revolving credit facilities are capitalized and amortized over the term of the related debt using the straight-line method. The unamortized balance of debt issuance costs at September 30, 2015, and December 31, 2014, was $463,792 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense were $287,227 and $229,936 for the nine months ended September 30, 2015 and 2014, respectively. When a loan is paid in full, any unamortized financing costs are removed from the related accounts and charged to interest expense.
Website Development Costs	Website Development Costs The Company accounts for website development costs in accordance with ASC 350-50, “Accounting for Website Development Costs” (“ASC 350-50”), wherein website development costs are segregated into three activities: 1) Initial stage (planning), whereby the related costs are expensed. 2) Development (web application, infrastructure, graphics), whereby the related costs are capitalized and amortized once the website is ready for use. Costs for development content of the website may be expensed or capitalized depending on the circumstances of the expenditures. 3) Post-implementation (after site is up and running: security, training, admin), whereby the related costs are expensed as incurred. Upgrades are usually expensed, unless they add additional functionality. We have capitalized a total of $56,660 of website development costs from inception through September 30, 2015. We depreciate our website development costs on a straight line basis over the estimated useful life of the assets, which is currently three years. We have recognized depreciation expense on these website costs of $257 and $14,165 for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, all website development costs have been fully depreciated.
Income Taxes	Income Taxes The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.
Basic and Diluted Loss Per Share	Basic and Diluted Loss Per Share The basic net loss per share is computed by dividing the net loss (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted net loss per common share is computed by dividing the net loss by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the three and nine months ended September 30, 2015 and 2014 are as follows: Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 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 – 1,608,049 – 1,844,447 Weighted average common shares outstanding – diluted 47,979,990 49,588,039 47,979,990 49,824,437 Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 15,757,209 and 8,249,542 for the three months ended September 30, 2015 and 2014, respectively, and 15,757,209 and 8,249,542 for the nine months ended September 30, 2015 and 2014, respectively.
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 $12,286 and $24,327 for the nine months ended September 30, 2015 and 2014, respectively.
Revenue Recognition	Revenue Recognition The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proven reserves were not adequate to cover an imbalance situation.
Asset Retirement Obligations	Asset Retirement Obligations The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Full Cost Method	Full Cost Method The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. Capitalized costs are summarized as follows for the nine months ended September 30, 2015 and 2014, respectively: Nine Months Ended September 30, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ – $ 54,820 Capitalized Interest Costs 352,572 216,895 Total $ 352,572 $ 271,715 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. As a result of currently prevailing low commodity prices and their effect on the proved reserve values of properties in 2015, we recorded non-cash ceiling test impairments of $52,634,000 in the nine months ended September 30, 2015. The Company did not have any impairment of its proved oil and gas properties for the nine months ended September 30, 2014. The impairment charges affected our reported net income but did not reduce our cash flow. Continued write downs of oil and natural gas properties are expected to occur until such time as commodity prices have recovered, and remain at recovered levels, so as to meaningfully increase the trailing 12-month average price used in the ceiling calculation. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
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 $465,876 and $433,294 for the nine months ended September 30, 2015 and 2014, respectively, using the Black-Scholes options pricing model and an effective term of 6 to 6.5 years based on the weighted average of the vesting periods and the stated term of the option grants and the discount rate on 5 to 7 year U.S. Treasury securities at the grant date. In addition, $484,012 and $468,670 of warrant related debt discounts were amortized during the nine months ended September 30, 2015 and 2014, respectively, and treated as interest expense. The fair value of warrants is determined similar to the method used in determining the fair value of employee stock options and the fair value is amortized over the life of the related credit facility and accelerated in the event of termination of the related credit facility.
Uncertain Tax Positions	Uncertain Tax Positions Effective upon inception at April 9, 2010, the Company adopted standards for accounting for uncertainty in income taxes. These standards prescribe a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. These standards also provide guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Various taxing authorities may periodically audit the Company’s income tax returns. These audits include questions regarding the Company’s tax filing positions, including the timing and amount of deductions and the allocation of income to various tax jurisdictions. In evaluating the exposures connected with these various tax filing positions, including state and local taxes, the Company records allowances for probable exposures. A number of years may elapse before a particular matter, for which an allowance has been established, is audited and fully resolved. Black Ridge Oil & Gas, Inc. has not yet undergone an examination by any taxing authorities. The assessment of the Company’s tax position relies on the judgment of management to estimate the exposures associated with the Company’s various filing positions.
Derivative Instruments and Price Risk Management	Derivative Instruments and Price Risk Management The Company enters into derivative contracts, including price swaps, caps and floors, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil without the exchange of underlying volumes. The notional amounts of these financial instruments are based on a portion of the expected production from existing wells. The Company has, and may continue to use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date. Any realized gains and losses are recorded to gain (loss) on settled derivatives and unrealized gains or losses as a result of mark-to market valuations are recorded to gain (loss) on the mark-to-market of derivatives on the statements of operations.
Recent Accounting Pronouncements	Recent Accounting Pronouncements New accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted by the Company as of the specified effective date. If not discussed below, management believes there have been no developments to recently issued accounting standards, including expected dates of adoption and estimated effects on our financial statements, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014. In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, Interest–Imputation of Interest (Subtopic 835-30) In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers

2. Basis of Presentation and 24

2. Basis of Presentation and Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Weighted average shares common and diluted	Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 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 – 1,608,049 – 1,844,447 Weighted average common shares outstanding – diluted 47,979,990 49,588,039 47,979,990 49,824,437
Schedule of Capitalized Costs	Nine Months Ended September 30, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ – $ 54,820 Capitalized Interest Costs 352,572 216,895 Total $ 352,572 $ 271,715

5. Property and Equipment (Tabl

5. Property and Equipment (Tables)	9 Months Ended
	Sep. 30, 2015
Property and equipment:
Property and equipment	September 30, December 31, 2015 2014 Oil and gas properties, full cost method: Evaluated costs $ 128,083,460 $ 112,418,105 Unevaluated costs, not subject to amortization or ceiling test 803,718 591,121 128,887,178 113,009,226 Other property and equipment 139,004 139,004 129,026,182 113,148,230 Less: Accumulated depreciation, amortization, depletion and impairments (78,895,166 ) (18,902,524 ) Total property and equipment, net $ 50,131,016 $ 94,245,706
Depreciation, depletion, and amortization expense	Nine Months Ended September 30, 2015 2014 Depletion of costs for evaluated oil and gas properties $ 7,346,356 $ 5,994,180 Depreciation and amortization of other property and equipment 12,286 24,327 Total depreciation, amortization and depletion $ 7,358,642 $ 6,018,507

6. Oil and Gas Properties (Tabl

6. Oil and Gas Properties (Tables)	9 Months Ended
	Sep. 30, 2015
Extractive Industries [Abstract]
Gross and net productive oil wells	September 30, 2015 September 30, 2014 Gross Net Gross Net North Dakota 336 10.51 230 7.28 Montana 5 0.37 1 0.08 Total 341 10.88 231 7.36
Capitalized costs	Nine Months Ended September 30, 2015 2014 Purchases of oil and gas properties and development costs for cash $ 17,968,423 $ 17,410,744 Purchase of oil and gas properties accrued at period-end 7,359,282 11,775,176 Purchase of oil and gas properties accrued at beginning of period (9,364,796 ) (7,953,801 ) Advances to operators applied to purchase of oil and gas properties – 4,285,575 Capitalized asset retirement costs, net of revision in estimate 42,391 61,815 Total purchase and development costs, oil and gas properties $ 16,005,300 $ 25,579,509

7. Asset Retirement Obligation

7. Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation	Nine Months Ended September 30, 2015 2014 Beginning ARO $ 286,804 $ 160,665 Liabilities incurred for new wells placed in production 42,391 61,815 Accretion of discount on ARO 23,900 15,486 Ending ARO $ 353,095 $ 237,966

9. Derivative Instruments (Tabl

9. Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding derivative contracts with respect to future production	Crude Oil Swaps Settlement Period Oil (Barrels) Fixed Price October 1, 2015 – December 31, 2015 6,000 $ 88.28 October 1, 2015 – December 31, 2015 5,250 $ 89.70 October 1, 2015 – December 31, 2015 3,000 $ 92.38 October 1, 2015 – December 31, 2015 7,500 $ 90.16 October 1, 2015 – December 31, 2015 36,000 $ 61.87 April 1, 2016 – May 31, 2016 15,000 $ 62.88 April 1, 2016 – May 31, 2016 10,000 $ 90.36 April 1, 2016 – May 31, 2016 4,000 $ 88.15 Crude Oil Costless Collars Floor/Ceiling Settlement Period Oil (Barrels) Price Basis October 1, 2015 – December 31, 2015 9,000 $75.00/$95.60 NYMEX April 1, 2016 – May 31, 2016 3,334 $80.00/$89.50 NYMEX
Realized and unrealized gains and losses on derivative instruments	Nine Months Ended September 30, 2015 2014 Gain (loss) on settled derivatives: Crude oil fixed price swaps $ 8,579,756 $ (449,135 ) Crude oil collars 857,147 – Gain (loss) on settled derivatives, net $ 9,436,903 $ (449,135 ) Gain (loss) on the mark-to-market of derivatives: Crude oil fixed price swaps $ (4,366,810 ) $ 1,012,502 Crude oil collars (519,374 ) 40,137 Gain (loss) on the mark-to-market of derivatives, net $ (4,886,184 ) $ 1,052,639
Gross amounts of recognized derivative assets and liabilities	September 30, 2015 December 31, 2014 Gross Net Gross Net Gross amounts amounts of Gross amounts amounts of amounts of offset assets amounts of offset assets recognized on balance on balance recognized on balance on balance assets sheet sheet assets sheet sheet Commodity derivative assets $ 2,694,001 $ (440 ) $ 2,693,561 $ 7,620,896 $ (41,151 ) $ 7,579,745 September 30, 2015 December 31, 2014 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 $ – $ – $ – $ – $ – $ –
Reconciliation of derivative assets and liabilities	September 30, December 31, 2015 2014 Derivative assets $ 2,693,561 $ 3,571,803 Noncurrent derivative assets – 4,007,942 Net amount of assets on the balance sheet 2,693,561 7,579,745 Current portion of derivative liabilities – – Derivative liabilities – – Net amount of liabilities on the balance sheet – – Total derivative assets (liabilities), net $ 2,693,561 $ 7,579,745

10. Fair Value of Financial I29

10. Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Valuation of financial instruments at fair value	Fair Value Measurements at September 30, 2015 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 58,599 $ – $ – Derivative Instruments (crude oil swaps and collars) – 2,693,561 – Total assets 58,599 2,693,561 – Liabilities Revolving credit facilities and long term debt, net of discounts – 57,458,543 – Total Liabilities – 57,458,543 – $ 58,599 $ (54,764,982 ) $ – Fair Value Measurements at December 31, 2014 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 94,682 $ – $ – Derivative Instruments (crude oil swaps and collars) – 7,579,745 – Total assets 94,682 7,579,745 – Liabilities Revolving credit facilities and long term debt, net of discounts – 51,834,603 – Total Liabilities – 51,834,603 – $ 94,682 $ (44,254,858 ) $ –

11. Revolving Credit Faciliti30

11. Revolving Credit Facilities and Long Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Revolving credit facility	September 30, December 31, 2015 2014 Senior Revolving Credit Facility, Cadence Bank, N.A. $ 26,650,000 $ 22,600,000 Subordinated Credit Agreement, Chambers 30,000,000 30,000,000 PIK Interest on Subordinated Credit Agreement, Chambers 2,269,636 1,307,086 Total credit facilities and long term debts 58,919,636 53,907,086 Less: Unamortized OID (299,356 ) (426,734 ) Less: Unamortized debt discount attributable to warrants (1,161,737 ) (1,645,749 ) Total credit facilities and long term debts, net of discounts 57,458,543 51,834,603 Less: current maturities – – Long term portion of credit facilities and long term debts $ 57,458,543 $ 51,834,603
Components of interest expense	Nine Months Ended September 30, 2015 2014 Accrued PIK interest $ 962,551 $ 787,344 Amortization of OID 127,378 102,566 Interest and commitment fees 3,287,131 2,444,676 Amortization of debt issuance costs 287,227 229,936 Amortization of warrant costs 484,012 468,670 Less interest capitalized to the full cost pool of our proved oil & gas properties (352,572 ) (216,895 ) $ 4,795,727 $ 3,816,297

2. Basis of Presentation and 31

2. Basis of Presentation and Significant Accounting Policies (Details Denominators) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
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	0	1,608,049	0	1,844,447
Weighted average common shares outstanding - diluted	47,979,990	49,588,039	47,979,990	49,824,437

2. Basis of Presentation and 32

2. Basis of Presentation and Significant Accounting Policies (Details-Capitalized costs) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Total capitalized costs	$ 352,572	$ 271,715
Certain Payroll and Other Internal Costs
Total capitalized costs	0	54,820
Capitalized Interest Costs
Total capitalized costs	$ 352,572	$ 216,895

2. Basis of Presentation and 33

2. Basis of Presentation and Significant Accounting Policies (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Accounting Policies [Abstract]
Cash equivalents	$ 0		$ 0		$ 0
Cash in excess of insured limits	0		0		0
Unamortized balance of debt issuance costs	463,792		463,792		$ 701,019
Amortization of debt issuance costs charged to interest expense			287,227	$ 229,936
Website development costs capitalized	$ 56,660		56,660
Depreciation expense on website development costs			$ 257	$ 14,165
Stock options and warrants excluded to to being antidilutive	15,757,209	8,249,542	15,757,209	8,249,542
Depreciation of Non-Oil and Gas Property and Equipment			$ 12,286	$ 24,327
Impairment of oil and gas properties	$ 30,995,000	$ 0	52,634,000	0
Share-based compensation expense			465,876	433,294
Amortization of warrant costs			$ 484,012	$ 468,670

4. Dahl Federal Recognition (De

4. Dahl Federal Recognition (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Oil and gas revenues	$ 3,359,684	$ 5,492,326	$ 11,296,220	$ 15,076,743
Production expenses	887,187	670,404	3,030,707	1,773,458
Production taxes	330,186	$ 588,923	1,171,530	$ 1,585,755
Dahl Federal
Capitalized well costs	$ 927,312		927,312
Dahl Federal | Production prior to 2015
Oil and gas revenues			1,241,214
Production expenses			75,359
Production taxes			$ 137,860

5. Property and Equipment (Deta

5. Property and Equipment (Details-Property and equipment) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Oil and gas properties, full cost method:
Evaluated costs	$ 128,083,460	$ 112,418,105
Unevaluated costs, not subject to amortization or ceiling test	803,718	591,121
Total Oil and Gas properties full cost method	128,887,178	113,009,226
Other property and equipment	139,004	139,004
Total property plant and equipment gross	129,026,182	113,148,230
Less: Accumulated depreciation, amortization and depletion	(78,895,166)	(18,902,524)
Total property and equipment, net	$ 50,131,016	$ 94,245,706

5. Property and Equipment (De36

5. Property and Equipment (Details-Depreciation) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Property and equipment:
Depletion of costs for evaluated oil and gas properties	$ 1,778,580	$ 2,275,703	$ 7,346,356	$ 5,994,180
Depreciation and amortization of other property and equipment	4,010	8,214	12,286	24,327
Total depreciation, amortization and depletion			7,358,642	6,018,507
Impairment of oil and gas	$ 30,995,000	$ 0	$ 52,634,000	$ 0

6. Oil and Gas Properties (Deta

6. Oil and Gas Properties (Details-Wells) - Wells	Sep. 30, 2015	Sep. 30, 2014
Productive oil wells, gross	341	231
Productive oil wells, net	10.88	7.36
North Dakota
Productive oil wells, gross	336	230
Productive oil wells, net	10.51	7.28
Montana
Productive oil wells, gross	5	1
Productive oil wells, net	0.37	.08

6. Oil and Gas Properties (De38

6. Oil and Gas Properties (Details-Development costs) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Extractive Industries [Abstract]
Purchases of oil and gas properties and development costs for cash	$ 17,968,423	$ 17,410,744
Purchase of oil and gas properties accrued at period-end	7,359,282	11,775,176
Purchase of oil and gas properties accrued at the beginning of period	(9,364,796)	(7,953,801)
Advances to operators applied to development of oil and gas properties	0	4,285,575
Capitalized asset retirement costs, net of revision in estimate	42,391	61,815
Total purchase and development costs, oil and gas properties	$ 16,005,300	$ 25,579,509

6. Oil and Gas Properties (De39

6. Oil and Gas Properties (Details Narrative)	9 Months Ended
	Sep. 30, 2015USD ($)aWells	Sep. 30, 2014USD ($)a
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and gas assets, net acres | a	8,509	9,919
Oil and gas acreage acquired | a	9	319
Oil and gas properties acquired, cost	$ 102,928	$ 2,401,318
Oil and gas acreage sold | a	14	490
Wellbores sold | Wells	3
Proceeds from oil and gas diverstitures	$ 127,348	$ 1,340,920
Oil and gas acres traded | a		52
Mineral acres acquired in trade | a		40
Cash received in trade		$ 20,000
Undeveloped acreage expirations | a	1,466
Undeveloped agreage expirations carrying costs	$ 1,443,848
Undeveloped acreage expirations, future	400
Undeveloped Acreage expirations, future carrying costs	$ 550,563

7. Asset Retirement Obligatio40

7. Asset Retirement Obligation (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Asset retirement rollforward
Beginning Asset Retirement Obligation			$ 286,804	$ 160,665
Liabilities incurred for new wells placed in production			42,391	61,815
Accretion of discount on asset retirement obligations	$ 8,039	$ 5,833	23,900	15,486
Ending asset retirement obligation	$ 353,095	$ 237,966	$ 353,095	$ 237,966

8. Related Party (Details Narra

8. Related Party (Details Narrative) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Related Party Transactions [Abstract]
Rent expense	$ 52,298	$ 52,284

9. Derivative Instruments (Deta

9. Derivative Instruments (Details-Outstanding derivative contracts)	9 Months Ended
	Sep. 30, 2015$ / Boebbl
Crude Oil Swaps 1 [Member]
Outstanding derivative contracts Settlement Period	October 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	6,000
Outstanding derivative contract, fixed price	88.28
Crude Oil Swaps 2 [Member]
Outstanding derivative contracts Settlement Period	October 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	5,250
Outstanding derivative contract, fixed price	89.70
Crude Oil Swaps 3 [Member]
Outstanding derivative contracts Settlement Period	October 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	3,000
Outstanding derivative contract, fixed price	92.38
Crude Oil Swaps 4 [Member]
Outstanding derivative contracts Settlement Period	October 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	7,500
Outstanding derivative contract, fixed price	90.16
Crude Oil Swaps 5 [Member]
Outstanding derivative contracts Settlement Period	October 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	36,000
Outstanding derivative contract, fixed price	61.87
Crude Oil Swaps 6 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2016 - May 31, 2016
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	15,000
Outstanding derivative contract, fixed price	62.88
Crude Oil Swaps 7 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2016 - May 31, 2016
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	10,000
Outstanding derivative contract, fixed price	90.36
Crude Oil Swaps 8 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2016 - May 31, 2016
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	4,000
Outstanding derivative contract, fixed price	88.15
Crude Oil Costless Collars1 [Member]
Outstanding derivative contracts Settlement Period	October 1, 2015 - December 31, 2015
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	9,000
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	95.60
Crude Oil Costless Collars2 [Member]
Outstanding derivative contracts Settlement Period	April 1, 2016 – May 31, 2016
Outstanding derivative contracts, amount of oil (in Barrels) | bbl	3,334
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	89.50

9. Derivative Instruments (De43

9. Derivative Instruments (Details-Derivative Gains and Losses) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Gain (loss) on settled derivatives	$ 7,456,284	$ (70,253)	$ 9,436,903	$ (449,135)
Gain (loss) on the mark-to-market of derivatives	$ (3,297,358)	$ 2,147,798	(4,886,184)	1,052,639
Crude Oil Fixed Price Swap [Member]
Gain (loss) on settled derivatives			8,579,756	(449,135)
Gain (loss) on the mark-to-market of derivatives			(4,366,810)	1,012,502
Crude Oil Collars [Member]
Gain (loss) on settled derivatives			857,147	0
Gain (loss) on the mark-to-market of derivatives			$ (519,374)	$ 40,137

9. Derivative Instruments (De44

9. Derivative Instruments (Details-Balance sheet derivatives) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Commodity derivative assets	$ 2,693,561	$ 7,579,745
Commodity derivative liabilities	0	0
Gross amounts recognized
Commodity derivative assets	2,694,001	7,620,896
Commodity derivative liabilities	0	0
Gross amounts offset on balance sheet
Commodity derivative assets	(440)	(41,151)
Commodity derivative liabilities	$ 0	$ 0

9. Derivative Instruments (De45

9. Derivative Instruments (Details-Reconciliation of derivatives) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 2,693,561	$ 3,571,803
Noncurrent derivative assets	0	4,007,942
Net amount of assets on the balance sheet	2,693,561	7,579,745
Current portion of derivative liabilities	0	0
Derivative liabilities	0	0
Net amounts of liabilities on the balance sheet	0	0
Total derivative assets (liabilities), net	$ 2,693,561	$ 7,579,745

9. Derivative Instruments (De46

9. Derivative Instruments (Details Narrative)	9 Months Ended
	Sep. 30, 2015USD ($)$ / Boebbl
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Total volume on open commodity swaps, barrels	86,750
Weighted average price per barrel | $ / Boe	73.55
Derivative liquidations | $	$ 6,255,000

10. Fair Value of Financial I47

10. Fair Value of Financial Instruments (Details-Recurring basis) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Fair Value Inputs Level1 [Member]
Assets
Cash and cash Equivalents		$ 94,682
Derivative Instruments (crude oil swaps and collars)		0
Total assets		94,682
Liabilities
Revolving credit facilities and long term debt, net of discounts		0
Total Liabilities		0
Total Assets and Liablilties		94,682
Fair Value Inputs Level2 [Member]
Assets
Cash and cash Equivalents		0
Derivative Instruments (crude oil swaps and collars)		7,579,745
Total assets		7,579,745
Liabilities
Revolving credit facilities and long term debt, net of discounts		51,834,603
Total Liabilities		51,834,603
Total Assets and Liablilties		(44,254,858)
Fair Value Inputs Level3 [Member]
Assets
Cash and cash Equivalents		0
Derivative Instruments (crude oil swaps and collars)		0
Total assets		0
Liabilities
Revolving credit facilities and long term debt, net of discounts		0
Total Liabilities		0
Total Assets and Liablilties		$ 0
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level1 [Member]
Assets
Cash and cash Equivalents	$ 58,599
Derivative Instruments (crude oil swaps and collars)	0
Total assets	58,599
Liabilities
Revolving credit facilities and long term debt, net of discounts	0
Total Liabilities	0
Total Assets and Liablilties	58,599
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level2 [Member]
Assets
Cash and cash Equivalents	0
Derivative Instruments (crude oil swaps and collars)	2,693,561
Total assets	2,693,561
Liabilities
Revolving credit facilities and long term debt, net of discounts	57,458,543
Total Liabilities	57,458,543
Total Assets and Liablilties	(54,764,982)
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level3 [Member]
Assets
Cash and cash Equivalents	0
Derivative Instruments (crude oil swaps and collars)	0
Total assets	0
Liabilities
Revolving credit facilities and long term debt, net of discounts	0
Total Liabilities	0
Total Assets and Liablilties	$ 0

11. Revolving Credit Faciliti48

11. Revolving Credit Facilities and Long Term Debt (Details-Debt outstanding) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Credit facilities outstanding	$ 58,919,636	$ 53,907,086
Less: Unamortized OID	(299,356)	(426,734)
Less: Unamortized debt discount attributable to warrants	(1,161,737)	(1,645,749)
Total credit facilities and long term debts, net of discounts	57,458,543	51,834,603
Less: current maturities	0	0
Long term portion of credit facilities and long term debts	57,458,543	51,834,603
Senior Revolving Credit Facility, Cadence Bank
Credit facilities outstanding	26,650,000	22,600,000
Subordinated Credit Agreement, Chambers
Credit facilities outstanding	30,000,000	30,000,000
PIK Interest on Subordinated Credit Agreement, Chambers
Credit facilities outstanding	$ 2,269,636	$ 1,307,086

11. Revolving Credit Faciliti49

11. Revolving Credit Facilities and Long Term Debt (Details-Interest expense) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Interest expense, debt	$ 4,795,727	$ 3,816,297
Accrued PIK interest
Interest expense, debt	962,551	787,344
Amortization of OID
Interest expense, debt	127,378	102,566
Interest and commitment fees
Interest expense, debt	3,287,131	2,444,676
Amortization of debt issuance costs
Interest expense, debt	287,227	229,936
Amortization of warrant costs
Interest expense, debt	484,012	468,670
Interest capitalized
Interest expense, debt	$ (352,572)	$ (216,895)

11. Revolving Credit Faciliti50

11. Revolving Credit Facilities and Long Term Debt (Details Narrative) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Line of credit outstanding	$ 58,919,636		$ 53,907,086
Amortization of debt discount	127,378	$ 102,566
Amortization of debt discounts, warrants	484,012	468,670
Unamortized balance of debt discount	1,461,093		2,072,483
Line of Credit [Member] | Senior Credit Facility
Maximum borrowing capacity	$ 34,000,000		35,000,000
Line of credit maturity date	Jan. 15, 2017
Line of credit outstanding	$ 26,650,000		22,600,000
Line of Credit [Member] | Subordinated Credit Facility
Maximum borrowing capacity	$ 30,000,000
Line of credit maturity date	Jun. 30, 2017
Line of credit outstanding	$ 30,000,000		30,000,000
Warrants issued with debt	5,000,000
Warrant expiration date	Aug. 8, 2018
Unamortized balance of debt discount	$ 299,356		426,734
Proceeds received from credit facility	29,400,000
Line of Credit [Member] | Subordinated Credit Facility | Warrants
Debt discount at time of issuance	2,473,576
Amortization of debt discounts, warrants	484,012	$ 468,670
Unamortized balance of debt discount	$ 1,161,737		$ 1,645,749

12. Changes in Stockholders' 51

12. Changes in Stockholders' Equity (Details Narrative) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
Equity [Abstract]
Preferred stock, par value (in Dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	20,000,000	20,000,000
Common stock, par value (in Dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	500,000,000	500,000,000

13. Options (Details Narrative)

13. Options (Details Narrative) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Compensation expense	$ 465,876	$ 433,294
Unamortized fair value of options	$ 1,650,044
Options exercised	0	0
Options forfeited	1,000,000	0
Options
Options granted	1,000,000	0
Exercise price of options granted	$ 0.172
Fair value of options granted	$ 143,379

14. Warrants (Details Narrative

14. Warrants (Details Narrative) - Warrants - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Finance expense related to warrants	$ 484,012	$ 468,670
Warrants granted	0	0
Warrants exercised	0	0

15. Income Taxes (Details Narra

15. Income Taxes (Details Narrative) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Tax Disclosure [Abstract]
Deferred tax liabilities	$ 1,066,200		$ 1,066,200
Deferred tax assets, valuation allowance	15,417,147		15,417,147
Net deferred tax assets (liabilities)	15,417,147		15,417,147
Tax benefit	0	$ (700,587)	6,593,040	$ (110,849)
Uncertain tax positions	$ 0		$ 0
Effective tax rate			12.00%

16. Commitments and Contingen55

16. Commitments and Contingencies (Details Narrative)	Sep. 30, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Commitment to AFE (approximately)	$ 1,600,000