Osage Exploration & Development (OSGE) 10-K 31 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 27, 2014	Jun. 30, 2013
Document And Entity Information	'	'	'
Entity Registrant Name	'OSAGE EXPLORATION & DEVELOPMENT INC	'	'
Entity Central Index Key	'0001405686	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filer	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Public Float	'	'	$32,413,158
Entity Common Stock, Shares Outstanding	'	57,591,342	'
Document Fiscal Period Focus	'FY	'	'
Document Fiscal Year Focus	'2013	'	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current Assets:	'	'
Cash and equivalents	$2,782,643	$486,205
Accounts receivable	2,769,414	371,544
Short term assets held for sale	'	114,568
Prepaid expenses and other current assets	596,742	83,090
Deferred financing costs	1,829,124	2,924,472
Total current assets	7,977,923	3,979,879
Property and equipment, at cost:	'	'
Oil and gas properties and equipment (successful efforts method)	27,339,460	9,503,172
Other property & equipment	85,746	85,746
Total property and equipment, gross	27,425,206	9,588,918
Less: accumulated depletion, depreciation and amortization	-2,683,085	-289,490
Total property and equipment, net	24,742,121	9,299,428
Restricted cash	908,645	157,467
Long term assets held for sale	'	1,289,273
Note receivable	'	6,000
Total assets	33,628,689	14,732,047
Current liabilities:	'	'
Accounts payable	555,784	218,190
Income taxes payable	56,469	58,093
Accrued expenses	61,331	22,152
Unrealized losses on oil and gas derivatives	265,961	'
Short term liabilities held for sale	'	1,325,287
Notes payable, current portion	20,000,000	3,000,000
Total current liabilities	20,939,545	4,623,722
Notes payable, net of current portion and net of $271,060 debt discount as of December 31, 2012	'	2,228,940
Unrealized losses on oil and gas derivatives, net of current portion	91,606	'
Liability for asset retirement obligations	3,886	19
Total liabilities	21,035,037	6,852,681
Commitments and contingencies	'	'
Stockholders' Equity:	'	'
Preferred stock, $0.0001 par value, 10,000,000 shares authorized, none issued and outstanding as of December 31, 2013 or December 31, 2012	'	'
Common stock, $0.0001 par value, 190,000,000 shares authorized; 49,854,675 and 49,094,675 shares issued and outstanding as of December 31, 2013 and December 31, 2012, respectively	4,985	4,909
Additional paid-in capital	16,903,147	16,371,305
Stock purchase notes receivable	-95,000	-95,000
Accumulated deficit	-4,219,480	-8,074,786
Accumulated other comprehensive loss - currency translation loss	'	-327,062
Total stockholders' equity	12,593,652	7,879,366
Total liabilities and stockholders' equity	$33,628,689	$14,732,047

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]	'	'
Notes payable, debt discount noncurrent	'	$271,060
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, shares authorized	$0.00	$0.00
Common stock, shares authorized	190,000,000	190,000,000
Common stock, shares issued	49,854,675	49,094,675
Common stock, shares outstanding	49,854,675	49,094,675

Consolidated_Statements_of_Ope

Consolidated Statements of Operations and Other Comprehensive Income (Loss) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Operating revenues	'	'
Oil revenues	$7,339,943	$2,030,596
Natural gas revenues	689,145	233,417
Total operating revenues	8,029,088	2,264,013
Operating costs and expenses	'	'
Operating costs	1,547,949	258,686
General and administrative expenses	2,613,920	2,661,922
Depreciation, depletion and accretion	2,320,441	314,540
Loss on disposal of fixed assets	'	21,599
Total operating costs and expenses	6,482,310	3,256,747
Operating income (loss)	1,546,778	-992,734
Other income (expenses):	'	'
Interest income	2,000	2,878
Interest expense	-4,566,246	-1,390,277
Loss on oil and gas derivatives	-495,803	'
Loss from continuing operations before income taxes	-3,513,271	-2,380,133
Provision for income taxes	1,624	'
Loss from continuing operations	-3,514,895	-2,380,133
Discontinued operations:	'	'
Income from discontinued operations net of income taxes	2,496,541	1,863,427
Gain on sale disposal of discontinued operations	4,873,660	'
Net income (loss)	3,855,306	-516,706
Other comprehensive income (loss), net of tax:	'	'
Foreign currency translation adjustment attributable to discontinued operations	24,153	-21,460
Comprehensive income (loss)	$3,879,459	($538,166)
Basic and diluted income (loss) per share	'	'
Continuing operations	($0.07)	($0.05)
Discontinued operations	$0.15	$0.04
Weighted average number of common share and common share equivalents used to compute basic and diluted income (loss) per share	49,762,499	48,385,866

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (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, 2011	$4,788	$12,107,920	($95,000)	($7,558,080)	($305,602)	$4,154,026
Balance, shares at Dec. 31, 2011	47,884,775	'	'	'	'	'
Issuance of Shares for Professional Services	61	438,922	'	'	'	448,583
Issuance of Shares for Professional Services, shares	610,000	'	'	'	'	'
Issuance of warrants for professional services	'	448,111	'	'	'	448,111
Cancellation of Shares, shares	-100	'	'	'	'	'
Issuance of Shares for Debt Discount	40	385,616	'	'	'	385,656
Issuance of Shares for Debt Discount, shares	400,000	'	'	'	'	'
Issuance of Warrants as Deferred Financing Costs	'	2,988,756	'	'	'	2,988,756
Exercise of Warrants	20	1,980	'	'	'	2,000
Exercise of Warrants, shares	200,000	'	'	'	'	'
Net income loss	'	'	'	-516,706	'	-516,706
Foreign Exchange Translation Adjustment	'	'	'	'	-21,460	-21,460
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	'	'	'	'	49,094,675
Issuance of Shares for Professional Services	41	375,959	'	'	'	528,418
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	'	'	'	'	49,854,675

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:	'	'
Net income (loss)	$3,855,306	($516,706)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'
Shares issued for services	528,418	448,583
Warrants issued for services	'	448,111
Amortization of deferred financing costs	1,295,348	734,976
Amortization of debt discount	271,060	114,596
(Gain) loss on sale of oil & gas properties	-4,873,660	21,599
Write off of expired mineral rights leases	44,717	'
Accretion of asset retirement obligation	228	'
Provision for depletion, depreciation and amortization	2,320,213	568,777
Unrealised loss on oil and gas derivatives	357,567	'
Changes in operating assets and liabilities:	'	'
(Increase) in accounts receivable	-2,660,855	-363,548
(Increase) in prepaid expenses and other current assets	-121,689	-34,732
(Decrease) in income tax payable	-1,624	-800
Increase (decrease) in accounts payable	332,782	-86,722
(Decrease) in asset retirement obligations	'	-59,950
(Decrease) increase in accrued expenses	-1,267,320	687,887
Net cash provided by operating activities	80,491	1,962,071
Cash flows from investing activities:	'	'
Investments in oil & gas properties	-17,891,932	-12,781,375
Investments in non-oil & gas properties	'	-5,804
Net proceeds from assignment of leases	14,568	4,686,610
(Increase) in restricted cash	-751,178	-127,467
Net proceeds from sale of oil & gas properties	6,295,193	125,000
Cash included in sale of oil & gas properties	-38,039	'
Proceeds from notes receivable	6,000	5,000
Net cash (used) by investing activities	-12,365,388	-8,098,036
Cash flows from financing activities:	'	'
Proceeds from notes payable	17,000,000	5,500,000
Proceeds from term loan	367,520	'
Principal payments on notes payable	-2,500,000	'
Principal payments on term loan	-118,205	'
Payment of deferred financing costs	-200,000	-670,692
Proceeds from exercise of warrants	3,500	2,000
Net cash provided by financing activities	14,552,815	4,831,308
Effect of exchange rate on cash and equivalents	28,520	-113,161
Net increase (decrease) in cash and equivalents	2,296,438	-1,417,818
Cash and equivalents - beginning of period	486,205	1,904,023
Cash and equivalents - end of period	2,782,643	486,205
SUPPLEMENTAL CASH FLOW INFORMATION:	'	'
Cash payment for interest	2,999,838	538,889
Cash payment for income taxes	1,624	800
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:	'	'
Warrants issued as deferred financing costs in connection with Note Purchase Agreement	'	2,988,756
Shares issued as debt discount in connection with Secured Promissory Note	'	385,656
Increase in asset retirement obligation	$3,639	$19

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

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 2013 or 2012.

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 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 $3,859,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis.

During the years ended December 31, 2013 and 2012, respectively, the Company made payments of $200,000 and $670,692 for deferred financing fees in connection with the Note Purchase Agreement.

Deferred financing costs at December 31, 2013 and 2012 were $1,829,124 and $2,924,472, respectively. Amortization of deferred financing costs was $1,295,348 for the year ended December 31, 2013 and $734,976 for the year ended December 31, 2012.

FAIR VALUE OF FINANCIAL INSTRUMENTS

As of December 31, 2013 and December 31, 2012, 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 us 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, 2013 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheet.

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

Total

Fair Value Measurements Using

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

Inputs

Inputs

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.

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 2013 and 2012. 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 four customers in 2013 and three customers in 2012. (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 $850,000, representing three months interest, as restricted cash as of December 31, 2013. In connection with the Boothbay Secured Promissory Note (see Note 6) the Company was required to deposit certain royalty interests of Boothbay’s into joint accounts held by the Company for the benefit of Boothbay. The royalty interests at December 31, 2012 were $102,467 and there were no royalty interests at December 31, 2013 as the Secured Promissory Note had been repaid in full. The Company has also pledged $58,645 for certain bonds and sureties. Restricted cash at December 31, 2013 was $908,645, compared to $157,467 at December 31, 2012.

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

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

During the year ended December 31, 2013, the Company sold 80% of its oil and gas production to one customer, Slawson Exploration Company (“Slawson”). 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, 2013 and 2012. 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 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, 2013 and 2012, the Company’s oil production from continuing operations are conducted in the United States of America. The cost of undeveloped properties not being amortized, to the extent there is such a cost, is assessed quarterly based on the estimated economic chance of success and the length of time that the Company expects to hold the properties 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, 2013 and 2012.

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 statement 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. In that event, a loss is recognized based on the amount by which the carrying amount exceeds the fair market value of the long-lived assets. Loss on long-lived assets to be disposed of is determined in a similar manner, except that fair market values are reduced for the cost of disposal. During the years ended December 31, 2013 and 2012, the Company did not record impairment charges related to its long-lived assets.

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, 2013 or 2012, 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. 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, 2013 and 2012:

Year Ended December 31,

2013

2012

Net loss allocable to continuing operations

$

(3,514,895

)

$

(2,380,133

)

Net income and gain allocable to discontinued operations

$

7,370,201

$

1,863,427

Basic and diluted net income (loss) per share

Continuing operations

$

(0.07

)

$

(0.05

)

Discontinued operations

$

0.15

$

0.04

Basic and diluted weighted average shares outstanding

49,762,499

48,385,866

Warrants to purchase 1,696,843 and 3,071,843 shares of common stock at December 31, 2013 and December 31, 2012, respectively, were excluded from the computation as their effect would have been anti-dilutive.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The Company does not expect the adoption of any recently issued accounting pronouncements to have a material effect on the consolidated financial statements.

Going_Concern

Going Concern	12 Months Ended
	Dec. 31, 2013
Going Concern	'
Going Concern	'
	2. GOING CONCERN
	The Company has an accumulated deficit of $4,219,480 and a working capital deficit of $12,961,622 as of December 31, 2013. As of December 31, 2013, as a result of production delays outside of the Company’s control, 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 and on April 5, 2013 we amended this agreement, increasing the facility to $20,000,000.
	In early 2014, the Company raised approximately $6.5 million of gross proceeds in a private placement. (See Note 14 - Subsequent Events)
	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, and (d) 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. 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 unaudited consolidated financial statements.

Equity_Transactions

Equity Transactions	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Equity Transations	'
	3. EQUITY TRANSACTIONS
	Common Stock
	On June 7, 2013, we issued a total of 10,000 shares which vest 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 January 27, 2012, the Company issued 90,000 shares of common stock at $41,400 or $0.46 per share, to a consultant as compensation for services rendered March through August 2012.
	On April 16, 2012, the Company issued 20,000 shares of common stock at $23,000 or $1.15 per share, to a consultant as compensation for services rendered.
	On April 17, 2012, in connection with the Secured Promissory Note, we issued to Boothbay 400,000 shares of common stock at $385,656, the relative fair value (see Note 6 – Debt).
	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 will be expensed over the three years of the employment agreement. We recognized $24,582 of expenses as of December 31, 2012. Pursuant to an amendment to this agreement, the 150,000 shares were issued and immediately vested in early January 2012, and accordingly we recognized the remaining stock-based compensation expense of $152,418 in the year ended December 31, 2013.
	On November 27, 2012, the Company issued 500,000 shares of common stock at $350,000 or $0.70 per share, to a consultant as compensation for services rendered.
	Warrants
	On April 16, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $229,056 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation include (1) discount rate of 0.27%, (2) expected life of 2 years, (3) expected volatility of 244.0% and (4) zero expected dividends. On August 24, 2012, the consultant exercised the warrant and purchased the 200,000 shares of common stock for $2,000.
	On April 20, 2012, we issued a warrant to purchase 200,000 shares of common stock, exercisable at $0.01 per share, with a Black-Scholes value of $219,055 and a term of 2 years, to a consultant as compensation for services rendered. Variables used in the valuation include (1) discount rate of 0.29%, (2) expected life of 2 years, (3) expected volatility of 243.0% and (4) zero expected dividends.
	On April 27, 2012, in connection with the Note Purchase Agreement, we issued a warrant to the investor 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 a term of 5 years. 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. At closing of the Note Purchase Agreement, we issued a warrant to the placement agent to purchase 250,000 shares of common stock, $0.0001 par value, exercisable at $0.01 per share, with a Black-Scholes value of $413,690 and a term of 2 years. 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. (see Note 6 – Debt).
	On December 27, 2012, we 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 5 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 5 years, (3) expected volatility of 242.0% and (4) zero expected dividends.
	Equity Compensation Plans
	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. No securities have yet been issued under this plan since inception.

Segment_and_Geographical_Infor

Segment and Geographical Information	12 Months Ended
	Dec. 31, 2013
Segments, Geographical Areas [Abstract]	'
Segment and Geographical Information	'
	4. SEGMENT AND GEOGRAPHICAL INFORMATION
	At December 31, 2013, the Company’s continuing operations comprised one segment in one geographic region.

Oil_and_Gas_Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012:
		December 31 2013			31-Dec-12
	Properties subject to amortization	$	25,551,336		$	8,140,918
	Properties not subject to amortization		1,784,465			1,362,235
	Capitalized asset retirement costs		3,659			19
	Accumulated depreciation and depletion		(2,606,243	)		(310,097	)
	Oil & gas properties, net	$	24,733,217		$	9,193,075
	Depreciation and depletion expense for oil and gas properties totaled $2,308,064 and $298,179 in 2013 and 2012, respectively.
	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 is responsible for up to 25% of the total well costs. Revenue from wells drilled pursuant to the Participation Agreement, after royalty payments, is 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 does 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”) which amended the Participation 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, Slawson 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 Slawson, 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.
	As a result of the Partition Agreement, Osage has become the project operator on a majority of its acreage in the Nemaha Ridge Project. As of December 31, 2013, Osage operated approximately 5,014 net acres (9,734 gross) in thirty sections, and remains joint-venture partners with the Slawson in approximately 4,181 net acres (26,823 gross) across forty-five sections.
	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, 2013, the Company had 4,190 net acres (5,085 gross) leased in Pawnee County. As of December 31, 2013, none of these leases have been assigned to B&W.
	In 2011, we also began to acquire leases in Coal County, Oklahoma, targeting the Oily Woodford Shale formation. The Oily Wood ford Shale formation is located mainly in southeastern Oklahoma in the Arkoma Basin. The Oily 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, 2013, we had 4,253 net (9,509 gross) acres leased in Coal County.
	At December 31, 2013, we have leased 51,151 gross (17,638 net) acres across three counties in Oklahoma as follows:
		Gross			Osage Net
	Logan (non operated)		26,823			4,181
	Logan		9,734			5,014
	Coal		9,509			4,253
	Pawnee		5,085			4,190
			51,151			17,638

Debt

Debt	12 Months Ended
	Dec. 31, 2013
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.
	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.
	During 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.
	The Company has recorded deferred financing costs in the aggregate amount of $3,859,448 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 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 also obligated to pay a quarterly standby fee, which accrues at a rate of 3.0%, on the amount of undrawn funds equal to the difference between $5,000,000 and the aggregate principal amount of notes issued on or after the closing date. 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. Financial covenants include the following:
			Minimum
		Interest	Production	Asset Coverage
	Each Quarter Ending:	Coverage Ratio	(MBbls)	Ratio
	31-Mar-14	2.50 to 1.00	70	1.75 to 1.00
	30-Jun-14	3.00 to 1.00	80	2.00 to 1.00
	30-Sep-14	3.00 to 1.00	90	2.00 to 1.00
	December 31, 2014, and thereafter	3.00 to 1.00	100	2.00 to 1.00
	As of December 31, 2013, as a result of production delays outside of the Company’s control, the Company was not in compliance with certain covenants including the minimum production covenant. The Company believes Apollo will provide a waiver of these covenants as of that date. The Company has classified amounts outstanding under the Note Purchase Agreement as short term in the accompanying consolidated financial statements.
	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.
	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 of common stock 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, 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. Non-cash interest expense related to the Note Purchase Agreement and the Secured Promissory Note represented $1,295,348 and $271,060 for the year ended December 31, 2013. The Company recognized $1,288,841 of interest expense, of which $538,889 was cash interest expense, for the year ended December 31, 2012. Non-cash interest expense related to the Note Purchase Agreement and the Secured Promissory Note represented $734,976 and $114,596 for the year ended December 31, 2012.

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2013
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 in the year ended December 31, 2013. Prior thereto, the Company had not entered into any derivative financial instruments. 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, 2013, 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		Weighted Average
		Volume			Floor Price		Ceiling Price
	Period		(BBLs/m)			($/BBL)		($/BBL)
	Q1 - Q4, 2014		6,000		$	85	$	95
	Q1 - Q2, 2015		6,000		$	80	$	93.5
	As of December 31, 2013, 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		Weighted Average
		Volume			Floor Price		Ceiling Price
	Period	(Btu/m)			($/Btu)		($/Btu)
	Q1 - Q4, 2014		10,000		$	3.75	$	4.4
	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 “Loss on oil and gas derivatives” caption in the accompanying consolidated statements of operations.
	The following table sets forth the cash settlements and unrealized gains and losses on fair value changes for commodity derivatives for the year ended December 31, 2013.
		Year Ended
		31-Dec-13
	Cash settlements to (by) Company	$	(138,236	)
	Unrealized gains (losses) on commodity derivatives		(357,567	)
	Loss on oil and gas derivatives	$	(495,803	)
	On October 15, 2013, the Company entered into an Intercreditor Agreement with Apollo and BP Energy Company to provide collateral for its oil and gas derivative financial instruments. BP Energy Corporation North America simultaneously provided a Guarantee for $25 million as collateral for its obligations to the Company.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
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, 2013, 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.
	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.
	Rental expense totaled $58,147 and $57,344 in 2013 and 2012, respectively.
	Future minimum commitments under operating leases are as follows as of December 31, 2013:
	Year	Amount
	2014	$	157,787
	2015		170,530
	2016		171,818
	2017		28,672
		$	528,807
	LEGAL PROCEEDINGS
	The Company is not a party to any litigation that has arisen in the normal course of its business or that of its subsidiaries.
	Division de Impuestos y Actuanas Nacionales (“DIAN”), the Colombian tax authorities, levies a tax based on the equity value of Cimarrona. In 2010, the Company was notified by DIAN that it owed $883,742 in equity taxes relating to the 2001 and 2003 equity tax years. To compute the value the equity tax is assessed upon, Cimarrona subtracted the cost of its non-producing wells in 2001 and 2003. However, DIAN’s position is that as long as the field is productive, Cimarrona should not have subtracted the cost of the non-producing wells. In May 2011, we settled in full the 2001 equity liability with DIAN. In January 2012, we were informed by DIAN that we had lost our appeal on the 2003 tax issue and we increased the amount attributable to the 2003 tax year by $322,288 as of December 31, 2011 to correspond to the amount DIAN indicated we owed for the 2003 tax year. In January 2013, we successfully concluded negotiations with DIAN with respect to the ultimate liability for the 2003 tax year. DIAN waived certain interest and penalties. We paid the agreed final liability to DIAN in January 2013, and financed the payment with an unsecured Colombian term loan facility in the amount of $367,521. We recognized in discontinued operations the $531,644 benefit of the amnesty in the quarter ended June 30, 2013, upon receipt of official confirmation that the liability is fully settled.
	SALE OF CIMARRONA LLC
	On October 7, 2013, the Company completed the sale of 100% of the membership interests in Cimarrona LLC to Raven Pipeline Company, LLC (“Raven”), pursuant to a Membership Interest Purchase Agreement dated September 30, 2013 (the “Agreement”) by and between the Company and Raven. 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
	Dec. 31, 2013
Equity [Abstract]	'
Dilutive Securities	'
	9. DILUTIVE SECURITIES
	As of December 31, 2013 and 2012, the Company had outstanding dilutive securities, consisting entirely of warrants. Changes in warrants outstanding are as follows:
		Shares			Weighted Average Exercise Price		Average Remaining Contractual Life
	Balance December 31, 2011		1,125,000		$	1.25	0.27 years
	Granted		2,246,843		$	0.01
	Exercised		(200,000	)	$	0.01
	Balance December 31, 2012		3,171,843		$	0.45	1.75 years
	Exercised		(350,000	)	$	0.01
	Cancelled or Expired		(1,125,000	)	$	1.25
	Balance December 31, 2013		1,696,843		$	0.01	3.35 years
	The intrinsic value of these dilutive securities as of December 31, 2013 was $1,662,906.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	10. INCOME TAXES
	The total provision for income taxes consists of the following in 2013 and 2012:
		Year Ended December 31,
		2013			2012
	Current Taxes:
	Federal	$	-		$	-
	State		-			-
	Foreign		-			-
			-			-
	Deferred Taxes:
	Federal		649,907			180,847
	State		60,070			16,793
	Foreign		-			-
	Valuation Allowance		(706,977	)		(197,640	)
			-			-
	Totals	$	-		$	-
	Following is a reconciliation of the Federal statutory rate to the effective income tax rate for 2013 and 2012:
		2013			2012
	Computed tax provision at statutory Federal rates		35	%		35.0	%
	Increase (decrease) in taxes resulting from:
	State taxes, net of Federal income tax benefit		3.25	%		3.25	%
	Nondeductible and other expenses		-4.33	%		-130.45	%
	Federal and State true ups		0	%		0	%
	Other adjustments		-15.5	%		0	%
	Valuation Allowance		-18.4	%		92.2	%
			0	%		0	%
	At December 31, 2013, the Company had federal and state net operating loss carry forwards of approximately $9.9 million which expire at various dates through 2032.
	Pursuant to Internal Revenue Code Sections 382 and 383, use of the Company’s net operating loss and credit carryforwards may be limited if a cumulative change in ownership of more than 50% occurs within a three-year period. These financial statements do not contain any adjustment relating to such potential limitations. The Company is subject to tax in the United States and in the state of California.  As of December 31, 2013, the Company’s tax years from 2010 are subject to examination by the tax authorities.  The Company is not currently under examination by any U.S. federal or state jurisdictions.
	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, 2013 and December 31, 2012:
		2013			2012
	Deferred tax liability:
	Net operating loss carry forward	$	3,807,000		$	2,772,000
	Other		879,000			5,000
	Oil and gas properties		(4,501,000	)		(1,837,000	)
	Valuation allowance		(185,000	)		(940,000	)
	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

Major Customers	12 Months Ended
	Dec. 31, 2013
Major Customers	'
Major Customers	'
	11. MAJOR CUSTOMERS
	During 2013 and 2012, four and three customers, respectively, accounted for all of the Company’s sales from continuing operations:
		Year ended December 31, 2013					Year ended December 31, 2012
		Amount		% of Total			Amount		% of Total
	Slawson	$	6,421,674		80	%	$	2,205,088		97.4	%
	Stephens		847,573		10.6	%		-		0	%
	Devon		738,178		9.2	%		44,159		2	%
	Sundance		21,663		0.3	%		-		0	%
	Coffeyville		-		0	%		14,766		0.7	%
	Total	$	8,029,088		100	%	$	2,264,013		100	%

Liability_for_Asset_Retirement

Liability for Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012, 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,
		2013		2012
	Beginning balance	$	19	$	24,231
	Incurred during the period		-		-
	Reversed during the period		-		(24,231	)
	Additions for new wells		3,639		19
	Accretion expense		228		-
	Ending balance	$	3,886	$	19

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2013
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 $6,800,000, less settlement of debt of Cimarrona LLC of approximately $250,000. Of the net sales price, $250,000 will 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 is not adjusted prior to March 31, 2014, then Raven will 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.
	Accordingly, the assets and liabilities of the Colombian operations are classified as Held for Sale in the balance sheet as of December 31, 2012, with the exception of cash of $150,950.
	The following table sets forth the results of operations for the discontinued operations for the periods presented:
		Year Ended December 31,
		2013			2012
	Revenues
	Oil revenues	$	1,458,616		$	1,943,070
	Pipeline revenues		1,828,256			1,912,941
	Total revenues		3,286,872			3,856,011
	Operating costs and expenses
	Operating expenses		1,007,987			1,554,039
	Depreciation, depletion and accretion		124,193			254,237
	Equity tax		(435,988	)		131,186
	General and administrative		72,756			54,311
	Total operating costs and expenses		768,948			1,993,773
	Operating income		2,517,924			1,862,238
	Other income (expenses):
	Interest income		103			1,189
	Interest expense		(21,486	)		-
	Income before income taxes		2,496,541			1,863,427
	Provision for income taxes		-			-
	Net income	$	2,496,541		$	1,863,427
	The following table sets forth balance sheet information for the discontinued operations as of December 31, 2012:
		As of
		31-Dec-12
	Accounts receivable		114,568
	Short term assets held for sale		114,568
	Oil and gas properties		2,979,980
	Less accumulated depletion, depreciation and amortization		(1,690,707	)
	Long term assets held for sale		1,289,273
	Accounts payable		18,786
	Accrued expenses		1,306,501
	Short term liabilities held for sale		1,325,287
	The Cimarrona property is subject to an Association Contract whereby 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 not possible to estimate the potential liability, if any.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	14. SUBSEQUENT EVENTS
	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 $6.5 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 will receive placement fees of 8%, in cash or warrants or a combination thereof at their election.

Supplemental_Information_About

Supplemental Information About oil And Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2013
Supplemental Information About Oil And Gas Producing Activities	'
Supplemental Information About oil And Gas Producing Activities	'
	15. SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
	Pinnacle Energy Services, LLC prepared reserve estimates for the year end reports for 2013 and 2012 for our continuing operations in Logan County, Oklahoma. Management cautions that there are many inherent uncertainties in estimating proved reserve quantities and related revenues and expenses, and in projecting future production rates and the timing and amount of development expenditures. Accordingly, these estimates will change, as further information becomes available.
	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, 2013 and 2012 are as follows:
		2013			2012
	Proved properties	$	25,551,336		$	8,140,819
	Unproved properties being amortized		-			-
	Unproved properties not being amortized		1,784,465			1,362,235
	Capitalised asset retirement costs		3,659			1 9
	Accumulated depletion, depreciation
	amortization and valuation allowances		(2,606,243	)		(310,097	)
		$	24,733,217		$	9,192,976
	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)
		2013			2012			2013			2012			2013			2012
	Proved developed and undeveloped reserves:
	Beginning of year		364,000			113,193			1,499			201			-			-
	Revisions of previous estimates		-			-						-			-			-
	Improved recovery		-			-						-			-			-
	Purchases of Minerals in place		-			-						-			-			-
	Extensions and discoveries		1,220,409			385,427			5,016			1,561			46,507			-
	Production		(76,409	)		(22,057	)		(150	)		(62	)		(3,507	)		-
	Sales of minerals in place		-			(112,563	)		-			(201	)		-			-
	End of year		1,508,000			364,000			6,365			1,499			43,000			-
	Proved developed reserves:
	Beginning of year		195,000			113,193			803			201			-			-
	End of year		460,000			195,000			2,005			803			33,000			-
	Proved undeveloped reserves:
	Beginning of year		169,000			-			696			-			-			-
	End of year		1,048,000			169,000			4,360			696			10,000			-
	The foregoing estimates have been prepared by Pinnacle Energy Services, LLC 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 $22.00 and $8.05 for 2013 and 2012.
	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 expenses, for oil and gas property acquisition, exploration and development for the years ended December 31, 2013 and 2012 were are follows:
		2013			2012
	Property acquisition costs	$	1,278,408		$	1,821,945
	Development costs		16,613,524			5,532,019
	Exploration costs		-			-
	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 $96.94 per BBL in 2013 and $94.71 per BBL in 2012. For natural gas, the average prices used in the reserve estimate were $3.67 per Mcf in 2013 and $2.757 per Mcf in 2012.
	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 2013 and 2012.
		2013			2012
	Future cash inflows	$	176,035,000		$	41,104,970
	Future production costs		(47,088,610	)		(9,538,070	)
	Future development costs		(35,500,100	)		(4,963,580	)
	Future abandonment costs		(451,200	)		(81,600	)
	Future income tax expenses		(37,198,036	)		(10,608,688	)
	Future net cash flow		55,797,054			15,913,032
	10% annual discount for estimated timing of cash flows		(29,219,748	)		(7,048,928	)
	Standardized measure of discounted future net cash flow	$	26,577,306		$	8,864,104
	The principal changes in the standardized measure of discounted future net cash flows during 2013 and 2012 were as follows:
		2013			2012
	Extensions		-			16,612,053
	Revisions of previous estimates
	Price changes	$	182,220		$	-
	Quantity Changes		105,407,911			-
	Changes in production rates, timing and other		(54,058,998	)		-
	Development costs incurred		-			-
	Changes in estimated future development costs		(17,009,887	)		-
Purchase of minerals in place		-			-
Sales of minerals in place		-			(5,284,705	)
Sales of oil and gas, net of production costs		(6,481,139	)		(1,838,547	)
Accretion of discount		1,481,896			-
Net change in income taxes		(11,808,801	)		(3,795,520	)
Net increase/ (decrease)	$	17,713,202		$	5,693,280

Organization_and_Summary_of_Si1

Organization and Summary of Significiant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

'

Nature of Operations

'

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

'

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

'

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 2013 or 2012.

Risk factors related to concentration of sales and products

'

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

'

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 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

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

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 $3,859,448 are being amortized over the term of the Note Purchase Agreement on a straight-line basis.

During the years ended December 31, 2013 and 2012, respectively, the Company made payments of $200,000 and $670,692 for deferred financing fees in connection with the Note Purchase Agreement.

Deferred financing costs at December 31, 2013 and 2012 were $1,829,124 and $2,924,472, respectively. Amortization of deferred financing costs was $1,295,348 for the year ended December 31, 2013 and $734,976 for the year ended December 31, 2012.

Fair Value of Financial Instruments

'

FAIR VALUE OF FINANCIAL INSTRUMENTS

As of December 31, 2013 and December 31, 2012, 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 us 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, 2013 the Company identified certain derivative financial instruments which required disclosure at fair value on the balance sheet.

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

Total

Fair Value Measurements Using

Carrying

Fair

Level 1

Level 2

Level 3

Amount

Value

Inputs

Inputs

Inputs

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.

Concentration of Credit Risk

'

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 2013 and 2012. 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 four customers in 2013 and three customers in 2012. (See “Accounts Receivable and Allowance for Doubtful Accounts” below).

Restricted Cash

'

RESTRICTED CASH

In connection with the Apollo Note Purchase Agreement, as amended (see Note 6), the Company has classified $850,000, representing three months interest, as restricted cash as of December 31, 2013. In connection with the Boothbay Secured Promissory Note (see Note 6) the Company was required to deposit certain royalty interests of Boothbay’s into joint accounts held by the Company for the benefit of Boothbay. The royalty interests at December 31, 2012 were $102,467 and there were no royalty interests at December 31, 2013 as the Secured Promissory Note had been repaid in full. The Company has also pledged $58,645 for certain bonds and sureties. Restricted cash at December 31, 2013 was $908,645, compared to $157,467 at December 31, 2012.

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.

During the year ended December 31, 2013, the Company sold 80% of its oil and gas production to one customer, Slawson Exploration Company (“Slawson”). 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, 2013 and 2012. The analysis was based on its evaluation of specific customers’ balances and the collectability thereof.

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.

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 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, 2013 and 2012, the Company’s oil production from continuing operations are conducted in the United States of America. The cost of undeveloped properties not being amortized, to the extent there is such a cost, is assessed quarterly based on the estimated economic chance of success and the length of time that the Company expects to hold the properties 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, 2013 and 2012.

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

'

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 statement 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

'

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

'

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. In that event, a loss is recognized based on the amount by which the carrying amount exceeds the fair market value of the long-lived assets. Loss on long-lived assets to be disposed of is determined in a similar manner, except that fair market values are reduced for the cost of disposal. During the years ended December 31, 2013 and 2012, the Company did not record impairment charges related to its long-lived assets.

Revenue Recognition

'

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, 2013 or 2012, and no receivables, payables or unearned revenue are recorded.

Stock Based Compensation

'

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. 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

'

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.

At December 31, 2013, the Company had Federal and state net operating loss carry forwards of approximately $7.9 million which expire at various dates through 2032.

Risk Management Activities

'

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

'

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, 2013 and 2012:

Year Ended December 31,

2013

2012

Net loss allocable to continuing operations

$

(3,514,895

)

$

(2,380,133

)

Net income and gain allocable to discontinued operations

$

7,370,201

$

1,863,427

Basic and diluted net income (loss) per share

Continuing operations

$

(0.07

)

$

(0.05

)

Discontinued operations

$

0.15

$

0.04

Basic and diluted weighted average shares outstanding

49,762,499

48,385,866

Warrants to purchase 1,696,843 and 3,071,843 shares of common stock at December 31, 2013 and December 31, 2012, respectively, were excluded from the computation as their effect would have been anti-dilutive.

Recently Issued Accounting Pronouncements

'

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

The Company does not expect the adoption of any recently issued accounting pronouncements to have a material effect on the consolidated financial statements.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013:
					Total			Fair Value Measurements Using
		Carrying			Fair			Level 1		Level 2			Level 3
		Amount			Value			Inputs		Inputs			Inputs
	December 31, 2013 assets (liabilities):
	Commodity derivative liability		(357,567	)		(357,567	)		-		(357,567	)		-
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, 2013 and 2012:
		Year Ended December 31,
		2013			2012
	Net loss allocable to continuing operations	$	(3,514,895	)	$	(2,380,133	)
	Net income and gain allocable to discontinued operations	$	7,368,201		$	1,863,427
	Basic and diluted net income (loss) per share
	Continuing operations	$	(0.07	)	$	(0.05	)
	Discontinued operations	$	0.15		$	0.04
	Basic and diluted weighted average shares outstanding		49,762,499			48,385,866

Oil_and_Gas_Properties_Tables

Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012 are as follows:
		2013			2012
	Proved properties	$	25,551,336		$	8,140,819
	Unproved properties being amortized		-			-
	Unproved properties not being amortized		1,784,465			1,362,235
	Capitalised asset retirement costs		3,659			1 9
	Accumulated depletion, depreciation
	amortization and valuation allowances		(2,606,243	)		(310,097	)
		$	24,733,217		$	9,192,976
Schedule of Area of Land Leased	'
	At December 31, 2013, we have leased 51,151 gross (17,638 net) acres across three counties in Oklahoma as follows:
		Gross			Osage Net
	Logan (non operated)		26,823			4,181
	Logan		9,734			5,014
	Coal		9,509			4,253
	Pawnee		5,085			4,190
			51,151			17,638

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule of Quarterly Coverage Ratio of Financial Covenants	'
	Financial covenants include the following:
			Minimum
		Interest	Production	Asset Coverage
	Each Quarter Ending:	Coverage Ratio	(MBbls)	Ratio
	31-Mar-14	2.50 to 1.00	70	1.75 to 1.00
	30-Jun-14	3.00 to 1.00	80	2.00 to 1.00
	30-Sep-14	3.00 to 1.00	90	2.00 to 1.00
	December 31, 2014, and thereafter	3.00 to 1.00	100	2.00 to 1.00

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
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 year ended December 31, 2013.
		Year Ended
		31-Dec-13
	Cash settlements to (by) Company	$	(138,236	)
	Unrealized gains (losses) on commodity derivatives		(357,567	)
	Loss on oil and gas derivatives	$	(495,803	)
Oil [Member]	'
Schedule of Oil and Natural Gas Open Derivative Positions	'
	As of December 31, 2013, 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		Weighted Average
		Volume			Floor Price		Ceiling Price
	Period		(BBLs/m)			($/BBL)		($/BBL)
	Q1 - Q4, 2014		6,000		$	85	$	95
	Q1 - Q2, 2015		6,000		$	80	$	93.5
Natural Gas Member]	'
Schedule of Oil and Natural Gas Open Derivative Positions	'
	As of December 31, 2013, 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		Weighted Average
		Volume			Floor Price		Ceiling Price
	Period	(Btu/m)			($/Btu)		($/Btu)
	Q1 - Q4, 2014		10,000		$	3.75	$	4.4
	Q1 - Q2, 2015		10,000		$	3.75	$	4.4

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013:
	Year	Amount
	2014	$	157,787
	2015		170,530
	2016		171,818
	2017		28,672
		$	528,807

Dilutive_Securities_Tables

Dilutive Securities (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Schedule of Stock Warrants Activity	'
	As of December 31, 2013 and 2012, the Company had outstanding dilutive securities, consisting entirely of warrants. Changes in warrants outstanding are as follows:
		Shares			Weighted Average Exercise Price		Average Remaining Contractual Life
	Balance December 31, 2011		1,125,000		$	1.25	0.27 years
	Granted		2,246,843		$	0.01
	Exercised		(200,000	)	$	0.01
	Balance December 31, 2012		3,171,843		$	0.45	1.75 years
	Exercised		(350,000	)	$	0.01
	Cancelled or Expired		(1,125,000	)	$	1.25
	Balance December 31, 2013		1,696,843		$	0.01	3.35 years

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Provision for Income Taxes	'
	The total provision for income taxes consists of the following in 2013 and 2012:
		Year Ended December 31,
		2013			2012
	Current Taxes:
	Federal	$	-		$	-
	State		-			-
	Foreign		-			-
			-			-
	Deferred Taxes:
	Federal		649,907			180,847
	State		60,070			16,793
	Foreign		-			-
	Valuation Allowance		(706,977	)		(197,640	)
			-			-
	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 2013 and 2012:
		2013			2012
	Computed tax provision at statutory Federal rates		35	%		35.0	%
	Increase (decrease) in taxes resulting from:
	State taxes, net of Federal income tax benefit		3.25	%		3.25	%
	Nondeductible and other expenses		-4.33	%		-130.45	%
	Federal and State true ups		0	%		0	%
	Other adjustments		-15.5	%		0	%
	Valuation Allowance		-18.4	%		92.2	%
			0	%		0	%
Schedule of Deferred Tax Assets and Liabilities	'
	Significant components of Osage’s deferred tax assets and liabilities are as follows at December 31, 2013 and December 31, 2012:
		2013			2012
	Deferred tax liability:
	Net operating loss carry forward	$	3,807,000		$	2,772,000
	Other		879,000			5,000
	Oil and gas properties		(4,501,000	)		(1,837,000	)
	Valuation allowance		(185,000	)		(940,000	)
	Net deferred tax liability		-			-

Major_Customers_Tables

Major Customers (Tables)	12 Months Ended
	Dec. 31, 2013
Major Customers	'
Schedule of Major Customers Accounting for All of Its Sale	'
	During 2013 and 2012, four and three customers, respectively, accounted for all of the Company’s sales from continuing operations:
		Year ended December 31, 2013					Year ended December 31, 2012
		Amount		% of Total			Amount		% of Total
	Slawson	$	6,421,674		80	%	$	2,205,088		97.4	%
	Stephens		847,573		10.6	%		-		0	%
	Devon		738,178		9.2	%		44,159		2	%
	Sundance		21,663		0.3	%		-		0	%
	Coffeyville		-		0	%		14,766		0.7	%
	Total	$	8,029,088		100	%	$	2,264,013		100	%

Liability_for_Asset_Retirement1

Liability for Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
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,
		2013		2012
	Beginning balance	$	19	$	24,231
	Incurred during the period		-		-
	Reversed during the period		-		(24,231	)
	Additions for new wells		3,639		19
	Accretion expense		228		-
	Ending balance	$	3,886	$	19

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2013
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,
		2013			2012
	Revenues
	Oil revenues	$	1,458,616		$	1,943,070
	Pipeline revenues		1,828,256			1,912,941
	Total revenues		3,286,872			3,856,011
	Operating costs and expenses
	Operating expenses		1,007,987			1,554,039
	Depreciation, depletion and accretion		124,193			254,237
	Equity tax		(435,988	)		131,186
	General and administrative		72,756			54,311
	Total operating costs and expenses		768,948			1,993,773
	Operating income		2,517,924			1,862,238
	Other income (expenses):
	Interest income		103			1,189
	Interest expense		(21,486	)		-
	Income before income taxes		2,496,541			1,863,427
	Provision for income taxes		-			-
	Net income	$	2,496,541		$	1,863,427
Schedule of Balance Sheet Information	'
	The following table sets forth balance sheet information for the discontinued operations as of December 31, 2012:
		As of
		31-Dec-12
	Accounts receivable		114,568
	Short term assets held for sale		114,568
	Oil and gas properties		2,979,980
	Less accumulated depletion, depreciation and amortization		(1,690,707	)
	Long term assets held for sale		1,289,273
	Accounts payable		18,786
	Accrued expenses		1,306,501
	Short term liabilities held for sale		1,325,287

Recovered_Sheet1

Supplemental Information about Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012 are as follows:
		2013			2012
	Proved properties	$	25,551,336		$	8,140,819
	Unproved properties being amortized		-			-
	Unproved properties not being amortized		1,784,465			1,362,235
	Capitalised asset retirement costs		3,659			1 9
	Accumulated depletion, depreciation
	amortization and valuation allowances		(2,606,243	)		(310,097	)
		$	24,733,217		$	9,192,976
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)
		2013			2012			2013			2012			2013			2012
	Proved developed and undeveloped reserves:
	Beginning of year		364,000			113,193			1,499			201			-			-
	Revisions of previous estimates		-			-						-			-			-
	Improved recovery		-			-						-			-			-
	Purchases of Minerals in place		-			-						-			-			-
	Extensions and discoveries		1,220,409			385,427			5,016			1,561			46,507			-
	Production		(76,409	)		(22,057	)		(150	)		(62	)		(3,507	)		-
	Sales of minerals in place		-			(112,563	)		-			(201	)		-			-
	End of year		1,508,000			364,000			6,365			1,499			43,000			-
	Proved developed reserves:
	Beginning of year		195,000			113,193			803			201			-			-
	End of year		460,000			195,000			2,005			803			33,000			-
	Proved undeveloped reserves:
	Beginning of year		169,000			-			696			-			-			-
	End of year		1,048,000			169,000			4,360			696			10,000			-
Costs Incurred, Both Capitalized and Expensed, Oil and Gas Property Acquisition, Exploration and Development	'
	Cost incurred, both capitalized and expenses, for oil and gas property acquisition, exploration and development for the years ended December 31, 2013 and 2012 were are follows:
		2013			2012
	Property acquisition costs	$	1,278,408		$	1,821,945
	Development costs		16,613,524			5,532,019
	Exploration costs		-			-
	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 2013 and 2012.
		2013			2012
	Future cash inflows	$	176,035,000		$	41,104,970
	Future production costs		(47,088,610	)		(9,538,070	)
	Future development costs		(35,500,100	)		(4,963,580	)
	Future abandonment costs		(451,200	)		(81,600	)
	Future income tax expenses		(37,198,036	)		(10,608,688	)
	Future net cash flow		55,797,054			15,913,032
	10% annual discount for estimated timing of cash flows		(29,219,748	)		(7,048,928	)
	Standardized measure of discounted future net cash flow	$	26,577,306		$	8,864,104
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 2013 and 2012 were as follows:
		2013			2012
	Extensions		-			16,612,053
	Revisions of previous estimates
	Price changes	$	182,220		$	-
	Quantity Changes		105,407,911			-
	Changes in production rates, timing and other		(54,058,998	)		-
	Development costs incurred		-			-
	Changes in estimated future development costs		(17,009,887	)		-
	Purchase of minerals in place		-			-
	Sales of minerals in place		-			(5,284,705	)
	Sales of oil and gas, net of production costs		(6,481,139	)		(1,838,547	)
	Accretion of discount		1,481,896			-
	Net change in income taxes		(11,808,801	)		(3,795,520	)
	Net increase/ (decrease)	$	17,713,202		$	5,693,280

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Deferred financing costs	$3,859,448	'
Deferred financing costs, current	1,829,124	2,924,472
Differed financing fees	200,000	670,692
Amortization of deferred finance costs	1,295,348	734,976
Pledged for bonds and sureties	58,645	'
Restricted cash	908,645	157,467
Percentage of oil and gas production sold	80.00%	'
Royalty interests	'	102,467
Percentage amount of tax benefit	50.00%	'
Net operating loss carry forwards	9,900,000	'
Number of warrants consisted in potential common shares to purchase common stock	1,696,843	3,071,843
Apollo Note Purchase Agreement [Member]	'	'
Restricted cash	850,000	'
State [Member]	'	'
Net operating loss carry forwards	0	'
Net operating loss carry forwards, expiration date	'2032	'
Federal [Member]	'	'
Net operating loss carry forwards	$0	'
Net operating loss carry forwards, expiration date	'2032	'

Summary_of_Significant_Account

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

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, 2013	Dec. 31, 2012
Accounting Policies [Abstract]	'	'
Net loss allocable to continuing operations	($3,514,895)	($2,380,133)
Net income and gain allocable to discontinued operations	$7,370,201	$1,863,427
Basic and diluted net income (loss) per share, Continuing operations	($0.07)	($0.05)
Basic and diluted net income (loss) per share, Discontinued operations	$0.15	$0.04
Basic and diluted weighted average shares outstanding	49,762,499	48,385,866

Going_Concern_Details_Narrativ

Going Concern (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Apr. 27, 2012	Apr. 05, 2013	Apr. 27, 2012
				Apollo Investment Corporation [Member]	Apollo Investment Corporation [Member]
Accumulated deficit	$4,219,480	$8,074,786	'	'	'
Working capital deficit	643,843	12,961,622	'	'	'
Senior secured notes	'	'	10,000,000	20,000,000	10,000,000
Proceeds from private placement	$6,500,000	'	'	'	'

Equity_Transactions_Details_Na

Equity Transactions (Details Narrative) (USD $)

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

Jun. 07, 2013

Jan. 02, 2013

Nov. 27, 2012

Aug. 24, 2012

Aug. 01, 2012

Apr. 16, 2012

Apr. 17, 2012

Jan. 27, 2012

Jun. 30, 2007

Dec. 31, 2013

Dec. 31, 2012

Dec. 27, 2012

Apr. 27, 2012

Apr. 20, 2012

Apr. 16, 2012

Dec. 31, 2012

Apr. 27, 2012

Aug. 01, 2012

Aug. 01, 2012

Aug. 01, 2012

Warrant [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

First Anniversary [Member]

Second Anniversary [Member]

Third Anniversary [Member]

Note Purchase Agreement [Member]

Stock issued during period for consideration of services, shares

10,000

'

500,000

'

'

20,000

'

90,000

'

'

'

'

'

'

'

'

'

'

'

'

Stock issued during period for consideration of services

$12,000

'

$350,000

'

'

$23,000

'

$41,400

'

$528,418

$448,583

'

'

'

'

'

'

'

'

'

Stock issuance, price per share

$1.20

$0.91

$0.70

'

$1.18

$1.15

'

$0.46

'

'

'

'

'

'

'

'

'

'

'

'

Stock issued to secured notes

'

'

'

'

'

'

400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock issued to secured notes, shares

'

'

'

'

'

'

385,656

'

'

'

'

'

'

'

'

'

'

'

'

'

Warrants issued to purchase of common stock, number

'

'

'

200,000

'

'

'

'

'

'

'

100,000

1,496,843

200,000

200,000

'

250,000

'

'

'

Proceeds from exercise of warrants

'

'

'

2,000

'

'

'

'

'

3,500

2,000

89,952

2,483,952

219,055

229,056

'

413,690

'

'

'

Warrants exercise price per share

'

'

'

'

'

'

'

'

'

'

'

$0.01

$0.01

$0.01

$0.01

'

$0.00

'

'

'

Shares issued under employment agreement

'

400,000

'

'

150,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares issued under employment agreement, value

'

364,000

'

'

177,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of shares issuing each anniversary

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000

50,000

50,000

Recognized expenses

'

'

'

'

'

'

'

'

'

152,418

'

'

'

'

'

'

'

'

'

'

Expected life

'

'

'

'

'

'

'

'

'

'

'

'5 years

'5 years

'5 years

'2 years

'5 years

'2 years

'

'

'

Fair value amount

'

'

'

'

'

'

'

'

'

'

'

$1,161

'

'

'

'

'

'

'

'

Discount rate

'

'

'

'

'

'

'

'

'

'

'

0.72%

0.82%

0.29%

0.27%

'

0.26%

'

'

'

Expected volatility rate

'

'

'

'

'

'

'

'

'

'

'

242.00%

245.00%

243.00%

244.00%

'

242.00%

'

'

'

Expected dividends

'

'

'

'

'

'

'

'

'

'

'

0.00%

0.00%

0.00%

0.00%

'

0.00%

'

'

'

Reservation of shares issued

'

'

'

'

'

'

'

'

5,000,000

'

'

'

'

'

'

'

'

'

'

'

Oil_and_Gas_Properties_Details

Oil and Gas Properties (Details Narrative) (USD $)	0 Months Ended	1 Months Ended
	Apr. 21, 2011	Jul. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
	acre		acre
Depreciation and depletion expense	'	'	$2,308,064	$298,179
Acres of land	10,000	'	'	'
Proceeds from sale of land	4,875,000	'	'	'
Percentage of well cost carried by parties	7.50%	'	'	'
Percentage of total well costs provided for first three horizontal Mississippian wells	17.50%	'	'	'
Percentage of total well cost responsible after first three horizontal Mississippian wells	25.00%	'	'	'
Allocated percentage of revenue	25.00%	'	'	'
Net acres of leased land	'	'	17,638	'
Gross acres of leased land	'	'	51,151	'
Purchase of oil prospects	'	8,500	'	'
Percentage of leases acquired	'	12.50%	'	'
Lease bonus paid	'	$200,000	'	'
Slawson Exploration Company [Member]	'	'	'	'
Net acres of leased land	'	'	5,014	'
Gross acres of leased land	'	'	9,734	'
Slawson Exploration Company [Member]	'	'	'	'
Percentage of business acquired by parties	45.00%	'	'	'
Allocated percentage of revenue	45.00%	'	'	'
USE [Member]	'	'	'	'
Percentage of business acquired by parties	30.00%	'	'	'
Allocated percentage of revenue	30.00%	'	'	'
Parent Company [Member]	'	'	'	'
Net acres of leased land	'	'	4,181	'
Gross acres of leased land	'	'	26,823	'
Pawnee County [Member]	'	'	'	'
Net acres of leased land	'	'	4,190	'
Gross acres of leased land	'	'	5,085	'
Coal County [Member]	'	'	'	'
Net acres of leased land	'	'	4,253	'
Gross acres of leased land	'	'	9,509	'
Oklahoma County [Member]	'	'	'	'
Net acres of leased land	'	'	17,638	'
Gross acres of leased land	'	'	51,151	'

Oil_and_Gas_Properties_Schedul

Oil and Gas Properties - Schedule of Oil and Gas Properties (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Property [Abstract]	'	'
Properties subject to amortization	$25,551,336	$8,140,819
Properties not subject to amortization	1,784,465	1,362,235
Capitalized asset retirement costs	3,659	19
Accumulated depreciation and depletion	-2,606,243	-310,097
Oil & Gas Properties, Net	$24,733,217	$9,192,976

Oil_and_Gas_Properties_Schedul1

Oil and Gas Properties - Schedule of Area of Land Leased (Details)	Dec. 31, 2013
	acre
Gross acres of leased land	51,151
Net acres of leased land	17,638
Logan Non Operated Country [Member]	'
Gross acres of leased land	26,823
Net acres of leased land	4,181
Logan Operated Company [Member]	'
Gross acres of leased land	9,734
Net acres of leased land	5,014
Coal County [Member]	'
Gross acres of leased land	9,509
Net acres of leased land	4,253
Pawnee County [Member]	'
Gross acres of leased land	5,085
Net acres of leased land	4,190

Debt_Details_Narrative

Debt (Details Narrative) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Apr. 27, 2012

Apr. 17, 2012

Apr. 17, 2012

Dec. 27, 2012

Apr. 27, 2012

Apr. 20, 2012

Apr. 16, 2012

Dec. 31, 2012

Apr. 27, 2012

Apr. 27, 2012

Dec. 31, 2013

Apr. 05, 2013

Dec. 31, 2013

Apr. 27, 2012

Dec. 31, 2013

Apr. 17, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Logan County Range Four [Member]

Logan County Range Three [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Apollo Investment Corporation [Member]

Apollo Investment Corporation [Member]

Apollo Investment Corporation [Member]

Apollo Investment Corporation [Member]

CC Natural Resource Partners, LLC [Member]

CC Natural Resource Partners, LLC [Member]

Boothbay Royalty Co [Member]

Boothbay Royalty Co [Member]

Boothbay Royalty Co [Member]

Boothbay Royalty Co [Member]

Boothbay Royalty Co [Member]

ApolloInvestmentCorporationAndCCNaturalResourcePartnersLLCMember

Note Purchase Agreement [Member]

Warrant [Member]

Warrant [Member]

Secured Promissory Note [Member]

Note Purchase Agreement [Member]

Senior secured notes

'

'

$10,000,000

'

'

'

'

'

'

'

'

$10,000,000

'

$20,000,000

'

'

'

'

'

'

'

'

'

Notes maturity date

'

'

'

'

'

'

'

'

'

'

'

27-Apr-15

'

'

'

'

'

17-Apr-14

'

'

'

'

'

Percentage of LIBOR floor interest rate

'

'

'

'

'

'

'

'

'

'

'

2.00%

'

'

'

'

'

'

'

'

'

'

'

Percentage of LIBOR plus interest rate

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

Warrants issued to purchase of common stock

100,000

'

'

'

'

'

'

'

'

100,000

'

1,496,843

'

'

'

250,000

'

'

'

'

'

'

'

Warrants exercise price

'

0.01

0.01

'

'

'

'

'

'

'

'

0.01

'

'

'

0.01

'

'

'

'

'

'

'

Warrants value using Black-Scholes

'

89,952

'

'

'

'

1,161

'

'

'

'

2,483,952

'

'

'

413,690

'

'

'

'

'

'

'

Warrants maturity date

'

'

'

'

'

'

'

'

'

'

'

27-Apr-17

'

'

'

27-Apr-14

'

'

'

'

'

'

'

Discount rate

'

'

'

'

'

'

0.82%

'

'

'

'

'

'

'

0.72%

'

0.26%

'

'

'

'

'

'

Expected volatility rate

'

'

'

'

'

242.00%

245.00%

243.00%

244.00%

'

242.00%

'

'

'

242.00%

'

242.00%

'

'

'

'

'

'

Expected life in years

'

'

'

'

'

'5 years

'5 years

'5 years

'2 years

'5 years

'2 years

'

'

'

'5 years

'

'2 years

'

'

'

'

'

'

Expected dividends rate

'

'

'

'

'

0.00%

0.00%

0.00%

0.00%

'

0.00%

'

'

'

0.00%

'

0.00%

'

'

'

'

'

'

Minimum amount draw through purchase of notes

3,000,000

'

'

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

Drawn from portion of debt

20,000,000

'

'

'

'

'

'

'

'

'

'

'

17,000,000

'

'

'

'

'

'

'

'

'

'

Note purchase agreement minimum placement fee

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000

'

'

'

'

'

'

'

Legal fees on notes

'

'

170,692

'

'

'

'

'

'

'

'

100,000

'

'

'

'

'

170,692

'

'

'

'

'

Additional placement fees

'

'

'

'

'

'

'

'

'

380,000

'

'

'

'

'

'

100,000

'

'

'

'

'

'

Warrantes expiration term

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Warrants expiration, range start

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Warrants expiratiom, range end

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred financing costs

1,829,124

2,924,472

'

'

'

'

'

'

'

'

'

'

3,759,448

'

'

'

'

'

'

'

'

'

3,859,448

Liability to pay administrative fees

'

'

50,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of standby fee

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of debt undrawn funds

'

'

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of upfront fee

'

'

2.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payment made for amendment fee

100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Secured promissory note

'

'

'

'

'

'

'

'

'

'

'

'

13,000,000

'

'

'

'

2,500,000

'

'

'

'

'

Secured promissory note, interest rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18.00%

'

'

'

'

'

Shares issued for secured promissory note

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000

'

'

'

'

'

Debt discount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

386,545

'

'

'

'

'

Percentage of overriding royalty

'

'

'

1.71%

1.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of overriding royalty interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

Common stock closing price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1.14

'

'

'

'

'

Non-cash interest expense related to the note purchase agreement and secured promissory note

732,839

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,295,348

271,060

538,889

1,288,841

'

Cash interest expense on secured promissory note

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$4,566,246

$2,999,838

$114,596

$734,976

'

Debt_Schedule_of_Quarterly_Cov

Debt - Schedule of Quarterly Coverage Ratio of Debt Instrument Covenants (Details)	12 Months Ended
	Dec. 31, 2013
	Time
	MBbls
March 31, 2014 [Member]	'
Interest Coverage Ratio	2.5
Minimum Production	70
Asset Coverage Ratio	1.75
June 30, 2014 [Member]	'
Interest Coverage Ratio	3
Minimum Production	80
Asset Coverage Ratio	2
September 30, 2014 [Member]	'
Interest Coverage Ratio	3
Minimum Production	90
Asset Coverage Ratio	2
December 31, 2014, And Thereafter [Member]	'
Interest Coverage Ratio	3
Minimum Production	100
Asset Coverage Ratio	2

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Details Narrative) (USD $)	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Collateral amount	$25,000,000

Derivative_Financial_Instrumen3

Derivative Financial Instruments - Schedule of Oil Open Derivative Positions (Details) (Oil [Member])	12 Months Ended
	Dec. 31, 2013
	bbl
Q1 - Q4, 2014 [Member]	'
Monthly Volume (BBLs/m)	6,000
Weighted Average Floor Price ($/BBL)	85
Weighted Average Ceiling Price ($/BBL)	95
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_Instrumen4

Derivative Financial Instruments - Schedule of Natural Gas Open Derivative Positions (Details) (Natural Gas Member])	12 Months Ended
	Dec. 31, 2013
	Btu
Q1 - Q4, 2014 [Member]	'
Monthly Volume (Btu/m)	10,000
Weighted Average Floor Price ($/Btu)	3.75
Weighted Average Ceiling Price ($/BBL)	4.4
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_Instrumen5

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, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Cash settlements to (by) Company	($138,236)	'
Unrealized gains (losses) on commodity derivatives	-357,567	'
Loss on oil and gas derivatives	($495,803)	'

Commitments_and_Contingencies_1

Commitments and Contingencies (Details Narrative) (USD $)

0 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

Oct. 07, 2013

Jan. 31, 2013

Feb. 29, 2012

Jan. 31, 2012

Feb. 28, 2011

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2010

Sep. 30, 2013

Dec. 31, 2013

Oct. 07, 2013

Cimarrona LLC [Member]

Cimarrona LLC [Member]

Cimarrona LLC [Member]

Lease periods in months

'

'

'24 months

'

'36 months

'

'

'

'

'

'

'

Rental expense

'

'

'

'

'

'

$58,147

$57,344

'

'

'

'

Percenatage of sale membership interest

'

'

'

'

'

'

'

'

'

9.40%

'

100.00%

Percentage of royalty received for oil produced

20.00%

'

'

'

'

'

'

'

'

'

20.00%

'

Percentage of additional royalty received

50.00%

'

'

'

'

'

'

'

'

'

50.00%

'

Percentage of received reimbursement of all historical costs

200.00%

'

'

'

'

'

'

'

'

'

200.00%

'

Value of equity taxes levied

'

'

'

'

'

'

'

'

883,742

'

'

'

Increase in amount of tax

'

'

'

322,288

'

'

'

'

'

'

'

'

Payment of tax liability

'

367,521

'

'

'

'

'

'

'

'

'

'

Recognized in discontinued operations

'

'

'

'

'

531,644

'

'

'

'

'

'

Oil revenues

'

'

'

'

'

'

$7,339,943

$2,030,596

'

$729,308

'

'

Commitments_and_Contingencies_2

Commitments and Contingencies - Schedule of Future Minimum Commitments Under Operating Leases (Details) (USD $)	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
2014	$157,787
2015	170,530
2016	171,818
2017	28,672
Total	$528,807

Dilutive_Securities_Details_Na

Dilutive Securities (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Dilutive securities	$1,662,906

Dilutive_Securities_Schedule_o

Dilutive Securities - Schedule of Stock Warrants Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]	'	'
Shares Outstanding, Beginning Balance	3,171,843	1,125,000
Shares Granted	'	2,246,843
Shares Exercised	-350,000	-200,000
Shares Cancelled or Expired	-1,125,000	'
Shares Outstanding, Ending Balance	1,696,843	3,171,843
Weighted Average Exercise Price, Outstanding, Beginning	$0.45	$1.25
Weighted Average Exercise Price, Granted	'	$0.01
Weighted Average Exercise Price, Exercised	$0.01	$0.01
Weighted Average Exercise Price, Cancelled or Expired	$1.25	'
Weighted Average Exercise Price, Outstanding, Ending	$0.01	$0.45
Weighted Average Remaining Contractual Terms (Years), Beginning	'1 year 9 months	'3 months 7 days
Weighted Average Remaining Contractual Terms (Years), Ending	'3 years 4 months 6 days	'1 year 9 months

Income_Taxes_Details_Narrative

Income Taxes (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Operating loss carry forwards	$9,900,000
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, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Federal	'	'
State	'	'
Foreign	'	'
Federal	649,907	180,847
State	60,070	16,793
Foreign	'	'
Valuation Allowance	-706,977	-197,640
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, 2013	Dec. 31, 2012
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%	3.25%
Nondeductible and other expenses	-4.33%	-130.45%
Federal and State true ups	0.00%	0.00%
Other adjustments	-15.50%	0.00%
Valuation Allowance	-18.40%	92.20%
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, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]	'	'
Net operating loss carry forward	$3,807,000	$2,772,000
Other	879,000	5,000
Oil and gas properties	-4,501,000	-1,837,000
Valuation allowance	185,000	940,000
Net deferred tax liability	'	'

Major_Customers_Schedule_of_Ma

Major Customers - Schedule of Major Customers Accounting for All of its Sale (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Revenue from major customers	$8,029,088	$2,264,013
Percentage of revenue from major customers	100.00%	100.00%
Slawson Exploration Company [Member]	'	'
Revenue from major customers	6,421,674	2,205,088
Percentage of revenue from major customers	80.00%	97.40%
Stephens [Member]	'	'
Revenue from major customers	847,573	'
Percentage of revenue from major customers	10.60%	0.00%
Devon [Member]	'	'
Revenue from major customers	738,178	14,766
Percentage of revenue from major customers	9.20%	0.70%
Sundance [Member]	'	'
Revenue from major customers	21,663	'
Percentage of revenue from major customers	0.30%	0.00%
Coffeyville [Member]	'	'
Revenue from major customers	'	$44,159
Percentage of revenue from major customers	0.00%	2.00%

Liability_for_Asset_Retirement2

Liability for Asset Retirement Obligations - Schedule of Reconciliation of Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]	'	'
Beginning balance	$19	$24,231
Incurred during the period	'	'
Reversed during the period	'	-24,231
Additions for new wells	3,639	19
Accretion expense	228	'
Ending balance	$3,886	$19

Discontinued_Operations_Detail

Discontinued Operations (Details Narrative) (USD $)	0 Months Ended	12 Months Ended			9 Months Ended	12 Months Ended
	Oct. 07, 2013	Dec. 31, 2013	Dec. 31, 2012	Apr. 21, 2011	Sep. 30, 2013	Dec. 31, 2013	Oct. 07, 2013
				acre	Cimarrona LLC [Member]	Cimarrona LLC [Member]	Cimarrona LLC [Member]
					acre
Percenatage of sale membership interest	'	'	'	'	9.40%	'	100.00%
Area of land of oil and gas assets	'	'	'	10,000	30,665	'	'
Cash	'	$422,955	'	'	'	$6,800,000	'
Liability payable to disposal group	'	'	'	'	'	250,000	'
Payment of sales price held in escrow	'	'	'	'	'	250,000	'
Payment of disposal of transportation cost	'	1,000,000	'	'	'	'	'
Recognized benefit of discontinued operation	'	4,873,660	'	'	'	'	'
Equity taxes owed by disposal group	'	'	150,950	'	'	'	'
Percentage of royalty received for oil produced	20.00%	'	'	'	'	20.00%	'
Percentage of additional royalty received	50.00%	'	'	'	'	50.00%	'
Percentage of received reimbursement of all historical costs	200.00%	'	'	'	'	200.00%	'
Maximum percentage of exposure for oil produced	'	'	'	'	'	0.5	'
Revenues	'	$3,286,872	$3,856,011	'	$729,308	'	'

Discontinued_Operations_Summar

Discontinued Operations - Summary of Discontinued Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Discontinued Operations and Disposal Groups [Abstract]	'	'
Oil revenues	$1,458,616	$1,943,070
Pipeline revenues	1,828,256	1,912,941
Total revenues	3,286,872	3,856,011
Operating expenses	1,007,987	1,554,039
Depreciation, depletion and accretion	124,193	254,237
Equity tax	-435,988	131,186
General and administrative	72,756	54,311
Total operating costs and expenses	768,948	1,993,773
Operating income	2,517,924	1,862,238
Interest income	103	1,189
Interest expense	-21,486	'
Income before income taxes	2,496,541	1,863,427
Provision for income taxes	'	'
Net income	$7,370,201	$1,863,427

Discontinued_Operations_Schedu

Discontinued Operations - Schedule of Balance Sheet Information (Details) (USD $)	Dec. 31, 2012
Extractive Industries [Abstract]	'
Accounts receivable	$114,568
Short term assets held for sale	114,568
Oil and gas properties	2,979,980
Less accumulated depletion, depreciation and amortization	-1,690,707
Long term assets held for sale	1,289,273
Accounts payable	18,786
Accrued expenses	1,306,501
Short term liabilities held for sale	$1,325,287

Subsequent_Events_Details_Narr

Subsequent Events (Details Narrative) (USD $)	0 Months Ended						12 Months Ended	0 Months Ended
	Jun. 07, 2013	Jan. 02, 2013	Nov. 27, 2012	Aug. 01, 2012	Apr. 16, 2012	Jan. 27, 2012	Dec. 31, 2013	Feb. 28, 2014
								Subsequent Event [Member]
Proceeds from issuance of private placement	'	'	'	'	'	'	$6,500,000	$6,500,000
Number of common stock warrants purchase	'	'	'	'	'	'	'	0.4
Common stock price per share	$1.20	$0.91	$0.70	$1.18	$1.15	$0.46	'	$1.80
Warrants price per share	'	'	'	'	'	'	'	$0.90
Percentage of placement fee in cash or warrants	'	'	'	'	'	'	'	8.00%

Supplemental_Information_About1

Supplemental Information About Oil and Gas Producing Activities (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	bbl	bbl
Depletion, depreciation and accretion per equivalent unit of production	22	8.05
Oil [Member]	'	'
Weighted average prices reserve estimate	96.94	94.71
Gas [Member]	'	'
Weighted average prices reserve estimate	3.67	2.757

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, 2013	Dec. 31, 2012
Extractive Industries [Abstract]	'	'
Proved properties	$25,551,336	$8,140,819
Unproved properties being amortized	'	'
Unproved properties not being amortized	1,784,465	1,362,235
Capitalized asset retirement costs	3,659	19
Accumulated depletion, depreciation, amortization and valuation allowances	-2,606,243	-310,097
Oil & Gas Properties, Net	$24,733,217	$9,192,976

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, 2013	Dec. 31, 2012
	bbl	bbl
Oil [Member]	'	'
Proved developed and undeveloped reserves, Beginning of year	364,000	113,193
Revisions of previous estimates	'	'
Improved recovery	'	'
Purchases of minerals in place	'	'
Extensions and discoveries	1,220,409	385,427
Production	-76,409	-22,057
Sales of minerals in place	'	-112,563
End of year	1,508,000	364,000
Proved developed reserves, Beginning of year	195,000	113,193
Proved developed reserves, End of year	460,000	195,000
Proved undeveloped reserves, Beginning of year	169,000	'
Proved undeveloped reserves, End of year	1,048,000	169,000
Gas [Member]	'	'
Proved developed and undeveloped reserves, Beginning of year	1,499	201
Revisions of previous estimates	'	'
Improved recovery	'	'
Purchases of minerals in place	'	'
Extensions and discoveries	5,016	1,561
Production	-150	-62
Sales of minerals in place	'	-201
End of year	6,365	1,499
Proved developed reserves, Beginning of year	803	201
Proved developed reserves, End of year	2,005	803
Proved undeveloped reserves, Beginning of year	696	'
Proved undeveloped reserves, End of year	4,360	696
Natural Gas Liquids [Member]	'	'
Proved developed and undeveloped reserves, Beginning of year	'	'
Revisions of previous estimates	'	'
Improved recovery	'	'
Purchases of minerals in place	'	'
Extensions and discoveries	46,507	'
Production	-3,507	'
Sales of minerals in place	'	'
End of year	43,000	'
Proved developed reserves, Beginning of year	'	'
Proved developed reserves, End of year	33,000	'
Proved undeveloped reserves, Beginning of year	'	'
Proved undeveloped reserves, End of year	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, 2013	Dec. 31, 2012
Extractive Industries [Abstract]	'	'
Property acquisition costs	$1,278,408	$1,821,945
Development costs	16,613,524	5,532,019
Exploration costs	'	'
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, 2013	Dec. 31, 2012
Extractive Industries [Abstract]	'	'
Future cash inflows	$176,035,000	$41,104,970
Future production costs	-47,088,610	-9,538,070
Future development costs	-35,500,100	-4,963,580
Future abandonment costs	-451,200	-81,600
Future income tax expenses	-37,198,036	-10,608,688
Future net cash flow	55,797,054	15,913,032
10% annual discount for estimated timing of cash flows	-29,219,748	-7,048,928
Standardized measure of discounted future net cash flow	$26,577,306	$8,864,104
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, 2013	Dec. 31, 2012
Extractive Industries [Abstract]	'	'
Extensions	'	$16,612,053
Revisions of previous estimates, Price changes	182,200	'
Revisions of previous estimates, Quantity changes	105,407,911	'
Changes in production rates, timing and other	-54,058,998	'
Development costs incurred	'	'
Changes in estimated future development costs	-17,009,887	'
Purchase of minerals in place	'	'
Sales of minerals in place	'	-5,284,705
Sales of oil and gas, net of production costs	-6,481,139	-1,838,547
Accretion of discount	1,481,896	'
Net change in income taxes	-11,808,801	-3,795,520
Net increase/ (decrease)	$17,713,202	$5,693,280