Osage Exploration & Development (OSGE) Inactive 10-K31 Mar 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2014	Jun. 30, 2014	Mar. 23, 2014
Document And Entity Information
Entity Registrant Name	OSAGE EXPLORATION & DEVELOPMENT, INC.
Entity Central Index Key	1405686
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filer	No
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	-19
Entity Filer Category	Smaller Reporting Company
Entity Public Float		$55,112,226
Entity Common Stock, Shares Outstanding			58,284,948
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and equivalents	$5,054,735	$2,782,643
Accounts receivable	3,595,555	2,769,414
Unrealized gains on oil and gas derivatives	1,116,740
Prepaid expenses and other current assets	120,390	596,742
Deferred financing costs	1,009,642	1,829,124
Total current assets	10,897,062	7,977,923
Property and equipment, at cost:
Oil & gas properties and equipment (successful efforts method)	62,115,916	27,339,460
Other property & equipment	260,526	85,746
Total property & equipment, gross	62,376,442	27,425,206
Less: accumulated depletion, impairment, depreciation and amortization	-39,270,342	-2,683,085
Total property & equipment, net	23,106,100	24,742,121
Restricted cash	896,367	908,645
Total assets	34,899,529	33,628,689
Current liabilities:
Accounts payable	16,949,047	555,784
Joint interest billing	2,313,801
Revenues and royalties payable	1,761,634
Accrued expenses	1,039,945	117,800
Unrealized losses on oil and gas derivatives		265,961
Capital lease liability, current portion	45,698
Notes payable	25,000,000	20,000,000
Total current liabilities	47,110,125	20,939,545
Unrealized losses on oil and gas derivatives, net of current portion		91,606
Capital lease liability, net of current portion	50,135
Liability for asset retirement obligations	6,281	3,886
Total liabilities	47,166,541	21,035,037
Commitments and contingencies
Stockholders' Equity (Deficit):
Preferred stock, $0.0001 par value, 10,000,000 authorized, none issued and outstanding as of December 31, 2014 or December 31, 2013
Common stock, $0.0001 par value, 190,000,000 shares authorized; 58,098,014 and 49,854,675 shares issued and outstanding as of December 31, 2014 and December 31, 2013, respectively	5,809	4,985
Additional paid-in capital	26,551,541	16,903,147
Stock purchase notes receivable	-95,000	-95,000
Accumulated deficit	-38,729,362	-4,219,480
Total stockholders' (deficit) equity	-12,267,012	12,593,652
Total liabilities and stockholders' equity (deficit)	$34,899,529	$33,628,689

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Preferred stock, par value	$0.00	$0.00
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued
Preferred stock, shares outstanding
Common stock, par value	$0.00	$0.00
Common stock, shares authorized	190,000,000	190,000,000
Common stock, shares issued	58,098,014	58,098,014
Common stock, shares outstanding	49,854,675	49,854,675

Consolidated_Statements_of_Ope

Consolidated Statements of Operations and Other Comprehensive Income (Loss) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Operating revenues
Oil revenues	$10,481,767	$7,339,943
Natural gas and natural gas liquids revenues	2,196,749	689,145
Total operating revenues	12,678,516	8,029,088
Operating costs and expenses
Well operating costs	1,935,367	1,547,949
General and administrative expenses	6,164,129	2,613,920
Depreciation, depletion and accretion	6,729,974	2,320,441
Impairment of oil & gas properties	29,858,178
Gain on sale of land interests	704,334
Total operating costs and expenses	43,983,314	6,482,310
Operating (loss) income	-31,304,798	1,546,778
Other income (expenses):
Interest income	9,494	2,000
Interest expense	-4,468,568	-4,566,246
Gain (loss) on oil and gas derivatives	1,253,990	-495,803
Loss from continuing operations before income taxes	-34,509,882	-3,513,271
Provision for income taxes		1,624
Loss from continuing operations	-34,509,882	-3,514,895
Discontinued operations:
Income from discontinued operations net of income taxes		2,496,541
Gain on sale of discontinued operations		4,873,660
Net (loss) income	-34,509,882	3,855,306
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment attributable to discontinued operations		24,153
Comprehensive (loss) income	($34,509,882)	$3,879,459
Basic and diluted loss per share
Continuing operations	($0.61)	($0.07)
Discontinued operations		$0.15
Weighted average number of common share and common share equivalents used to compute basic and diluted loss per share	56,480,460	49,762,499

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (Deficit) (USD $)	Common Stock [Member]	Additional Paid-In Capital [Member]	Stock Purchase Note Receivable [Member]	Accumulated Deficit [Member]	Accumulated Other Comprehensive Income / (Loss) [Member]	Total
Balance at Dec. 31, 2012	$4,909	$16,371,305	($95,000)	($8,074,786)	($327,062)	$7,879,366
Balance, shares at Dec. 31, 2012	49,094,675
Issuance of shares for professional services	41	375,959				376,000
Issuance of shares for professional services, shares	410,000
Stock based compensation		152,418				152,418
Exercise of warrants	35	3,465				3,500
Exercise of warrants, shares	350,000
Net income (loss)				3,855,306		3,855,306
Foreign exchange translation adjustment					24,153	24,153
Recognition of accumulated currency translation loss					302,909	302,909
Balance at Dec. 31, 2013	4,985	16,903,147	-95,000	-4,219,480		12,593,652
Balance, shares at Dec. 31, 2013	49,854,675
Exercise of warrants	20	1,980				2,000
Exercise of warrants, shares	200,000
Issuance of shares and warrants	749	6,394,311				6,395,060
Issuance of shares and warrants, shares	7,493,339
Stock based compensation	55	3,252,103				3,252,158
Stock based compensation, shares	550,000
Net income (loss)				-34,509,882		-34,509,882
Foreign exchange translation adjustment
Balance at Dec. 31, 2014	$5,809	$26,551,541	($95,000)	($38,729,362)		($12,267,012)
Balance, shares at Dec. 31, 2014	58,098,014

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
Consolidated Statements of Cash Flows (USD $)	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net (loss) income	($34,509,882)	$3,855,306
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Stock based compensation	3,252,158	528,418
Amortization of deferred financing costs	919,482	1,295,348
Amortization of debt discount		271,060
Impairment of oil & gas properties	29,858,178
Gain on sale of oil & gas properties		-4,873,660
Gain on sale of land interests	-704,334
Write off of expired mineral rights leases	323,848	44,717
Accretion of asset retirement obligation	895	228
Provision for depletion, depreciation and amortization	6,729,079	2,320,213
Unrealized (gain) loss on oil and gas derivatives	-1,474,307	357,567
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	-826,141	-2,660,855
Decrease (increase) in prepaid expenses and other current assets	53,396	-121,689
Increase (decrease) in accounts payable and accrued expenses	546,322	-936,162
Increase in joint interest billing account	2,313,801
Increase in revenue and royalties payable	1,761,634
Net cash provided by operating activities	8,244,129	80,491
Cash flows from investing activities:
Investments in oil & gas properties	-18,500,615	-17,891,932
Investments in non-oil & gas properties	-47,345
Net proceeds from sale of oil & gas properties	422,955	6,295,193
Decrease (increase) in restricted cash	12,278	-751,178
Net proceeds from sale of land interests	875,232	14,568
Cash included in sale of oil & gas properties		-38,039
Proceeds from notes receivable		6,000
Net cash used in investing activities	-17,237,495	-12,365,388
Cash flows from financing activities:
Net proceeds from offering of securities	6,744,000
Proceeds from secured promissory notes	5,000,000	17,000,000
Principal payments on notes payable		-2,500,000
Proceeds from term loan		367,520
Principal payments on term loan		-118,205
Principal payments on capital leases	-31,602
Payment of placement fees and expenses	-348,940
Payment of deferred financing costs	-100,000	-200,000
Proceeds from exercise of warrants	2,000	3,500
Net cash provided by financing activities	11,265,458	14,552,815
Effect of exchange rate on cash and equivalents		28,520
Net increase in cash and equivalents	2,272,092	2,296,438
Cash and equivalents - beginning of period	2,782,643	486,205
Cash and equivalents - end of period	5,054,735	2,782,643
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payment for interest	3,549,086	2,999,838
Cash payment for income taxes		1,624
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Increase in asset retirement obligation	1,500	3,639
Purchase of furniture and fixtures through capital leases	127,436
Oil and gas additions in accounts payable	$16,769,086

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Summary of Significant Accounting Policies

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

Osage Exploration and Development, Inc. (“Osage” or the “Company”) is an independent energy company engaged primarily in the acquisition, development, production and sale of oil, natural gas and natural gas liquids. The Company’s production activities are located in the State of Oklahoma. The principal executive offices of the Company are at 2445 Fifth Avenue, Suite 310, San Diego, CA 92101.

BASIS OF CONSOLIDATION

The consolidated financial statements include the accounts of Osage and its wholly owned subsidiaries, Osage Energy Company, LLC and Osage Exploration and Development Operating, LLC. Accordingly, all references herein to Osage or the Company include the consolidated results. All significant inter-company accounts and transactions were eliminated in consolidation. The results, assets and liabilities of the Company’s former wholly owned subsidiary, Cimarrona, LLC, have been presented as discontinued operations in the consolidated financial statements.

RECLASSIFICATIONS

Certain amounts included in the prior year financial statements have been reclassified to conform to the current year’s presentation. These reclassifications have no affect on the reported results in 2014 or 2013.

RISK FACTORS RELATED TO CONCENTRATION OF SALES AND PRODUCTS

The Company’s future financial condition and results of operations depend upon prices received for its oil and natural gas and the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer product demand and the price and availability of alternative fuels.

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management used significant estimates in determining the carrying value of its oil and gas producing assets and the associated impairment, depreciation and depletion expense related to sales’ volumes. The significant estimates included the use of proved oil and gas reserve volumes and the related present value of estimated future net revenues there-from (See Note 15: Supplemental Information About Oil and Gas Producing Activities).

CASH AND EQUIVALENTS

Cash and equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three months or less.

DEFERRED FINANCING COSTS

The Company incurred deferred financing costs in connection with the Note Purchase Agreement (see Note 6), which represented the fair value of warrants, placement fees and legal fees. Deferred financing costs of $3,959,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis. In 2014, the term of the Note Purchase Agreement was extended by one year.

During the years ended December 31, 2014 and 2013, respectively, the Company made payments of $100,000 and $200,000 for deferred financing fees in connection with the Note Purchase Agreement.

Deferred financing costs at December 31, 2014 and 2013 were $1,009,642 and $1,829,124, respectively. Amortization of deferred financing costs was $919,482 for the year ended December 31, 2014 and $1,295,348 for the year ended December 31, 2013.

FAIR VALUE OF FINANCIAL INSTRUMENTS

As of December 31, 2014 and December 31, 2013, the fair value of cash, accounts receivable, short term debt and accounts payable approximate carrying values because of the short-term maturity of these instruments.

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 820, “Fair Value Measurements and Disclosures,” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic 825, “Financial Instruments,” defines fair value, and establishes a three-level valuation hierarchy for disclosures of fair value measurement that enhances disclosure requirements for fair value measures. The carrying amounts reported in the consolidated balance sheets for receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of their fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.

The three levels of valuation hierarchy are defined as follows:

●

Level 1 inputs to the valuation methodology are quoted prices for identical assets or liabilities in active markets.

●

Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets in inactive markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

●

Level 3 inputs to the valuation methodology use one or more unobservable inputs which are significant to the fair value measurement.

The Company analyzes all financial instruments with features of both liabilities and equity under ASC Topic 480, “Distinguishing Liabilities from Equity,” and ASC Topic 815, “Derivatives and Hedging.”

As of December 31, 2014 and December 31, 2013 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheets.

The following table presents information for those assets and liabilities requiring disclosure at fair value as of December 31, 2014 and December 31, 2013:

Total

Fair Value Measurements Using:

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

December 31, 2014 assets (liabilities):

Commodity derivative asset

1,116,740

December 31, 2013 assets (liabilities):

Commodity derivative liability

(357,567

)

(357,567

)

(357,567

)

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 2 Fair Value Measurements

Commodity derivatives — The fair values of commodity derivatives are estimated using internal option pricing models based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Assets and Liabilities Measured on a non-recurring basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests on its oil & gas properties when required. During the year ended December 31, 2014, the Company recognized impairment on proved oil & gas properties of $29,858,178. These proved oil & gas properties are located in the Logan County Field in Oklahoma and the fair value evaluation was performed on a field basis. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent actual or proposed sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected and would generally be classified within Level 3.

Total

Fair Value Measurements Using:

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

(before impairment)

December 31, 2014 assets (liabilities):

Proved oil & gas properties, net book value

50,872,404

21,014,226

CONCENTRATION OF CREDIT RISK

Financial instruments that potentially subject the Company to concentrations of credit risk are cash and accounts receivable arising from its normal business activities. The Company places its cash in what it believes are credit-worthy financial institutions. However, the Company’s cash balances have exceeded the FDIC insured levels at various times during 2014 and 2013. The Company maintains cash accounts only at large, high quality financial institutions and believes the credit risk associated with cash held in banks exceeding the FDIC insured levels is remote. The Company generated substantially all of its revenues from five customers in 2014 and four customers in 2013. (See “Accounts Receivable and Allowance for Doubtful Accounts” below).

RESTRICTED CASH

In connection with the Apollo Note Purchase Agreement, as amended (see Note 6), the Company has classified $812,500 and $850,000, representing three months interest, as restricted cash as of December 31, 2014 and 2013, respectively. The Company has also pledged $83,867 and $58,645 for certain bonds and sureties as of December 31, 2014 and 2013, respectively. Restricted cash at December 31, 2014 was $896,367, compared to $908,645 at December 31, 2013.

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

The Company recognizes accounts receivable when sales are invoiced and regularly reviews accounts receivable for doubtful accounts.

In the year ended December 31, 2014, the Company sold 81.0% of its oil and gas production to three customers. However, the Company believes it can sell all its production to many different purchasers, most of whom pay similar prices that vary with the international spot market prices. The Company controls credit risk related to accounts receivable through credit approvals, credit limits and monitoring procedures. The Company routinely assesses the financial strength of its customers and, based upon factors surrounding the credit risk, establishes an allowance, if required, for uncollectible accounts and, as a consequence, believes that its accounts receivable credit risk exposure beyond such allowance is limited. The Company had no allowance as of December 31, 2014 and 2013. The analysis was based on its evaluation of specific customers’ balances and the collectability thereof.

OIL AND GAS PROPERTIES

Osage is an exploration and production oil and natural gas company with proved reserves and existing production in the state of Oklahoma.

The costs of drilling and equipping exploratory wells are capitalized until they are determined to be either successful or unsuccessful. If the wells are successful, the costs of the wells remain capitalized. If, however, the wells are unsuccessful, the capitalized costs of drilling the wells, net of any salvage value, are charged to operations in the period the wells are determined to be unsuccessful. The costs of drilling and equipping development wells are capitalized, whether the wells are successful or unsuccessful.

The provision for depreciation and depletion of oil and gas properties is computed by the unit-of-production method. Under this method, the Company computes the provision by multiplying the total unamortized costs of oil and gas properties including future development, site restoration, and dismantlement abandonment costs, but excluding costs of unproved properties by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a field-by-field basis. As of December 31, 2014 and 2013, the Company’s oil production operations are conducted in the United States of America. The cost of unevaluated properties not being amortized, to the extent there is such a cost, is assessed quarterly to determine whether the value has been impaired below the capitalized cost. The costs associated with unevaluated properties relate to projects which were undergoing exploration or development activities or in which the Company intends to commence such activities in the future. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. Management believes no such impairment exists at December 31, 2014 and 2013.

The Company follows the “successful efforts” method of accounting for its oil and gas exploration and development activities, as set forth in FASB ASC topic 932. Under this method, the Company initially capitalizes expenditures for oil and gas property acquisitions until they are either determined to be successful (capable of commercial production) or unsuccessful. The carrying value of all undeveloped oil and gas properties is evaluated periodically and reduced if such carrying value appears to have been impaired. Leasehold costs relating to successful oil and gas properties remain capitalized while leasehold costs which have been proved unsuccessful are charged to operations in the period the leasehold costs are proved unsuccessful. Costs of carrying and retaining unproved properties are expensed as incurred.

ASSET RETIREMENT OBLIGATIONS

In accordance with FASB ASC topic 410, the Company reports a liability for any legal retirement obligations on its oil and gas properties. The asset retirement obligations represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate the producing properties at the end of their productive lives, in accordance with state laws, as well as the estimated costs associated with the reclamation of the property surrounding. The Company determines the asset retirement obligations by calculating the present value of estimated cash flows related to the liability. The asset retirement obligations are recorded as a liability at the estimated present value as of the asset’s inception, with an offsetting increase to producing properties. Periodic accretion of the discount related to the estimated liability is recorded as interest expense in the statements of operations.

The estimated liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells, and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations. Revisions to the asset retirement obligations are recorded with an offsetting change to producing properties, resulting in prospective changes to depletion and depreciation expense and accretion of the discount. Because of the subjectivity of assumptions and the relatively long lives of most of the wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

OTHER PROPERTY AND EQUIPMENT

Non-oil and gas producing properties and equipment are stated at cost; major renewals and improvements are charged to the property and equipment accounts; while replacements, maintenance and repairs, which do not improve or extend the lives of the respective assets, are expensed as incurred. At the time property and equipment are retired or otherwise disposed of, the asset and related accumulated depreciation accounts are relieved of the applicable amounts. Gains or losses from retirements or sales are credited or charged to operations.

Depreciation for non-oil and gas properties is recorded on the straight-line method at rates based on estimated useful lives ranging from three to fifteen years of the assets.

IMPAIRMENT OF LONG-LIVED ASSETS

The Company follows the guidance provided under FASB ASC Topic 360 (“ASC 360”), “Accounting for the Impairment or Disposal of Long-Lived Assets”, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The Company periodically evaluates the carrying value of long-lived assets to be held and used in accordance with ASC 360. ASC 360 requires impairment losses to be recorded on long-lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts.

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. We recorded an impairment charge of $29,858,178 in 2014. During 2013, we did not record any charge for impairment. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.

The assessment of unproved properties to determine any possible impairment requires significant judgment. No impairment was recorded on unproved properties in 2014 or 2013.

REVENUE RECOGNITION

Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized when the product is delivered at a fixed or determinable price, title has transferred, collectability is reasonably assured and evidenced by a contract. The Company follows the sales method of accounting for its oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas and natural gas liquids sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. The Company has no imbalance positions at December 31, 2014 or 2013, and no receivables, payables or unearned revenue are recorded.

STOCK BASED COMPENSATION

The Company accounts for its stock-based compensation in accordance with FASC ASC topic 718. The Company recognizes in the statement of operations the grant-date fair value of stock options and other equity-based compensation issued to employees and non-employees over the requisite service period. For stock-based awards the value is based on the market value for the stock on the date of grant and if the stock has restrictions as to transferability a discount is provided for lack of tradability. Stock option awards are valued using the Black-Scholes option-pricing model. For shares issued for services or property, the value is based on the market value for the stock on the date of grant.

INCOME TAXES

The Company follows FASB ASC Topic 740 (“ASC 740”), “Accounting for Uncertainty in Income Taxes.” When tax returns are filed, it is likely some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheets along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest associated with unrecognized tax benefits are classified as interest expense and penalties are classified in selling, general and administrative expenses in the Consolidated Statement of Operations. Due to a history of operating losses, the Company records a full valuation allowance against its net deferred tax assets.

RISK MANAGEMENT ACTIVITIES

The Company has entered into certain derivative financial instruments to manage the inherent uncertainty of future revenues. The Company does not intend to hold or issue derivative financial instruments for speculative purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment. These derivative financial instruments are marked to market at each reporting period.

EARNINGS (LOSS) PER SHARE

In accordance with FASB ASC Topic 260 “Earnings Per Share,” the Company’s basic net income/loss per share of common stock is calculated by dividing net income/loss by the weighted-average number of shares of common stock outstanding for the period. The diluted net income/loss per share of common stock is computed by dividing the net income/loss using the weighted-average number of common shares including potential dilutive common shares outstanding during the period. Potential common shares are excluded from the computation of diluted net loss per share if anti-dilutive.

The following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2014 and 2013:

Year Ended December 31,

2014

2013

Net loss allocable to continuing operations

(34,509,882

)

(3,514,895

)

Net income and gain allocable to discontinued operations

7,370,201

Basic and diluted net income (loss) per share

Continuing operations

(0.61

)

(0.07

)

Discontinued operations

0.15

Basic and diluted weighted average shares outstanding

56,480,460

49,762,499

Warrants and options to purchase 7,487,559 and 1,696,843 shares of common stock at December 31, 2014 and December 31, 2013, respectively, were excluded from the computation as their effect would have been anti-dilutive.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. The ASU will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new standard is effective for the Company on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements—Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date of issuance of the entity’s financial statements. Further, an entity must provide certain disclosures if there is substantial doubt about the entity’s ability to continue as a going concern. The ASU is effective for annual periods ending after December 15, 2016 and interim periods thereafter, and early adoption is permitted.

The Company is evaluating the impact, if any, that ASU 2014-09 and ASU 2014-15 will have on its consolidated financial statements.

Going_Concern

Going Concern	12 Months Ended
Going Concern	Dec. 31, 2014
Going Concern
Going Concern	2. GOING CONCERN

	The Company has an accumulated deficit of $38,729,362 and a working capital deficit of $36,213,063 as of December 31, 2014. As of December 31, 2014, the Company was not in compliance with certain covenants including the minimum production covenant under the senior secured note purchase agreement. (see Note 6 - Debt). These factors raise substantial doubt about the Company’s ability to continue as a going concern.

	On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement with Apollo Investment Corporation, on April 5, 2013 we amended this agreement, increasing the facility to $20,000,000. On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. During the year ended December 31, 2014, we drew down $5,000,000 of additional funds and, as of December 31, 2014, the amount outstanding under the senior secured note purchase agreement was $25,000,000.

	In early 2014, the Company raised approximately $6.7 million of gross proceeds in a private placement.

	Management of the Company has undertaken steps as part of a plan to improve operations with the goal of sustaining our operations for the next 12 months and beyond. These steps include (a) becoming operators of our own wells, (b) participating in drilling of wells in Logan County, Oklahoma within the next 12 months, (c) controlling overhead and expenses, (d) selling portions of existing operations, and (e) raising additional equity and/or debt.

	The Company’s operating plans require additional funds which may take the form of debt or equity financings. The Company’s ability to continue as a going concern is dependent upon achieving profitable operations and obtaining additional financing. Our cash flows and results of operations depend to a great extent on the prevailing prices for oil and gas. Prolonged or substantial declines in oil / and/or gas prices may materially and adversely affect our liquidity, the amount of cash flows we have available for our capital expenditures and other operating expenses, our ability to access credit and capital markets and our results of operations. There is no assurance additional funds will be available on acceptable terms or at all.

	These consolidated financial statements do not give effect to any adjustments which would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and discharge its liabilities in other than the normal course of business and at amounts different from those reflected in the accompanying consolidated financial statements.

Equity_Transactions

Equity Transactions	12 Months Ended
Equity Transactions	Dec. 31, 2014
Equity [Abstract]
Equity Transactions	3. EQUITY TRANSACTIONS

	Common Stock and Options

	In February 2014, the Company initiated a private placement, pursuant to Securities Purchase Agreements between Osage and certain purchasers, with aggregate gross proceeds of approximately $6.7 million. The purchase price of each unit, representing one share of common stock and a warrant to purchase 0.4 shares of common stock at $1.80 per share, was $0.90. The warrants have a term of five years. The placement agent received placement fees of 8%, in cash or warrants or a combination thereof at their election. As of December 31, 2014 units representing $6,744,000 had been sold, representing 7,493,339 shares of common stock and warrants to purchase 2,997,333 shares of common stock. The placement agent fees related to these units as of December 31, 2014 were cash fees of $338,940 and warrants to purchase 193,380 shares of common stock at $0.01 per share. In addition, the Company incurred legal fees of $10,000 with respect to the private placement.

	On January 2, 2014 we issued a total of 550,000 shares to three individuals in connection with amended employment and consulting agreements. Stock based compensation had already been expensed for 150,000 shares as discussed below. The remaining 400,000 shares vest on January 1, 2015, were originally valued at $436,000 based on closing prices of $1.00 for 200,000 shares and $1.18 for 200,000 shares. 200,000 of the shares, issued pursuant to a consulting agreement, were revalued from $236,000 to $138,000 as of December 31, 2014, based on a closing price of $0.32. The stock based compensation related to the 400,000 shares was expensed in 2014.

	On June 5, 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share, with a Black-Scholes value of $629,714 and an expiration date of June 4, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 5 years for employees and 10 years for the consultant, (3) expected volatility of 220.0% and 219.0% for employees and consultant, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.

	On September 8, 2014 we issued a total of 200,000 non-qualified stock options to a consultant, exercisable at $0.96 per share, with a Black-Scholes value of $173,906 and an expiration date of September 8, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 219.0%, and (4) zero expected dividends. These options were fully vested as of the grant date.

	On June 7, 2013, we issued a total of 10,000 shares which vested immediately to two consultants for services rendered with a fair value of $12,000, or $1.20 per share.

	On January 2, 2013 we issued 400,000 shares which vested immediately to two employees with a fair value of $364,000, or $0.91 per share.

	On August 1, 2012, in connection with a three-year employment agreement, we agreed to issue 150,000 shares of common stock at future dates as specified in the agreement. The agreement specified that we would issue 50,000 shares on each of the first, second, and third anniversaries of the execution of the agreement subject to other terms and conditions of the agreement. The 150,000 shares were valued at $177,000, or $1.18 per share, and were to be expensed over the three years of the employment agreement. Pursuant to an amendment to this agreement, the 150,000 shares were issued and immediately vested in early January 2014, and accordingly we recognized the remaining stock-based compensation expense of $152,418 in the year ended December 31, 2013.

	Warrants

	During the three months ended March 31, 2014, 200,000 warrants were exercised by a consultant who had previously received the warrants in exchange for services.

	In addition to the warrants issued pursuant to the private placement discussed above, on April 10, 2014 we issued a warrant to purchase 2,000,000 shares of common stock to a consultant, exercisable at $1.04 per share, with a Black-Scholes value of $2,184,538 and an expiration date of April 9, 2017. Variables used in the valuation include (1) discount rate of 0.81%, (2) expected life of 3 years, (3) expected volatility of 223.0% and (4) zero expected dividends. This warrant was fully vested as of the grant date. This consultant, who acts as project manager for the Company’s drilling operations, is president and a shareholder of an entity which holds stock in the Company and participating in certain of the Company’s wells.

	Total stock-based compensation expense was $3,252,158 and $528,418 for the years ended December 31, 2014 and 2013, respectively. All stock-based compensation expense is included in general and administrative expenses in the accompanying consolidated financial statements.

Segment_and_Geographical_Infor

Segment and Geographical Information	12 Months Ended
Segment and Geographical Information	Dec. 31, 2014
Segments, Geographical Areas [Abstract]
Segment and Geographical Information	4. SEGMENT AND GEOGRAPHICAL INFORMATION

	At December 31, 2014, the Company’s continuing operations comprised one segment in one geographic region.

Oil_and_Gas_Properties

Oil and Gas Properties	12 Months Ended
Oil and Gas Properties	Dec. 31, 2014
Oil and Gas Property [Abstract]
Oil and Gas Properties	5. OIL AND GAS PROPERTIES

	Oil and gas properties consisted of the following as of December 31, 2014 and 2013:

		31-Dec-14			31-Dec-13
	Properties subject to amortization	$	60,168,713		$	25,551,336
	Properties not subject to amortization		1,942,045			1,784,465
	Capitalized asset retirement costs		5,158			3,659
	Accumulated depreciation, depletion and impairment		(39,154,487	)		(2,606,243	)
	Oil & gas properties, net	$	22,961,429		$	24,733,217

	Depreciation and depletion expense for oil and gas properties totaled $6,690,066 and $2,308,064 in 2014 and 2013, respectively. We also recorded an impairment charge of $29,858,178 in 2014.

	On April 21, 2011, the Company entered into a participation agreement (“Participation Agreement”) with Slawson Exploration Company (“Slawson”) and U.S. Energy Development Corporation (“USE,” Slawson and USE, together, the “Parties”). Pursuant to the terms of the Participation Agreement, Slawson and USE acquired 45% and 30% respectively, of our 10,000 acre Nemaha Ridge prospect in Logan County, Oklahoma for $4,875,000. In addition, the Parties carried Osage for 7.5% of the cost of the first three horizontal Mississippian wells, which means that for the first three horizontal Mississippian wells, the Company provided up to 17.5% of the total well costs. After the first three wells, the Company was responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty and third party acreage interest payments, was allocated 45% to Slawson, 30% to USE and 25% to Osage. Slawson was the operator of all wells in the Nemaha Ridge prospect in sections where the Parties’ acreage controlled the section. In sections where the Parties’ acreage did not control the section, we may elect to participate in wells operated by others.

	On December 12, 2013, Osage and Slawson entered into an agreement (the “Partition Agreement”) related to certain lands located within the Nemaha Ridge in Logan County, Oklahoma, and for the exploration and development of those leases by the Parties.

	Under the Partition Agreement and effective as of September 1, 2013, the Slawson Exploration Group agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to Osage and Osage agreed to assign all of its rights, title and interest in and to the oil and gas leases and force-pooled acreage which are part of the Nemaha Ridge Project within certain sections to the Slawson Exploration Group, such that the net acreage controlled by the parties would remain substantially unchanged, but that the acreage controlled by each of the parties in undeveloped sections would be located in sections where the other party did not control acreage. The parties also agreed that the Participation Agreement would terminate as to all lands within the Nemaha Ridge Project except for lands within sections already developed by the parties which shall continue to be controlled by the Participation Agreement.

	In September 2014, Slawson sold its interests in its oil and gas properties in Logan County, Oklahoma to Stephens Energy Group, LLC and Stephens Production Company (collectively “Stephens”).

	As a result of the Partition Agreement, Osage has become the project operator on much of its acreage in the Nemaha Ridge Project. As of December 31, 2014, Osage operated or has the right to operate approximately 4,675 net acres (6,967 gross), and remains joint-venture or potential joint-venture partners with others in approximately 5,032 net acres (31,772 gross).

	In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Woodford Shale formation. The Woodford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Woodford shale lies directly under the Mississippian and started as a vertical play, but horizontal drilling techniques and multi-stage fracturing technology have been used in the Woodford in recent years with much success. At December 31, 2014, we had 4,367 net (10,106 gross) acres leased in Coal County.

	In 2011, the Company began to acquire leases in Pawnee County, Oklahoma, targeting the Mississippian formation. In July 2011, we purchased from B&W Exploration, Inc. (“B&W”) the Pawnee County prospect targeting the Mississippian, for $8,500. In addition, B&W is also entitled to an overriding royalty interest on the leases acquired and a 12.5% carry on the first $200,000 of lease bonus paid in the form of an assignment of 12.5% of the leases acquired. Subsequently, B&W shall have an option to purchase a 12.5% share of leasehold acquired on a heads-up basis. As of December 31, 2014, the Company had 3,934 net acres (5,085 gross) leased in Pawnee County.

	At December 31, 2014, we have leased 18,008 net (53,930 gross) acres across three counties in Oklahoma as follows:

		Gross			Osage Net
	Logan (non operated)		31,772			5,032
	Logan - Osage		6,967			4,675
	Coal		10,106			4,367
	Pawnee		5,085			3,934
			53,930			18,008

Debt

Debt	12 Months Ended
Debt	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	6. DEBT

	Apollo - Note Purchase Agreement

	On April 27, 2012, we entered into a $10,000,000 senior secured note purchase agreement (“Note Purchase Agreement” or “Notes”) with Apollo Investment Corporation (“Apollo”). The Notes, which mature on April 27, 2015, are secured by substantially all of the assets of the Company, including a mortgage on all our Oklahoma leases. The Notes bear interest of Libor plus 15.0% with a Libor floor of 2.0%, with interest payable monthly. In addition, Apollo received a warrant to purchase 1,496,843 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $2,483,952 and an expiration date of April 27, 2017. Variables used in the valuation include (1) discount rate of 0.82%, (2) expected life of 5 years, (3) expected volatility of 245.0% and (4) zero expected dividends. The minimum draw amount on the Note Purchase Agreement is $1,000,000. At closing, we did not draw down any funds. In the year ended December 31, 2013, we drew down $17,000,000 and, as of December 31, 2013, the amount outstanding under the Note Purchase Agreement was $20,000,000.

	At closing of the Note Purchase Agreement, we paid $100,000 of a minimum placement fee to CC Natural Resource Partners, LLC (“CCNRP”) and issued a warrant to purchase 250,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and an expiration date of April 27, 2014. Variables used in the valuation include (1) discount rate of 0.26%, (2) expected life of 2 years, (3) expected volatility of 242.0% and (4) zero expected dividends. In addition, we paid $170,692 in legal fees, of which $100,000 were paid to Apollo. In December 2012, we paid an additional $380,000 in placement fees. We also issued a warrant to purchase 100,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $89,952 and a term of five years, to the placement agent for the Note Purchase Agreement and amended the term of the warrant granted on April 27, 2012 from two to five years, with a Black-Scholes value of $1,161. Variables used in the valuation include (1) discount rate of 0.72%, (2) expected life of five years, (3) expected volatility of 242.0% and (4) zero expected dividends. In December 2013 we paid an additional $100,000 in placement fees.

	On April 5, 2013 the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the facility to $20,000,000 and modifying certain covenants for the remainder of the Note Purchase Agreement term. The amendment also provided a waiver of certain covenants as of March 31, 2013, as the Company did not meet certain covenants including the minimum production covenant as of that date. The Company paid an amendment fee of $100,000 which is being amortized over the remaining term of the Note Purchase Agreement.

	On August 12, 2013, the Company and Apollo amended the Note Purchase Agreement. The amendment required that the Company, within 75 days of the effective date as defined in the amendment, complete either (1) a sale of certain assets, or (2) the issuance of capital stock in a transaction that resulted in aggregate net proceeds as defined in the amendment. In the event that the Company did not complete either one of the aforementioned transactions, the Company would have been required under the terms of the amendment to issue to Apollo additional warrants equivalent to three percent of the Company’s common stock, on a fully-diluted basis. On October 7, 2013 the Company completed the sale of its membership interests in Cimarrona LLC as more fully discussed in Note 13. This sale satisfied the requirements of the amendment and the Company is thus not obligated to issue additional Warrants to Apollo.

	On April 3, 2014, the Company and Apollo amended the Note Purchase Agreement, increasing the amount of the total facility to $30,000,000, extending the term by one year and reducing the interest rate from Libor plus 15% to Libor plus 11%. During the nine months ended September 30, 2014, we drew down $5,000,000 of additional funds and, as of December 31, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000.

	The Company has recorded deferred financing costs in the aggregate amount of $3,959,448 in connection with the Note Purchase Agreement, which represented the fair value of warrants issued to Apollo and CCNRP, placement fees, amendment fees and legal fees, which are amortized on a straight-line basis over the term of the Notes, which approximates the effective interest method, as the Company did not draw funds at issuance.

	On each anniversary of the closing date, the Company is obligated to pay an administrative fee of $50,000. The Company is subject to certain precedents in connection with each draw, an upfront fee equal to 2.0% of the principal amount of each draw, and is required to maintain a deposit account equal to three months of interest payments.

	The Company is subject to various affirmative, negative and financial covenants under the Note Purchase Agreement as amended along with other restrictions and requirements, all as defined in the Note Purchase Agreement. Affirmative covenants include by October 31st of each year beginning in 2012, a reserve report prepared as of the immediately preceding September 30, concerning the Company’s domestic oil and gas properties prepared by approved petroleum engineers, and thereafter as of September 30th of each year.

	The Company and Apollo are negotiating new covenants to the Note Purchase Agreement. Until these negotiations are complete existing covenants, some of which the Company is not in compliance with, remain in place. Accordingly, the Company has classified borrowings under the Note Purchase Agreement as short term in the accompanying consolidated balance sheets.

	Use of proceeds is limited to those purposes specified in the Note Purchase Agreement. The Notes are subject to mandatory prepayment in the event of certain asset sales, insurance or condemnation proceeds, issuance of indebtedness, extraordinary receipts and tax refunds. All terms are as defined in the Note Purchase Agreement.

	In the year ended December 31, 2014, we drew down $5,000,000 and, as of December 31, 2014, the amount outstanding under the Note Purchase Agreement was $25,000,000.

	Boothbay - Secured Promissory Note

	On April 17, 2012, we issued a secured promissory note (“Secured Promissory Note”) to Boothbay Royalty Co., (“Boothbay”) for gross proceeds of $2,500,000. The Secured Promissory Note had a maturity date of April 17, 2014 and bore interest of 18%, payable monthly. In addition, Boothbay received 400,000 shares for which the relative fair value of $386,545 was recorded as debt discount, a 1.5% overriding royalty on our leases in section 29, township 17 North, range 3 and a 1.7143% overriding royalty on our leases in section 36, township 19 North, range 4 West in Logan County, Oklahoma. The closing price of the Company’s common stock on April 17, 2012 was $1.14. The Secured Promissory Note was secured by a first mortgage (with power of sale), security agreement and financing statement covering a 5% overriding royalty interest, proportionately reduced, in all of the Company’s leases in Logan County, Oklahoma. The Company repaid the Secured Promissory Note in full in December 2013.

	In connection with the Note Purchase Agreement and certain capital leases, the Company recognized $4,468,568 of interest expense, of which $3,549,086 was cash interest expense, for the year ended December 31, 2014. In connection with the Note Purchase Agreement, Secured Promissory Note and certain terms of the Partition Agreement with Slawson, the Company recognized $4,566,246 of interest expense, of which $2,999,838 was cash interest expense, for the year ended December 31, 2013.

Derivative_Financial_Instrumen

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

7. DERIVATIVE FINANCIAL INSTRUMENTS

The Company entered into certain derivative financial instruments with respect to a portion of its oil and gas production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and currently include only costless price collars. The Company does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

As of December 31, 2014, the Company had the following open oil derivative positions. These oil derivatives settle against the average of the daily settlement prices for the WTI first traded contract month on the New York Mercantile Exchange (“NYMEX”) for each successive day of the calculation period.

Price Collars

Monthly

Weighted Average

Volume

Floor Price

Ceiling Price

Period

(BBLs/m)

($/BBL)

Q1 - Q2, 2015

6,000

93.5

As of December 31, 2014, the Company had the following open natural gas derivative positions. These natural gas derivatives settle against the NYMEX Penultimate for the calculation period.

Price Collars

Monthly

Weighted Average

Volume

Floor Price

Ceiling Price

Period

(Btu/m)

($/Btu)

Q1 - Q2, 2015

10,000

3.75

4.4

Cash settlements and unrealized gains and losses on fair value changes associated with the Company’s commodity derivatives are presented in the “Oil and gas derivatives’ caption in the accompanying consolidated statements of earnings.

The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the years ended December 31, 2014 and 2013.

Year Ended

31-Dec-14

31-Dec-13

Cash settlements to (by) Company

(220,317

)

(138,236

)

Unrealized gains (losses) on commodity derivatives

1,474,307

(357,567

)

Gain (loss) on oil and gas derivatives

1,253,990

(495,803

)

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	8. COMMITMENTS AND CONTINGENCIES

	ENVIRONMENT

	Osage, as owner and operator of oil and gas fields, is subject to various federal, state, and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the owner of real property and the lessee under oil and gas leases for the cost of pollution clean-up resulting from operations, subject the owner/lessee to liability for pollution damages and impose restrictions on the injection of liquids into subsurface strata.

	Although Company environmental policies and practices are designed to ensure compliance with these laws and regulations, future developments and increasing stringent regulations could require the Company to make additional unforeseen environmental expenditures.

	The Company maintains insurance coverage that it believes is customary in the industry, although it is not fully insured against all environmental risks.

	The Company is not aware of any environmental claims existing as of December 31, 2014, that would have a material impact on its consolidated financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company’s property.

	RENTALS AND OPERATING LEASES

	In February 2011, the Company entered into a 36 month lease for its corporate offices in San Diego. In February 2014 the Company amended this lease to extend the term for an additional three years through February 2017. In February 2012, the Company entered into a 24 month lease for a vehicle to be utilized by its operations in Oklahoma. In December 2013, the Company entered into a three year lease for office space in Oklahoma City, and also entered into certain equipment leases for furniture and office equipment at that location.

	Rental expense totaled $163,401 and $58,147 in 2014 and 2013, respectively.

	Future minimum commitments under operating leases are as follows as of December 31, 2014:

	Year	Amount
	2015		184,810
	2016		186,098
	2017		29,862
		$	400,770

	CAPITAL LEASES

	The Company entered into a lease for certain office furniture and equipment in the first quarter of 2014. The term of the lease is three years and as the lease essentially transfers the risks of ownership it is being accounted for as a capital lease.

	Leased property under capital leases at December 31, 2014 includes:

	Capital Leases	December 31, 2014
	Furniture and equipment	$	127,436
	less: accumulated depreciation		(21,240	)
		$	106,196

	Total depreciation expense under capital leases was $21,240 for the year ended December 31, 2014 and as of that date the future minimum lease payments under capital leases were as follows:

	Year	Amount
	2015		46,166
	2016		42,956
	2017		7,158
			96,280
	Less amount representing interest		(447	)
	Present value of minimum lease payments	$	95,833

	Current maturities	$	45,698
	Non-current maturities		50,135
		$	95,833

	LEGAL PROCEEDINGS

	The Company has initiated litigation against Stephen’s with respect to their right to operate 22 wells in which we have a working interest as we contend that we should be the operator. The Company is not a party to any other litigation that has arisen in the normal course of its business or that of its subsidiaries.

	SALE OF CIMARRONA LLC

	The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.

Dilutive_Securities

Dilutive Securities	12 Months Ended
Dilutive Securities	Dec. 31, 2014
Equity [Abstract]
Dilutive Securities	9. DILUTIVE SECURITIES

	As of December 31, 2014 and 2013, the Company had outstanding dilutive securities, consisting of warrants and options. Changes in warrants and options outstanding are as follows:

	Warrants

					Weighted Average		Average Remaining
		Shares			Exercise Price		Contractual Life
	Balance December 31, 2012		3,171,843		$	0.45	2.72 years
	Exercised		(350,000	)	$	0.01
	Expired		(1,125,000	)	$	1.25
	Balance December 31, 2013		1,696,843		$	0.01	3.35 years
	Granted		5,190,713		$	1.44
	Exercised		(200,000	)	$	0.01
	Balance December 31, 2014		6,687,556		$	1.12	3.16 years

	The intrinsic value of these warrants as of December 31, 2014 was $523,969. The intrinsic value of warrants exercised during 2014 was $226,000. The weighted average grant date fair value for warrants issued in 2014 was $1.03.

	Options

	In June 2007, we implemented the 2007 Osage Exploration and Development, Inc. Equity-Based Compensation Plan (the “Plan”) which allows the reservation of 5,000,000 shares under the Plan. Under this Plan, securities issued may include options, stock appreciation rights (“SARs”) and restricted stock. The first grants under this plan took place in 2014, and are presented below.

					Weighted Average		Average Remaining
		Shares			Exercise Price		Contractual Life
	Balance December 31, 2013		-		$	-	n/a
	Granted		800,000		$	0.91
	Balance December 31, 2014		800,000		$	0.91	9.51 years

	Exercisable at December 31,2014		800,000		$	0.91	9.51 years

	These options had no intrinsic value as of December 31, 2014. The weighted average grant date fair value of these options was $1.00.

	On June 5, 2014 we issued a total of 600,000 non-qualified stock options to two employees and a consultant, exercisable at $0.8925 per share, with a Black-Scholes value of $629,714 and an expiration date of June 4, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 5 years for employees and 10 years for the consultant, (3) expected volatility of 220.0% and 219.0% for employees and consultant, respectively, and (4) zero expected dividends. These options were fully vested as of the grant date.

	On September 8, 2014 we issued a total of 200,000 non-qualified stock options to a consultant, exercisable at $0.96 per share, with a Black- Scholes value of $173,906 and an expiration date of September 8, 2024. Variables used in the valuation include (1) discount rate of 0.85%, (2) expected life of 10 years, (3) expected volatility of 219.0%, and (4) zero expected dividends. These options were fully vested as of the grant date.

	All stock based compensation is reflected in general and administrative expenses in the consolidated financial statements for 2014 and 2013.

	Definitions

	Expected Dividends—The Company has never declared or paid dividends on common stock and has no plans to do so.

	Expected Volatility—Volatility is a measure of the amount by which a financial variable such as a share price has fluctuated or is expected to fluctuate during a period. The Company considered the historical volatility of its share price and business and economic considerations in order to estimate the expected volatility.

	Discount Rate—This is the U.S. Treasury rate for the day of each option grant having a term that most closely resembles the expected life of the option.

	Expected Life—This is the period of time that the options granted are expected to remain unexercised. Options granted during the year have a maximum contractual term of ten years. The Company estimates the expected life of the option term based on the simplified method as defined in Staff Accounting Bulletin 110. For non-employee options granted, this is the remaining contractual term of the option as of the reporting date.

Income_Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	10. INCOME TAXES

	The total provision for income taxes consists of the following in 2014 and 2013:

		Year Ended December 31,
		2014			2013
	Current Taxes:
	Federal	$	-		$	-
	State		-			-
	Foreign		-			-
			-			-

	Deferred Taxes:
	Federal		(9,933,029	)		646,907
	State		(922,353	)		60,070
	Foreign					-

	Valuation Allowance		10,855,382			(706,977	)
			-			-
	Totals	$	-		$	-

	Following is a reconciliation of the Federal statutory rate to the effective income tax rate for 2014 and 2013:

		2014			2013
	Computed tax provision at statutory Federal rates		35	%	35	%
	Increase (decrease) in taxes resulting from:
	State taxes, net of Federal income tax benefit		3.25	%	3.25	%
	Nondeductible and other expenses		-0.01	%	-4.33	%
	Federal and State true ups		0	%	0	%
	Other adjustments		-6.78	%	-15.52	%
	Valuation Allowance		-31.46	%	-18.4	%
			0	%	0	%

	At December 31, 2014, the Company had federal and state net operating loss carry forwards of approximately $11.8 million which expire at various dates through 2032.

	Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Significant components of Osage’s deferred tax assets and liabilities are as follows at December 31, 2014 and December 31, 2013:

		2014			2013
	Deferred tax liability:

	Net operating loss carry forward	$	4,528,527		$	3,807,000
	Oil and gas properties		25,630,977			-
	Stock based compensation		1,653,650			-
	Other		242,141			879,000
	Oil and gas properties		(20,201,526	)		(4,501,000	)
	Deferred financing costs		(813,341	)		-
	Valuation allowance		(11,040,428	)		(185,000	)
	Net deferred tax liability	$	-		$	-

	The non-current portions of the deferred tax asset and the deferred tax liability accounts offset each other in the Company’s consolidated balance sheet.

Major_Customers_and_Vendors

Major Customers and Vendors	12 Months Ended
Major Customers and Vendors	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Major Customers and Vendors	11. MAJOR CUSTOMERS AND VENDORS

	During 2014 and 2013, the following customers accounted for all of the Company’s sales from continuing operations:

		Year ended					Year ended
		31-Dec-14					31-Dec-13
		Amount		% of Total			Amount		% of Total
	Slawson	$	4,117,056		32.5	%	$	6,421,674		80	%
	Phillips 66		3,954,306		31.2	%		-		0	%
	Stephens		2,192,007		17.3	%		847,573		10.6	%
	Devon		1,742,848		13.7	%		738,178		9.2	%
	Energy Financial		375,140		3	%		-		0	%
	Other		297,159		2.3	%		21,663		0.3	%
	Total	$	12,678,516		100	%	$	8,029,088		100	%

	During 2014, we purchased products or services of $9,667,450 from Weatherford US, LP and $6,105,859 from Nabors Drilling, LP, representing 17.5% and 11.1% of total purchases, respectively. In 2013, no vendor represented more than 10% of purchases.

Liability_for_Asset_Retirement

Liability for Asset Retirement Obligations	12 Months Ended
Liability for Asset Retirement Obligations	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Liability for Asset Retirement Obligations	12. LIABILITY FOR ASSET RETIREMENT OBLIGATIONS

	The Company recognizes a liability at discounted fair value for the future retirement of tangible long-lived assets and associated assets retirement cost associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The related accretion expense is recognized in the statement of operations. The provision will be revised for the effect of any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized in income in the period the actual costs are incurred. There are no legally restricted assets for the settlement of asset retirement obligations. No income tax is applicable to the asset retirement obligation as of December 31, 2014 and 2013, because the Company records a valuation allowance on deductible temporary differences due to the uncertainty of its realization. A reconciliation of the Company’s asset retirement obligations from the periods presented is as follows:

		Year Ended
		December 31,
		2014		2013
	Beginning balance	$	3,886	$	19
	Incurred during the period		-		-
	Reversed during the period		-		-
	Additions for new wells		1,500		3,639
	Accretion expense		895		228
	Ending balance	$	6,281	$	3,886

Discontinued_Operations

Discontinued Operations	12 Months Ended
Discontinued Operations	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	13. DISCONTINUED OPERATIONS

	On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven, pursuant to the Agreement dated September 30, 2013 by and between the Company and Raven. Cimarrona LLC is the owner of a 9.4% interest in certain oil and gas assets including a pipeline in the Guaduas field, located in the Dindal and Rio Seco Blocks that covers 30,665 acres in the Middle Magdalena Valley in Colombia.

	The sales price consisted of cash of $6,550,000 exclusive of escrow, less settlement of debt of Cimarrona LLC of approximately $250,000. $250,000 was to be held in escrow for 12 months to secure any post-Closing purchase price adjustments and any indemnity obligations of the Company pursuant to the Agreement. In addition, so long as the per barrel transportation rate charged with respect to the pipeline was not adjusted prior to March 31, 2014, then Raven was obligated to pay the Company an additional $1,000,000 in cash. Pursuant to the Agreement, the Company also recognized a receivable for a working capital adjustment of $422,955 in other current assets as of December 31, 2013 and recognized a gain on disposal of discontinued operations of $4,873,660 in the year ended December 31, 2013. Raven has reimbursed the Company for the working capital adjustment. On August 31, 2014 the Company and Raven entered into a settlement agreement, due to numerous uncertainties, whereby the escrow was released to Raven and whereby no additional cash is payable by Raven to the Company.

	The following table sets forth the results of operations for the discontinued operations for the periods presented:

		Year Ended December 31,
		2014		2013
	Revenues
	Oil revenues	$	-	$	1,458,616
	Pipeline revenues		-		1,828,256
	Total revenues		-		3,286,872

	Operating costs and expenses
	Operating expenses		-		1,007,987
	Depreciation, depletion and accretion		-		124,193
	Equity tax		-		(435,988	)
	General and administrative		-		72,756
	Total operating costs and expenses		-		768,948

	Operating income		-		2,517,924

	Other income (expenses):
	Interest income		-		103
	Interest expense		-		(21,486	)
	Income before income taxes		-		2,496,541
	Provision for income taxes		-		-

	Net income	$	-	$	2,496,541

	The Cimarrona property is subject to an Ecopetrol Association Contract (the “Association Contract”) whereby Ecopetrol S.A. (“Ecopetrol”) receives royalties of 20% of the oil produced. The pipeline is not subject to the Association Contract. In addition to the royalty, according to the Association Contract, Ecopetrol may, for no consideration, become a 50% partner, once an audit of revenues and expenses indicate that the partners in the Association Contract have received a 200% reimbursement of all historical costs to develop and operate the Guaduas field. If such an audit determines that the specified reimbursement of historical costs occurred prior to September 30, 2013, the Company is required to reimburse Raven for any amounts due to Ecopetrol from Cimarrona LLC which relate to the period prior to that date. The Company believes its maximum exposure is 50% of Cimarrona LLC’s oil revenues for the nine months ended September 30, 2013, or $729,308. The Company has not recorded any provision for this matter, as it is not possible to estimate the potential liability, if any.

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	14. SUBSEQUENT EVENTS

	None.

Supplemental_Information_About

Supplemental Information About oil And Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2014
Supplemental Information About Oil And Gas Producing Activities
Supplemental Information About oil And Gas Producing Activities (Unaudited)	15. SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

	There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company and the operators. The reserve data set forth in this Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and condensate, natural gas liquids and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate upward or downward. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.

	Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations as promulgated by the SEC. The Company retained Pinnacle Energy Services, LLC (“Pinnacle”) to independently prepare estimates of our oil and gas reserves in our properties in Logan County, Oklahoma. Management is responsible for providing the following information related to our oil and gas properties to the firm: working and net revenue interests, historical production rates, current operating and future development costs, and geoscience, engineering and other information. Our Chief Geologist reviews the final reserve estimate for completeness and reasonableness and, if necessary, discusses the process used and findings with the designated technical person at Pinnacle. Our Chief Geologist has over 25 years of oil and gas experience. The technical person primarily responsible for audit of our reserve estimates at Pinnacle meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Pinnacle is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

	Pinnacle prepared reserve estimates for the year end reports for 2014 and 2013 for our continuing operations in Logan County, Oklahoma. For wells on production with sufficient historical data, remaining reserves were determined by decline curve analysis. For wells with limited production or pressure data history and those with definable reserves using offset well and reservoir parameters, remaining reserves were estimated based on analogy well and test data and other available geological and engineering information.

	Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

	Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

	FASB ASC Topic 932, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, requires disclosure of certain financial data for oil and gas operations and reserve estimates or oil and gas. This information, presented here is intended to enable the reader to better evaluate the operations of the Company. All of the Company’s oil and gas reserves from continuing operations are located in the United States.

	The aggregate amount of capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation, amortization and valuation allowances as of December 31, 2014 and 2013 are as follows:

			31-Dec-14				31-Dec-13
	Proved properties		$	60,168,713			$	25,551,336
	Unproved properties being amortized
	Unproved properties not being amortized			1,942,045				1,784,465
	Capitalized asset retirement costs			5,158				3,659
	Accumulated depreciation, amortization and impairment			(39,154,487	)			(2,606,243	)
			$	22,961,429			$	24,733,217

	Estimated quantities of proved developed and undeveloped reserves of crude oil, natural gas and natural gas liquids, as well as changes in proved developed and undeveloped reserves for our continuing operations during the past two years are indicated below.

			Oil (BBLS)							Gas (MMCF)						Natural Gas Liquids (BBLs)
			2014				2013			2014			2013			2014			2013
	Proved developed and undeveloped reserves:
	Beginning of year			1,508,000				364,000			6,365			1,499			43,000			-
	Revisions of previous estimates			-				-						-			-			-
	Improved recovery			-				-						-			-			-
	Purchases of Minerals in place			-				-						-			-			-
	Extensions and discoveries			1,579,278				1,220,409			3,028			5,016			1,488,756			46,507
	Production			(124,278	)			(76,409	)		(367	)		(150	)		(27,756	)		(3,507	)
	Sales of minerals in place			-				-			-			-			-			-
	End of year			2,963,000				1,508,000			9,026			6,365			1,504,000			43,000

	Proved developed reserves:
	Beginning of year			460,000				195,000			2,005			803			33,000			-
	End of year			678,000				460,000			2,485			2,005			414,000			33,000

	Proved undeveloped reserves:
	Beginning of year			1,048,000				169,000			4,360			696			10,000			-
	End of year			2,285,000				1,048,000			6,541			4,360			1,090,000			10,000

	All changes in estimated proved developed and proved undeveloped reserves during 2014 and 2013 were as a result of extensions and discoveries.

	In December 2011, the Company commenced drilling its first well in Logan County and at December 31, 2014 the Company had commenced drilling 58 gross development wells, 54 of which achieved production and revenues as of December 31, 2014 and two of which were gross dry development wells. During 2014, we participated in drilling 14 gross productive development wells (2.7 net wells), two gross dry development wells (1.8 net wells) and two gross development wells (0.4 net wells) which had not yet achieved production and revenues as of December 31, 2014. During 2013, we participated in the drilling of 35 gross productive wells (6.1 net wells) and 2 gross wells (0.3 net wells) which had not yet achieved production and revenues as of December 31, 2013. During 2012, we participated in the drilling of 5 gross productive wells (1.1 net wells) and 3 gross wells (0.6 net wells) which had not yet achieved production as of December 31, 2012. Also as of December 31, 2014, the Company had completed six gross salt water disposal wells.

	The foregoing estimates have been prepared by Pinnacle for the Logan County, Oklahoma property. The reserve estimates are believed to be reasonable and consistent with presently known physical data concerning size and character of the reservoirs and are subject to change as additional knowledge concerning the reservoirs becomes available.

	Depletion, depreciation and accretion per equivalent unit of production was $31.56 and $22.00 for 2014 and 2013, respectively.

	FASB ASC Topic 932, “Disclosure About Oil and Gas Producing Activities”, requires certain disclosures of the costs and results of exploration and production activities and established a standardized measure of oil and gas reserves and the year-to-year changes therein.

	Cost incurred, both capitalized and expensed, for oil and gas property acquisition, exploration and development for the years ended December 31, 2014 and 2013 were are follows:

			2014				2013
	Property acquisition costs		$	1,506,755			$	1,278,408
	Exploration costs			-				-
	Development costs			35,698,314				16,613,524
	Asset retirement costs			-				-

Future cash inflows were computed by applying the average prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) and using the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming the continuation of existing economic conditions.

The average prices used in the reserve estimate for oil were $94.99 per BBL in 2014 and $96.94 per BBL in 2013. For natural gas, the average prices used in the reserve estimate were $4.35 per Mcf in 2014 and $3.67 per Mcf in 2013.

Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows related to the Company’s proved oil and gas reserves and the tax basis of proved oil and gas properties and available operating loss and excess statutory depletion carryovers reduced by investment tax credits. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.

The following table presents the standardized measure of discounted estimated net cash flows relating to proved oil and gas reserves for 2014 and 2013.

		2014				2013
Future cash inflows		$	342,004,710			$	176,035,000
Future production costs			(90,841,910	)			(47,088,610	)
Future development costs			(81,090,570	)			(35,500,100	)
Future abandonment costs			(676,200	)			(451,200	)
Future income tax expenses			(67,758,412	)			(37,198,036	)

Future net cash flow			101,637,618				55,797,054
10% annual discount for estimated timing of cash flows			(52,246,511	)			(29,219,748	)
Standardized measure of discounted future net cash flow		$	49,391,107			$	26,577,306

The principal changes in the standardized measure of discounted future net cash flows during 2014 and 2013 were as follows:

		2014				2013
Extensions			-				-
Revisions of previous estimates
Price changes		$	(2,425,938	)		$	182,220
Quantity Changes			155,123,408				105,407,911
Changes in production rates, timing and other			(86,304,124	)			(54,058,997	)
Development costs incurred			-				-
Changes in estimated future development costs			(21,715,696	)			(17,009,887	)
Purchase of minerals in place			-				-
Sales of minerals in place			-				-
Sales of oil and gas, net of production costs			(10,743,149	)			(6,481,139	)
Accretion of discount			4,088,500				1,481,896
Net change in income taxes			(15,209,200	)			(11,808,801	)
Net increase/(decrease)		$	22,813,801			$	17,713,203

Organization_and_Summary_of_Si1

Organization and Summary of Significiant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

NATURE OF OPERATIONS

Basis of Consolidation

BASIS OF CONSOLIDATION

Reclassifications

RECLASSIFICATIONS

Risk Factors Related to Concentration of Sales and Products

RISK FACTORS RELATED TO CONCENTRATION OF SALES AND PRODUCTS

Use of Estimates

USE OF ESTIMATES

Cash and Equivalents

CASH AND EQUIVALENTS

Cash and equivalents consist of short-term, highly liquid investments readily convertible into cash with an original maturity of three months or less.

Deferred Financing Costs

DEFERRED FINANCING COSTS

During the years ended December 31, 2014 and 2013, respectively, the Company made payments of $100,000 and $200,000 for deferred financing fees in connection with the Note Purchase Agreement.

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

The three levels of valuation hierarchy are defined as follows:

●

Level 1 inputs to the valuation methodology are quoted prices for identical assets or liabilities in active markets.

●

Level 3 inputs to the valuation methodology use one or more unobservable inputs which are significant to the fair value measurement.

As of December 31, 2014 and December 31, 2013 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheets.

The following table presents information for those assets and liabilities requiring disclosure at fair value as of December 31, 2014 and December 31, 2013:

Total

Fair Value Measurements Using:

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

December 31, 2014 assets (liabilities):

Commodity derivative asset

1,116,740

December 31, 2013 assets (liabilities):

Commodity derivative liability

(357,567

)

(357,567

)

(357,567

)

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 2 Fair Value Measurements

Assets and Liabilities Measured on a non-recurring basis

Total

Fair Value Measurements Using:

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

(before impairment)

December 31, 2014 assets (liabilities):

Proved oil & gas properties, net book value

50,872,404

21,014,226

Concentration of Credit Risk

CONCENTRATION OF CREDIT RISK

Restricted Cash

RESTRICTED CASH

Accounts Receivable and Allowance for Doubtful Accounts

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

The Company recognizes accounts receivable when sales are invoiced and regularly reviews accounts receivable for doubtful accounts.

Oil and Gas Properties

OIL AND GAS PROPERTIES

Osage is an exploration and production oil and natural gas company with proved reserves and existing production in the state of Oklahoma.

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

Other Property and Equipment

OTHER PROPERTY AND EQUIPMENT

Depreciation for non-oil and gas properties is recorded on the straight-line method at rates based on estimated useful lives ranging from three to fifteen years of the assets.

Impairment of Long-Lived Assets

IMPAIRMENT OF LONG-LIVED ASSETS

The assessment of unproved properties to determine any possible impairment requires significant judgment. No impairment was recorded on unproved properties in 2014 or 2013.

Revenue Recognition

REVENUE RECOGNITION

Stock Based Compensation

STOCK BASED COMPENSATION

Income Taxes

INCOME TAXES

Risk Management Activities

RISK MANAGEMENT ACTIVITIES

Earnings (Loss) Per Share

EARNINGS (LOSS) PER SHARE

The following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2014 and 2013:

Year Ended December 31,

2014

2013

Net loss allocable to continuing operations

(34,509,882

)

(3,514,895

)

Net income and gain allocable to discontinued operations

7,370,201

Basic and diluted net income (loss) per share

Continuing operations

(0.61

)

(0.07

)

Discontinued operations

0.15

Basic and diluted weighted average shares outstanding

56,480,460

49,762,499

Recently Issued Accounting Pronouncements

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The Company is evaluating the impact, if any, that ASU 2014-09 and ASU 2014-15 will have on its consolidated financial statements.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Fair Value Measurements Assets and Liability	The following table presents information for those assets and liabilities requiring disclosure at fair value as of December 31, 2014 and December 31, 2013:

					Total			Fair Value Measurements Using:
		Carrying			Fair			Level 1		Level 2			Level 3
		Amount			Value			Inputs		Inputs			Inputs
	December 31, 2014 assets (liabilities):
	Commodity derivative asset		1,116,740			1,116,740			-		1,116,740			-
	December 31, 2013 assets (liabilities):
	Commodity derivative liability		(357,567	)		(357,567	)		-		(357,567	)		-
Schedule of Assets and Liabilities Measured on Non-recurring Basis					Total			Fair Value Measurements Using:
		Carrying			Fair			Level 1		Level 2			Level 3
		Amount			Value			Inputs		Inputs			Inputs
		(before impairment)			Value			Inputs		Inputs			Inputs
	December 31, 2014 assets (liabilities):
	Proved oil & gas properties, net book value	$	50,872,404		$	21,014,226			-		-		$	21,014,226
Schedule of Computation of Basic and Diluted Net Income (Loss) Per Share	The following table shows the computation of basic and diluted net income (loss) per share for the years ended December 31, 2014 and 2013:

		Year Ended December 31,
		2014			2013
	Net loss allocable to continuing operations	$	(34,509,882	)	$	(3,514,895	)
	Net income and gain allocable to discontinued operations	$	-		$	7,370,201
	Basic and diluted net income (loss) per share
	Continuing operations	$	(0.61	)	$	(0.07	)
	Discontinued operations	$	-		$	0.15
	Basic and diluted weighted average shares outstanding		56,480,460			49,762,499

Oil_and_Gas_Properties_Tables

Oil and Gas Properties (Tables)	12 Months Ended
Oil and Gas Properties (Tables)	Dec. 31, 2014
Oil and Gas Property [Abstract]
Schedule of Oil and Gas Properties	The aggregate amount of capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation, amortization and valuation allowances as of December 31, 2014 and 2013 are as follows:

		31-Dec-14			31-Dec-13
	Proved properties	$	60,168,713		$	25,551,336
	Unproved properties being amortized
	Unproved properties not being amortized		1,942,045			1,784,465
	Capitalized asset retirement costs		5,158			3,659
	Accumulated depreciation, amortization and impairment		(39,154,487	)		(2,606,243	)
		$	22,961,429		$	24,733,217
Schedule of Area of Land Leased	At December 31, 2014, we have leased 18,008 net (53,930 gross) acres across three counties in Oklahoma as follows:

		Gross			Osage Net
	Logan (non operated)		31,772			5,032
	Logan - Osage		6,967			4,675
	Coal		10,106			4,367
	Pawnee		5,085			3,934
			53,930			18,008

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2014

Schedule of Cash Settlements and Unrealized Gains (Losses) on Fair Value Changes for Commodity Derivatives

The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the years ended December 31, 2014 and 2013.

Year Ended

31-Dec-14

31-Dec-13

Cash settlements to (by) Company

(220,317

)

(138,236

)

Unrealized gains (losses) on commodity derivatives

1,474,307

(357,567

)

Gain (loss) on oil and gas derivatives

1,253,990

(495,803

)

Oil [Member]

Schedule of Oil and Natural Gas Open Derivative Positions

Price Collars

Monthly

Weighted Average

Volume

Floor Price

Ceiling Price

Period

(BBLs/m)

($/BBL)

Q1 - Q2, 2015

6,000

93.5

Natural Gas Member]

Schedule of Oil and Natural Gas Open Derivative Positions

As of December 31, 2014, the Company had the following open natural gas derivative positions. These natural gas derivatives settle against the NYMEX Penultimate for the calculation period.

Price Collars

Monthly

Weighted Average

Volume

Floor Price

Ceiling Price

Period

(Btu/m)

($/Btu)

Q1 - Q2, 2015

10,000

3.75

4.4

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Commitments Under Operating Leases	Future minimum commitments under operating leases are as follows as of December 31, 2014:

	Year	Amount
	2015		184,810
	2016		186,098
	2017		29,862
		$	400,770
Schedule of Leased Property Under Capital Leases	Leased property under capital leases at December 31, 2014 includes:

	Capital Leases	December 31, 2014
	Furniture and equipment	$	127,436
	less: accumulated depreciation		(21,240	)
		$	106,196
Schedule of Future Minimum Lease Payments Under Capital Leases	Total depreciation expense under capital leases was $21,240 for the year ended December 31, 2014 and as of that date the future minimum lease payments under capital leases were as follows:

	Year	Amount
	2015		46,166
	2016		42,956
	2017		7,158
			96,280
	Less amount representing interest		(447	)
	Present value of minimum lease payments	$	95,833

	Current maturities	$	45,698
	Non-current maturities		50,135
		$	95,833

Dilutive_Securities_Tables

Dilutive Securities (Tables)	12 Months Ended
Dilutive Securities (Tables)	Dec. 31, 2014
Equity [Abstract]
Schedule of Warrants Activity	As of December 31, 2014 and 2013, the Company had outstanding dilutive securities, consisting of warrants and options. Changes in warrants and options outstanding are as follows:

	Warrants

					Weighted Average		Average Remaining
		Shares			Exercise Price		Contractual Life
	Balance December 31, 2012		3,171,843		$	0.45	2.72 years
	Exercised		(350,000	)	$	0.01
	Expired		(1,125,000	)	$	1.25
	Balance December 31, 2013		1,696,843		$	0.01	3.35 years
	Granted		5,190,713		$	1.44
	Exercised		(200,000	)	$	0.01
	Balance December 31, 2014		6,687,556		$	1.12	3.16 years
Schedule of Stock Option Activity	The first grants under this plan took place in 2014, and are presented below.

					Weighted Average		Average Remaining
		Shares			Exercise Price		Contractual Life
	Balance December 31, 2013		-		$	-	n/a
	Granted		800,000		$	0.91
	Balance December 31, 2014		800,000		$	0.91	9.51 years

	Exercisable at December 31,2014		800,000		$	0.91	9.51 years

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The total provision for income taxes consists of the following in 2014 and 2013:

		Year Ended December 31,
		2014			2013
	Current Taxes:
	Federal	$	-		$	-
	State		-			-
	Foreign		-			-
			-			-

	Deferred Taxes:
	Federal		(9,933,029	)		646,907
	State		(922,353	)		60,070
	Foreign					-

	Valuation Allowance		10,855,382			(706,977	)
			-			-
	Totals	$	-		$	-
Schedule of Federal Statutory Rate to Effective Income Tax Rate	Following is a reconciliation of the Federal statutory rate to the effective income tax rate for 2014 and 2013:

		2014			2013
	Computed tax provision at statutory Federal rates		35	%	35	%
	Increase (decrease) in taxes resulting from:
	State taxes, net of Federal income tax benefit		3.25	%	3.25	%
	Nondeductible and other expenses		-0.01	%	-4.33	%
	Federal and State true ups		0	%	0	%
	Other adjustments		-6.78	%	-15.52	%
	Valuation Allowance		-31.46	%	-18.4	%
			0	%	0	%
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and amounts used for income tax purposes. Significant components of Osage’s deferred tax assets and liabilities are as follows at December 31, 2014 and December 31, 2013:

		2014			2013
	Deferred tax liability:

	Net operating loss carry forward	$	4,528,527		$	3,807,000
	Oil and gas properties		25,630,977			-
	Stock based compensation		1,653,650			-
	Other		242,141			879,000
	Oil and gas properties		(20,201,526	)		(4,501,000	)
	Deferred financing costs		(813,341	)		-
	Valuation allowance		(11,040,428	)		(185,000	)
	Net deferred tax liability	$	-		$	-

Major_Customers_and_Vendor_Tab

Major Customers and Vendor (Tables)	12 Months Ended
Major Customers and Vendor (Tables)	Dec. 31, 2014
Major Customers And Vendor Tables
Schedule of Major Customers Accounting for All of Its Sale	During 2014 and 2013, the following customers accounted for all of the Company’s sales from continuing operations:

		Year ended					Year ended
		31-Dec-14					31-Dec-13
		Amount		% of Total			Amount		% of Total
	Slawson	$	4,117,056		32.5	%	$	6,421,674		80	%
	Phillips 66		3,954,306		31.2	%		-		0	%
	Stephens		2,192,007		17.3	%		847,573		10.6	%
	Devon		1,742,848		13.7	%		738,178		9.2	%
	Energy Financial		375,140		3	%		-		0	%
	Other		297,159		2.3	%		21,663		0.3	%
	Total	$	12,678,516		100	%	$	8,029,088		100	%

Liability_for_Asset_Retirement1

Liability for Asset Retirement Obligations (Tables)	12 Months Ended
Liability for Asset Retirement Obligations (Tables)	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Schedule of Reconciliation of Asset Retirement Obligations	A reconciliation of the Company’s asset retirement obligations from the periods presented is as follows:

		Year Ended
		December 31,
		2014		2013
	Beginning balance	$	3,886	$	19
	Incurred during the period		-		-
	Reversed during the period		-		-
	Additions for new wells		1,500		3,639
	Accretion expense		895		228
	Ending balance	$	6,281	$	3,886

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
Discontinued Operations (Tables)	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Summary of Discontinued Operations	The following table sets forth the results of operations for the discontinued operations for the periods presented:

		Year Ended December 31,
		2014		2013
	Revenues
	Oil revenues	$	-	$	1,458,616
	Pipeline revenues		-		1,828,256
	Total revenues		-		3,286,872

	Operating costs and expenses
	Operating expenses		-		1,007,987
	Depreciation, depletion and accretion		-		124,193
	Equity tax		-		(435,988	)
	General and administrative		-		72,756
	Total operating costs and expenses		-		768,948

	Operating income		-		2,517,924

	Other income (expenses):
	Interest income		-		103
	Interest expense		-		(21,486	)
	Income before income taxes		-		2,496,541
	Provision for income taxes		-		-

	Net income	$	-	$	2,496,541

Recovered_Sheet1

Supplemental Information about Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Information About Oil And Gas Producing Activities Tables
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities	The aggregate amount of capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation, amortization and valuation allowances as of December 31, 2014 and 2013 are as follows:

		31-Dec-14			31-Dec-13
	Proved properties	$	60,168,713		$	25,551,336
	Unproved properties being amortized
	Unproved properties not being amortized		1,942,045			1,784,465
	Capitalized asset retirement costs		5,158			3,659
	Accumulated depreciation, amortization and impairment		(39,154,487	)		(2,606,243	)
		$	22,961,429		$	24,733,217
Schedule of Estimated Quantities of Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas	Estimated quantities of proved developed and undeveloped reserves of crude oil, natural gas and natural gas liquids, as well as changes in proved developed and undeveloped reserves for our continuing operations during the past two years are indicated below.

		Oil (BBLS)						Gas (MMCF)						Natural Gas Liquids (BBLs)
		2014			2013			2014			2013			2014			2013
	Proved developed and undeveloped reserves:
	Beginning of year		1,508,000			364,000			6,365			1,499			43,000			-
	Revisions of previous estimates		-			-						-			-			-
	Improved recovery		-			-						-			-			-
	Purchases of Minerals in place		-			-						-			-			-
	Extensions and discoveries		1,579,278			1,220,409			3,028			5,016			1,488,756			46,507
	Production		(124,278	)		(76,409	)		(367	)		(150	)		(27,756	)		(3,507	)
	Sales of minerals in place		-			-			-			-			-			-
	End of year		2,963,000			1,508,000			9,026			6,365			1,504,000			43,000

	Proved developed reserves:
	Beginning of year		460,000			195,000			2,005			803			33,000			-
	End of year		678,000			460,000			2,485			2,005			414,000			33,000

	Proved undeveloped reserves:
	Beginning of year		1,048,000			169,000			4,360			696			10,000			-
	End of year		2,285,000			1,048,000			6,541			4,360			1,090,000			10,000
Costs Incurred, Both Capitalized and Expensed, Oil and Gas Property Acquisition, Exploration and Development	Cost incurred, both capitalized and expensed, for oil and gas property acquisition, exploration and development for the years ended December 31, 2014 and 2013 were are follows:

		2014			2013
	Property acquisition costs	$	1,506,755		$	1,278,408
	Exploration costs		-			-
	Development costs		35,698,314			16,613,524
	Asset retirement costs		-			-
Standardized Measure of Discounted Estimated Net Cash Flows Relating to Proved Oil and Gas Reserves	The following table presents the standardized measure of discounted estimated net cash flows relating to proved oil and gas reserves for 2014 and 2013.

		2014			2013
	Future cash inflows	$	342,004,710		$	176,035,000
	Future production costs		(90,841,910	)		(47,088,610	)
	Future development costs		(81,090,570	)		(35,500,100	)
	Future abandonment costs		(676,200	)		(451,200	)
	Future income tax expenses		(67,758,412	)		(37,198,036	)

	Future net cash flow		101,637,618			55,797,054
	10% annual discount for estimated timing of cash flows		(52,246,511	)		(29,219,748	)
	Standardized measure of discounted future net cash flow	$	49,391,107		$	26,577,306
Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows	The principal changes in the standardized measure of discounted future net cash flows during 2014 and 2013 were as follows:

		2014			2013
	Extensions		-			-
	Revisions of previous estimates
	Price changes	$	(2,425,938	)	$	182,220
	Quantity Changes		155,123,408			105,407,911
	Changes in production rates, timing and other		(86,304,124	)		(54,058,997	)
	Development costs incurred		-			-
	Changes in estimated future development costs		(21,715,696	)		(17,009,887	)
	Purchase of minerals in place		-			-
	Sales of minerals in place		-			-
	Sales of oil and gas, net of production costs		(10,743,149	)		(6,481,139	)
	Accretion of discount		4,088,500			1,481,896
	Net change in income taxes		(15,209,200	)		(11,808,801	)
	Net increase/(decrease)	$	22,813,801		$	17,713,203

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Customers	Dec. 31, 2013
Deferred financing costs	$3,959,448
Note purchase agreement extended period	1 year
Deferred financing fees	100,000	200,000
Deferred financing costs, current	1,009,642	1,829,124
Amortization of deferred finance costs	919,482	1,295,348
Impairment of oil & gas properties	29,858,178
Restricted cash	896,367	908,645
Pledged for bonds and sureties	83,867	58,645
Percentage of oil and gas production sold	81.00%
Number of customers	3
Accounts receivable and allowance for doubtful accounts		0
Impairment of long-lived assets	29,858,178
Percentage amount of tax benefit	50.00%
Warrant and options to purchase share of common stock were excluded from the computation as their effect would have been anti-dilutive	7,487,559	1,696,843
Minimum [Member]
Estimated useful lives of assets	P3Y
Maximum [Member]
Estimated useful lives of assets	P15Y
Apollo Note Purchase Agreement [Member]
Restricted cash	$812,500	$850,000

Summary_of_Significant_Account

Summary of Significant Accounting Policies - Schedule of Fair Value Measurements Assets and Liability (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Commodity derivative asset	$1,116,740
Commodity derivative liability		-357,567
Carrying Amount [Member]
Commodity derivative asset	1,116,740
Commodity derivative liability		-357,567
Level 1 Inputs [Member]
Commodity derivative asset
Commodity derivative liability
Level 2 Inputs [Member]
Commodity derivative asset	1,116,740
Commodity derivative liability		-357,567
Level 3 Inputs [Member]
Commodity derivative asset
Commodity derivative liability

Organization_and_Summary_of_Si4

Organization and Summary of Significant Accounting Policies - Schedule of Assets and Liabilities Measured on Non-recurring Basis (Details) (USD $)	Dec. 31, 2014
Proved oil & gas properties, net book value	$21,014,226
Level 1 Inputs [Member]
Proved oil & gas properties, net book value
Level 2 Inputs [Member]
Proved oil & gas properties, net book value
Level 3 Inputs [Member]
Proved oil & gas properties, net book value	21,014,226
Carrying Amount [Member]
Proved oil & gas properties, net book value	$50,872,404

Summary_of_Significant_Account1

Summary of Significant Accounting Policies - Schedule of Computation of Basic and Diluted Net Income (Loss) Per Share (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Net loss allocable to continuing operations	($34,509,882)	($3,514,895)
Net income and gain allocable to discontinued operations		$7,370,201
Basic and diluted net income (loss) per share Continuing operations	($0.61)	($0.07)
Basic and diluted net income (loss) per share Discontinued operations		$0.15
Basic and diluted weighted average shares outstanding	56,480,460	49,762,499

Going_Concern_Details_Narrativ

Going Concern (Details Narrative) (USD $)	12 Months Ended
Going Concern (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Apr. 03, 2014	Apr. 27, 2012	Apr. 05, 2013
Accumulated deficit	$38,729,362	$4,219,480
Working capital deficit	36,213,063
Debt term	1 year
Proceeds from secured promissory notes	5,000,000	17,000,000
Proceeds from private placement	6,700,000
Apollo Investment Corporation [Member] \| Minimum [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt interest rate			15.00%
Apollo Investment Corporation [Member] \| Senior Secured Note Purchase Agreement [Member]
Senior secured notes	25,000,000			10,000,000
Apollo Investment Corporation [Member] \| Senior Secured Note Purchase Agreement [Member] \| Maximum [Member]
Senior secured notes			30,000,000		$20,000,000
Apollo Investment Corporation [Member] \| Senior Secured Note Purchase Agreement [Member] \| Maximum [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt interest rate			11.00%

Equity_Transactions_Details_Na

Equity Transactions (Details Narrative) (USD $)

0 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Jun. 05, 2014

Jan. 02, 2014

Aug. 01, 2012

Feb. 28, 2014

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Jun. 07, 2013

Jan. 02, 2013

Sep. 08, 2014

Apr. 10, 2014

Apr. 27, 2012

Dec. 31, 2012

Proceeds from issuance of private placement

$6,700,000

Number of common stock warrants purchase

0.4

Common stock price per share

$1.18

$1.80

Warrants price per share

$0.90

Warrant, expiration term

5 years

Percentage of placement fee in cash or warrants

8.00%

Units sold

6,744,000

Common stock, shares

58,098,014

Legal fees

10,000

Shares issued under employment agreement

550,000

150,000

Shares subscribed but unissued

50,000

Stock based compensation, shares

150,000

Shares issued during period remaining shares vested

400,000

Shares issued during period remaining shares vested, value

436,000

Shares issued pursuant to consulting agreement, shares

150,000

Stock options to two employees

600,000

Consultant exercisable price per share

$0.89

$0.96

Shares issued for services, value

376,000

Value of non qualified stock option issued

629,714

Stock option expiration date

6/4/24

Discount rate

0.85%

Expected dividends rate

0.00%

Stock based compensation, expensed period

1 year

3 years

Shares issued under employment agreement, value

177,000

Stock based compensation, expenses recognized

152,418

Warrants, exercised

200,000

Stock-based compensation expense

400,000

152,418

3,252,158

528,418

Consultants [Member]

Consultant exercisable price per share

$1.20

Shares issued for services

10,000

Shares issued for services, value

12,000

Employees [Member]

Consultant exercisable price per share

$0.91

Shares issued for services

400,000

Shares issued for services, value

364,000

Employees [Member]

Expected life in years

5 years

Expected volatility rate

220.00%

Consultant [Member]

Stock options to two employees

200,000

Value of non qualified stock option issued

173,906

Stock option expiration date

9/8/24

Discount rate

0.85%

Expected life in years

10 years

Expected volatility rate

219.00%

Expected dividends rate

0.00%

Consulting Agreement [Member]

Shares, closing prices, per share

$0.32

Shares issued pursuant to consulting agreement, shares

200,000

Consulting Agreement [Member] | Minimum [Member]

Shares issued pursuant to consulting agreement

236,000

Consulting Agreement [Member] | Maximum [Member]

Shares issued pursuant to consulting agreement

138,000

Placement Agent Fees [Member]

Common stock price per share

$0.01

Warrants issued to purchase of common stock

193,380

Placement agent fees paid in cash

338,940

Share Valuation Condition One [Member]

Shares issued during period remaining shares vested

200,000

Shares, closing prices, per share

Share Valuation Condition Two [Member]

Shares issued during period remaining shares vested

200,000

Shares, closing prices, per share

$1.18

Common Stock [Member]

Common stock, shares

7,493,339

Warrants issued to purchase of common stock

2,997,333

Shares issued for services

410,000

Shares issued for services, value

Stock based compensation, expenses recognized

Warrant [Member]

Warrants issued to purchase of common stock

100,000

Discount rate

0.81%

0.82%

0.72%

Expected life in years

3 years

5 years

Expected volatility rate

245.00%

242.00%

Expected dividends rate

0.00%

Warrants issued to purchase common stock, shares

2,000,000

Exercisable price per share

$1.04

Warrants value using Black-Scholes

$2,184,538

$1,161

$89,952

Warrants maturity date

9-Apr-17

Warrants, expected volatility rate

223.00%

Segment_and_Geographical_Infor1

Segment and Geographical Information (Details Narrative)	12 Months Ended
	Dec. 31, 2014
	Region
	Segment
Segments, Geographical Areas [Abstract]
Number of segment	1
Number of geographic region	1

Oil_and_Gas_Properties_Details

Oil and Gas Properties (Details Narrative) (USD $)	1 Months Ended	12 Months Ended		0 Months Ended
	Jul. 31, 2011	Dec. 31, 2014	Dec. 31, 2013	Apr. 21, 2011
	Jul. 31, 2011	acre	Dec. 31, 2013	Apr. 21, 2011
Impairment of oil & gas properties		$29,858,178
Net acres of leased land		18,008
Gross acres of leased land		53,930
Purchase of oil prospects	8,500	22,961,429	24,733,217
Percentage of leases acquired	12.50%
Lease bonus paid	200,000
Percentage of the cost of wells				7.50%
Others [Member]
Net acres of leased land		5,032
Gross acres of leased land		31,772
Parent Company [Member]
Net acres of leased land		4,675
Gross acres of leased land		6,967
Pawnee [Member]
Net acres of leased land		3,934
Gross acres of leased land		5,085
Coal [Member]
Net acres of leased land		4,367
Gross acres of leased land		10,106
Oklahoma County [Member]
Net acres of leased land		18,008
Gross acres of leased land		53,930
Slawson Exploration Company [Member]
Percentage of leases acquired				45.00%
Percentage of interest payments				45.00%
USE [Member]
Percentage of leases acquired				30.00%
Percentage of interest payments				30.00%
Nemaha Ridge Logan County [Member]
Gross acres of leased land				10,000
Purchase of oil prospects				4,875,000
First Three Horizontal Mississippian Wells [Member]
Percentage of the cost of wells				17.50%
After First Three Horizontal Mississippian Wells [Member]
Percentage of the cost of wells				25.00%
Osage [Member]
Percentage of interest payments				25.00%
Oil and Gas Properties [Member]
Depreciation and depletion expense		$6,690,066	$2,308,064

Oil_and_Gas_Properties_Schedul

Oil and Gas Properties - Schedule of Oil and Gas Properties (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Jul. 31, 2011
Oil and Gas Property [Abstract]
Properties subject to amortization	$60,168,713	$25,551,336
Properties not subject to amortization	1,942,045	1,784,465
Capitalized asset retirement costs	5,158	3,659
Accumulated depreciation and depletion	-39,154,487	-2,606,243
Oil & Gas Properties, Net	$22,961,429	$24,733,217	$8,500

Oil_and_Gas_Properties_Schedul1

Oil and Gas Properties - Schedule of Area of Land Leased (Details)	Dec. 31, 2014
	acre
Gross acres of leased land	53,930
Net acres of leased land	18,008
Logan (Non Operated) [Member]
Gross acres of leased land	31,772
Net acres of leased land	5,032
Logan - Osage [Member]
Gross acres of leased land	6,967
Net acres of leased land	4,675
Coal [Member]
Gross acres of leased land	10,106
Net acres of leased land	4,367
Pawnee [Member]
Gross acres of leased land	5,085
Net acres of leased land	3,934

Debt_Details_Narrative

Debt (Details Narrative) (USD $)	0 Months Ended	1 Months Ended	9 Months Ended	12 Months Ended		0 Months Ended					1 Months Ended	0 Months Ended	3 Months Ended
Debt (Details Narrative) (USD $)	Jun. 05, 2014	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Apr. 03, 2014	Apr. 03, 2014	Apr. 10, 2014	Apr. 27, 2012	Apr. 27, 2012	Dec. 31, 2012	Apr. 17, 2012	Dec. 31, 2014	Dec. 31, 2013	Apr. 05, 2013
Discount rate	0.85%
Expected dividends rate	0.00%
Minimum amount draw through purchase of notes				$5,000,000									$5,000,000
Legal fees on notes									170,692	170,692
Additional placement fees		100,000
Payment made for agreement fee				100,000
Percentage of common stock equivalent to additional warrants				3.00%
Amount of drew down in additional funds			5,000,000
Note purchase agreemnt outstanding amount				25,000,000									25,000,000
Deferred financing costs		1,829,124		1,009,642	1,829,124								1,009,642	1,829,124
Liability to pay administrative fees				50,000									50,000
Percentage of upfront fee				2.00%									2.00%
Interest expense				4,468,568	4,566,246
Logan County Range Three [Member]
Percentage of overriding royalty												1.50%
Logan County Range Four [Member]
Percentage of overriding royalty												1.71%
Minimum [Member]
Percentage of LIBOR plus interest rate						15.00%
Maximum [Member]
Percentage of LIBOR plus interest rate							11.00%
Warrant [Member]
Warrants issued to purchase of common stock											100,000
Warrants exercise price											$0.00
Warrants value using Black-Scholes								2,184,538	1,161	1,161	89,952
Warrants maturity date								9-Apr-17
Terms of warrants granted									Two to five years
Discount rate								0.81%		0.82%	0.72%
Expected life in years								3 years		5 years	5 years
Expected volatility rate										245.00%	242.00%
Expected dividends rate								0.00%		0.00%	0.00%
Additional placement fees											380,000
Warrants expiration term											5 years
Apollo Investment Corporation [Member]
Notes maturity date										27-Apr-15
Percentage of LIBOR plus interest rate										15.00%
Percentage of LIBOR floor interest rate										2.00%
Warrants issued to purchase of common stock										1,496,843
Warrants maturity date										27-Apr-17
Note purchase agreemnt outstanding amount						30,000,000	30,000,000								20,000,000
Line of credit facility, interest rate description				reducing the interest rate from Libor plus 15% to Libor plus 11%
Apollo Investment Corporation [Member] \| Senior Secured Note Purchase Agreement [Member]
Senior secured notes									10,000,000	10,000,000
Warrants exercise price									$0.01	$0.01
Warrants value using Black-Scholes									2,483,952	2,483,952
Minimum amount draw through purchase of notes		17,000,000		1,000,000	17,000,000								1,000,000	17,000,000
Legal fees on notes				100,000									100,000
Note purchase agreemnt outstanding amount		20,000,000			20,000,000									20,000,000
Secured promissory note				25,000,000					10,000,000	10,000,000			25,000,000
Apollo Investment Corporation [Member] \| Senior Secured Note Purchase Agreement [Member] \| Maximum [Member]
Secured promissory note						30,000,000	30,000,000								20,000,000
CC Natural Resource Partners, LLC [Member]
Note purchase agreement minimum placement fee									100,000	100,000
Warrants issued to purchase of common stock										250,000
Warrants exercise price									$0.01	$0.01
Warrants value using Black-Scholes									413,690	413,690
Warrants maturity date										27-Apr-14
Additional placement fees										100,000
CC Natural Resource Partners, LLC [Member] \| Warrant [Member]
Discount rate				0.26%
Expected life in years				2 years
Expected volatility rate				242.00%
Expected dividends rate				0.00%
Boothbay Royalty Co [Member]
Notes maturity date												17-Apr-14
Secured promissory note												2,500,000
Secured promissory note, interest rate												18.00%
Shares issued for secured promissory note												400,000
Debt discount												386,545
Common stock closing price												$1.14
Percentage of overriding royalty interest												5.00%
Boothbay Royalty Co [Member] \| Note Purchase Agreement [Member]
Interest expense													4,468,568
Cash interest expense on secured promissory note													3,549,086
Boothbay Royalty Co [Member] \| Note Purchase Agreement and Secured Promissory Note [Member]
Interest expense														4,566,246
Cash interest expense on secured promissory note														$2,999,838

Derivative_Financial_Instrumen2

Derivative Financial Instruments - Schedule of Oil Open Derivative Positions (Details) (Oil [Member], Q1 - Q2, 2015 [Member])	12 Months Ended
	Dec. 31, 2014
	bbl
Oil [Member] \| Q1 - Q2, 2015 [Member]
Monthly Volume (BBLs/m)	6,000
Weighted Average Floor Price ($/BBL)	80
Weighted Average Ceiling Price ($/BBL)	93.5

Derivative_Financial_Instrumen3

Derivative Financial Instruments - Schedule of Natural Gas Open Derivative Positions (Details) (Natural Gas Member], Q1 - Q2, 2015 [Member])	12 Months Ended
	Dec. 31, 2014
	Btu
Natural Gas Member] \| Q1 - Q2, 2015 [Member]
Monthly Volume (Btu/m)	10,000
Weighted Average Floor Price ($/Btu)	3.75
Weighted Average Ceiling Price ($/BBL)	4.4

Derivative_Financial_Instrumen4

Derivative Financial Instruments - Schedule of Cash Settlements and Unrealized Gains (Losses) on Fair Value Changes for Commodity Derivatives (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash settlements to (by) Company	($220,317)	($138,236)
Unrealized gains (losses) on commodity derivatives	1,474,307	-357,567
Gain (loss) on oil and gas derivatives	$1,253,990	($495,803)

Commitments_and_Contingencies_1

Commitments and Contingencies (Details Narrative) (USD $)	1 Months Ended			9 Months Ended	12 Months Ended
Commitments and Contingencies (Details Narrative) (USD $)	Feb. 28, 2014	Feb. 29, 2012	Feb. 28, 2011	Sep. 30, 2013	Dec. 31, 2014	Dec. 31, 2013
Lease periods in months		24 months	36 months
Capital lease terms	3 years					3 years
Rental expense					$163,401	$58,147
Depreciation expense					21,240
Percentage of royalty received for oil produced				20.00%
Percentage of additional royalty received				50.00%
Percentage of received reimbursement of all historical costs				200.00%
Oil revenues				$729,308	$10,481,767	$7,339,943
Cimarrona LLC [Member]
Lease periods in months				36 months
Percentage of maximum exposure				50.00%

Commitments_and_Contingencies_2

Commitments and Contingencies - Schedule of Future Minimum Commitments Under Operating Leases (Details) (USD $)	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
2015	$184,810
2016	186,098
2017	29,862
Total	$400,770

Commitments_and_Contingencies_3

Commitments and Contingencies - Schedule of Leased Property Under Capital Leases (Details) (USD $)	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Furniture and equipment	$127,436
less: accumulated depreciation	-21,240
Leased property under capital leases, total	$106,196

Commitments_and_Contingencies_4

Commitments and Contingencies - Schedule of Future Minimum Lease Payments Under Capital Leases (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
2015	$46,166
2016	42,956
2017	7,158
Future minimum payments due	96,280
Less amount representing interest	-447
Present value of minimum lease payments	95,833
Current maturities	45,698
Non-current maturities	50,135
Capital lease	$95,833

Dilutive_Securities_Details_Na

Dilutive Securities (Details Narrative) (USD $)	0 Months Ended		12 Months Ended	0 Months Ended
	Jun. 05, 2014	Jun. 05, 2014	Dec. 31, 2014	Sep. 08, 2014	Jun. 30, 2007
	Employees
	Consultant
Stock option intrinsic value			$0
Weighted average date fair value of option price per share			$1
Number of employees	2
Number of consultant	1
Value of non qualified stock option issued		629,714
Expected life in years			10 years
Employees [Member]
Expected life in years		5 years
Expected volatility rate		220.00%
Consultant [Member]
Issuance of non-qualified stock options				200,000
Stock option exercisable price per share				$0.96
Value of non qualified stock option issued				173,906
Stock option expiration date				8-Sep-24
Discount rate				0.85%
Expected life in years		10 years		10 years
Expected volatility rate		219.00%		219.00%
Expected dividends rate				0.00%
Employees and Consultant [Member]
Issuance of non-qualified stock options	600,000
Stock option exercisable price per share	0.8925	$0.89
Value of non qualified stock option issued	629,714
Stock option expiration date	4-Jun-24
Discount rate	0.85%
Expected dividends rate	0.00%
Equity-Based Compensation Plan
Stock option reservation shares under the plan					5,000,000
Warrant [Member]
Intrinsic value of warrants			523,969
Intrinsic value of warrants exercised			$226,000
Average grant date fair value for warrants issued price per share			$1.03

Dilutive_Securities_Schedule_o

Dilutive Securities - Schedule of Warrants Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Shares Outstanding, Beginning Balance	1,696,843	3,171,843
Shares Granted	5,190,713
Shares Exercised	-200,000	-350,000
Shares Expired		-1,125,000
Shares Outstanding, Ending Balance	6,687,556	1,696,843
Weighted Average Exercise Price, Outstanding, Beginning	$0.01	$0.45
Weighted Average Exercise Price, Granted	$1.44
Weighted Average Exercise Price, Exercised	$0.01	$0.01
Weighted Average Exercise Price, Expired		$1.25
Weighted Average Exercise Price, Outstanding, Ending	$1.12	$0.01
Weighted Average Remaining Contractual Terms (Years), Beginning	3 years 4 months 6 days	2 years 8 months 19 days
Weighted Average Remaining Contractual Terms (Years), Ending	3 years 6 months 15 days	3 years 1 month 28 days

Dilutive_Securities_Schedule_o1

Dilutive Securities - Schedule of Stock Option Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Shares Outstanding, Beginning Balance
Shares Granted	800,000
Shares Outstanding, Ending Balance	800,000
Shares Exercisable, Balance	800,000
Weighted Average Exercise Price, Outstanding, Beginning
Weighted Average Exercise Price, Granted	$0.91
Weighted Average Exercise Price, Outstanding, Ending	$0.91
Weighted Average Exercise Price, Exercisable	$0.91
Weighted Average Remaining Contractual Terms (Years), Beginning	9 years 6 months 4 days	0 years
Weighted Average Remaining Contractual Terms (Years), Exercisable	9 years 6 months 4 days

Income_Taxes_Details_Narrative

Income Taxes (Details Narrative) (USD $)	12 Months Ended
Income Taxes (Details Narrative) (USD $)	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Operating loss carry forwards	$11,800,000
Operating loss carry forwards expiration date	2032

Income_Taxes_Schedule_of_Provi

Income Taxes - Schedule of Provision for Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal
State
Foreign
Federal	-9,933,029	646,907
State	-922,353	60,070
Foreign
Valuation Allowance	10,855,382	-706,977
Deferred income tax total
Income tax expense benefit		$1,624

Income_Taxes_Schedule_of_Feder

Income Taxes - Schedule of Federal Statutory Rate to Effective Income Tax Rate (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Computed tax provision at statutory Federal rates	35.00%	35.00%
State taxes, net of Federal income tax benefit	3.25%
Nondeductible and other expenses	-0.01%	-4.33%
Federal and State true ups	0.00%	0.00%
Other adjustments	-6.78%	-15.52%
Valuation Allowance	-31.46%	-18.40%
Net deferred tax liability	0.00%	0.00%

Income_Taxes_Schedule_of_Defer

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Net operating loss carry forward	$4,528,527	$3,807,000
Oil and gas properties	25,630,977
Stock based compensation	1,653,650
Other	242,141	879,000
Oil and gas properties	-20,201,526	-4,501,000
Deferred financing costs	-813,341
Valuation allowance	-11,040,428	-185,000
Net deferred tax liability	$0	$0

Major_Customers_and_Vendors_De

Major Customers and Vendors (Details Narrative) (USD $)	12 Months Ended
Major Customers and Vendors (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Purchased products or services	$1,935,367	$1,547,949
Total purchases percentage	100.00%	100.00%
Weatherford US, LP [Member]
Purchased products or services	9,667,450
Total purchases percentage	17.50%
Nabors Drilling, LP [Member]
Purchased products or services	$6,105,859
Total purchases percentage	11.10%
Purchases Net [Member] \| Maximum [Member]
Total purchases percentage		10.00%

Major_Customers_and_Vendors_Sc

Major Customers and Vendors - Schedule of Major Customers Accounting for All of its Sale (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Revenue from major customers	$12,678,516	$8,029,088
Percentage of revenue from major customers	100.00%	100.00%
Slawson Exploration Company [Member]
Revenue from major customers	4,117,056	6,421,674
Percentage of revenue from major customers	32.50%	80.00%
Phillips 66 [Member]
Revenue from major customers	3,954,306
Percentage of revenue from major customers	31.20%	0.00%
Stephens [Member]
Revenue from major customers	2,192,007	847,573
Percentage of revenue from major customers	17.30%	10.60%
Devon [Member]
Revenue from major customers	1,742,848	738,178
Percentage of revenue from major customers	13.70%	9.20%
Energy Financial [Member]
Revenue from major customers	375,140
Percentage of revenue from major customers	3.00%	0.00%
Others [Member]
Revenue from major customers	$297,159	$21,663
Percentage of revenue from major customers	2.30%	0.30%

Liability_for_Asset_Retirement2

Liability for Asset Retirement Obligations (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Legally restricted assets for settlement of AROs	$0
Asset retirement obligation, income tax	$0	$0

Liability_for_Asset_Retirement3

Liability for Asset Retirement Obligations - Schedule of Reconciliation of Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$3,886	$19
Incurred during the period
Reversed during the period
Additions for new wells	1,500	3,639
Accretion expense	895	228
Ending balance	$6,281	$3,886

Discontinued_Operations_Detail

Discontinued Operations (Details Narrative) (USD $)	12 Months Ended		9 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Oct. 07, 2013
	Dec. 31, 2014	Dec. 31, 2013	acre	Oct. 07, 2013
Cash		$422,955
Payment of disposal of transportation cost		1,000,000
Recognized benefit of discontinued operation		4,873,660
Revenues	12,678,516	8,029,088
Cimarrona LLC [Member]
Percentage of sale membership interest			9.40%	100.00%
Area of land of oil and gas assets			30,665
Cash	6,550,000
Liability payable to disposal group	250,000
Payment of sales price held in escrow	250,000
Percentage of maximum exposure			50.00%
Revenues			$729,308
Ecopetrol S.A [Member]
Percentage of royalties received for oil produced	20.00%
Percentage of partnership	50.00%
Percentage of reimbursements of historical costs	200.00%

Discontinued_Operations_Summar

Discontinued Operations - Summary of Discontinued Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]
Oil revenues		$1,458,616
Pipeline revenues		1,828,256
Total revenues		3,286,872
Operating expenses		1,007,987
Depreciation, depletion and accretion		124,193
Equity tax		-435,988
General and administrative		72,756
Total operating costs and expenses		768,948
Operating income		2,517,924
Interest income		103
Interest expense		-21,486
Income before income taxes		2,496,541
Provision for income taxes
Net income		$2,496,541

Supplemental_Information_About1

Supplemental Information About Oil and Gas Producing Activities (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Wells	Wells	Wells
Depletion, depreciation and accretion per equivalent unit of production	31.56	22
Number of gross development drilling wells	58
Number of drilling wells achieved Production and revenue	54
Number of gross dry development drilling well	2
Number of completed gross salt water disposal wells	6
Percentage of annual net cash flows	10.00%
Oil [Member]
Weighted average prices reserve estimate	94.99
Sales price	4.35
Gas [Member]
Weighted average prices reserve estimate		96.94
Sales price		3.67
Gross Productive Development Wells [Member]
Net drilling wells	2.7	6.1	1.1
Number of gross productive development well	14	35	5
Gross Dry Development Wells [Member]
Number of gross dry development drilling well	2
Net drilling wells	1.8
Gross Development Wells [Member]
Net drilling wells		0.3	0.6
Number of gross well		2	3
Greg Franklin [Member]
Number of years experience in oil and gas		25 years

Recovered_Sheet2

Supplemental Information about Oil and Gas Producing Activities - Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Jul. 31, 2011
Extractive Industries [Abstract]
Proved properties	$60,168,713	$25,551,336
Unproved properties being amortized
Unproved properties not being amortized	-1,942,045	-1,784,465
Capitalized asset retirement costs	5,158	3,659
Accumulated depletion, depreciation, amortization and impairment	-39,154,487	-2,606,243
Oil & Gas Properties, Net	$22,961,429	$24,733,217	$8,500

Supplemental_Information_about2

Supplemental Information about Oil and Gas Producing Activities - Schedule of Estimated Quantities of Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	bbl	bbl
Oil [Member]
Proved developed and undeveloped reserves, Beginning of year	1,508,000	364,000
Revisions of previous estimates
Improved recovery
Purchases of minerals in place
Extensions and discoveries	1,579,278	1,220,409
Production	-124,278	-76,409
Sales of minerals in place
End of year	2,963,000	1,508,000
Proved developed reserves, Beginning of year	460,000	195,000
Proved developed reserves, End of year	678,000	460,000
Proved undeveloped reserves, Beginning of year	1,048,000	169,000
Proved undeveloped reserves, End of year	2,285,000	1,048,000
Gas [Member]
Proved developed and undeveloped reserves, Beginning of year	6,365	1,499
Revisions of previous estimates
Improved recovery
Purchases of minerals in place
Extensions and discoveries	3,028	5,016
Production	-367	-150
Sales of minerals in place
End of year	9,026	6,365
Proved developed reserves, Beginning of year	2,005	803
Proved developed reserves, End of year	2,485	2,005
Proved undeveloped reserves, Beginning of year	4,360	696
Proved undeveloped reserves, End of year	6,541	4,360
Natural Gas Liquids [Member]
Proved developed and undeveloped reserves, Beginning of year	43,000
Revisions of previous estimates
Improved recovery
Purchases of minerals in place
Extensions and discoveries	1,488,756	46,507
Production	-27,756	-3,507
Sales of minerals in place
End of year	1,504,000	43,000
Proved developed reserves, Beginning of year	33,000
Proved developed reserves, End of year	414,000	33,000
Proved undeveloped reserves, Beginning of year	10,000
Proved undeveloped reserves, End of year	1,090,000	10,000

Supplemental_Information_about3

Supplemental Information about Oil and Gas Producing Activities - Costs Incurred, Both Capitalized and Expensed, Oil and Gas Property Acquisition, Exploration and Development (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Property acquisition costs	$1,506,755	$1,278,408
Exploration costs
Development costs	35,698,314	16,613,524
Asset retirement costs

Supplemental_Information_about4

Supplemental Information about Oil and Gas Producing Activities - Standardized Measure of Discounted Estimated Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash inflows	$342,004,710	$176,035,000
Future production costs	-90,841,910	-47,088,610
Future development costs	-81,090,570	-35,500,100
Future abandonment costs	-676,200	-451,200
Future income tax expenses	-67,758,412	-37,198,036
Future net cash flow	101,637,618	55,797,054
10% annual discount for estimated timing of cash flows	-52,246,511	-29,219,748
Standardized measure of discounted future net cash flow	$49,391,107	$26,577,306
Percentage of annual discount for estimated timing of cash flows	$0.10	$0.10

Supplemental_Information_about5

Supplemental Information about Oil and Gas Producing Activities - Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Extensions
Revisions of previous estimates, Price changes	-2,425,938	182,200
Revisions of previous estimates, Quantity changes	155,123,408	105,407,911
Changes in production rates, timing and other	-86,304,124	-54,058,997
Development costs incurred
Changes in estimated future development costs	-21,715,696	-17,009,887
Purchase of minerals in place
Sales of minerals in place
Sales of oil and gas, net of production costs	-10,743,149	-6,481,139
Accretion of discount	4,088,500	1,481,896
Net change in income taxes	-15,209,200	-11,808,801
Net increase/ (decrease)	$22,813,801	$17,713,203