Sow Good (SOWG) 10-K 30 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 28, 2016	Jun. 30, 2015
Document And Entity Information
Entity Registrant Name	Black Ridge Oil & Gas, Inc.
Entity Central Index Key	1,490,161
Document Type	10-K
Document Period End Date	Dec. 31, 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 Public Float			$ 10,625,746
Entity Common Stock, Shares Outstanding		47,979,990
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,015

BALANCE SHEETS

BALANCE SHEETS - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash	$ 228,194	$ 94,682
Derivative instruments, current	1,154,400	3,571,803
Accounts receivable	5,038,146	5,740,171
Prepaid expenses	37,100	41,387
Total current assets	6,457,840	9,448,043
Oil and natural gas properties, full cost method of accounting
Proved properties	131,168,906	112,418,105
Unproved properties	10,394	591,121
Other property and equipment	139,004	139,004
Total property and equipment	131,318,304	113,148,230
Less, accumulated depreciation, amortization, depletion and allowance for impairment	(99,468,927)	(18,902,524)
Total property and equipment, net	31,849,377	94,245,706
Derivative instruments, long term	0	4,007,942
Debt issuance costs, net	0	701,019
Total assets	38,307,217	108,402,710
Current liabilities:
Accounts payable	7,906,438	10,291,262
Accrued expenses	55,830	57,435
Current portion of revolving credit facility and long term debt	60,350,629	0
Total current liabilities	68,312,897	10,348,697
Asset retirement obligations	368,089	286,804
Revolving credit facility and long term debt, net of discounts of $-0- and $2,072,483, respectively, net of current portion	0	51,834,603
Deferred tax liability	0	6,593,040
Total liabilities	$ 68,680,986	$ 69,063,144
Commitments and contingencies (See note 17)
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	34,275,414	33,651,714
Retained earnings (accumulated deficit)	(64,697,163)	5,639,872
Total stockholders' equity	(30,373,769)	39,339,566
Total liabilities and stockholders' equity	$ 38,307,217	$ 108,402,710

BALANCE SHEETS (Parenthetical)

BALANCE SHEETS (Parenthetical) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Current liabilities:
Discounts on long term debt	$ 0	$ 2,072,483
Stockholders' equity:
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

STATEMENTS OF OPERATIONS

STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Oil and gas sales	$ 15,104,629	$ 21,102,823
Gain on settled derivatives	11,477,653	511,451
Gain (loss) on the mark-to-market of derivatives	(6,425,345)	7,793,421
Total revenues	20,156,937	29,407,695
Operating expenses:
Production expenses	3,767,444	2,705,763
Production taxes	1,574,110	2,203,501
General and administrative	3,023,631	2,891,641
Depletion of oil and natural gas properties	9,278,108	9,359,952
Impairment of oil and natural gas properties	71,272,000	0
Accretion of discount on asset retirement obligations	32,574	22,361
Depreciation and amortization	16,295	29,138
Total operating expenses	88,964,162	17,212,356
Net operating income (loss)	(68,807,225)	12,195,339
Other income (expense):
Other income	13,398	0
Interest income	0	972
Interest (expense)	(8,136,248)	(5,285,236)
Total other income (expense)	(8,122,850)	(5,284,264)
Income (loss) before provision for income taxes	(76,930,075)	6,911,075
Provision for income taxes	6,593,040	(2,559,195)
Net income (loss)	$ (70,337,035)	$ 4,351,880
Weighted average common shares outstanding - basic	47,979,990	47,979,990
Weighted average common shares outstanding - fully diluted	47,979,990	49,179,725
Net income (loss) per common share - basic	$ (1.47)	$ 0.09
Net income (loss) per common share - fully diluted	$ (1.47)	$ 0.09

STATEMENTS OF STOCKHOLDERS' EQU

STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($)	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-In Capital [Member]	Accumulated (Deficit) [Member]	Total
Beginning Balance, amount at Dec. 31, 2013	$ 0	$ 47,980	$ 33,072,795	$ 1,287,992	$ 34,408,767
Beginning Balance, shares at Dec. 31, 2013	0	47,979,990
Common stock options granted for services to employees			578,919		578,919
Net income (loss)				4,351,880	4,351,880
Ending Balance, amount at Dec. 31, 2014	$ 0	$ 47,980	33,651,714	5,639,872	39,339,566
Ending Balance, shares at Dec. 31, 2014	0	47,979,990
Common stock options granted for services to employees			623,700		623,700
Net income (loss)				(70,337,035)	(70,337,035)
Ending Balance, amount at Dec. 31, 2015	$ 0	$ 47,980	$ 34,275,414	$ (64,697,163)	$ (30,373,769)
Ending Balance, shares at Dec. 31, 2015	0	47,979,990

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (70,337,035)	$ 4,351,880
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion of oil and gas properties	9,278,108	9,359,952
Depreciation and amortization	16,295	29,138
Amortization of debt issuance costs	751,019	326,258
Accretion of discount on asset retirement obligations	32,574	22,361
Loss (gain) on the mark-to-market of derivatives	6,425,345	(7,793,421)
Accrued payment in kind interest applied to long term debt	1,293,543	1,105,203
Amortization of original issue discount on debt	426,734	144,904
Amortization of debt discounts, warrants	1,645,749	628,195
Common stock options issued to employees and directors	623,700	578,919
Deferred income taxes	(6,593,040)	2,559,195
Impairment of oil and natural gas properties	71,272,000	0
Decrease (increase) in current assets:
Accounts receivable	702,025	(2,834,704)
Prepaid expenses	4,287	(15,245)
Increase (decrease) in current liabilities:
Accounts payable	80,469	426,558
Accrued expenses	(1,605)	52,622
Net cash provided by operating activities	15,620,168	8,941,815
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale or swap of oil and gas properties	127,348	1,441,929
Purchases of oil and natural gas properties and development capital expenditures	(20,714,004)	(24,739,407)
Advances to operators	0	(5,822,086)
Purchases of other property and equipment	0	(23,522)
Net cash used in investing activities	(20,586,656)	(29,143,086)
CASH FLOWS FROM FINANCING ACTIVITIES
Advances from revolving credit facilities and long term debt	16,050,000	29,800,000
Repayments on revolving credit facilities	(10,900,000)	(10,400,000)
Debt issuance costs	(50,000)	(254,394)
Net cash provided by financing activities	5,100,000	19,145,606
NET CHANGE IN CASH	133,512	(1,055,665)
CASH AT BEGINNING OF PERIOD	94,682	1,150,347
CASH AT END OF PERIOD	228,194	94,682
SUPPLEMENTAL INFORMATION:
Interest paid	4,382,262	3,401,028
Income taxes paid	0	0
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Net change in accounts payable for purchase of oil and gas properties	(2,465,293)	1,410,995
Advances to operators applied to purchase of oil and gas properties	0	6,036,748
Advances to operators reclassified to accounts receivable	0	1,000,000
Capitalized asset retirement costs, net of revision in estimate	$ 48,711	$ 103,778

1. Organization and Nature of B

1. Organization and Nature of Business	12 Months Ended
	Dec. 31, 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 trade its common stock on the OTCQB under the trading symbol “ANFC”. Black Ridge Oil & Gas, Inc. (Formerly Ante5, Inc.) (the “Company”) became an independent company in April 2010 when the spin-off from our former parent company, Ante4, Inc. (now Emerald Oil, Inc. and also formerly known as Voyager Oil & Gas, Inc.), became effective. 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 in a growing, diversified portfolio of oil and gas wells. We aggressively seek to accumulate mineral leases to position us to 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, and engage in the drilling process. As a non-operator we are focused on maintaining a low overhead structure.

2. Summary of Significant Accou

2. Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Basis of Accounting Our financial statements are prepared using the accrual method of accounting as generally accepted in the United States of America (U.S. GAAP) and the rules of the Securities and Exchange Commission (SEC). Segment Reporting FASB ASC 280-10-50 requires annual and interim reporting for an enterprise’s operating segments and related disclosures about its products, services, geographic areas and major customers. An operating segment is defined as a component of an enterprise that engages in business activities from which it may earn revenues and expenses, and about which separate financial information is regularly evaluated by the chief operating decision maker in deciding how to allocate resources. The Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations. 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. The Company had no cash equivalents on hand as of December 31, 2015 and December 31, 2014. Cash in Excess of FDIC Insured Limits The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (FDIC) up to $250,000, under current regulations. The Company didn’t have any funds in excess of FDIC insured limits at December 31, 2015 and 2014. 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 certain debts are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. The Company paid $50,000 and $254,394 of debt issuance costs during the years ended December 31, 2015 and 2014, respectively, of which the unamortized balance of debt issuance costs at December 31, 2015 and 2014 was $0 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense was $751,019 and $326,258 for the years ended December 31, 2015 and 2014, respectively. When a loan is paid in full or becomes due on demand due to a default on the loan, 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 December 31, 2015. We have recognized depreciation expense on these website costs of $257 and $15,380 for the years ended December 31, 2015 and 2014, respectively. Income Taxes The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not. 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 natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $16,295 and $29,138 for the years ended December 31, 2015 and 2014, respectively. Revenue Recognition The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proved reserves were not adequate to cover the current 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 natural 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 years ended December 31, 2015 and 2014, respectively: Years Ended December 31, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ – $ 61,861 Capitalized Interest Costs 362,075 372,673 Total $ 362,075 $ 434,534 Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 20% or more of the proved reserves related to a single full cost pool. During the year ended December 31, 2015, the Company sold approximately 14 net acres and rights to individual well bores for total proceeds of $127,348. During the year ended December 31, 2014, the Company sold approximately 502 net acres for total proceeds of $1,441,929. 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 natural 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. The Company recognized impairments of oil and gas properties of $71,272,000 in the year ended December 31, 2015. No impairment was recognized during the year ended December 31, 2014. Concentrations Our revenue is solely derived from oil and gas sales to various purchasers, the market for which has very inelastic demand. Due to this, we do not consider any purchasers to represent a material concentration to our sales for the years ended December 31, 2015 or 2014, as we believe any of our customers could easily be replaced. Since we do not operate any of our wells, we depend on our drilling partner operators to perform the drilling and other operating activities required for all sales of oil and gas. These operators are also responsible for remitting to us our revenue proceeds and billing us for drilling costs and lease operating expenses incurred. We had material concentrations of accounts receivable owed from four (4) and four (4) operators during the years ended December 31, 2015 and 2014, respectively, representing 70% and 56% of total oil and gas revenues and 73% and 49% of total oil and gas accounts receivable as of December 31, 2015 and 2014, respectively. As of December 31, 2015 and 2014, we had 10.95 and 7.88 net producing wells, respectively. As of December 31, 2015 and 2014, these operating partners operated 56% and 52% of the net producing wells, respectively. Basic and Diluted Loss Per Share Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2015 and 2014 are as follows: Years Ended December 31, 2015 2014 Weighted average common shares outstanding – basic 47,979,990 47,979,990 Plus: Potentially dilutive common shares: Stock options and warrants – 1,199,735 Weighted average common shares outstanding – diluted 47,979,990 49,179,725 For 2015, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share. Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 15,603,375 and 13,683,209 as of December 31, 2015 and 2014, respectively. Stock-Based Compensation Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. Amortization of the fair values of stock options issued for services and compensation totaled $623,700 and $578,919 for the years ended December 31, 2015 and 2014, respectively. The fair values of stock options were determined 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 and are being amortized over the related implied service term, or vesting period. Uncertain Tax Positions In accordance with ASC 740, “Income Taxes” (“ASC 740”), the Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be capable of withstanding examination by the taxing authorities based on the technical merits of the position. 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 can 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. The Company 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. Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board ("FASB") that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company's financial statements upon adoption. In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers." The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers – Deferral of the Effective Date," In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40)." The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period beginning after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company has chosen to adopt this pronouncement beginning with the issuance of this report due to the applicability to our current condition. In April 2015, the FASB issued ASU No. 2015-03, "Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs," that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items. The Company is currently evaluating the impact that this new guidance will have on its financial statements. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts in a classified statement of financial position. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent in a statement of financial position. This standard is effective financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted. The Company elected early application of this ASU as of December 31, 2015, and has applied its provisions prospectively.

3. Going Concern

3. Going Concern	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Going Concern	As shown in the accompanying financial statements, the Company has incurred losses from operations resulting in an accumulated deficit of ($64,697,163), as of December 31, 2015, the Company’s current liabilities exceeded its current assets by $61,855,057, which includes the current classification of all of the Company’s debt, and its total liabilities exceeded its total assets by $30,373,769. As of December 31, 2015, the Company is out of compliance with the collateral coverage ratio covenant contained in both its Senior Secured Facility and Subordinated Credit Facility which constitutes an event of default. These factors raise substantial doubt about the Company’s ability to continue as a going concern. In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40)". The Company has chosen to adopt this pronouncement beginning with the issuance of this report due to the applicability to our current condition. The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. On March 29, 2016, the Company entered into an Asset Contribution Agreement with Black Ridge Holding Company, LLC, a Delaware limited liability company (“BRHC”) which was recently formed by the Company to contribute and assign to BRHC, all of the Company's (i) oil and gas assets (including working capital and tangible and intangible assets) (the “Assets”), (ii) outstanding balances under that certain Credit Agreement between the Company, as borrower, and Cadence Bank, N.A. (“Cadence”), as lender (the “Cadence Credit Facility”) and the outstanding balances under that certain Credit Agreement between the Company, as borrower, and the several banks and other financial institutions or entities from time to time parties thereto (the “Chambers”), and Chambers, as administrative agent (the “Chambers Credit Facility”) and (iii) all current liabilities related to the Assets, in exchange for 5% of the issued and outstanding Class A Units (the “Class A Units”) in BRHC (the “Asset Contribution”). On March 29, 2016, affiliates of Chambers Energy Management, LP (“Chambers”) (specifically, Chambers Energy Capital II, LP and CEC II TE, LLC (collectively, the “Chambers Affiliates”)) entered into a Debt Contribution Agreement between BRHC and the Chambers Affiliates, pursuant to which BRHC will issue a number of Class A Units representing 95% of the Class A Units of BRHC to the Chambers Affiliates in exchange for the release of BRHC's obligations under the Chambers Credit Facility (the “Satisfaction of Debt” and, together with the Asset Contribution, the “BRHC Transaction”). Concurrent with the Satisfaction of Debt, each warrant originally issued with the Chambers Credit Facility shall be automatically retired and cancelled. The closing of the BRHC Transaction is subject to the Company obtaining the approval of stockholders holding a majority of its outstanding capital stock and to the Company having assigned the Cadence Credit Agreement to BRHC with Cadence’s consent, and BRHC and Cadence entering into any applicable amendment agreements related to such assignment and waiver of financial covenant ratio compliance for the quarter ended December 31, 2015 and quarter ending March 31, 2016. The Company is currently in the process of preparing to satisfy both conditions. The terms of the Class A Units of BRHC will be set forth in the limited liability company agreement of BRHC (the “LLC Agreement”), which will be effective upon the closing of the BRHC Transaction. All distributions by BRHC of cash or other property, and whether upon liquidation or otherwise, will be made as follows: · First, 100% to the Class A Members, pro rata, until each Class A Member has received distributions in aggregate totaling the then Class A Preference, which is an amount equal to a 10.0% internal rate of return on the invested capital amount. · Second, 90% to the Class A Members, pro rata, and 10% to the Class B Members, pro rata, until such time as the aggregate distributions to Chambers equals 250% of the capital contribution of its Class A Units. · Third, 80% to the Class A Members, pro rata, and 20% to the Class B Members, pro rata. BRHC will be managed by the BRHC Board, which will be responsible for the conduct of the day-to-day business of BRHC and the management, oversight and disposition of the assets of BRHC. The initial BRHC Board will be comprised of three managers, consisting of two managers appointed by Chambers and one member from the Company. In addition, under the LLC Agreement, Chambers will commit to contribute up to $30 million cash (the “Chambers Investment Commitment”) to BRHC in exchange for Class A Units. At Closing, Chambers shall fund $10 million (the “Initial Chambers Investment”) of the Chambers Investment Commitment, the proceeds of which shall be used to reduce outstanding amounts owed by BRHC to Cadence under the Cadence Credit Facility and for general corporate purposes. The remaining $20 million (the “Subsequent Chambers Investment”), subject to certain conditions, may be called from time to time during the Investment Period by the board of managers of BRHC (the “BRHC Board”). The Initial Chambers Investment and any Subsequent Chambers Investment shall serve to proportionately reduce the Company's Class A Units percentage ownership in BRHC. The investment period shall be the lesser of three years or such time as the entire Chambers Investment Commitment has been called by the BRHC Board (the “Investment Period”). Any portion of Chambers Investment Commitment not called by the BRHC Board prior to the expiration of the Investment Period will be cancelled. In no event will Chambers be required to make a capital contribution in an amount in excess of its undrawn commitment. The Company will be granted 1,000,000 Class B Units in BRHC at the Closing of the BRHC Transaction. At the discretion of the BRHC’s Board of Managers, the Company may be granted additional Class B Units in BRHC, and in turn, the Company may transfer such Class B Units to certain members of the Company's management. Subject to certain conditions, the Class B Units will entitle the holders to participate in any future distributions of BRHC after distributions equal to the capital contributions and preferred return have been made to the holders of Class A Units of BRHC. At the closing of the BRHC Transaction, the Company will enter into a Management Services Agreement with BRHC. Under the Management Services Agreement, the Company will provide services to BRHC with respect to the business operations of BRHC, including but not limited to locating, investigating and analyzing potential non-operator oil and gas projects and day-to-day operations related to such projects. The Company will be paid a fee under the Management Services Agreement intended to cover the costs of providing such services and will be reimbursed for certain third party expenses. The term of the Management Services Agreement commences on the closing of the BRHC Transaction and continues indefinitely, unless terminated. The Management Services Agreement will provide termination provisions upon reasonable notice for both the BRHC and the Company as well as upon a change of control, provided that if the Management Services Agreement is terminated before December 31, 2016 that BRHC shall pay the Company a termination fee equal to the amount that would have been paid if the Management Services Agreement was in place until December 31, 2016. The Company believes that the BRHC Transaction and related actions will allow the Company to continue as a manager of the oil and gas assets in which we will continue to have an indirect minority interest. In addition, it will give us the flexibility to pursue distressed asset acquisitions in the Bakken and/or Three Forks formation that may be acquired with capital from our secured lenders as part of the restructuring terms, existing joint venture partners or other capital providers. However, the BRHC Transaction has not closed as of the date of this report and certain conditions remain to be met prior to closing. ASU 2014-15 does not allow the Company to consider a plan when evaluating going concern uncertainties until that plan has been fully implemented. As the Company’s plans are not fully implemented, there remains substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of any uncertainty as to the Company’s ability to continue as a going concern. These financial statements also do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

4. Joint Venture

4. Joint Venture	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Joint Venture	On July 20, 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 to this joint venture.

5. Dahl Federal Recognition

5. Dahl Federal Recognition	12 Months Ended
	Dec. 31, 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 $1,170,236 of oil and gas revenues, $75,359 of operating expenses and $130,014 of production taxes during the year ended December 31, 2015 related to production prior to 2015 in addition to actual revenue and expenses for the period.

6. Related Party

6. Related Party	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party	During the years ended December 31, 2015 and 2014, we granted various awards to our Officers and Directors as compensation for their services. These related party grants are fully disclosed in Note 14 below. Other Related Party Transactions We currently lease office space on a month to month basis where the lessor is an entity owned by our Chairman of the Board of Directors, Bradley Berman for 2,813 square feet of office space. In accordance with this lease, our lease term is on a month-to-month basis, provided that either party may provide 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. As of December 31, 2015 the base rent is $2,344 per month. We have paid a total of $69,703 and $69,300 to this entity during the years ended December 31, 2015 and 2014, respectively.

7. Property and Equipment

7. Property and Equipment	12 Months Ended
	Dec. 31, 2015
Property and equipment:
Property and Equipment	Property and equipment December 31, 2015 and 2014, consisted of the following: December 31, 2015 2014 Oil and natural gas properties, full cost method: Evaluated costs $ 131,168,906 $ 112,418,105 Unevaluated costs, not subject to amortization or ceiling test 10,394 591,121 131,179,300 113,009,226 Other property and equipment 139,004 139,004 131,318,304 113,148,230 Less: Accumulated depreciation, amortization, depletion and impairments (99,468,927 ) (18,902,524 ) Total property and equipment, net $ 31,849,377 $ 94,245,706 The following table shows depreciation, depletion and amortization expense by type of asset: Years Ended December 31, 2015 2014 Depletion of costs for evaluated oil and natural gas properties $ 9,278,108 $ 9,359,952 Depreciation and amortization of other property and equipment 16,295 29,138 Total depreciation, amortization and depletion $ 9,294,403 $ 9,389,090 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 $71,272,000 for the year ended December 31, 2015. The Company did not have any impairment of its proved oil and gas properties for the year ended December 31, 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.

8. Oil and Natural Gas Properti

8. Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Natural Gas Properties	The following tables summarize gross and net productive oil wells by state at December 31, 2015 and 2014. A net well represents our percentage ownership of a gross well. The following tables do not include wells in which our interest is limited to royalty and overriding royalty interests. The following tables also do not include wells which were awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation. December 31, 2015 December 31, 2014 Gross Net Gross Net North Dakota 344 10.58 242 7.51 Montana 5 0.37 5 0.37 349 10.95 247 7.88 The Company’s oil and natural 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 December 31, 2015 and 2014, our principal oil and gas assets included approximately 8,100 and 10,000 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 natural gas properties for the years ended December 31, 2015 and 2014: Years Ended December 31, 2015 2014 Purchases of oil and natural gas properties and development costs for cash $ 20,714,004 $ 24,739,407 Purchase of oil and natural gas properties accrued at year-end 6,899,503 9,364,796 Purchase of oil and natural gas properties accrued at the beginning of the year (9,364,796 ) (7,953,801 ) Advances to operators applied to development of oil and natural gas properties – 6,036,748 Capitalized asset retirement obligations 48,711 103,778 Total purchase and development costs, oil and natural gas properties $ 18,297,422 $ 32,290,928 2015 Acquisitions During 2015, the Company purchased approximately 9 net mineral acres of oil and natural gas properties in North Dakota and Montana. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $102,928. 2015 Divestitures During 2015, the Company sold approximately 14 net mineral acres of oil and natural gas properties and rights to individual well bores in North Dakota for total proceeds of $127,348. No gain or loss was recorded pursuant to the sales. 2014 Acquisitions During 2014, the Company purchased approximately 374 net mineral acres of oil and natural gas properties in North Dakota and Montana. In consideration for the assignment of these mineral leases, we paid the sellers a total of approximately $3,102,568. 2014 Divestitures During 2014, the Company sold approximately 502 net mineral acres of oil and natural gas properties and rights to individual well bores in North Dakota for total proceeds of $1,441,929. No gain or loss was recorded pursuant to the sales. Undeveloped Acreage Expirations During 2015 and 2014, we had leases encompassing 1,866 and 4,202 net acres, respectively; expire with carrying costs of $1,982,674 and $6,198,163, respectively that have been transferred to the full cost pool subject to depletion. We estimate that approximately 1,114 net acres with carrying costs of approximately $689,000 will expire prior to the commencement of production activities during 2016. The carrying costs of these leases, including those which we estimate will expire in 2016 have also been transferred to the full cost pool and are subject to depletion and ceiling test impairments. Additionally, approximately $285,000 of carrying cost related relating to leasehold interests expiring in 2017 and 2018 were transferred to the full cost pool due to impairments in the market value of the leasehold assets and were also subject to depreciation and ceiling test impairments.

9. Asset Retirement Obligation

9. Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. Under the provisions of FASB ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC 410-20-25 during the years ended December 31, 2015 and 2014: Years ended December 31, 2015 2014 Beginning asset retirement obligation $ 286,804 $ 160,665 Liabilities incurred for new wells placed in production 48,711 103,778 Accretion of discount on asset retirement obligations 32,574 22,361 Ending asset retirement obligation $ 368,089 $ 286,804

10. Derivative Instruments

10. Derivative Instruments	12 Months Ended
	Dec. 31, 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 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 “Losses on the mark-to-market of derivatives.” The Company has utilized swap and collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of crude oil production. 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 December 31, 2015, the Company had outstanding derivative contracts with respect to future production as follows: Crude Oil Swaps Oil Fixed Settlement Period (Barrels) Price April 1, 2016 – May 31, 2016 10,000 $ 90.36 April 1, 2016 – May 31, 2016 4,000 $ 88.15 April 1, 2016 – May 31, 2016 15,000 $ 62.88 Crude Oil Costless Collars Oil Floor/Ceiling Settlement Period (Barrels) Price Basis April 1, 2016 – May 31, 2016 3,334 $80.00/$89.50 NYMEX As of December 31, 2015, the Company had total volume on open commodity swaps of 29,000 barrels at a weighted average price of approximately $75.84. 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 realized gain on derivatives for the year ended December 31, 2015. Derivative Gains and Losses The following table presents realized and unrealized gains and losses on derivative instruments for the periods presented: Years Ended December 31, 2015 2014 Realized gain on derivatives: Crude oil fixed price swaps $ 10,325,126 $ 511,451 Crude oil collars 1,152,527 – Realized gain on derivatives, net $ 11,477,653 $ 511,451 Gain (loss) on the mark-to-market of derivatives: Crude oil fixed price swaps $ (5,669,678 ) $ 6,827,126 Crude oil collars (755,667 ) 966,295 Gain (loss) on the mark-to-market of derivatives, net $ (6,425,345 ) $ 7,793,421 Balance Sheet Offsetting of Derivative Assets and Liabilities 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 “Current portion of derivative instruments” and “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. December 31, 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 $ 1,154,417 $ (17 ) $ 1,154,400 $ 7,620,896 $ (41,151 ) $ 7,579,745 December 31, 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: December 31, 2015 2014 Derivative assets $ 1,154,400 $ 3,571,803 Noncurrent derivative assets – 4,007,942 Net amount of assets on the balance sheet 1,154,400 7,579,745 Derivative liabilities – – Noncurrent derivative liabilities – – Net amounts of liabilities on the balance sheet – – Total derivative assets, net $ 1,154,400 $ 7,579,745

11. Fair Value of Financial Ins

11. Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	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 cash and cash equivalents and a revolving credit facility that must be measured under the 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 balances sheet as of December 31, 2015 and 2014: Fair Value Measurements at December 31, 2015 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 228,194 $ – $ – Derivative Instruments (crude oil swaps and collars) – 1,154,400 – Total assets 228,194 1,154,400 – Liabilities Revolving credit facilities and long term debt, net of discounts – 60,350,629 – Total Liabilities – 60,350,629 – $ 228,194 $ (59,196,229 ) $ – 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 years ended December 31, 2015 and 2014. Level 2 liabilities include revolving credit facilities. No fair value adjustment was necessary during the years ended December 31, 2015 and 2014.

12. Revolving Credit Facilities

12. Revolving Credit Facilities and Long Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Revolving Credit Facilities and Long Term Debt	Senior Credit Facility 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 $32 million as of December 31, 2015, of which $27.75 million was borrowed and outstanding as of December, 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 $27.75 million and $22.6 million outstanding under the Senior Credit Agreement as of December 31, 2015 and 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 December 31, 2015. The Company had borrowings of $30 million and $30 million outstanding under the Subordinated Credit Facility as of December 31, 2015 and 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 December 31, 2015, except as noted below under “Covenant Violations”. Covenant Violations The Company was out of compliance with the collateral coverage ratio as of December 31, 2015. Additionally, the audit report the Company received with respect to its financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under both its Senior Credit Facility and Subordinated Credit Facility. See Note 3, “Going Concern”, for additional information. As such, both the Senior Credit Facility and the Subordinated Credit Facility are in default and are classified on the balance sheet as current liabilities. 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 $1,645,749 and $628,195 was amortized during the years ended December 31, 2015 and 2014. The remaining unamortized balance of the debt discount attributable to the warrants is $-0- as of December 31, 2015. The amortization of the debt discount attributable to the warrants was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt. Amounts outstanding under revolving credit facilities and long term debts consisted of the following as of December 31, 2015 and 2014, respectively: December 31, 2015 2014 Senior Revolving Credit Facility, Cadence Bank, N.A. $ 27,750,000 $ 22,600,000 Subordinated Credit Agreement, Chambers 30,000,000 30,000,000 PIK Interest on Subordinated Credit Agreement, Chambers 2,600,629 1,307,086 Total credit facilities and long term debts 60,350,629 53,907,086 Less: Unamortized OID – (426,734 ) Less: Unamortized debt discount attributable to warrants – (1,645,749 ) Total credit facilities and long term debts, net of discounts 60,350,629 51,834,603 Less: current maturities (1) (60,350,629 ) – Long term portion of credit facilities and long term debts $ – $ 51,834,603 (1) Due to existing and anticipated covenant violations, the Company’s Senior Credit Facility and Subordinated Credit Facility were classified as current at December 31, 2015. 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 $426,734 and $144,904 was amortized during the years ended December 31, 2015 and 2014, respectively. The remaining unamortized balance of the debt discount attributable to the OID is $-0- as of December 31, 2015 as the amortization was accelerated in 2015 to fully amortize the discount as of December 31, 2015 when the related debt became payable on demand due to a default on the related debt. The following presents components of interest expense for the years ended December 31, 2015 and 2014, respectively: Years Ended December 31, 2015 2014 Credit Facilities, accrued PIK interest $ 1,293,543 $ 1,105,203 Credit Facilities, amortization of OID 426,734 144,904 Credit Facilities, interest and commitment fees 4,381,278 3,453,349 Credit Facilities, amortization of debt issuance costs 751,019 326,258 Credit Facilities, amortization of warrant costs 1,645,749 628,195 Capitalized interest (362,075 ) (372,673 ) $ 8,136,248 $ 5,285,236

13. Stockholders' Equity

13. Stockholders' Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
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.

14. Options

14. Options	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Options	The following table presents all options granted during the year ended December 31, 2015: Number Term Vesting Black-Scholes Options Total Expense Expense Grant of Strike in Term in Pricing Model: Fair Recognized Recognized Date Recipient Options Price Years (1) Years (1) Volatility Call Value Value in 2015 in 2014 9/30/15 Kenneth DeCubellis, CEO 200,000 $ 0.172 10 5 106% $ 0.1434 $ 28,676 $ 1,434 $ – 9/30/15 James Moe, CFO 150,000 $ 0.172 10 5 106% $ 0.1434 21,507 1,075 – 9/30/15 Michael Eisele, COO 200,000 $ 0.172 10 5 106% $ 0.1434 28,676 1,434 – 9/30/15 Employee 150,000 $ 0.172 10 5 106% $ 0.1434 21,507 1,075 – 9/30/15 Employee 30,000 $ 0.172 10 5 106% $ 0.1434 4,301 215 – 9/30/15 Employee 30,000 $ 0.172 10 5 106% $ 0.1434 4,301 215 – 9/30/15 Employee 30,000 $ 0.172 10 5 106% $ 0.1434 4,301 215 – 9/30/15 Employee 10,000 $ 0.172 10 5 106% $ 0.1434 1,434 72 – 9/30/15 Joseph Lahti, Director 100,000 $ 0.172 10 5 106% $ 0.1434 14,338 717 – 9/30/15 Benjamin Oehler, Director 100,000 $ 0.172 10 5 106% $ 0.1434 14,338 717 – 1,000,000 $ 143,379 $ 7,169 $ – The following table presents all options granted during the year ended December 31, 2014: Number Term Vesting Black-Scholes Options Total Expense Expense Grant of Strike in Term in Pricing Model: Fair Recognized Recognized Date Recipient Options Price Years (1) Years (1) Volatility Call Value Value in 2015 in 2014 12/22/14 Kenneth DeCubellis, CEO 58,000 $ 0.280 10 5 198% $ 0.2237 $ 12,974 $ 2,596 $ 64 12/22/14 James Moe, CFO 40,000 $ 0.280 10 5 198% $ 0.2237 8,947 1,788 44 12/22/14 Michael Eisele, COO 40,000 $ 0.280 10 5 198% $ 0.2237 8,947 1,788 44 12/22/14 Employee 36,000 $ 0.280 10 5 198% $ 0.2237 8,053 1,612 40 12/22/14 Employee 12,000 $ 0.280 10 5 198% $ 0.2237 2,684 536 13 12/22/14 Employee 12,000 $ 0.280 10 5 198% $ 0.2237 2,684 536 13 12/22/14 Employee 2,000 $ 0.280 10 5 198% $ 0.2237 447 88 2 12/8/14 Joseph Lahti, Director 100,000 $ 0.374 10 5 202% $ 0.2956 29,563 5,912 372 12/8/14 Benjamin Oehler, Director 100,000 $ 0.374 10 5 202% $ 0.2956 29,563 5,912 372 12/8/14 Bradley Berman, Director 100,000 $ 0.374 10 5 202% $ 0.2956 29,563 5,912 372 12/1/14 Employee 100,000 $ 0.379 10 5 193% $ 0.2999 29,988 5,996 500 02/10/14 Employee 27,500 $ 0.782 10 5 116% $ 0.6778 18,639 – 1,976 01/30/14 Employee 5,000 $ 0.630 10 5 115% $ 0.5471 2,735 548 499 632,500 $ 184,787 $ 33,224 $ 4,311 (1) Options Cancelled On September 30, 2015, 1,000,000 common stock options were voluntarily forfeited by our chairman of the board. On August 22, 2014, 27,500 common stock options with a strike price of $0.782 were forfeited pursuant to the resignation of an employee. No other options were cancelled during 2015 or 2014. Options Expired On November 30, 2015, a total of 66,667 options with a strike price of $0.30 per share expired. On October 17, 2015, a total of 86,667 options with a strike price of $1.00 per share expired. On November 30, 2014, a total of 12,000 options with a strike price of $0.92 per share expired. On August 8, 2014, a total of 24,000 options with a strike price of $0.51 per share expired. No other options expired during 2015 or 2014. Options Exercised No options were exercised during the year ended December 31, 2015 and 2014. The following is a summary of information about the Stock Options outstanding at December 31, 2015. Shares Underlying Shares Underlying Options Outstanding Options Exercisable Weighted Shares Average Weighted Shares Weighted Underlying Remaining Average Underlying Average Range of Options Contractual Exercise Options Exercise Exercise Prices Outstanding Life Price Exercisable Price $0.03 - $1.00 7,055,500 7.51 years $0.44 3,111,000 $0.47 The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants under the fixed option plan: December 31, December 31, 2015 2014 Average risk-free interest rates 1.75% 2.00% Average expected life (in years) 5 5 Volatility 106% 97% The Black-Scholes option pricing model was developed for use in estimating the fair value of short-term traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including expected stock price volatility. Because the Company’s employee stock options have characteristics significantly different from those of traded options and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. During the years ended December 31, 2015 and 2014 there were no options granted with an exercise price below the fair value of the underlying stock at the grant date. The following is a summary of activity of outstanding stock options: Weighted Average Number Exercise of Shares Prices Balance, December 31, 2013 6,639,834 $ 0.59 Options expired (36,000 ) (0.65 ) Options cancelled (27,500 ) (0.78 ) Options granted 632,500 0.36 Options exercised – – Balance, December 31, 2014 7,208,834 0.56 Options expired (153,334 ) (0.70 ) Options cancelled (1,000,000 ) (1.00 ) Options granted 1,000,000 0.17 Options exercised – – Balance, December 31, 2015 7,055,500 0.44 Exercisable, December 31, 2015 3,111,000 $ 0.47 The Company expensed $623,700 and $578,919 from the amortization of common stock options during the years ended December 31, 2015 and 2014, respectively.

15. Warrants

15. Warrants	12 Months Ended
	Dec. 31, 2015
Warrants and Rights Note Disclosure [Abstract]
Warrants	Warrants Granted No warrants were granted during the year ended December 31, 2015 and 2014. Warrants Cancelled No warrants were cancelled during the year ended December 31, 2015. A total of 330,000 warrants with a strike price of $1.50 per share were voluntarily forfeited on December 30, 2014. Warrants Expired A total of 585,000 warrants with a strike price of $0.38 per share expired on August 31, 2015. No warrants expired during the year ended December 31, 2014. Warrants Exercised No warrants were exercised during the years ended December 31, 2015 and 2014. The following is a summary of information about the Warrants outstanding at December 31, 2015: Shares Underlying Shares Underlying Warrants Outstanding Warrants Exercisable Weighted Shares Average Weighted Shares Weighted Underlying Remaining Average Underlying Average Range of Warrants Contractual Exercise Warrants Exercise Exercise Prices Outstanding Life Price Exercisable Price $0.65 - $1.50 8,548,375 1.74 years $0.95 8,548,375 $0.95 The fair value of each warrant grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants under the fixed option plan: December 31, 2015 2014 Average risk-free interest rates N/A N/A Average expected life (in years) N/A N/A Volatility N/A N/A The Black-Scholes option pricing model was developed for use in estimating the fair value of short-term traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including expected stock price volatility. Because the Company’s warrants have characteristics significantly different from those of traded warrants and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion the existing models do not necessarily provide a reliable single measure of the fair value of its warrants. During the years ended December 31, 2015 and 2014, there were no warrants granted with an exercise price below the fair value of the underlying stock at the grant date. The following is a summary of activity of outstanding warrants: Weighted Average Number Exercise of Shares Prices Balance, December 31, 2013 9,463,375 $ 0.94 Warrants expired – – Warrants cancelled (330,000 ) (1.50 ) Warrants granted – – Warrants exercised – – Balance, December 31, 2014 9,133,375 0.92 Warrants expired (585,000 ) (0.38 ) Warrants cancelled – – Warrants granted – – Warrants exercised – – Balance, December 31, 2015 8,548,375 0.95 Exercisable, December 31, 2015 8,548,375 $ 0.95

16. Income Taxes

16. Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	We account for income taxes under the provisions of ASC Topic 740, Income taxes, Our provision for income taxes for the years ended December 31, 2015 and 2014 consisted of the following: December 31, 2015 2014 Current taxes $ – $ – Deferred tax provision (benefit) (6,593,040 ) 2,559,195 Valuation allowance – – Net income tax provision (benefit) $ (6,593,040 ) $ 2,559,195 The effective income tax rate for the years ended December 31, 2015 and 2014 consisted of the following: December 31, 2015 2014 Federal statutory income tax rate 35.00% 35.00% State income taxes 4.13% 2.09% Effect of statutory rate change on deferred taxes (0.44% ) (0.35% ) Permanent differences 0.00% 0.07% Change in valuation allowance (30.12% ) 0.22% Net effective income tax rate 8.57% 37.03% The Company’s state income tax rate as of December 31, 2015 increased by 2.03% from 2.09% as of December 31, 2014, to 4.12%. This increase in the effective tax rate is attributable to changes in the Company’s state apportionment factors in the current year. In 2015, due to the realized derivatives being sourced to the state of Minnesota for income tax purposes, a larger percentage of the Company’s activity was expected to be apportioned to that state. As compared to North Dakota and Montana, the other states the Company files tax returns in which have a corporate income tax rate of 4.31% and 6.75%, respectively, the state of Minnesota has a 9.80% corporate income tax rate. The components of the deferred tax assets and liabilities as of December 31, 2015 and 2014 are as follows: December 31, 2015 2014 Deferred tax assets: Federal and state net operating loss carryovers $ 9,294,824 $ 10,438,275 Stock compensation 2,531,641 1,558,409 Ceiling test impairment, intangible drilling costs and other exploration costs capitalized for financial reporting purposes 12,186,927 – Derivative liabilities – – Reorganization costs 52,415 49,693 Asset retirement obligation 144,005 106,377 Total deferred tax assets $ 24,209,812 $ 12,152,754 Deferred tax liabilities: Ceiling test impairment, intangible drilling costs and other exploration costs capitalized for financial reporting purposes $ – $ (15,344,769 ) Derivative assets (451,628 ) (2,811,366 ) Property and equipment (7,006 ) (10,107 ) Total deferred liabilities (458,634 ) (18,166,242 ) Net deferred tax assets (liabilities) 23,751,178 (6,013,488 ) Less: valuation allowance (23,751,178 ) (579,552 ) Deferred tax assets (liabilities) $ – $ (6,593,040 ) As of December 31, 2015, the Company has net operating loss carryover of approximately $23,758,360. Under existing Federal law, the net operating loss may be utilized to offset taxable income through the year ended December 31, 2035. A portion of the net operating loss carryover begins to expire in 2030. ASC Topic 740 provides that a valuation allowance is recognized if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. The Company had recognized a valuation allowance reducing the carrying value of its deferred tax asset by $579,552 as of December 31, 2014. As of December 31, 2015, the Company has increased its valuation allowance by $23,171,626 to result in an allowance of $23,751,178. This increase was to more accurately reflect an allowance on the net deferred tax assets which the Company believes it is more likely than not that the benefit of these assets will not be realized. The Company files annual US Federal income tax returns and annual income tax returns for the states of Minnesota, North Dakota and Montana. We are not subject to income tax examinations by tax authorities for years before 2010 for all returns. Income taxing authorities have conducted no formal examinations of our past federal or state income tax returns and supporting records. The Company adopted the provisions of ASC Topic 740 regarding uncertainty in income taxes. The Company has found no significant uncertain tax positions as of any date on or before December 31, 2015.

17. Commitments and Contingenci

17. Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	The Company is involved in various inquiries, administrative proceedings and litigation relating to matters arising in the normal course of business. The Company 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. Management is not able to estimate the minimum loss to be incurred, if any, as a result of the final outcome of the matters arising in the normal course of business but believes they are not likely to have a material adverse effect upon the Company’s financial position or results of operations and, accordingly, no provision for loss has been recorded. 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 December 31, 2015 the Company had committed to AFE’s of approximately $1.0 million beyond amounts previously paid or accrued.

18. Subsequent Events

18. Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Debt Financing On March 26, 2016, the Company signed documentation to commence the BRHC Transaction, which is expected to close in April or May of 2016. Please refer to Note 3 – Going Concern, for details of the transaction. From January 1, 2016 through March 25, 2016, the Company received cumulative advances, net of repayments, of $1.05 million pursuant to the Credit Facility with Cadence. Subsequent to December 31, 2015, the Company has added the following derivative contracts in the form of crude oil swaps based on NYMEX pricing: Contract Settlement Oil Fixed Date Period (Barrels) Price March 9, 2016 June 2016 10,000 $40.75 March 9, 2016 July 1, 2016 – December 31, 2016 8,000 / month $42.10 March 9, 2016 January 1, 2017 – December 31, 2017 6,000 / month $44.50

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information	12 Months Ended
	Dec. 31, 2015
Supplemental Oil And Gas Information Details - Proved And Unproved Costs
Supplemental Oil and Gas Information	Oil and Natural Gas Exploration and Production Activities Oil and gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company's oil and natural gas production activities are provided in the Company's related statements of operations. Costs Incurred and Capitalized Costs Net capitalized costs related to the Company’s oil and gas producing activities were as follows: December 31, 2015 2014 Proved oil and natural gas properties $ 131,168,906 $ 112,418,105 Unproved oil and natural gas properties 10,394 591,121 Accumulated depreciation, depletion and amortization, and impairment (99,371,071 ) (18,820,963 ) Total $ 31,808,229 $ 94,188,263 The Company incurred the following costs for oil and natural gas acquisition, exploration and development activities during the years ended December 31, 2015 and 2014: Years Ended December 31, 2015 2014 Costs incurred for the year: Proved property acquisition $ 102,928 $ 3,164,469 Unproved property acquisition – – Development 18,145,783 29,022,721 Total $ 18,248,711 $ 32,187,190 Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion: Years Ended December 31, 2015 2014 Property acquisition $ 10,394 $ 591,121 Development – – Total $ 10,394 $ 591,121 Oil and Natural Gas Reserves and Related Financial Data Information with respect to the Company's crude oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Netherland, Sewell & Associates, Inc. , independent petroleum consultants based on information provided by the Company. Oil and Natural Gas Reserve Data The following tables present the Company's independent petroleum consultants' estimates of its proved oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Oil Natural (Bbls) Gas (Mcf) Proved developed and undeveloped reserves as of December 31, 2013 4,074,492 2,778,593 Revisions of previous estimates (201,995 ) (131,966 ) Extensions, discoveries and other additions 1,199,673 925,763 Sale of reserves in place (17,982 ) (12,482 ) Production (256,257 ) (213,141 ) Proved developed and undeveloped reserves as of December 31, 2014 4,797,931 3,346,767 Revisions of previous estimates (2,604,830 ) (1,160,775 ) Extensions, discoveries and other additions 175,602 166,953 Sale of reserves in place – – Production (356,678 ) (413,913 ) Proved developed and undeveloped reserves as of December 31, 2015 2,012,025 1,939,032 Proved developed reserves: December 31, 2014 1,799,515 1,363,076 December 31, 2015 1,969,223 1,913,914 Proved undeveloped reserves: December 31, 2014 2,998,416 1,983,691 December 31, 2015 42,802 25,118 Proved reserves are estimated quantities of oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years. The Company recognized significant additions in net quantities of its proved reserves relating to acquisitions, extensions, discoveries and other additions during the year ended December 31, 2014. The Company’s increase in proved reserves during 2014 was primarily due to acquisitions, extensions, discoveries, and other additions related to drilling activity in and adjacent to our Bakken/Three Forks acreage. During that period, the Company’s net producing well count increased from 4.87 net wells at December 31, 2013 to 7.88 net wells at December 31, 2014. This rapid growth caused the Company’s proved reserves to grow significantly. As a percentage of total acquisitions, extensions, discoveries and other additions to proved reserves for the years ended December 31, 2015 and 2014, -0-% and 48%, respectively, were to the Company’s proved undeveloped reserves. During 2015, we had a negative revision of 2,798,293 Boe, or 52%, of our December 31, 2014 estimated proved reserves balance. The primary cause for these revisions was related to wells that were non-economical due to lower oil prices and wells that will not be developed due to the Company’s cash flow. Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein The following table presents a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas were prepared in accordance with the provisions of ASC 932-235-50-5. Future cash inflows were computed by applying average prices of oil and natural gas for the first day of the last twelve months as of December 31, 2015 to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company's oil and natural gas reserves. The following is a summary of the Company’s standardized measure of discounted future cash flows for the years as indicated: Years Ended December 31, 2015 2014 Future cash inflows $ 86,500,194 $ 423,219,613 Future production costs (39,241,657 ) (148,863,530 ) Future development costs (468,738 ) (78,208,378 ) Future income tax expense – (42,717,592 ) Future net cash flows 46,789,799 153,430,113 10% annual discount for estimated timing of cash flows (14,992,255 ) (68,308,455 ) Standardized measure of discounted future net cash flows $ 31,797,544 $ 85,121,658 The twelve month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company's reserves. The prices for the Company's reserve estimates were as follows: Oil Natural (Bbl) Gas (Mcf) December 31, 2015 $ 41.34 $ 1.71 December 31, 2014 $ 83.26 $ 7.10 Changes in the Standardized Measure of Discounted Future Net Cash Flows at 10% per annum are as follows: Years Ended December 31, 2015 2014 Standard measure, beginning of year $ 85,121,658 $ 61,659,271 Sales of oil and natural gas produced, net of production costs (9,763,075 ) (16,193,558 ) Net changes of prices and production costs (56,694,415 ) (6,329,518 ) Revisions of quantity estimates (33,837,468 ) (5,567,648 ) Extensions and discoveries and other adjustments 3,441,930 34,053,998 Changes in estimated future development costs 216,624 1,453,332 Sale of reserves in place – (276,920 ) Previously estimated development costs incurred during the period 16,391,373 8,946,915 Accretion of discount 10,033,467 7,437,666 Net changes in income taxes 15,240,529 (2,523,100 ) Changes in timing and other 1,646,921 2,461,220 Standard measure, end of year $ 31,797,544 $ 85,121,658

2. Summary of Significant Acc26

2. Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Accounting	Basis of Accounting Our financial statements are prepared using the accrual method of accounting as generally accepted in the United States of America (U.S. GAAP) and the rules of the Securities and Exchange Commission (SEC).
Segment Reporting	Segment Reporting FASB ASC 280-10-50 requires annual and interim reporting for an enterprise’s operating segments and related disclosures about its products, services, geographic areas and major customers. An operating segment is defined as a component of an enterprise that engages in business activities from which it may earn revenues and expenses, and about which separate financial information is regularly evaluated by the chief operating decision maker in deciding how to allocate resources. The Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations.
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. The Company had no cash equivalents on hand as of December 31, 2015 and December 31, 2014.
Cash in Excess of FDIC and SIPC 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) up to $250,000, under current regulations. The Company didn’t have any funds in excess of FDIC insured limits at December 31, 2015 and 2014. 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 certain debts are capitalized and amortized over the term of the related debt using the straight-line method, which approximates the effective interest method. The Company paid $50,000 and $254,394 of debt issuance costs during the years ended December 31, 2015 and 2014, respectively, of which the unamortized balance of debt issuance costs at December 31, 2015 and 2014 was $0 and $701,019, respectively. Amortization of debt issuance costs charged to interest expense was $751,019 and $326,258 for the years ended December 31, 2015 and 2014, respectively. When a loan is paid in full or becomes due on demand due to a default on the loan, 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 December 31, 2015. We have recognized depreciation expense on these website costs of $257 and $15,380 for the years ended December 31, 2015 and 2014, respectively.
Income Taxes	Income Taxes The Company recognizes deferred tax assets and liabilities based on differences between the financial reporting and tax basis of assets and liabilities using the enacted tax rates and laws that are expected to be in effect when the differences are expected to be recovered. The Company provides a valuation allowance for deferred tax assets for which it does not consider realization of such assets to be more likely than not.
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 natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non-oil and gas long-lived assets. Depreciation expense was $16,295 and $29,138 for the years ended December 31, 2015 and 2014, respectively.
Revenue Recognition	Revenue Recognition The Company recognizes oil and gas revenues from its interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for gas balancing of gas production and would recognize a liability if the existing proved reserves were not adequate to cover the current 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 natural 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 years ended December 31, 2015 and 2014, respectively: Years Ended December 31, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ – $ 61,861 Capitalized Interest Costs 362,075 372,673 Total $ 362,075 $ 434,534 Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 20% or more of the proved reserves related to a single full cost pool. During the year ended December 31, 2015, the Company sold approximately 14 net acres and rights to individual well bores for total proceeds of $127,348. During the year ended December 31, 2014, the Company sold approximately 502 net acres for total proceeds of $1,441,929. 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 natural 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. The Company recognized impairments of oil and gas properties of $71,272,000 in the year ended December 31, 2015. No impairment was recognized during the year ended December 31, 2014.
Concentrations	Concentrations Our revenue is solely derived from oil and gas sales to various purchasers, the market for which has very inelastic demand. Due to this, we do not consider any purchasers to represent a material concentration to our sales for the years ended December 31, 2015 or 2014, as we believe any of our customers could easily be replaced. Since we do not operate any of our wells, we depend on our drilling partner operators to perform the drilling and other operating activities required for all sales of oil and gas. These operators are also responsible for remitting to us our revenue proceeds and billing us for drilling costs and lease operating expenses incurred. We had material concentrations of accounts receivable owed from four (4) and four (4) operators during the years ended December 31, 2015 and 2014, respectively, representing 70% and 56% of total oil and gas revenues and 73% and 49% of total oil and gas accounts receivable as of December 31, 2015 and 2014, respectively. As of December 31, 2015 and 2014, we had 10.95 and 7.88 net producing wells, respectively. As of December 31, 2015 and 2014, these operating partners operated 56% and 52% of the net producing wells, respectively.
Basic and Diluted Loss Per Share	Basic and Diluted Loss Per Share Basic earnings per share (“EPS”) are computed by dividing net income (the numerator) by the weighted average number of common shares outstanding for the period (the denominator). Diluted EPS is computed by dividing net income by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants and restricted stock. The number of potential common shares outstanding relating to stock options, warrants and restricted stock is computed using the treasury stock method. The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the years ended December 31, 2015 and 2014 are as follows: Years Ended December 31, 2015 2014 Weighted average common shares outstanding – basic 47,979,990 47,979,990 Plus: Potentially dilutive common shares: Stock options and warrants – 1,199,735 Weighted average common shares outstanding – diluted 47,979,990 49,179,725 For 2015, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share. Stock options and warrants excluded from the calculation of diluted EPS because their effect was anti-dilutive were 15,603,375 and 13,683,209 as of December 31, 2015 and 2014, respectively.
Stock-Based Compensation	Stock-Based Compensation Under FASB ASC 718-10-30-2, all share-based payments to employees, including grants of employee stock options, are to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. Amortization of the fair values of stock options issued for services and compensation totaled $623,700 and $578,919 for the years ended December 31, 2015 and 2014, respectively. The fair values of stock options were determined 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 and are being amortized over the related implied service term, or vesting period.
Uncertain Tax Positions	Uncertain Tax Positions In accordance with ASC 740, “Income Taxes” (“ASC 740”), the Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be capable of withstanding examination by the taxing authorities based on the technical merits of the position. 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 can 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. The Company 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.
Recent Accounting Pronouncements	Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board ("FASB") that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company's financial statements upon adoption. In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers." The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers – Deferral of the Effective Date," In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40)." The new guidance addresses management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period beginning after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. The Company has chosen to adopt this pronouncement beginning with the issuance of this report due to the applicability to our current condition. In April 2015, the FASB issued ASU No. 2015-03, "Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs," that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items. The Company is currently evaluating the impact that this new guidance will have on its financial statements. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which eliminates the current requirement to present deferred tax liabilities and assets as current and noncurrent amounts in a classified statement of financial position. Instead, entities will be required to classify all deferred tax assets and liabilities as noncurrent in a statement of financial position. This standard is effective financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application is permitted. The Company elected early application of this ASU as of December 31, 2015, and has applied its provisions prospectively.

2. Summary of Significant Acc27

2. Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Schedule of Capitalized Costs	Years Ended December 31, 2015 2014 Capitalized Certain Payroll and Other Internal Costs $ – $ 61,861 Capitalized Interest Costs 362,075 372,673 Total $ 362,075 $ 434,534
Basic and Diluted Loss Per Share	Years Ended December 31, 2015 2014 Weighted average common shares outstanding – basic 47,979,990 47,979,990 Plus: Potentially dilutive common shares: Stock options and warrants – 1,199,735 Weighted average common shares outstanding – diluted 47,979,990 49,179,725

7. Property and Equipment (Tabl

7. Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property and equipment:
Property and equipment	December 31, 2015 2014 Oil and natural gas properties, full cost method: Evaluated costs $ 131,168,906 $ 112,418,105 Unevaluated costs, not subject to amortization or ceiling test 10,394 591,121 131,179,300 113,009,226 Other property and equipment 139,004 139,004 131,318,304 113,148,230 Less: Accumulated depreciation, amortization, depletion and impairments (99,468,927 ) (18,902,524 ) Total property and equipment, net $ 31,849,377 $ 94,245,706
Depreciation, depletion, and amortization expense	Years Ended December 31, 2015 2014 Depletion of costs for evaluated oil and natural gas properties $ 9,278,108 $ 9,359,952 Depreciation and amortization of other property and equipment 16,295 29,138 Total depreciation, amortization and depletion $ 9,294,403 $ 9,389,090

8. Oil and Gas Properties (Tabl

8. Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Gross and net productive oil wells	December 31, 2015 December 31, 2014 Gross Net Gross Net North Dakota 344 10.58 242 7.51 Montana 5 0.37 5 0.37 349 10.95 247 7.88
Capitalized costs for oil and gas properties	Years Ended December 31, 2015 2014 Purchases of oil and natural gas properties and development costs for cash $ 20,714,004 $ 24,739,407 Purchase of oil and natural gas properties accrued at year-end 6,899,503 9,364,796 Purchase of oil and natural gas properties accrued at the beginning of the year (9,364,796 ) (7,953,801 ) Advances to operators applied to development of oil and natural gas properties – 6,036,748 Capitalized asset retirement obligations 48,711 103,778 Total purchase and development costs, oil and natural gas properties $ 18,297,422 $ 32,290,928

9. Asset Retirement Obligation

9. Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation	Years ended December 31, 2015 2014 Beginning asset retirement obligation $ 286,804 $ 160,665 Liabilities incurred for new wells placed in production 48,711 103,778 Accretion of discount on asset retirement obligations 32,574 22,361 Ending asset retirement obligation $ 368,089 $ 286,804

10. Derivative Instruments (Tab

10. Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding derivative contracts with respect to future production	Crude Oil Swaps Oil Fixed Settlement Period (Barrels) Price April 1, 2016 – May 31, 2016 10,000 $ 90.36 April 1, 2016 – May 31, 2016 4,000 $ 88.15 April 1, 2016 – May 31, 2016 15,000 $ 62.88 Crude Oil Costless Collars Oil Floor/Ceiling Settlement Period (Barrels) Price Basis April 1, 2016 – May 31, 2016 3,334 $80.00/$89.50 NYMEX
Realized and unrealized gains and losses on derivative instruments	Years Ended December 31, 2015 2014 Realized gain on derivatives: Crude oil fixed price swaps $ 10,325,126 $ 511,451 Crude oil collars 1,152,527 – Realized gain on derivatives, net $ 11,477,653 $ 511,451 Gain (loss) on the mark-to-market of derivatives: Crude oil fixed price swaps $ (5,669,678 ) $ 6,827,126 Crude oil collars (755,667 ) 966,295 Gain (loss) on the mark-to-market of derivatives, net $ (6,425,345 ) $ 7,793,421
Offsetting derivative assets and liabilities	December 31, 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 $ 1,154,417 $ (17 ) $ 1,154,400 $ 7,620,896 $ (41,151 ) $ 7,579,745 December 31, 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	December 31, 2015 2014 Derivative assets $ 1,154,400 $ 3,571,803 Noncurrent derivative assets – 4,007,942 Net amount of assets on the balance sheet 1,154,400 7,579,745 Derivative liabilities – – Noncurrent derivative liabilities – – Net amounts of liabilities on the balance sheet – – Total derivative assets, net $ 1,154,400 $ 7,579,745

11. Fair Value of Financial I32

11. Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Valuation of financial instruments at fair value	Fair Value Measurements at December 31, 2015 Level 1 Level 2 Level 3 Assets Cash and cash equivalents $ 228,194 $ – $ – Derivative Instruments (crude oil swaps and collars) – 1,154,400 – Total assets 228,194 1,154,400 – Liabilities Revolving credit facilities and long term debt, net of discounts – 60,350,629 – Total Liabilities – 60,350,629 – $ 228,194 $ (59,196,229 ) $ – 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 ) $ –

12. Revolving Credit Faciliti33

12. Revolving Credit Facilities and Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Revolving credit facilities and long term debts	December 31, 2015 2014 Senior Revolving Credit Facility, Cadence Bank, N.A. $ 27,750,000 $ 22,600,000 Subordinated Credit Agreement, Chambers 30,000,000 30,000,000 PIK Interest on Subordinated Credit Agreement, Chambers 2,600,629 1,307,086 Total credit facilities and long term debts 60,350,629 53,907,086 Less: Unamortized OID – (426,734 ) Less: Unamortized debt discount attributable to warrants – (1,645,749 ) Total credit facilities and long term debts, net of discounts 60,350,629 51,834,603 Less: current maturities (1) (60,350,629 ) – Long term portion of credit facilities and long term debts $ – $ 51,834,603 (1) Due to existing and anticipated covenant violations, the Company’s Senior Credit Facility and Subordinated Credit Facility were classified as current at December 31, 2015.
Components of interest expense	Years Ended December 31, 2015 2014 Credit Facilities, accrued PIK interest $ 1,293,543 $ 1,105,203 Credit Facilities, amortization of OID 426,734 144,904 Credit Facilities, interest and commitment fees 4,381,278 3,453,349 Credit Facilities, amortization of debt issuance costs 751,019 326,258 Credit Facilities, amortization of warrant costs 1,645,749 628,195 Capitalized interest (362,075 ) (372,673 ) $ 8,136,248 $ 5,285,236

14. Options (Tables)

14. Options (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Options granted	The following table presents all options granted during the year ended December 31, 2015: Number Term Vesting Black-Scholes Options Total Expense Expense Grant of Strike in Term in Pricing Model: Fair Recognized Recognized Date Recipient Options Price Years (1) Years (1) Volatility Call Value Value in 2015 in 2014 9/30/15 Kenneth DeCubellis, CEO 200,000 $ 0.172 10 5 106% $ 0.1434 $ 28,676 $ 1,434 $ – 9/30/15 James Moe, CFO 150,000 $ 0.172 10 5 106% $ 0.1434 21,507 1,075 – 9/30/15 Michael Eisele, COO 200,000 $ 0.172 10 5 106% $ 0.1434 28,676 1,434 – 9/30/15 Employee 150,000 $ 0.172 10 5 106% $ 0.1434 21,507 1,075 – 9/30/15 Employee 30,000 $ 0.172 10 5 106% $ 0.1434 4,301 215 – 9/30/15 Employee 30,000 $ 0.172 10 5 106% $ 0.1434 4,301 215 – 9/30/15 Employee 30,000 $ 0.172 10 5 106% $ 0.1434 4,301 215 – 9/30/15 Employee 10,000 $ 0.172 10 5 106% $ 0.1434 1,434 72 – 9/30/15 Joseph Lahti, Director 100,000 $ 0.172 10 5 106% $ 0.1434 14,338 717 – 9/30/15 Benjamin Oehler, Director 100,000 $ 0.172 10 5 106% $ 0.1434 14,338 717 – 1,000,000 $ 143,379 $ 7,169 $ – The following table presents all options granted during the year ended December 31, 2014: Number Term Vesting Black-Scholes Options Total Expense Expense Grant of Strike in Term in Pricing Model: Fair Recognized Recognized Date Recipient Options Price Years (1) Years (1) Volatility Call Value Value in 2015 in 2014 12/22/14 Kenneth DeCubellis, CEO 58,000 $ 0.280 10 5 198% $ 0.2237 $ 12,974 $ 2,596 $ 64 12/22/14 James Moe, CFO 40,000 $ 0.280 10 5 198% $ 0.2237 8,947 1,788 44 12/22/14 Michael Eisele, COO 40,000 $ 0.280 10 5 198% $ 0.2237 8,947 1,788 44 12/22/14 Employee 36,000 $ 0.280 10 5 198% $ 0.2237 8,053 1,612 40 12/22/14 Employee 12,000 $ 0.280 10 5 198% $ 0.2237 2,684 536 13 12/22/14 Employee 12,000 $ 0.280 10 5 198% $ 0.2237 2,684 536 13 12/22/14 Employee 2,000 $ 0.280 10 5 198% $ 0.2237 447 88 2 12/8/14 Joseph Lahti, Director 100,000 $ 0.374 10 5 202% $ 0.2956 29,563 5,912 372 12/8/14 Benjamin Oehler, Director 100,000 $ 0.374 10 5 202% $ 0.2956 29,563 5,912 372 12/8/14 Bradley Berman, Director 100,000 $ 0.374 10 5 202% $ 0.2956 29,563 5,912 372 12/1/14 Employee 100,000 $ 0.379 10 5 193% $ 0.2999 29,988 5,996 500 02/10/14 Employee 27,500 $ 0.782 10 5 116% $ 0.6778 18,639 – 1,976 01/30/14 Employee 5,000 $ 0.630 10 5 115% $ 0.5471 2,735 548 499 632,500 $ 184,787 $ 33,224 $ 4,311 (1)
Stock options outstanding	Shares Underlying Shares Underlying Options Outstanding Options Exercisable Weighted Shares Average Weighted Shares Weighted Underlying Remaining Average Underlying Average Range of Options Contractual Exercise Options Exercise Exercise Prices Outstanding Life Price Exercisable Price $0.03 - $1.00 7,055,500 7.51 years $0.44 3,111,000 $0.47
Options assumption	December 31, December 31, 2015 2014 Average risk-free interest rates 1.75% 2.00% Average expected life (in years) 5 5 Volatility 106% 97%
Summary of activity of outstanding stock options	Weighted Average Number Exercise of Shares Prices Balance, December 31, 2013 6,639,834 $ 0.59 Options expired (36,000 ) (0.65 ) Options cancelled (27,500 ) (0.78 ) Options granted 632,500 0.36 Options exercised – – Balance, December 31, 2014 7,208,834 0.56 Options expired (153,334 ) (0.70 ) Options cancelled (1,000,000 ) (1.00 ) Options granted 1,000,000 0.17 Options exercised – – Balance, December 31, 2015 7,055,500 0.44 Exercisable, December 31, 2015 3,111,000 $ 0.47

15. Warrants (Tables)

15. Warrants (Tables)	12 Months Ended
	Dec. 31, 2015
Warrants and Rights Note Disclosure [Abstract]
Warrants outstanding	Shares Underlying Shares Underlying Warrants Outstanding Warrants Exercisable Weighted Shares Average Weighted Shares Weighted Underlying Remaining Average Underlying Average Range of Warrants Contractual Exercise Warrants Exercise Exercise Prices Outstanding Life Price Exercisable Price $0.65 - $1.50 8,548,375 1.74 years $0.95 8,548,375 $0.95
Assumptions used for grants under the fixed option	December 31, 2015 2014 Average risk-free interest rates N/A N/A Average expected life (in years) N/A N/A Volatility N/A N/A
Summary of activity of outstanding warrants	Weighted Average Number Exercise of Shares Prices Balance, December 31, 2013 9,463,375 $ 0.94 Warrants expired – – Warrants cancelled (330,000 ) (1.50 ) Warrants granted – – Warrants exercised – – Balance, December 31, 2014 9,133,375 0.92 Warrants expired (585,000 ) (0.38 ) Warrants cancelled – – Warrants granted – – Warrants exercised – – Balance, December 31, 2015 8,548,375 0.95 Exercisable, December 31, 2015 8,548,375 $ 0.95

16. Income Taxes (Tables)

16. Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Provision for income taxes	December 31, 2015 2014 Current taxes $ – $ – Deferred tax provision (benefit) (6,593,040 ) 2,559,195 Valuation allowance – – Net income tax provision (benefit) $ (6,593,040 ) $ 2,559,195
Tax rate reconciliation	December 31, 2015 2014 Federal statutory income tax rate 35.00% 35.00% State income taxes 4.13% 2.09% Effect of statutory rate change on deferred taxes (0.44% ) (0.35% ) Permanent differences 0.00% 0.07% Change in valuation allowance (30.12% ) 0.22% Net effective income tax rate 8.57% 37.03%
Deferred tax assets and liabilities	December 31, 2015 2014 Deferred tax assets: Federal and state net operating loss carryovers $ 9,294,824 $ 10,438,275 Stock compensation 2,531,641 1,558,409 Ceiling test impairment, intangible drilling costs and other exploration costs capitalized for financial reporting purposes 12,186,927 – Derivative liabilities – – Reorganization costs 52,415 49,693 Asset retirement obligation 144,005 106,377 Total deferred tax assets $ 24,209,812 $ 12,152,754 Deferred tax liabilities: Ceiling test impairment, intangible drilling costs and other exploration costs capitalized for financial reporting purposes $ – $ (15,344,769 ) Derivative assets (451,628 ) (2,811,366 ) Property and equipment (7,006 ) (10,107 ) Total deferred liabilities (458,634 ) (18,166,242 ) Net deferred tax assets (liabilities) 23,751,178 (6,013,488 ) Less: valuation allowance (23,751,178 ) (579,552 ) Deferred tax assets (liabilities) $ – $ (6,593,040 )

Supplemental Oil and Gas Info37

Supplemental Oil and Gas Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Oil And Gas Information Details - Proved And Unproved Costs
Net capitalized costs related to oil and gas producing activities	December 31, 2015 2014 Proved oil and natural gas properties $ 131,168,906 $ 112,418,105 Unproved oil and natural gas properties 10,394 591,121 Accumulated depreciation, depletion and amortization, and impairment (99,371,071 ) (18,820,963 ) Total $ 31,808,229 $ 94,188,263
Costs incurred for oil and natural gas acquisition, exploration and development activities	Years Ended December 31, 2015 2014 Costs incurred for the year: Proved property acquisition $ 102,928 $ 3,164,469 Unproved property acquisition – – Development 18,145,783 29,022,721 Total $ 18,248,711 $ 32,187,190
Capitalized costs excluded from depletion	Years Ended December 31, 2015 2014 Property acquisition $ 10,394 $ 591,121 Development – – Total $ 10,394 $ 591,121
Schedule of proved oil and natural gas reserves	Oil Natural (Bbls) Gas (Mcf) Proved developed and undeveloped reserves as of December 31, 2013 4,074,492 2,778,593 Revisions of previous estimates (201,995 ) (131,966 ) Extensions, discoveries and other additions 1,199,673 925,763 Sale of reserves in place (17,982 ) (12,482 ) Production (256,257 ) (213,141 ) Proved developed and undeveloped reserves as of December 31, 2014 4,797,931 3,346,767 Revisions of previous estimates (2,604,830 ) (1,160,775 ) Extensions, discoveries and other additions 175,602 166,953 Sale of reserves in place – – Production (356,678 ) (413,913 ) Proved developed and undeveloped reserves as of December 31, 2015 2,012,025 1,939,032 Proved developed reserves: December 31, 2014 1,799,515 1,363,076 December 31, 2015 1,969,223 1,913,914 Proved undeveloped reserves: December 31, 2014 2,998,416 1,983,691 December 31, 2015 42,802 25,118
Schedule of standardized discounted future cash flows	Years Ended December 31, 2015 2014 Future cash inflows $ 86,500,194 $ 423,219,613 Future production costs (39,241,657 ) (148,863,530 ) Future development costs (468,738 ) (78,208,378 ) Future income tax expense – (42,717,592 ) Future net cash flows 46,789,799 153,430,113 10% annual discount for estimated timing of cash flows (14,992,255 ) (68,308,455 ) Standardized measure of discounted future net cash flows $ 31,797,544 $ 85,121,658
Reserve estimate pricing	Oil Natural (Bbl) Gas (Mcf) December 31, 2015 $ 41.34 $ 1.71 December 31, 2014 $ 83.26 $ 7.10
Schedule of changes in discounted future net cash flows	Years Ended December 31, 2015 2014 Standard measure, beginning of year $ 85,121,658 $ 61,659,271 Sales of oil and natural gas produced, net of production costs (9,763,075 ) (16,193,558 ) Net changes of prices and production costs (56,694,415 ) (6,329,518 ) Revisions of quantity estimates (33,837,468 ) (5,567,648 ) Extensions and discoveries and other adjustments 3,441,930 34,053,998 Changes in estimated future development costs 216,624 1,453,332 Sale of reserves in place – (276,920 ) Previously estimated development costs incurred during the period 16,391,373 8,946,915 Accretion of discount 10,033,467 7,437,666 Net changes in income taxes 15,240,529 (2,523,100 ) Changes in timing and other 1,646,921 2,461,220 Standard measure, end of year $ 31,797,544 $ 85,121,658

2. Summary of Significant Acc38

2. Summary of Significant Accounting Policies (Details-Capitalized Costs) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Total capitalized costs	$ 362,075	$ 434,534
Certain Payroll and Other Internal Costs [Member]
Total capitalized costs	0	61,861
Interest Costs [Member]
Total capitalized costs	$ 362,075	$ 372,673

2. Summary of Significant Acc39

2. Summary of Significant Accounting Policies (Details-Weighted Average Shares) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Weighted average common shares outstanding - basic	47,979,990	47,979,990
Plus: Potentially dilutive common shars: Stock options and warrants	0	1,199,735
Weighted average common shares outstanding - diluted	47,979,990	49,179,725

2. Summary of Significant Acc40

2. Summary of Significant Accounting Policies (Details Narrative)	12 Months Ended
	Dec. 31, 2015USD ($)aNetNumberOfWells / pureshares	Dec. 31, 2014USD ($)aNetNumberOfWells / pureshares
Cash Uninsured Amount in Federal Deposit Insurance Corporation	$ 0	$ 0
Debt issuance costs paid	50,000	254,394
Unamortized balance of debt issuance costs	0	701,019
Amortization of debt issuance costs	751,019	326,258
Website development costs capitalized from inception	56,660
Proceeds from property sales	$ 127,348	$ 1,441,929
Net acres sold | a	14	502
Impairments on oil and gas properties	$ 71,272,000	$ 0
Net producing wells	10.95	7.88
Antidilutive shares excluded from EPS calculation | shares	15,603,375	13,683,209
Amortization of fair values of common stock and stock options issued for services and compensation	$ 623,700	$ 578,919
Accounts Receivable [Member] | Oil and gas revenues [Member]
Material concentrations	70.00%	56.00%
Accounts Receivable [Member] | Oil and gas accounts receivable [Member]
Material concentrations	73.00%	49.00%
Net Producing Operators [Member]
Material concentrations	56.00%	52.00%
Non-Oil and Gas Property and Equipment [Member]
Depreciation expense	$ 16,295	$ 29,138
Website Development Costs [Member]
Depreciation expense	$ 257	$ 15,380

3. Going Concern (Details Narra

3. Going Concern (Details Narrative) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accumulated deficit	$ (64,697,163)	$ 5,639,872
Working capital	(61,855,057)
Total liabilities exceeding total assets	$ 30,373,769

5. Dahl Federal Recognition (De

5. Dahl Federal Recognition (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Oil and gas revenues	$ 15,104,629	$ 21,102,823
Production expenses	3,767,444	2,705,763
Production taxes	1,574,110	$ 2,203,501
Dahl Federal [Member]
Capitalized well costs	927,312
Dahl Federal [Member] | Production prior to 2015 [Member]
Oil and gas revenues	1,170,236
Production expenses	75,359
Production taxes	$ 130,014

6. Related Party (Details Narra

6. Related Party (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
Base monthly rent	$ 2,344
Rent expense	$ 69,703	$ 69,300

7. Property and Equipment (Deta

7. Property and Equipment (Details-Property and equipment) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Oil and gas properties, full cost method:
Evaluated costs	$ 131,168,906	$ 112,418,105
Unevaluated costs, not subject to amortization or ceiling test	10,394	591,121
Total Oil and Gas properties full cost method	131,179,300	113,009,226
Other property and equipment	139,004	139,004
Total property plant and equipment gross	131,318,304	113,148,230
Less: Accumulated depreciation, amortization, depletion and impairments	(99,468,927)	(18,902,524)
Total property and equipment, net	$ 31,849,377	$ 94,245,706

7. Property and Equipment (De45

7. Property and Equipment (Details-Depreciation) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property and equipment:
Depletion of costs for evaluated oil and gas properties	$ 9,278,108	$ 9,359,952
Depreciation and amortization of other property and equipment	16,295	29,138
Total depreciation, amortization and depletion	$ 9,294,403	$ 9,389,090

7. Property and Equipment (De46

7. Property and Equipment (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property and equipment:
Impairment of oil and gas properties	$ 71,272,000	$ 0

8. Oil and Gas Properties (Deta

8. Oil and Gas Properties (Details-Gross and Net Wells)	Dec. 31, 2015NetNumberOfWells / pureNumberOfWells / pure	Dec. 31, 2014NetNumberOfWells / pureNumberOfWells / pure
Productive oil wells, gross	349	247
Productive oil wells, net	10.95	7.88
NORTH DAKOTA
Productive oil wells, gross	344	242
Productive oil wells, net	10.58	7.51
MT
Productive oil wells, gross	5	5
Productive oil wells, net	.37	.37

8. Oil and Gas Properties (De48

8. Oil and Gas Properties (Details-Capitalized Costs) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Purchases of oil and gas properties and development costs for cash	$ 20,714,004	$ 24,739,407
Purchase of oil and gas properties accrued at year-end	6,899,503	9,364,796
Purchase of oil and gas properties accrued at the beginning of the year	(9,364,796)	(7,953,801)
Advances to operators applied to development of oil and gas properties	0	6,036,748
Capitalized asset retirement obligations	48,711	103,778
Total purchase and development costs, oil and gas properties	$ 18,297,422	$ 32,290,928

8. Oil and Gas Properties (De49

8. Oil and Gas Properties (Details Narrative)	12 Months Ended
	Dec. 31, 2015USD ($)a	Dec. 31, 2014USD ($)a
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and gas assets, net acres | a	8,100	10,000
Oil and gas acreage acquired | a	9	374
Oil and gas properties acquired, cost	$ 102,928	$ 3,102,568
Oil and gas acreage sold | a	14	502
Proceeds from oil and gas diverstitures	$ 127,348	$ 1,441,929
Undeveloped acreage expirations | a	1,866	4,202
Undeveloped agreage expirations carrying costs	$ 1,982,674	$ 6,198,163
Undeveloped acreage expirations, future	1,114
Undeveloped Acreage expirations, future carrying costs	689,000
Leasehold interests carrying cost transferred to full cost pool	$ 285,000

9. Asset Retirement Obligatio50

9. Asset Retirement Obligation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Beginning Asset Retirement Obligation	$ 286,804	$ 160,665
Liabilities incurred for new wells placed in production	48,711	103,778
Accretion of discount on asset retirement obligations	32,574	22,361
Ending asset retirement obligation	$ 368,089	$ 286,804

10. Derivative Instruments (Det

10. Derivative Instruments (Details-Oustanding Derivative Contracts)	12 Months Ended
	Dec. 31, 2015$ / bblbbl
Crude Oil Swaps 1 [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 2 [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 Swaps 3 [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 Costless Collars1 [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 Collars1 [Member] | Minimum [Member]
Outstanding derivative contract, fixed price	80
Crude Oil Costless Collars1 [Member] | Maximum [Member]
Outstanding derivative contract, fixed price	89.50

10. Derivative Instruments (D52

10. Derivative Instruments (Details-Derivative Gains and Losses) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Realized gain on derivatives, net	$ 11,477,653	$ 511,451
Gain (loss) on the mark-to-market of derivatives, net	(6,425,345)	7,793,421
Crude Oil Fixed Price Swap [Member]
Realized gain on derivatives, net	10,325,126	511,451
Gain (loss) on the mark-to-market of derivatives, net	(5,669,678)	6,827,126
Crude Oil Collars [Member]
Realized gain on derivatives, net	1,152,527	0
Gain (loss) on the mark-to-market of derivatives, net	$ (755,667)	$ 966,295

10. Derivative Instruments (D53

10. Derivative Instruments (Details-Derivative Liabilities and Assets) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Commodity derivative assets	$ 1,154,400	$ 7,579,745
Commodity derivative liabilities	0	0
Gross amounts of recognized assets [Member]
Commodity derivative assets	1,154,417	7,620,896
Commodity derivative liabilities	0	0
Gross amounts offset on balance sheet [Member]
Commodity derivative assets	(17)	(41,151)
Commodity derivative liabilities	$ 0	$ 0

10. Derivative Instruments (D54

10. Derivative Instruments (Details-Reconciliation of derivatives) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 1,154,400	$ 3,571,803
Noncurrent derivative assets	0	4,007,942
Net amount of assets on the balance sheet	1,154,400	7,579,745
Derivative liabilities	0	0
Noncurrent derivative liabilities		0
Net amounts of liabilities on the balance sheet	0	0
Total derivative liabilities, net	$ 1,154,400	$ 7,579,745

10. Derivative Instruments (D55

10. Derivative Instruments (Details Narrative)	12 Months Ended
	Dec. 31, 2015USD ($)$ / bblbbl
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Total volume on open commodity swaps, barrels | bbl	29,000
Weighted average price per barrel | $ / bbl	75.84
Proceeds from derivative liquidations | $	$ 6,255,000

11. Fair Value of Financial I56

11. Fair Value of Financial Instruments (Details) - Fair Value, Measurements, Recurring [Member] - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Level 1 [Member]
Assets
Cash and cash equivalents	$ 228,194	$ 94,682
Derivative Instruments (crude oil swaps and collars)	0	0
Total assets	228,194	94,682
Liabilities
Revolving credit facilities and long term debt, net of discounts	0	0
Total Liabilities	0	0
Total Assets and Liablilties	228,194	94,682
Level 2 [Member]
Assets
Cash and cash equivalents	0	0
Derivative Instruments (crude oil swaps and collars)	1,154,400	7,579,745
Total assets	1,154,400	7,579,745
Liabilities
Revolving credit facilities and long term debt, net of discounts	60,350,629	51,834,603
Total Liabilities	60,350,629	51,834,603
Total Assets and Liablilties	(59,196,229)	(44,254,858)
Level 3 [Member]
Assets
Cash and cash equivalents	0	0
Derivative Instruments (crude oil swaps and collars)	0	0
Total assets	0	0
Liabilities
Revolving credit facilities and long term debt, net of discounts	0	0
Total Liabilities	0	0
Total Assets and Liablilties	$ 0	$ 0

12. Revolving Credit Faciliti57

12. Revolving Credit Facilities and Long Term Debt (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Total credit facilities and long term debts	$ 60,350,629	$ 53,907,086
Less: Unamortized OID	0	(426,734)
Less: Unamortized debt discount attributable to warrants	0	(1,645,749)
Total credit facilities and long term debts, net of discounts	60,350,629	51,834,603
Less: current maturities	(60,350,629)	0
Long term portion of credit facilities and long term debts	0	51,834,603
Senior Revolving Credit Facility, Cadence Bank, N.A. [Member]
Total credit facilities and long term debts	27,750,000	22,600,000
Subordinated Credit Agreement, Chambers [Member]
Total credit facilities and long term debts	30,000,000	30,000,000
PIK Interest on Subordinated Credit Agreement, Chambers [Member]
Total credit facilities and long term debts	$ 2,600,629	$ 1,307,086

12. Revolving Credit Faciliti58

12. Revolving Credit Facilities and Long Term Debt (Details-Interest expense) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Revolving Credit Facilities, interest	$ 8,136,248	$ 5,285,236
Accrued PIK interest [Member]
Revolving Credit Facilities, interest	1,293,543	1,105,203
Amortization of OID [Member]
Revolving Credit Facilities, interest	426,734	144,904
Interest and commitment fees [Member]
Revolving Credit Facilities, interest	4,381,278	3,453,349
Amortization of debt issuance costs [Member]
Revolving Credit Facilities, interest	751,019	326,258
Amortization of warrant costs [Member]
Revolving Credit Facilities, interest	1,645,749	628,195
Capitalized interest [Member]
Revolving Credit Facilities, interest	$ (362,075)	$ (372,673)

12. Revolving Credit Faciliti59

12. Revolving Credit Facilities and Long Term Debt (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Amortization of debt discounts, warrants	$ 1,645,749	$ 628,195
Unamortized balance of debt discount	0	426,734
Amortization of original issue discount on debt	426,734	144,904
Line of Credit [Member] | Senior Credit Facility [Member]
Maximum borrowing capacity	$ 32,000,000
Line of credit maturity date	Jan. 15, 2017
Line of credit outstanding	$ 27,750,000	22,600,000
Line of Credit [Member] | Subordinated Credit Facility [Member]
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	$ 0	426,734
Proceeds received from credit facility	29,400,000
Line of Credit [Member] | Subordinated Credit Facility [Member] | Warrants [Member]
Debt discount at time of issuance	2,473,576
Amortization of debt discounts, warrants	1,645,749	628,195
Amortization of original issue discount on debt	$ 426,734	$ 144,904

13. Stockholders' Equity (Detai

13. Stockholders' Equity (Details Narrative) - $ / shares	Dec. 31, 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

14. Options (Details-Options Gr

14. Options (Details-Options Granted)	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares
Options granted in 2015 [Member]
Number of options granted | shares	1,000,000
Options fair value	$ 143,379
Share based compensation expense recognized	7,169
Options granted in 2014 [Member]
Options fair value	184,787
Share based compensation expense recognized	$ 33,224	$ 4,311
Option Granted 16 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Kenneth DeCubellis, CEO
Number of options granted | shares	200,000
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 28,676
Share based compensation expense recognized	$ 1,434
Option Granted 2 [Member]
Options grant date	Sep. 30, 2015
Options recipient	James Moe, CFO
Number of options granted | shares	150,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 21,507
Share based compensation expense recognized	$ 1,075
Option Granted 3 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Michael Eisele, COO
Number of options granted | shares	200,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 28,676
Share based compensation expense recognized	$ 1,434
Option Granted 4 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Employee
Number of options granted | shares	150,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 21,507
Share based compensation expense recognized	$ 1,075
Option Granted 5 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Employee
Number of options granted | shares	30,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 4,301
Share based compensation expense recognized	$ 215
Option Granted 6 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Employee
Number of options granted | shares	30,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 4,301
Share based compensation expense recognized	$ 215
Option Granted 7 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Employee
Number of options granted | shares	30,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 4,301
Share based compensation expense recognized	$ 215
Option Granted 8 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Employee
Number of options granted | shares	10,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 1,434
Share based compensation expense recognized	$ 72
Option Granted 9 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Joseph Lahti, Director
Number of options granted | shares	100,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 14,338
Share based compensation expense recognized	$ 717
Option Granted 10 [Member]
Options grant date	Sep. 30, 2015
Options recipient	Benjamin Oehler, Director
Number of options granted | shares	100,000
Options strike price | $ / shares	0.172
Options term in years	10 years
Options vesting term in years	5 years
Options volatility	106.00%
Options call value | $ / shares	$ 0.1434
Options fair value	$ 14,338
Share based compensation expense recognized	$ 717
Option Granted 11 [Member]
Options grant date	Dec. 22, 2014	Dec. 22, 2014
Options recipient	Kenneth DeCubellis, CEO	Kenneth DeCubellis, CEO
Number of options granted | shares		58,000
Options strike price | $ / shares		0.280
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		198.00%
Options call value | $ / shares		$ 0.2237
Options fair value		$ 12,974
Share based compensation expense recognized	$ 2,596	$ 64
Option Granted 12 [Member]
Options grant date	Dec. 22, 2014	Dec. 22, 2014
Options recipient	James Moe, CFO	James Moe, CFO
Number of options granted | shares		40,000
Options strike price | $ / shares		0.280
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		198.00%
Options call value | $ / shares		$ 0.2237
Options fair value		$ 8,947
Share based compensation expense recognized	$ 1,788	$ 44
Option Granted 13 [Member]
Options grant date	Dec. 22, 2014	Dec. 22, 2014
Options recipient	Michael Eisele, COO	Michael Eisele, COO
Number of options granted | shares		40,000
Options strike price | $ / shares		0.280
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		198.00%
Options call value | $ / shares		$ 0.2237
Options fair value		$ 8,947
Share based compensation expense recognized	$ 1,788	$ 44
Option Granted 14 [Member]
Options grant date	Dec. 22, 2014	Dec. 22, 2014
Options recipient	Employee	Employee
Number of options granted | shares		36,000
Options strike price | $ / shares		0.280
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		198.00%
Options call value | $ / shares		$ 0.2237
Options fair value		$ 8,053
Share based compensation expense recognized	$ 1,612	$ 40
Option Granted 15 [Member]
Options grant date	Dec. 22, 2014	Dec. 22, 2014
Options recipient	Employee	Employee
Number of options granted | shares		12,000
Options strike price | $ / shares		0.280
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		198.00%
Options call value | $ / shares		$ 0.2237
Options fair value		$ 2,684
Share based compensation expense recognized	$ 536	$ 13
Option Granted 16 [Member]
Options grant date	Dec. 22, 2014	Dec. 22, 2014
Options recipient	Employee	Employee
Number of options granted | shares		12,000
Options strike price | $ / shares		0.280
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		198.00%
Options call value | $ / shares		$ 0.2237
Options fair value		$ 2,684
Share based compensation expense recognized	$ 536	$ 13
Option Granted 17 [Member]
Options grant date	Dec. 22, 2014	Dec. 22, 2014
Options recipient	Employee	Employee
Number of options granted | shares		2,000
Options strike price | $ / shares		0.280
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		198.00%
Options call value | $ / shares		$ 0.2237
Options fair value		$ 447
Share based compensation expense recognized	$ 88	$ 2
Option Granted 18 [Member]
Options grant date	Dec. 8, 2014	Dec. 8, 2014
Options recipient	Joseph Lahti, Director	Joseph Lahti, Director
Number of options granted | shares		100,000
Options strike price | $ / shares		0.374
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		202.00%
Options call value | $ / shares		$ 0.2956
Options fair value		$ 29,563
Share based compensation expense recognized	$ 5,912	$ 372
Option Granted 19 [Member]
Options grant date	Dec. 8, 2014	Dec. 8, 2014
Options recipient	Benjamin Oehler, Director	Benjamin Oehler, Director
Number of options granted | shares		100,000
Options strike price | $ / shares		0.374
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		202.00%
Options call value | $ / shares		$ 0.2956
Options fair value		$ 29,563
Share based compensation expense recognized	$ 5,912	$ 372
Option Granted 20 [Member]
Options grant date	Dec. 8, 2014	Dec. 8, 2014
Options recipient	Bradley Berman, Director	Bradley Berman, Director
Number of options granted | shares		100,000
Options strike price | $ / shares		0.374
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		202.00%
Options call value | $ / shares		$ 0.2956
Options fair value		$ 29,563
Share based compensation expense recognized	$ 5,912	$ 372
Option Granted 21 [Member]
Options grant date	Dec. 1, 2014	Dec. 1, 2014
Options recipient	Employee	Employee
Number of options granted | shares		100,000
Options strike price | $ / shares		0.379
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		193.00%
Options call value | $ / shares		$ 0.2999
Options fair value		$ 29,988
Share based compensation expense recognized	$ 5,996	$ 500
Option Granted 22 [Member]
Options grant date	Feb. 10, 2014	Feb. 10, 2014
Options recipient	Employee	Employee
Number of options granted | shares		27,500
Options strike price | $ / shares		0.782
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		116.00%
Options call value | $ / shares		$ 0.6778
Options fair value		$ 18,639
Share based compensation expense recognized	$ 0	$ 1,976
Option Granted 23 [Member]
Options grant date	Jan. 30, 2014	Jan. 30, 2014
Options recipient	Employee	Employee
Number of options granted | shares		5,000
Options strike price | $ / shares		0.630
Options term in years		10 years
Options vesting term in years		5 years
Options volatility		115.00%
Options call value | $ / shares		$ 0.5471
Options fair value		$ 2,735
Share based compensation expense recognized	$ 548	$ 499
Option Granted 1 [Member]
Options strike price | $ / shares	0.172

14. Options (Details-Summary)

14. Options (Details-Summary) - Options [Member]	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Range of exercise price, lower limit	$ 0.03
Range of exercise price, upper limit	$ 1
Shares Underlying Options Outstanding | shares	7,055,500
Weighted Average Remaining Contractual Life	7 years 6 months 4 days
Weighted Average Exercise Price	$ 0.44
Shares Underlying Options Exercisable | shares	3,111,000
Weighted Average Exercise Price Exercisable	$ .47

14. Options (Details-Assumption

14. Options (Details-Assumptions) - Options [Member]	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Average risk-free interest rates	1.75%	2.00%
Average expected life (in years)	5 years	5 years
Volatility	106.00%	9.70%

14. Options (Details-Options Ou

14. Options (Details-Options Outstanding) - Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Shares
Options Outstanding, Beginning	7,208,834	6,639,834
Options Expired	(153,334)	(36,000)
Options Cancelled	(1,000,000)	(27,500)
Options Granted	1,000,000	632,500
Options Exercised	0	0
Options Outstanding, Ending	7,055,500	7,208,834
Options Exercisable, Ending	3,111,000
Weighted Average Exercise Price
Outstanding, Beginning	$ 0.56	$ .59
Expired	(.70)	(0.65)
Cancelled	(1)	(0.78)
Granted	.17	0.36
Exercised	0	0
Outstanding, Ending	.44	$ 0.56
Exercisable, Ending	$ .47

14. Options (Details Narrative)

14. Options (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Options [Member]
Compensation expense	$ 623,700	$ 578,919

15. Warrants (Details-Summary)

15. Warrants (Details-Summary) - Warrants [Member]	12 Months Ended
	Dec. 31, 2015$ / shares$ / Warrantshares	Dec. 31, 2014$ / sharesshares	Dec. 31, 2013$ / sharesshares
Range of exercise prices, lower limit	$ 0.65
Range of exercise prices, upper limit	$ 1.50
Shares underlying warrants outstanding | shares	8,548,375	9,133,375	9,463,375
Weighted Average Remaining Contractual Life	1 year 8 months 27 days
Weighted Average Exercise Price	$ .95	$ .92	$ .94
Shares underlying warrants exercisable | shares	8,548,375
Weighted Average Exercise Price Exercisable | $ / Warrant	.95

15. Warrants (Details-Assumptio

15. Warrants (Details-Assumptions) - Warrants [Member]	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Average risk-free interest rates
Volatility

15. Warrants (Details-Warrants

15. Warrants (Details-Warrants Outstanding) - Warrants [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Shares
Warrants outstanding, beginning balance	9,133,375	9,463,375
Warrants expired	(585,000)	0
Warrants cancelled	0	(330,000)
Warrants granted	0	0
Warrants exercised	0	0
Warrants outstanding, ending balance	8,548,375	9,133,375
Warrants exercisable	8,548,375
Weighted Average Exercise Price
Weighted price, beginning balance	$ .92	$ .94
Weighted price, warrants expired	(.38)	0
Weighted price, warrants cancelled	0	(1.50)
Weighted price, warrants granted	0	0
Warrants outstanding, ending balance	.95	$ .92
Weighted price, warrants exercisable	$ .95

16. Income Taxes (Details-Incom

16. Income Taxes (Details-Income Tax Provision) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current taxes	$ 0	$ 0
Deferred tax provision (benefit)	(6,593,040)	2,559,195
Valuation allowance	0	0
Net income tax provision (benefit)	$ (6,593,040)	$ 2,559,195

16. Income Taxes (Details-Effec

16. Income Taxes (Details-Effective tax rate)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Federal statutory income tax rate	35.00%	35.00%
State income taxes	4.13%	2.09%
Effect of statutory rate change on deferred taxes	(0.44%)	(0.35%)
Permanent differences	0.00%	0.07%
Change in valuation allowance	(30.12%)	0.22%
Net effective income tax rate	8.57%	37.03%

16. Income Taxes (Details-Defer

16. Income Taxes (Details-Deferred Tax Assets) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Federal and state net operating loss carryovers	$ 9,294,824	$ 10,438,275
Stock compensation	2,531,641	1,558,409
Ceiling test impairment, intangible drilling costs and other exploration costs capitalized for financial reporting purposes	12,186,927	0
Derivative liabilities	0	0
Reorganization costs	52,415	49,693
Asset retirement obligation	144,005	106,377
Total deferred tax assets	24,209,812	12,152,754
Deferred tax liabilities:
Ceiling test impairment, intangible drilling costs and other exploration costs capitalized for financial reporting purposes	0	(15,344,769)
Derivative assets	(451,628)	(2,811,366)
Property and equipment	(7,006)	(10,107)
Total deferred liabilities	(458,634)	(18,166,242)
Net deferred tax assets (liabilities)	23,751,178	(6,013,488)
Less: valuation allowance	(23,751,178)	(579,552)
Deferred tax assets (liabilities)	$ 0	$ (6,593,040)

16. Income Taxes (Details Narra

16. Income Taxes (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Operating loss carryover	$ 23,758,360
Loss carryover expiration date	Dec. 31, 2035
Increase in deferred tax valuation allowance		$ 579,552

17. Commitments and Contingen73

17. Commitments and Contingencies (Details Narrative)	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Commitment to AFE (approximately)	$ 1,000,000

Supplemental Oil and Gas Info74

Supplemental Oil and Gas Information (Details - Net capitalized costs) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Information Details - Proved And Unproved Costs
Proved oil and natural gas properties	$ 131,168,906	$ 112,418,105
Unproved oil and natural gas properties	10,394	591,121
Accumulated depreciation, depletion and amortization, and impairment	(99,371,071)	(18,820,963)
Total	$ 31,808,229	$ 94,188,263

Supplemental Oil and Gas Info75

Supplemental Oil and Gas Information (Details - Proved and unproved costs) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Information Details - Proved And Unproved Costs
Proved property acquisition	$ 102,928	$ 3,164,469
Unproved property acquisition	0	0
Development	18,145,783	29,022,721
Total	$ 18,248,711	$ 32,187,190

Supplemental Oil and Gas Info76

Supplemental Oil and Gas Information (Details - Costs excluded) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Information Details - Proved And Unproved Costs
Property acquisition	$ 10,394	$ 591,121
Development	0	0
Total costs excluded for unproved properties	$ 10,394	$ 591,121

Supplemental Oil and Gas Info77

Supplemental Oil and Gas Information (Details - Proved reserves)	12 Months Ended
	Dec. 31, 2015bblMcf	Dec. 31, 2014bblMcf
Oil (Bbls)
Proved developed and undeveloped rollforward
Proved developed and undeveloped reserves, beginning balance | bbl	4,797,931	4,074,492
Revisions of previous estimates | bbl	(2,604,830)	(201,995)
Extensions, discoveries and other additions | bbl	175,602	1,199,673
Sale of reserves in place | bbl	0	(17,982)
Production | bbl	(356,678)	(256,257)
Proved developed and undeveloped reserves, ending balance | bbl	2,012,025	4,797,931
Proved developed reserves | bbl	1,969,223	1,799,515
Proved undeveloped reserves | bbl	42,802	2,998,416
Natural Gas (Mcf)
Proved developed and undeveloped rollforward
Proved developed and undeveloped reserves, beginning balance | Mcf	3,346,767	2,778,593
Revisions of previous estimates | Mcf	(1,160,775)	(131,966)
Extensions, discoveries and other additions | Mcf	166,953	925,763
Sale of reserves in place | Mcf	0	(12,482)
Production | Mcf	(413,913)	(213,141)
Proved developed and undeveloped reserves, ending balance | Mcf	1,939,032	3,346,767
Proved developed reserves | Mcf	1,913,914	1,363,076
Proved undeveloped reserves | Mcf	25,118	1,983,691

Supplemental Oil and Gas Info78

Supplemental Oil and Gas Information (Details - Future cash flows) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil And Gas Information Details - Proved And Unproved Costs
Future cash inflows	$ 86,500,194	$ 423,219,613
Future production costs	(39,241,657)	(148,863,530)
Future development costs	(468,738)	(78,208,378)
Future income tax expense	0	(42,717,592)
Future net cash flows	46,789,799	153,430,113
10% annual discount for estimated timing of cash flows	(14,992,255)	(68,308,455)
Standardized measure of discounted future net cash flows	$ 31,797,544	$ 85,121,658	$ 61,659,271

Supplemental Oil and Gas Info79

Supplemental Oil and Gas Information (Details - Average prices) - $ / Unit	Dec. 31, 2015	Dec. 31, 2014
Oil (Bbls)
Reserve estimate pricing	41.34	83.26
Natural Gas (Mcf)
Reserve estimate pricing	1.71	7.10

Supplemental Oil and Gas Info80

Supplemental Oil and Gas Information (Details - Changes in Future Cash Flows) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes in Standardized Measure of Discounted Future net Cash Flows
Standard measure, beginning of year	$ 85,121,658	$ 61,659,271
Sales of oil and natural gas produced, net of production costs	(9,763,075)	(16,193,558)
Net changes of prices and production costs	(56,694,415)	(6,329,518)
Revisions of quantity estimates	(33,837,468)	(5,567,648)
Extensions and discoveries and other adjustments	3,441,930	34,053,998
Changes in estimated future development costs	216,624	1,453,332
Sale of reserves in place	0	(276,920)
Previously estimated development costs incurred during the period	16,391,373	8,946,915
Accretion of discount	10,033,467	7,437,666
Net changes in income taxes	15,240,529	(2,523,100)
Changes in timing and other	1,646,921	2,461,220
Standard measure, end of year	$ 31,797,544	$ 85,121,658