Cross Border Resources (XBOR) 10-K 19 May 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	18-May-15	Jun. 30, 2014
Document And Entity Information
Entity Registrant Name	Cross Border Resources, Inc.
Entity Central Index Key	1373485
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity a Well-known Seasoned Issuer	No
Entity a Voluntary Filer	No
Entity's Reporting Status Current	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$1,100,000
Entity Common Stock, Shares Outstanding		17,336,226
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014

Balance_Sheets

Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
Current Assets
Cash and Cash Equivalents	$356,950	$726,239
Accounts Receivable - Oil and Natural Gas Sales	1,594,990	2,086,239
Accounts Receivable - Related Party		24,630
Derivative Asset	71,598
Prepaid Expenses & Other Current Assets		87,443
Assets Held for Sale	15,617,472
Current Tax Asset	19,600	19,600
Total Current Assets	17,660,610	2,944,151
Oil and Gas Properties	27,243,106	56,561,040
Less Accumulated Depletion, Amortization, and Impairment	-11,956,319	-20,941,867
Net Oil and Gas Properties	15,286,787	35,619,173
Other Assets
Other Property and Equipment, net of Accumulated Depreciation of $110,278 and $95,828 in 2014 and 2013, respectively	26,258	34,641
Restricted Cash	214,751	206,087
Deferred financing costs	47,512	91,242
Other Assets	54,324	54,324
Total Other Assets	342,845	386,294
TOTAL ASSETS	33,290,242	38,949,618
Current Liabilities
Accounts Payable - Trade	1,865,625	1,268,257
Accrued Expenses & Other Payables	664,368	63,101
Derivative Liability		38,109
Line of Credit	8,200,000
Environmental Liability - Current Portion	2,057,175	1,400,000
Liabilities Held for Sale	1,594,711
Deferred Tax Liability	19,600	19,600
Total Current Liabilities	14,401,479	2,789,067
Non-Current Liabilities:
Asset Retirement Obligations	1,594,710	3,514,898
Environmental Liability, Net of Current Portion		687,973
Line of Credit		12,200,000
Litigation Settlement Payable
Total Non-Current Liabilities	1,594,710	16,402,871
Total Liabilities	15,996,189	19,191,938
Commitments & Contingencies (Note 9)
STOCKHOLDERS' EQUITY
Common Stock ($0.001 par value; 99,000,000 shares authorized and 17,336,226 issued and outstanding as of December 31, 2014 and as of December 31, 2013, respectively)	17,336	17,336
Additional Paid in Capital	33,462,473	33,462,473
Accumulated Deficit	-16,185,756	-13,722,129
Total Stockholders' Equity	17,294,053	19,757,680
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$33,290,242	$38,949,618

Balance_Sheets_Parenthetical

Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Balance Sheets
Accumulated depreciation of other property and equipment	$110,277	$95,828
Common Stock, par value	$0.00	$0.00
Common Stock, shares authorized	99,000,000	99,000,000
Common Stock, shares issued	17,336,226	17,336,226
Common Stock, shares outstanding	17,336,226	17,336,226

Statements_of_Operations

Statements of Operations (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Oil and gas sales	$12,352,299	$13,125,960
EXPENSES:
Operating costs	2,287,908	2,300,899
Natural gas marketing and transportation expenses	102,736	78,211
Production taxes	999,395	1,246,153
Depreciation, depletion, amortization, and Impairment	9,154,536	4,941,614
Accretion Expense	185,773	148,364
General and administrative	695,613	1,007,065
Total expense	13,425,961	9,722,306
Income (loss) from operations	-1,073,662	3,403,654
Other income (expense):
Gain (loss) on derivatives	-3,479	-269,769
Loss on settlement of litigation	-900,000
Gain on settlement of debt		858,429
Interest expense	-486,488	-639,578
Miscellaneous other income (expense)
Total other income (expense)	-1,389,967	-50,918
Income (loss) before income taxes	-2,463,629	3,352,736
Income tax expense	0	0
Net income (loss)	($2,463,629)	$3,352,736
Net income (loss) per share:
Basic	($0.14)	$0.20
Fully diluted	($0.12)	$0.16
Weighted average shares outstanding:
Basic	17,336,226	17,169,041
Fully diluted	21,023,726	20,856,541

Statements_of_Cash_Flows

Statements of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	($2,463,629)	$3,352,736
Adjustments to reconcile net income (loss) to cash used by operating activities:
Depreciation, depletion, amortization, and impairment	9,154,536	4,941,614
Gain on settlement of creditors liability		-350,800
Gain on conversion of notes payable		-485,416
Settlement of environmental liability	-20,798	-12,027
Accretion of asset retirement obligations	185,773	148,364
Amortization of and deferred financing costs	43,730	9,803
Change in derivative instrument	-38,109	328,897
Changes in operating assets and liabilities:
Accounts receivable	685,645	1,083,856
Accounts receivable - related party	24,630
Prepaid expenses and other current assets	-176,534	375,666
Accounts payable	597,368	-2,245,392
Restricted cash	8,664	-206,087
Accrued expenses	648,846	7,527
NET CASH PROVIDED BY OPERATING ACTIVITIES	8,650,122	6,948,741
CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures - oil and gas properties	-5,013,345	-9,253,152
Capital expenditures - other assets	-6,066
NET CASH USED IN INVESTING ACTIVITIES	-5,019,411	-9,253,152
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings on line of credit		12,200,000
Reduction of principal on line of credit	-4,000,000
Payments on line of credit		-8,750,000
Repayments to creditors		-660,911
NET CASH (USED) PROVIDED BY FINANCING ACTIVITIES	-4,000,000	2,789,089
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	-369,292	484,678
Cash and cash equivalents, beginning of year	726,239	241,561
Cash and cash equivalents, end of year	356,950	726,239
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid	443,067	518,756
NON-CASH TRANSACTIONS
Revisions of ARO	-554,287
Issuance of common stock to settle liability		-692,967
Additions of ARO	$46,447	$51,290

Statements_of_Equity

Statements of Equity (USD $)	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Total
Balance, beginning at Dec. 31, 2012	$16,302	$32,770,540	($17,074,865)	$19,757,680
Balance, beginning, shares at Dec. 31, 2012	16,301,946
Issuance of shares to Red Mountain Resources, Inc. upon conversion of unsecured liabilities	612	409,180		409,792
Issuance of shares to Red Mountain Resources, Inc. upon conversion of unsecured liabilities, shares	611,630
Issuance of shares to settle creditors payable claims	422	282,753		283,175
Issuance of shares to settle creditors payable claims, shares	422,650
Net income (loss) attributable to common shareholders			3,352,736	3,352,736
Balance, ending at Dec. 31, 2013	17,336	33,462,473	-13,722,129	19,757,680
Balance, ending, shares at Dec. 31, 2013	17,336,226
Net income (loss) attributable to common shareholders			-2,463,629	-2,463,629
Balance, ending at Dec. 31, 2014	$17,336	$33,462,473	($16,185,758)	$17,294,053
Balance, ending, shares at Dec. 31, 2014	17,336,226

Organization

Organization	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	1.   Organization
	Nature of Operations
	Cross Border Resources, Inc. (the Company) is an independent natural gas and oil company engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America.  The Company’s area of focus is the State of New Mexico, particularly southeastern New Mexico.  The Company has two wholly-owned subsidiaries, which are inactive: Doral West Corporation and Pure Energy Operating, Inc, and accordingly are not consolidated in these financial statements.

Going_Concern

Going Concern	12 Months Ended
	Dec. 31, 2014
Going Concern
Going Concern	2.   Going Concern
	At December 31, 2014, the Company had working capital of $3,259,133 (including Assets Held for Sale of $15,617,472) and outstanding debt of $8,200,000 (consisting of a line of credit). The company would have a working capital deficit of $10,763,628 (excluding Assets Held for Sale, Net of ARO Liabilities associated with the Assets Held for Sale). The Company was not in compliance with the covenants of its line of credit with Independent Bank and had no availability under this line of credit. The Company currently does not have sufficient funds to repay these obligations. The Company is exploring available financing options, including the sale of debt, equity, or assets. If the Company is unable to finance its operations on acceptable terms or at all, its business, financial condition and results of operations may be materially and adversely affected. As a result of these conditions, there is substantial doubt regarding the Company's ability to continue as a going concern. The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Company to continue as a going concern.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	3.   Summary of Significant Accounting Policies
	Reclassification
	Certain amounts have been reclassified to conform with the current period presentation. The amounts reclassified did not have an effect on the Company’s results of operations or stockholders’ equity.
	Cash and cash equivalents
	The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. The Company monitors the soundness of the financial institutions and believes the Company’s risk is negligible.
	Financial instruments
	The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and long-term debt, approximate fair value as of December 31, 2014 and 2013.
	Oil and natural gas properties
	The Company follows the successful efforts method of accounting for its oil and natural gas producing activities.  Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If the Company determines that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at December 31, 2014 or December 31, 2013. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through December 31, 2014, the Company had capitalized no interest costs because its exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
	On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.
	Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”). The ratio of six Mcf of natural gas to one Boe is based upon energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.
	It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. The Company records these advance payments in prepaid and other current assets and release this account when the actual expenditure is later billed to it by the operator.
	On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
	Impairment of long-lived assets
	The Company evaluates its long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
	Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, the Company’s history in exploring the area, the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
	Revenue and accounts receivable
	The Company recognizes revenue for its production when the quantities are delivered to, or collected by, the purchaser. Prices for such production are generally defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.
	Accounts receivable—oil and natural gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—other consist of amounts owed from interest owners of the Company’s operated wells.  No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible.  There was no reserve for bad debts as of December 31, 2014 or December 31, 2013.
	Other property
	Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.
	Income taxes
	The Company is subject to U.S. federal income taxes along with state income taxes in New Mexico. When tax returns are filed, it is highly certain that 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 that 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 sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the Company’s Statements of Operations. The Company accrues interest and penalties, if any, related to unrecognized tax benefits as a component of income tax expense.
	Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.
	Asset retirement obligations
	Asset retirement obligations (“AROs”) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
	Earnings per common share
	The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.
	Recently issued accounting pronouncements
	In April 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition ofdiscontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, the Company does not expect the adoption of ASU 2014-08 to have a material impact on our financial statements or results of operations.
	Effective January 1, 2016, the Company will be required to adopt the amended guidance of Accounting Standards Codification (ASC) Topic 718, Compensation - Stock Compensation, which seeks to resolve the diversity in practice that exists when accounting for share-based payments. The amended guidance requires a performance target that affects vesting and that could be achieved after the requisite service period to be treated as a performance condition.
	The Company will be required to adopt the amended guidance either prospectively to all awards granted or modified after the effective date or retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the consolidated financial statements and to all new or modified awards thereafter. The Company does not expect the adoption of this amended guidance to impact financial results.
	Effective January 1, 2016, the Company will be required to adopt the amended guidance of ASC Topic 810, Consolidation (Topic 810), which seeks to improve targeted areas of the consolidation guidance for legal entities such as limited partnerships, limited liability corporations, and securitization structures. The amended guidance changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The changes include, among others, modification of the evaluation whether limited partnerships and similar legal entities are variable interest entities or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. The Company will be required to adopt Topic 810 either on a full retrospective basis to each prior reporting period presented or on a modified retrospective basis with the cumulative effect of initially applying the new guidance recognized at the date of initial application. The Company has not yet completed its assessment of the impact of the amended guidance on its financial statements but does not expect the adoption of this amended guidance to have a significant impact on financial results.
	Effective January 1, 2017, the Company will be required to adopt the new guidance of ASC Topic 606, Revenue from Contracts with Customers (Topic 606), which will supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition. Topic 606 requires the Company to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance requires the Company to apply the following steps: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when, or as, the Company satisfies a performance obligation. The Company will be required to adopt Topic 606 either on a full retrospective basis to each prior reporting period presented or on a modified retrospective basis with the cumulative effect of initially applying the new guidance recognized at the date of initial application. If the Company elects the modified retrospective approach, it will be required to provide additional disclosures of the amount by which each financial statement line item is affected in the current reporting period, as compared to the guidance that was in effect before the change, and an explanation of the reasons for significant changes. The Company has not yet completed its assessment of the impact of the new guidance on its consolidated financial statements. On April 29, 2015, the Financial Accounting Standards Board issued a proposed Accounting Standards Update (FASB) to defer the effective date of Topic 606 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. If the FASB proceeds with the deferral of the effective date as proposed, this will mean the Company will be required to adopt the new guidance of ASC 606 effective January 1, 2018.
	In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), an amendment to FASB Accounting Standards Codification (“ASC”) Topic 205, Presentation of Financial Statements. This update provides guidance on management’s responsibility in evaluating whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Company does not expect the adoption of ASU 2014-15 to have a material impact on our financial statements or results of operations. If events occur in future periods that could affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.
	The Company has reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our results of operations, financial position and cash flows. Based on that review, we believe that none of these recent pronouncements will have a significant effect on our current or future earnings or operations.

Asset_retirement_obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	4.   Asset retirement obligations
	The following is a description of the changes to the Company’s asset retirement obligations for the years ended December 31, 2014 and December 31, 2013:
		December 31,			December 31,
		2014			2013
	Asset retirement obligations at beginning of year	$	3,515,898		$	3,317,358
	Loss on Settlement		(926	)		—
	Settlement of liabilities		(3,314	)		(1,114	)
	Revision of previous estimates		(554,287	)		—
	Accretion expense		185,773			148,364
	Additions		46,447			51,290
	Asset retirement obligations at end of year	$	3,189,421		$	3,515,898
	ARO classified as liabilities associated with assets held for sale		1,594,711			—
	ARO, Non-Current	$	1,594,710		$	3,515,898

Property_and_equipment

Property and equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property and equipment	5.   Property and equipment
	Oil and natural gas properties
	The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:
		December 31,			December 31,
		2014			2013
	Oil and natural gas properties	$	27,243,106		$	56,561,040
	Less accumulated depletion and impairment		(11,956,319	)		(20,941,867	)
	Net oil and natural gas properties capitalized costs	$	15,286,787		$	35,619,173
	Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on the Company’s analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income equal to the difference between carrying value and the estimated fair value of the properties. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and natural gas production, operating and development costs, and discount rates.
	Uncertainties affect the recoverability of these costs as the recovery of the costs outlined above are dependent upon the Company obtaining and maintaining leases and achieving commercial production or sale.
	During the year ended December 31, 2014, the Company recorded a $6.5 million impairment charge against its oil and gas assets. Additionally, the Company reclassified half of its oil and gas assets to assets held for sale.
	Other property and equipment
	The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation is summarized as follows:
		December 31,			December 31,
		2014			2013
	Other property and equipment	$	136,535		$	130,470
	Less accumulated depreciation		(110,277	)		(95,828	)
	Net property and equipment	$	26,258		$	34,641

Stockholders_equity_and_earnin

Stockholders' equity and earnings per share	12 Months Ended
	Dec. 31, 2014
Stockholders' Equity Note [Abstract]
Stockholders' equity and earnings per share	6.   Stockholders’ equity and earnings per share
	2011 Equity Financing
	On May 26, 2011, the Company closed a private offering exempt from registration under the Securities Act of 1933 pursuant to Rule 506 of Regulation D promulgated thereunder.  In the offering, the Company issued an aggregate of 3,600,000 units.  Each unit was sold at $1.50 and was comprised of one share of common stock and one five-year warrant to purchase a share of common stock at an exercise price of $2.25 per share.   The warrants became exercisable on November 26, 2011.  The Company agreed to use the net proceeds from the sale of the units for general business and working capital purposes and not to use such proceeds for the redemption of any common stock or common stock equivalents.
	The investors in the offering (“Selling Stockholders”) received registration rights.  The Company agreed to file a registration statement covering the resale of the common stock issued and the common stock underlying the warrants issued to the Selling Stockholders within sixty days after the closing date.  If the registration statement was not declared effective by the SEC within the time periods defined within the agreement, then the Company would have made pro rata cash payments to each Selling Stockholder as liquidated damages in an amount equal to 1.0% of the aggregate amount invested by such Selling Stockholder for each 30-day period or pro rata for any portion thereof following the date by which such Registration Statement should have been effective.  If at the time of exercise of the warrants there is no effective registration statement covering the resale of the shares underlying the warrant, then the Selling Stockholders have the right at such time to exercise warrants in full or in part on a cashless basis. The Company filed an S-1 registration statement registering the shares on July 25, 2011, which was declared effective on August 5, 2011. In April 2015, the foregoing registration statement was terminated by the Company.
	In addition to registration rights, the Selling Stockholders were offered a right of first refusal to participate in future offerings of common stock if the principal purpose of which was to raise capital.  This right of first refusal terminated upon the one-year anniversary of the closing date.
	Warrants
	In connection with the equity offering closed on May 26, 2011, the Company issued warrants to purchase an aggregate of 3,600,000 shares of the Company’s common stock at a per share price of $2.25 (the "$2.25 Warrants").  The Company also has outstanding warrants to purchase 3,125 shares of the Company’s common stock at a per share price of $5.00.  The $2.25 Warrants became exercisable in November 2011 and expire in November 2015. On the date of issuance, the warrants were valued at $898,384. Management determined the fair value of the warrants based upon the Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of the Company’s common stock on the OTCBB on the date of issuance. The volatility and remaining term was 50% and 2.92 years, respectively. The Company does not expect the immediate exercise of these warrants as the exercise price exceeds the average closing market price for the Company's common stock. Furthermore, no assurances can be made that any of the warrants will ever be exercised for cash or at all.
	Stock Options
	In 2011, the Company issued options to purchase 87,500 shares of its common stock at $4.80 to its directors.  For the year ended December 31, 2014 and 2013, there was no stock based compensation.
	Stock option activity summary is presented in the table below:
						Weighted-
						average
					Weighted-	Remaining
					average	Contractual
			Number of		Exercise	Term
			Shares		Price	(years)
	Outstanding and exercisable December 31, 2012		87,500	$	4.8	4.08
	Granted		—		—	—
	Cancelled		—		—	—
	Exercised		—		—	—
	Forfeited		—		—	—
	Expired		—		—	—
	Outstanding and exercisable at December 31, 2013		87,500	$	4.8	3.08
	Granted		—		—	—
	Cancelled		—		—	—
	Exercised		—		—	—
	Forfeited		—		—	—
	Expired		—		—	—
	Outstanding and exercisable at December 31, 2014		87,500	$	4.8	2.08
	There is no intrinsic value in the outstanding options since the option price is in excess of the market price of the Company's common stock.
	The fair value of the options granted during 2011 was estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions:
	Closing market price of stock on grant date	$3.11
	Risk-free interest rate	2.43%
	Dividend yield	0.00%
	Volatility factor	50%
	Expected life	2.5 years
	The Company elected to use the “simplified” method to calculate the estimated life of options granted to employees. The use of the “simplified” method has been extended until such time when the Company has sufficient information to make more refined estimates on the estimated life of its options. The expected stock price volatility was calculated by averaging the historical volatility of the Company’s common stock over a term equal to the expected life of the options.
	Issuance of Common Shares to Settle Creditors Payable
	The Company entered into settlement agreements with two of the creditors payable arising out of the 2002 bankruptcy. The Company paid the creditors $633,975 in cash and the Company’s largest shareholder, Red Mountain Resources, Inc. (“RMR”), issued approximately 750,000 shares of its common stock to the creditors in settlement of the claims. In return for RMR issuing its shares to the creditors payable, the Company issued RMR 422,650 shares of its common stock.
	Conversion of Notes Payable
	On February 28, 2013, RMR, the holder of the Green Shoe and Little Bay notes, elected to convert the outstanding notes and accrued interest into common shares. The board of directors of the Company had previously resolved to change the conversion feature from $4.00 per common share to $1.50 per common share. As a result, the Company issued 611,630 common shares to RMR.

Related_party_transactions

Related party transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related party transactions	7.   Related party transactions
	The Company and RMR are party to a Technical Services Agreement under which RMR incurs costs on behalf of the Company, primarily related to wells in the Company’s Tom Tom and Tomahawk fields. During the year ended December 31, 2014, RMR incurred approximately $1,880,000 on behalf of the Company. During the period ended December 31, 2014, the Company advanced RMR $5,880,000 to use for its general and administrative and operating costs. Effective June 30, 2014 and December 31, 2014 RMR assumed $3,000,000 and $1,000,000, respectively, of the Company’s obligation under the Credit Facility
	The net amount of $0 is shown on the Company’s balance sheet under the caption Accounts Receivable – Related Party.

Long_term_debt

Long term debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long term debt	8.   Long term debt
	Operating Line of Credit
	On February 5, 2013, the Company entered into a Senior First Lien Secured Credit Agreement with RMR, Black Rock Capital, Inc. and RMR Operating, LLC, as borrowers (the “Borrowers”) and Independent Bank, as Lender, providing for an up to $100,000,000 credit facility (the “Credit Facility”). RMR owns approximately 83% of the outstanding common stock of Cross Border, and Black Rock and RMR Operating are wholly owned subsidiaries of RMR. On February 5, 2013, the Company drew $8,900,000 on the line of credit and used those funds to pay off its prior line of credit and associated accrued interest. On February 29, 2013, the Company drew $2,000,000 and on May 24, 2013, the Company drew a further $1,300,000 on the line of credit and used those funds to pay accounts payable related to the drilling program. Effective June 30, 2014, RMR assumed the Company’s obligations with respect to $3,000,000 of the Company’s outstanding borrowings under the Credit Facility in exchange for the satisfaction and discharge of a $2,900,000 intercompany payable from RMR to the Company. Effective December 31, 2014, RMR assumed the Company’s obligation with respect to $1,000,000 of the Company’s outstanding borrowings under the Credit Facility in exchange for the satisfaction and discharge of a $1,000,000 intercompany payable from RMR to the Company.
	The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base.
	As of December 31, 2014, the Company’s outstanding borrowings under the line of credit were $8,200,000 and the Company was not in compliance with all debt covenants. The Company received waivers from the lenders for covenants that were not in compliance.
	On March 11, 2015, the Company entered into an amendment and waiver (the “Third Amendment”) to the Senior First Lien Secured Credit Agreement, dated February 5, 2013, as amended (the “Credit Agreement”), with RMR, Black Rock and RMR Operating (together with the Company, the “Borrowers”) and Independent Bank (“Lender”). Pursuant to the Third Amendment, (i) the Lender waived any default or right to exercise any remedy as a result of the failure by the Borrowers to be in compliance with the requirements of Section 6.18 of the Credit Agreement with respect to the permitted ratio of consolidated current assets to consolidated current liabilities of Borrowers for the fiscal quarter ended September 30, 2014; and (ii) the borrowing base was decreased from $30 million to $27.8 million, effective as of March 1, 2015, and the commitment amount was decreased to $27.8 million, subject to monthly commitment reductions of $350,000 beginning March 1, 2015.
	On April 21, 2015, the Company entered into an amendment (the “Fourth Amendment”) to the Credit Agreement, with the other Borrowers and the Lender. Pursuant to the Fourth Amendment, the borrowing base was decreased from $27.8 million to $12.4 million, effective as of April 21, 2015, and the commitment amount was decreased to $12.4 million. In addition, the monthly commitment reduction amount was set to $0 as of April 1, 2015.

Commitments_and_contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	9.   Commitments and contingencies
	Litigation
	The Company, the Company’s former Chief Executive Officer, and the Company’s former Chief Operating Officer are party to a lawsuit with a former employee. On May 4, 2011, Clifton M. (Marty) Bloodworth initially filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. (the predecessor entity of Cross Border) (“Doral Energy”) and Everett Willard Gray II, the Company’s former Chief Executive Officer. Mr. Bloodworth later amended his lawsuit to name Horace Patrick Seale, the Company’s former Chief Operating Officer, as an additional defendant. Mr. Bloodworth generally alleges that Mr. Gray and Mr. Seale, as agents of the Company, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by the Company. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral Energy, fraud in the inducement and common law fraud, civil conspiracy, breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray, Mr. Seale and the Company deny that Mr. Bloodworth’s claims have any merit.
	The Company was previously party to an engagement letter, dated February 7, 2012 (the “Engagement Letter”) with KeyBanc Capital Markets Inc. (“KeyBanc”) pursuant to which KeyBanc was to act as exclusive financial advisor to the Company’s board of directors in connection with a possible “Transaction” (as defined in the Engagement Letter). The Engagement Letter was formally terminated by the Company on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to the Company representing a fee and out-of-pocket expenses purportedly owed by the Company to KeyBanc as a result of the consummation of a purported Transaction that KeyBanc asserts had been consummated within the required time period. The Company disputed that any Transaction was consummated and that KeyBanc was entitled to any fees or out-of-pocket expenses. The Company filed a complaint seeking (i) a declaration that it was not liable to KeyBanc for any amounts in connection with the Engagement Letter, (ii) attorneys’ fees, and (iii) costs of suit. KeyBanc filed a counterclaim seeking (i) compensatory damages, (ii) interest, (iii) expenses and court costs, and (iv) reasonable and necessary attorneys’ fees. The matter was originally filed in the 44th Judicial District Court for the State of Texas, Dallas County but was subsequently removed to the United States District Court for the Northern District of Texas, Dallas Division. On August 26, 2014, the Company entered into a settlement agreement with KeyBanc, settling a lawsuit between the parties. In connection with the settlement, the Company agreed to pay KeyBanc $900,000 in three equal installments of $300,000 each on or before August 28, 2014, October 31, 2014 and December 31, 2014, and the parties agreed to mutual releases of liability related to the Engagement Letter. This balance was paid in full at December 31, 2014.
	In addition to the foregoing, in the ordinary course of business, the Company is periodically a party to various litigation matters that it does not believe will have a material adverse effect on its results of operations or financial condition.
	Environmental Contingencies
	The Company is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in all oil and natural gas operations, and the Company could be subject to environmental cleanup and enforcement actions. The Company manages this environmental risk through appropriate environmental policies and practices to minimize the impact to the Company.
	As of December 31, 2014 and 2013, the Company had approximately $2.1 million in environmental remediation liabilities related to the Company’s operated Tom Tom and Tomahawk fields located in Chaves and Roosevelt counties in New Mexico. In February 2013, the Bureau of Land Management (“BLM”) accepted the Company’s remediation plan for the Tom Tom and Tomahawk fields. The Company is working in conjunction with the BLM to initiate remediation on a site-by-site basis. This is management’s best estimate of the costs of remediation and restoration with respect to these environmental matters, although the ultimate cost could differ materially. Inherent uncertainties exist in these estimates due to unknown conditions, changing governmental regulation, and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration. Pursuant to the PSA dated April 21, 2015 between the Companies and the Buyer, the Companies retained certain obligations and covenanted to bear and pay all costs attributable to the Tom Tom and Tomahawk fields as further defined in the PSA. The Company expects to incur the remaining costs during the next fiscal year.

Price_risk_management_activiti

Price risk management activities	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price risk management activities	10.   Price risk management activities
	ASC 815-25 (formerly SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”) requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of each derivative are recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. When choosing to designate a derivative as a hedge, management formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring effectiveness. This process includes linking all derivatives that are designated as cash-flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions. Based on the above, management has determined the swaps noted below do not qualify for hedge accounting treatment.
	At December 31, 2014, the Company had a net derivative asset of $0, as compared to a net derivative liability of $38,109 at December 31, 2013.  The change in net derivative asset/liability is recorded as non-cash mark-to-market income or loss.  Mark-to-market income of $0 was recorded in the twelve months ended December 31, 2014 as compared to mark-to-market income of $283,831 during the year ended December 31, 2013.  Net realized hedge settlement loss for the year ended December 31, 2014 was $3,479 as compared to net realized hedge settlement loss of $14,062 for the twelve months ended December 31, 2013.  The combination of these two components of derivative expense/income is reflected in "Other Income (Expense)" on the Statements of Operations as "Gain (loss) on derivatives."
	As of December 31, 2014, the Company had not crude oil swaps in place remaining.
							Fair Value of Outstanding
					Price	Volumes	Derivative Contracts (1)
							as of
	Transaction				Per	Per		December 31,		December
	Date	Type (2)	Beginning	Ending	Unit	Month		2014		31, 2013
	Nov-11	Swap	12/1/11	11/30/14	$93.50	2,000		—		-62,730
	Feb-12	Swap	3/1/12	2/28/14	$106.50	1,000		—		24,621
							$	—	$	-38,109
	(1) The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. All of our derivatives were with the same counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities.
	(2) These crude oil hedges were entered into on a per barrel delivered price basis, using the NYMEX - West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	11.   Fair Value Measurements
	Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
		Level 1 –	quoted prices for identical assets or liabilities in active markets.
		Level 2 –	quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.
		Level 3 –	unobservable inputs for the asset or liability.
	The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.
	The following tables summarize the valuation of the Company’s financial assets and liabilities at December 31, 2014 and December 31, 2013:
			Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets or Liabilities		Significant or Other Observable Inputs			Significant Unobservable Inputs			Fair Value at
			(Level 1)		(Level 2)			(Level 3)			31-Dec-14
	Liabilities
	Environmental liability		$	—	$	—		$	(2,057,175	)	$	(2,057,175	)
	Assets associated with liabilities held for sale			—		—			(1,594,711	)		(1,594,711	)
	Asset retirement obligations (non-recurring)		$	—	$	—		$	(1,594,710	)	$	(1,594,710	)
	Total		$	—	$	—		$	(5,246,596	)	$	(5,246,596	)
			Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets or Liabilities		Significant or Other Observable Inputs						Fair Value at  December 31, 2013
			(Level 1)		(Level 2)			Significant Unobservable Inputs
								(Level 3)
	Assets:
	Commodities derivatives		$	—	$	3,504		$	—		$	3,504
	Total		$	—	$	3,504		$	—		$	3,504
	Liabilities:
	Environmental liability		$	—	$	—		$	(2,086,973	)	$	(2,086,973	)
	Commodities derivatives			—		(38,109	)					(38,109	)
	Asset retirement obligations (non-recurring)			—		—			(3,514,898	)		(3,514,898	)
	Total		$	—	$	(38,109	)	$	(5,601,871	)	$	(5,639,980	)

Supplemental_information_relat

Supplemental information relating to oil and natural gas producing activities (unaudited)	12 Months Ended
	Dec. 31, 2014
Supplemental Information Relating To Oil And Natural Gas Producing Activities
Supplemental information relating to oil and natural gas producing activities (unaudited)	12.   Supplemental information relating to oil and natural gas producing activities (unaudited)
	Costs incurred in oil and natural gas property acquisition, exploration and development
	Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities:
			Year Ended December 31,
			2014			2013
	Property acquisition costs:
	Unproved properties		$	—		$	—
	Proved properties			—			—
	Exploration costs			—			—
	Development costs (1)			4,360,946			8,312,662
	Total costs incurred		$	4,360,946		$	8,312,662
		-1	For the years ended December 31, 2014 and 2013, development costs included ($508,711) and $51,290, respectively, in non-cash, asset retirement costs.
	Results of operations for oil and natural gas producing activities
	Set forth below is certain information regarding the results of operations for oil and gas producing activities:
			Year Ended December 31,
			2014			2013
	Revenues		$	12,352,299		$	13,125,960
	Production costs			2,287,908			2,300,899
	Depletion and impairment			9,154,536			4,941,614
	Accretion expense			185,773			148,364
	Natural gas marketing			102,736			78,211
	Production taxes			999,395			1,246,153
	Results of operations		$	(378,049	)	$	4,410,719
	Proved reserves
	Cawley, Gillespie and Associates, Inc, independent petroleum engineers estimated 100% of the proved reserve information for the Company properties as of December 31, 2014 and 2013. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current provisions of ASC 932, Extractive Activities.
	Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of the Company’s estimated oil and natural gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2014 and 2013 are as follows:
			Oil (MBbl)			Natural Gas (MMcf)			Total (Mboe)
	31-Dec-12			1,271			1,695			1,554
	Acquisitions			—			—			—
	Extensions and Discoveries			371			817			507
	Revisions to Previous Estimates			11			906			161
	Production			(123	)		(283	)		(170	)
	31-Dec-13			1,530			3,135			2,052
	Acquisitions			—			—			—
	Extensions and Discoveries			250			477			330
	Revisions to Previous Estimates			43			503			127
	Production			(128	)		(375	)		(190	)
	31-Dec-14			1,695			3,740			2,319
	Proved Developed Reserves
	31-Dec-13			804			2,215			1,173
	31-Dec-14			916			2,691			1,364
	Proved Undeveloped Reserves
	31-Dec-13			726			920			879
	31-Dec-14			780			1,050			955
	Standardized measure of discounted future net cash flows relating to proved reserves
	Future cash inflows were computed by applying the average on the closing price on the first day of each month for the 12-month period prior to December 31, 2014 to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.
	Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved.
	Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company’s oil and natural gas properties.
	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
			Year Ended December 31,
			2014			2013
	Future cash inflows		$	172,561,969		$	153,544,250
	Future production costs			(48,818,696	)		(41,381,543	)
	Future development costs			(18,080,062	)		(18,821,422	)
	Future income tax expense			(26,902,690	)		(20,243,102	)
	Future net cash flows			78,760,521			73,098,179
	10% annual discount for estimated timing of cash flows			(41,988,630	)		(36,817,148	)
	Standardized measure of discounted future net cash flows		$	36,771,891		$	36,281,031
	Changes in standardized measure of discounted future net cash flows
	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
			Year Ended December 31,
			2014			2013
	Balance, beginning of year		$	36,281,031		$	28,147,572
	Net change in sales and transfer prices and in production (lifting) costs related to future production			1,728,874			9,374,986	)
Changes in estimated future development costs			5,076,840			4,042,730
Sales and transfers of oil and natural gas produced during the period			(8,962,260	)		(10,825,061	)
Net change due to extensions and discoveries			8,255,840			12,107,955	)
Net change due to revisions in quantity estimates			3,182,507			3,883,464
Previously estimated development costs incurred during the period			(4,360,946	)		(8,312,662	)
Accretion of discount			4,899,710			2,747,142
Other			(2,791,193	)		(672,750	)
Net change in income taxes			(6,538,512	)		(4,212,345	)
Balance, end of year		$	36,771,891		$	36,281,031

Income_taxes

Income taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes
Income taxes	13 – Income Taxes
	Total income tax expense (benefit) differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income:
		Year Ended December 31,
	(in thousands)	2014			2013
	Income taxes at U.S. statutory rate		-838			1,140
	State taxes, net of federal impact		-65			88
	Change in valuation allowance		937			(1,229	)
	Permanent differences		0			1
	Other differences		(34	)		0
	Total		0			0
	Deferred tax assets/(liabilities) consist of the following:
		Year Ended December 31,
	(in thousands)	2014			2013
	Derivatives		(0	)		-34
	Valuation allowance		(6,909	)		(5,972	)
	Difference in depreciation and capitalization methods-natural gas properties,		(8,826	)		(3,444	)
	Accrued expenses		776			765
	Net operating losses		14,959			8,685
	Total		0			0
	Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. The Company’s net deferred tax assets and liabilities are recorded as a long-term liability of $0 at December 31, 2014 and 2013, respectively.
	As of December 31, 2014, the Company had net operating loss carryfowards (“NOLs”) of approximately $40.8 million which will begin to expire, if unused, in 2026.
	The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration.  Management monitors Company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company's NOLs and other deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized prior to their expiration.  The Company establishes a valuation allowance to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2014, and 2013 the Company had a valuation allowance of $6.9 million and $6.0 million, respectively, related to its deferred tax assets.
	The company recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. We have not taken a tax position that, if challenged, would have a material effect on the financial statements or the effective tax rate for the periods ended December 31, 2013 and December 31, 2012. There were no interest and penalties related to unrecognized tax positions for the periods ended December 31, 2013 and December 31, 2012. The tax years subject to examination by tax jurisdictions in the United States are 2009 through 2012.

Assets_and_Liabilities_Held_Fo

Assets and Liabilities Held For Sale	12 Months Ended
	Dec. 31, 2014
Assets And Liabilities Held For Sale
Assets and Liabilities Held For Sale	14.   Assets and Liabilities Associated with Assets Held for Sale
	On April 21, 2015, the Company entered into a purchase and sale agreement (the “PSA”) with RMR Operating, LLC (“RMR Operating”), Black Rock Capital, Inc. (“Black Rock”), RMR KS Holdings, LLC (“RMR KS”) and Black Shale Minerals, LLC (“Buyer”). Each of the Company, RMR Operating, Black Rock and RMR KS is an operating subsidiary (together, the “Operating Subsidiaries”) of Red Mountain Resources, Inc. (“RMR,” and together with the Operating Subsidiaries, the “Companies”).
	Pursuant to the PSA the Operating Subsidiaries sold, assigned, transferred and conveyed to Buyer, effective as of April 1, 2015, fifty percent (50%) of their right, title, and interest in and to certain oil and natural gas assets and properties (the “Assets”), including their oil and natural gas leasehold interests, wells, contracts, and oil and natural gas produced after April 1, 2015 (the “Sale”). The aggregate purchase price for the Assets under the PSA was $25.0 million, subject to certain adjustments, including post-closing adjustments for any title or environmental benefits or title or environmental defects resulting from Buyer’s title and environmental reviews.
	As of December 31, 2014, the carrying values of the Company’s ownership in half of its interest in its oil and gas properties, mineral interests, and leaseholds were included in assets and liabilities held for sale in the accompanying balance sheet and were comprised of the following (the Company had no assets held for sale as of December 31, 2013):
		December 31,
		2014
	Composition of assets included in assets held for sale:
	Oil and Gas Properties, Net	$	15,617,472
	Composition of liabilities included in liabilities held for sale:
	Asset Retirement Obligations	$	1,594,711
	Non-current assets and liabilities held for sale are presented in current assets and current liabilities, respectively, within the balance sheet. Assets held for sale are not depreciated, depleted or amortized and they are measured at the lower of the fair value less costs to sell and their carrying amount. Comparative period balance sheets are not restated.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	15.   Subsequent Events
	Purchase and Sale Agreement
	On April 21, 2015, the Company entered into a purchase and sale agreement (the “PSA”) with RMR Operating, LLC (“RMR Operating”), Black Rock Capital, Inc. (“Black Rock”), RMR KS Holdings, LLC (“RMR KS”) and Black Shale Minerals, LLC (“Buyer”). Each of the Company, RMR Operating, Black Rock and RMR KS is an operating subsidiary (together, the “Operating Subsidiaries”) of Red Mountain Resources, Inc. (“RMR,” and together with the Operating Subsidiaries, the “Companies”).
	Pursuant to the PSA the Operating Subsidiaries sold, assigned, transferred and conveyed to Buyer, effective as of April 1, 2015, fifty percent (50%) of their right, title, and interest in and to certain oil and natural gas assets and properties (the “Assets”), including their oil and natural gas leasehold interests, wells, contracts, and oil and natural gas produced after April 1, 2015 (the “Sale”). The aggregate purchase price for the Assets under the PSA was $25.0 million, subject to certain adjustments, including post-closing adjustments for any title or environmental benefits or title or environmental defects resulting from Buyer’s title and environmental reviews.
	The PSA contains customary representations, warranties and covenants. Pursuant to the PSA, the Operating Subsidiaries and Buyer have agreed to indemnify each other, their respective affiliates and their respective employees, officers, directors, managers, shareholders, members, partners, or representatives from and against all losses that such indemnified parties incur arising from any breach of representations, warranties or covenants in the PSA and certain other matters.
	The Companies intend to use the cash consideration from the Sale to repay a portion of the outstanding balance on the Credit Agreement (as defined below), pay accounts receivable and for working capital.
	Third Amendment and Waiver to the Credit Agreement
	On March 11, 2015, the Company entered into an amendment and waiver (the “Third Amendment”) to the Senior First Lien Secured Credit Agreement, dated February 5, 2013, as amended (the “Credit Agreement”), with RMR, Black Rock and RMR Operating (together with the Company, the “Borrowers”) and Independent Bank (“Lender”). Pursuant to the Third Amendment, (i) the Lender waived any default or right to exercise any remedy as a result of the failure by the Borrowers to be in compliance with the requirements of Section 6.18 of the Credit Agreement with respect to the permitted ratio of consolidated current assets to consolidated current liabilities of Borrowers for the fiscal quarter ended September 30, 2014; and (ii) the borrowing base was decreased from $30 million to $27.8 million, effective as of March 1, 2015, and the commitment amount was decreased to $27.8 million, subject to monthly commitment reductions of $350,000 beginning March 1, 2015.
	Fourth Amendment to the Credit Agreement
	In conjunction with the PSA, on April 21, 2015, the Company entered into an amendment (the “Fourth Amendment”) to the Credit Agreement, with the other Borrowers and the Lender. Pursuant to the Fourth Amendment, the borrowing base was decreased from $27.8 million to $12.4 million, effective as of April 21, 2015, and the commitment amount was decreased to $12.4 million. In addition, the monthly commitment reduction amount was set to $0 as of April 1, 2015.
	The Company has evaluated its subsequent events through the date of the financial statements that were available for filing with the SEC.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Reclassification	Reclassification
	Certain amounts have been reclassified to conform with the current period presentation. The amounts reclassified did not have an effect on the Company’s results of operations or stockholders’ equity.
Cash and cash equivalents	Cash and cash equivalents
	The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. The Company monitors the soundness of the financial institutions and believes the Company’s risk is negligible.
Financial instruments	Financial instruments
	The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and long-term debt, approximate fair value as of December 31, 2014 and December 31, 2013.
Oil and natural gas properties	Oil and natural gas properties
	The Company follows the successful efforts method of accounting for its oil and natural gas producing activities.  Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If the Company determines that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at December 31, 2014 or December 31, 2013. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through December 31, 2014, the Company had capitalized no interest costs because its exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
	On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.
	Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”). The ratio of six Mcf of natural gas to one Boe is based upon energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.
	It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. The Company records these advance payments in prepaid and other current assets and release this account when the actual expenditure is later billed to it by the operator.
	On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Impairment of long-lived assets	Impairment of long-lived assets
	The Company evaluates its long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
	Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, the Company’s history in exploring the area, the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Revenue and accounts receivable	Revenue and accounts receivable
	The Company recognizes revenue for its production when the quantities are delivered to, or collected by, the purchaser. Prices for such production are generally defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.
	Accounts receivable—oil and natural gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—other consist of amounts owed from interest owners of the Company’s operated wells.  No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible.  There was no reserve for bad debts as of December 31, 2014 or December 31, 2013.
Other property	Other property
	Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.
Income taxes	Income taxes
	The Company is subject to U.S. federal income taxes along with state income taxes in New Mexico. When tax returns are filed, it is highly certain that 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 that 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 sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the Company’s Statements of Operations. The Company accrues interest and penalties, if any, related to unrecognized tax benefits as a component of income tax expense.
	Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.
Asset retirement obligations	Asset retirement obligations
	Asset retirement obligations (“AROs”) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Earnings per common share
	Earnings per common share
	The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.
Recently issued accounting pronouncements	Recently issued accounting pronouncements
	In April 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition ofdiscontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, the Company does not expect the adoption of ASU 2014-08 to have a material impact on our financial statements or results of operations.
	Effective January 1, 2016, the Company will be required to adopt the amended guidance of Accounting Standards Codification (ASC) Topic 718, Compensation - Stock Compensation, which seeks to resolve the diversity in practice that exists when accounting for share-based payments. The amended guidance requires a performance target that affects vesting and that could be achieved after the requisite service period to be treated as a performance condition.
	The Company will be required to adopt the amended guidance either prospectively to all awards granted or modified after the effective date or retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the consolidated financial statements and to all new or modified awards thereafter. The Company does not expect the adoption of this amended guidance to impact financial results.
	Effective January 1, 2016, the Company will be required to adopt the amended guidance of ASC Topic 810, Consolidation (Topic 810), which seeks to improve targeted areas of the consolidation guidance for legal entities such as limited partnerships, limited liability corporations, and securitization structures. The amended guidance changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The changes include, among others, modification of the evaluation whether limited partnerships and similar legal entities are variable interest entities or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. The Company will be required to adopt Topic 810 either on a full retrospective basis to each prior reporting period presented or on a modified retrospective basis with the cumulative effect of initially applying the new guidance recognized at the date of initial application. The Company has not yet completed its assessment of the impact of the amended guidance on its financial statements but does not expect the adoption of this amended guidance to have a significant impact on financial results.
	Effective January 1, 2017, the Company will be required to adopt the new guidance of ASC Topic 606, Revenue from Contracts with Customers (Topic 606), which will supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition. Topic 606 requires the Company to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance requires the Company to apply the following steps: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when, or as, the Company satisfies a performance obligation. The Company will be required to adopt Topic 606 either on a full retrospective basis to each prior reporting period presented or on a modified retrospective basis with the cumulative effect of initially applying the new guidance recognized at the date of initial application. If the Company elects the modified retrospective approach, it will be required to provide additional disclosures of the amount by which each financial statement line item is affected in the current reporting period, as compared to the guidance that was in effect before the change, and an explanation of the reasons for significant changes. The Company has not yet completed its assessment of the impact of the new guidance on its consolidated financial statements. On April 29, 2015, the Financial Accounting Standards Board issued a proposed Accounting Standards Update (FASB) to defer the effective date of Topic 606 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. If the FASB proceeds with the deferral of the effective date as proposed, this will mean the Company will be required to adopt the new guidance of ASC 606 effective January 1, 2018.
	In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), an amendment to FASB Accounting Standards Codification (“ASC”) Topic 205, Presentation of Financial Statements. This update provides guidance on management’s responsibility in evaluating whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Company does not expect the adoption of ASU 2014-15 to have a material impact on our financial statements or results of operations. If events occur in future periods that could affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.
	The Company has reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our results of operations, financial position and cash flows. Based on that review, we believe that none of these recent pronouncements will have a significant effect on our current or future earnings or operations.

Asset_retirement_obligations_T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of changes to the Company's asset retirement obligations	The following is a description of the changes to the Company’s asset retirement obligations for the years ended December 31, 2014 and December 31, 2013:
		December 31,			December 31,
		2014			2013
	Asset retirement obligations at beginning of year	$	3,515,898		$	3,317,358
	Loss on Settlement		(926	)		—
	Settlement of liabilities		(3,314	)		(1,114	)
	Revision of previous estimates		(554,287	)		—
	Accretion expense		185,773			148,364
	Additions		46,447			51,290
	Asset retirement obligations at end of year	$	3,189,421		$	3,515,898
	ARO classified as liabilities associated with assets held for sale		1,594,711			—
	ARO, Non-Current	$	1,594,710		$	3,515,898

Property_and_equipment_Tables

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule of capitalized costs under the successful efforts method for oil and gas properties	The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:
		December 31,			December 31,
		2014			2013
	Oil and natural gas properties	$	27,243,106		$	56,561,040
	Less accumulated depletion and impairment		(11,956,319	)		(20,941,867	)
	Net oil and natural gas properties capitalized costs	$	15,286,787		$	35,619,173
Schedule of other property and equipment	The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation is summarized as follows:
		December 31,			December 31,
		2014			2013
	Other property and equipment	$	136,535		$	130,470
	Less accumulated depreciation		(110,277	)		(95,828	)
	Net property and equipment	$	26,258		$	34,641

Stockholders_equity_and_earnin1

Stockholders' equity and earnings per share (Tables)	12 Months Ended
	Dec. 31, 2014
Stockholders Equity And Earnings Per Share Tables
Schedule of stock option activity summary	Stock option activity summary is presented in the table below:
						Weighted-
						average
					Weighted-	Remaining
					average	Contractual
			Number of		Exercise	Term
			Shares		Price	(years)
	Outstanding and exercisable December 31, 2012		87,500	$	4.8	4.08
	Granted		—		—	—
	Cancelled		—		—	—
	Exercised		—		—	—
	Forfeited		—		—	—
	Expired		—		—	—
	Outstanding and exercisable at December 31, 2013		87,500		4.8	3.08
	Granted		—		—	—
	Cancelled		—		—	—
	Exercised		—		—	—
	Forfeited		—		—	—
	Expired		—		—	—
	Outstanding and exercisable at December 31, 2014		87,500	$	4.8	2.08
Schedule of fair value assumptions used in the valuation of stock options	The fair value of the options granted during 2011 was estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions:
	Closing market price of stock on grant date	$3.11
	Risk-free interest rate	2.43%
	Dividend yield	0.00%
	Volatility factor	50%
	Expected life	2.5 years

Price_risk_management_activiti1

Price risk management activities (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of crude oil swaps	As of December 31, 2014, the Company had not crude oil swaps in place remaining.
							Fair Value of Outstanding
					Price	Volumes	Derivative Contracts (1)
							as of
	Transaction				Per	Per		December 31,		December
	Date	Type (2)	Beginning	Ending	Unit	Month		2014		31, 2013
	Nov-11	Swap	12/1/11	11/30/14	$93.50	2,000		—		-62,730
	Feb-12	Swap	3/1/12	2/28/14	$106.50	1,000		—		24,621
							$	—	$	-38,109
	(1) The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. All of our derivatives were with the same counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities.
	(2) These crude oil hedges were entered into on a per barrel delivered price basis, using the NYMEX - West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of fair value of financial assets and liabilities	The following tables summarize the valuation of the Company’s financial assets and liabilities at December 31, 2014 and December 31, 2013:
		Fair Value Measurements at Reporting Date Using
		Quoted Prices in Active Markets for Identical Assets or Liabilities		Significant or Other Observable Inputs			Significant Unobservable Inputs			Fair Value at
		(Level 1)		(Level 2)			(Level 3)			31-Dec-14
	Liabilities
	Environmental liability	$	—	$	—		$	(2,057,175	)	$	(2,057,175	)
	Assets associated with liabilities held for sale		—		—			(1,594,711	)		(1,594,711	)
	Asset retirement obligations (non-recurring)	$	—	$	—		$	(1,594,710	)	$	(1,594,710	)
	Total	$	—	$	—		$	(5,246,596	)	$	(5,246,596	)
		Fair Value Measurements at Reporting Date Using
		Quoted Prices in Active Markets for Identical Assets or Liabilities		Significant or Other Observable Inputs						Fair Value at  December 31, 2013
		(Level 1)		(Level 2)			Significant Unobservable Inputs
							(Level 3)
	Assets:
	Commodities derivatives	$	—	$	3,504		$	—		$	3,504
	Total	$	—	$	3,504		$	—		$	3,504
	Liabilities:
	Environmental liability	$	—	$	—		$	(2,086,973	)	$	(2,086,973	)
	Commodities derivatives		—		(38,109	)					(38,109	)
	Asset retirement obligations (non-recurring)		—		—			(3,514,898	)		(3,514,898	)
	Total	$	—	$	(38,109	)	$	(5,601,871	)	$	(5,639,980	)

Supplemental_information_relat1

Supplemental information relating to oil and natural gas producing activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Information Relating To Oil And Natural Gas Producing Activities Tables
Schedule of costs incurred for oil and gas property acquisition, exploration and development	Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities:
			Year Ended December 31,
			2014			2013
	Property acquisition costs:
	Unproved properties		$	—		$	—
	Proved properties			—			—
	Exploration costs			—			—
	Development costs (1)			4,360,946			8,312,662
	Total costs incurred		$	4,360,946		$	8,312,662
		-1	For the years ended December 31, 2014 and 2013, development costs included ($508,711) and $51,290, respectively, in non-cash, asset retirement costs.
Schedule of results of operations for oil and gas properties	Set forth below is certain information regarding the results of operations for oil and gas producing activities:
			Year Ended December 31,
			2014			2013
	Revenues		$	12,352,299		$	13,125,960
	Production costs			2,287,908			2,300,899
	Depletion and impairment			9,154,536			4,941,614
	Accretion expense			185,773			148,364
	Natural gas marketing			102,736			78,211
	Production taxes			999,395			1,246,153
	Results of operations		$	(378,049	)	$	4,410,719
Schedule of changes in proved reserves	A summary of the Company’s changes in quantities of proved oil and natural gas reserves for the years ended December 31, 2014 and 2013 are as follows:
			Oil (MBbl)			Natural Gas (MMcf)			Total (Mboe)
	31-Dec-12			1,271			1,695			1,554
	Acquisitions			—			—			—
	Extensions and Discoveries			371			817			507
	Revisions to Previous Estimates			11			906			161
	Production			(123	)		(283	)		(170	)
	31-Dec-13			1,530			3,135			2,052
	Acquisitions			—			—			—
	Extensions and Discoveries			250			477			330
	Revisions to Previous Estimates			43			503			127
	Production			(128	)		(375	)		(190	)
	31-Dec-14			1,695			3,740			2,319
	Proved Developed Reserves
	31-Dec-13			804			2,215			1,173
	31-Dec-14			916			2,691			1,364
	Proved Undeveloped Reserves
	31-Dec-13			726			920			879
	31-Dec-14			780			1,050			955
Schedule of standardized measure of discounted future net cash flows relating to proved reserves	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
			Year Ended December 31,
			2014			2013
	Future cash inflows		$	172,561,969		$	153,544,250
	Future production costs			(48,818,696	)		(41,381,543	)
	Future development costs			(18,080,062	)		(18,821,422	)
	Future income tax expense			(26,902,690	)		(20,243,102	)
	Future net cash flows			78,760,521			73,098,179
	10% annual discount for estimated timing of cash flows			(41,988,630	)		(36,817,148	)
	Standardized measure of discounted future net cash flows		$	36,771,891		$	36,281,031
Schedule of changes in standardized measure of discounted future net cash flows	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
			Year Ended December 31,
			2014			2013
	Balance, beginning of year		$	36,281,031		$	28,147,572
	Net change in sales and transfer prices and in production (lifting) costs related to future production			1,728,874			9,374,986	)
	Changes in estimated future development costs			5,076,840			4,042,730
	Sales and transfers of oil and natural gas produced during the period			(8,962,260	)		(10,825,061	)
	Net change due to extensions and discoveries			8,255,840			12,107,955	)
	Net change due to revisions in quantity estimates			3,182,507			3,883,464
	Previously estimated development costs incurred during the period			(4,360,946	)		(8,312,662	)
	Accretion of discount			4,899,710			2,747,142
	Other			(2,791,193	)		(672,750	)
	Net change in income taxes			(6,538,512	)		(4,212,345	)
	Balance, end of year		$	36,771,891		$	36,281,031

Income_taxes_Tables

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes Tables
Schedule of income tax reconciliation	Total income tax expense (benefit) differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income:
		Year Ended December 31,
	(in thousands)	2014			2013
	Income taxes at U.S. statutory rate		-838			1,140
	State taxes, net of federal impact		-65			88
	Change in valuation allowance		937			(1,229	)
	Permanent differences		0			1
	Other differences		(34	)		0
	Total		0			0
Schedule of deferred tax assets	Deferred tax assets/(liabilities) consist of the following:
		Year Ended December 31,
	(in thousands)	2014			2013
	Derivatives		(0	)		-34
	Valuation allowance		(6,909	)		(5,972	)
	Difference in depreciation and capitalization methods-natural gas properties,		(8,826	)		(3,444	)
	Accrued expenses		776			765
	Net operating losses		14,959			8,685
	Total		0			0

Assets_and_Liabilities_Held_Fo1

Assets and Liabilities Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2014
Assets And Liabilities Held For Sale Tables
Schedule of composition of assets and liabilities included in assets and liabilities held for sale	As of December 31, 2014, the carrying values of the Company’s ownership in half of its interest in its oil and gas properties, mineral interests, and leaseholds were included in assets and liabilities held for sale in the accompanying balance sheet and were comprised of the following (the Company had no assets held for sale as of December 31, 2013):
		December 31,
		2014
	Composition of assets included in assets held for sale:
	Oil and Gas Properties, Net	$	15,617,472
	Composition of liabilities included in liabilities held for sale:
	Asset Retirement Obligations	$	1,594,711

Going_Concern_Detail_Narrative

Going Concern (Detail Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014
Going Concern Detail Narrative
Working capital	$3,259,133

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details Narrative) (Other property [Member])	12 Months Ended
	Dec. 31, 2014
Lower range [Member]
Estimated useful lives	3 years
Upper range [Member]
Estimated useful lives	10 years

Asset_retirement_obligations_D

Asset retirement obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations Rollfoward:
Asset retirement obligations at beginning of year	$3,514,898	$3,317,358
Loss on Settlement	-926
Settlement of liabilities	-3,314	-1,114
Revision of previous estimates	-554,287
Accretion expense	185,773	148,364
Additions	46,447	51,290
Asset retirement obligations at end of year	3,189,421	3,514,898
ARO Classified as Liabilities Held for Sale	1,594,711
Asset Retirement Obligation, Non-Current	$1,594,710	$3,514,898

Property_and_Equipment_Details

Property and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Abstract]
Oil and natural gas properties	$27,243,106	$56,561,040
Less accumulated depletion, amortization and impairment	-11,956,319	-20,941,867
Net Oil and Gas Properties	$15,286,787	$35,619,173

Property_and_Equipment_Details1

Property and Equipment (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Abstract]
Other property and equipment	$136,535	$130,470
Less accumulated depreciation	-110,277	-95,828
Net property and equipment	$26,258	$34,641

Stockholders_equity_and_earnin2

Stockholders' equity and earnings per share (Details Narrative) (USD $)	0 Months Ended	12 Months Ended	0 Months Ended		12 Months Ended
	26-May-11	Dec. 31, 2014	Feb. 28, 2013	Mar. 13, 2014	Dec. 31, 2013	Dec. 31, 2011
Private offering, units issued	3,600,000
Sales price, units	$1.50
Unit composition, number of shares	1
Unit composition, number of warrants	1
Warrant term	5 years
Volatility factor		50.00%
Expected life		2 years 6 months
Cash paid to settle claims			633,975
Debt conversion rate - original			4
Debt conversion rate - amended			1.5
Red Mountain Resources [Member]
Shares issued by affiliate to settle creditor claims			750,000
Notes- Green Shoe and Little Bay [Member] | Red Mountain Resources [Member]
Shares issued upon conversion of notes			611,630
Senior First Lien Secured Credit Agreement [Member]
Issuance of shares to settle creditors payable claims, shares				422,650
Warrants - $2.25 exercise price [Member]
Warrant exercise price	$2.25
Shares callable under warrants issued	3,600,000
Fair value of warrants	$898,384
Date of expiration of warrants	30-Nov-15
Volatility factor	50.00%
Expected life	2 years 11 months 1 day
Warrants - $5.00 exercise price [Member]
Warrant exercise price		5
Shares callable under warrants issued		3,125
Stock Options [Member]
Number of options granted
Option exercise price
Stock Options [Member] | Directors [Member]
Number of options granted						87,500
Option exercise price						$4.80

Stockholders_equity_and_earnin3

Stockholders' equity and earnings per share (Details) (Stock Options [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options [Member]
Number of options:
Options outstanding, beginning	87,500	87,500
Options granted
Options cancelled
Options exercised
Options forfeited
Options expired
Options outstanding, ending	87,500	87,500	87,500
Weighted Average Exercise Price:
Options outstanding, beginning	$4.80	$4.80
Options granted
Options cancelled
Options exercised
Options forfeited
Options expired
Options outstanding, ending	$4.80	$4.80	$4.80
Weighted Average Remaining Contractual Term:
Weighted Average Remaining Contractual Term of options outstanding, Beginning	2 years 3 months 29 days	3 years 0 months 29 days	4 years 0 months 29 days

Stockholders_equity_and_earnin4

Stockholders' equity and earnings per share (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014
Stockholders Equity And Earnings Per Share Details 1
Closing market price of stock on grant date	$3.11
Risk-free interest rate	2.43%
Dividend yield	0.00%
Volatility factor	50.00%
Expected life	2 years 6 months

Related_party_transactions_Det

Related party transactions (Details Narrative) (Red Mountain Resources [Member], USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Red Mountain Resources [Member]
General and administrative expenses and operating costs paid	$2,365,000	$6,000,000	$3,000,000

Long_term_debt_Details_Narrati

Long term debt (Details Narrative) (USD $)	0 Months Ended					12 Months Ended
	Apr. 21, 2015	Mar. 11, 2015	24-May-13	Feb. 28, 2013	Feb. 05, 2013	Dec. 31, 2014	Dec. 31, 2013
Line of Credit							$12,200,000
Senior First Lien Secured Credit Agreement [Member]
Borrowing Base					100,000,000
Proceeds from draws from secured line of credit			1,300,000	2,000,000	8,900,000
Line of Credit						27,800,000
Borrowing Base	12,400,000	27,800,000				30,000,000
Available borrowing capacity						3,200,000
Decrease of borrowing base (Monthly)	$0	$350,000
Red Mountain Resources [Member]
Percentage ownership of Company by Red Mountain						83.00%

Commitments_and_contingencies_

Commitments and contingencies (Details Narrative) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Bloodworth [Member]
Contingency held for lawsuits	$280,000
Tom Tom and Tomahawk [Member]
Environmental liabilities	2,100,000	2,100,000
KeyBanc Capital Markets Inc ( Engagement Letter) [Member]
Contingency held for lawsuits	$900,000

Price_risk_management_activiti2

Price risk management activities (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	bbl
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net Derivative Asset	$0
Net Derivative Liability		38,109
Change in Net Derivative Asset/Liability, mark-to-market adjustments	0	283,831
Net Realized Hedge Settlement Gains (loss)	$3,479	$14,062
Volumes Per Month	2,000

Price_risk_management_activiti3

Price risk management activities (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
	bbl
Volumes Per Month	2,000
Fair Value of Outstanding Derivatives Contracts	$12,028	[1],[2]	($38,109)	[1],[2]
November 2011 Swap [Member]
Beginning Date	1-Dec-11	[1]
Ending Date	30-Nov-14	[1]
Price Per Unit	93.5	[1]
Volumes Per Month	2,000	[1]
Fair Value of Outstanding Derivatives Contracts	12,028	[1],[2]	-62,730	[1],[2]
February 2012 Swap [Member]
Beginning Date	1-Mar-12	[1]
Ending Date	28-Feb-14	[1]
Price Per Unit	106.5	[1]
Volumes Per Month	1,000	[1]
Fair Value of Outstanding Derivatives Contracts			$24,621	[1],[2]
[1]	These crude oil hedges were entered into on a per barrel delivered price basis, using the NYMEX - West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.
[2]	The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. Currently all of our derivatives are with the same counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities.

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Liabilities:
Asset retirement obligations (non-recurring)	($3,189,421)		($3,514,898)		($3,317,358)
Commodities Derivative	12,028	[1],[2]	-38,109	[1],[2]
Significant or Other Observable Inputs (Level 2) [Member]
Assets:
Commodities derivatives			3,504
Total			3,504
Liabilities:
Commodities Derivative			-38,109
Total			-38,109
Significant Unobservable Inputs (Level 3) [Member]
Liabilities:
Environmental liability	-2,057,175		-2,086,973
Assets associated with liabilities held for sale	-1,594,711
Asset retirement obligations (non-recurring)	-1,594,710		-3,514,898
Total	-5,246,596		-5,601,871
Fair Value [Member]
Assets:
Commodities derivatives			3,504
Total			3,504
Liabilities:
Environmental liability	-2,057,175		-2,086,973
Assets associated with liabilities held for sale	-1,594,711
Asset retirement obligations (non-recurring)	-1,594,710		-3,514,898
Commodities Derivative			-38,109
Total	($5,246,596)		($5,639,980)
[1]	These crude oil hedges were entered into on a per barrel delivered price basis, using the NYMEX - West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.
[2]	The fair value of the Company's outstanding transactions is presented on the balance sheet by counterparty. Currently all of our derivatives are with the same counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities.

Supplemental_information_relat2

Supplemental information relating to oil and natural gas producing activities (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013
Supplemental Information Relating To Oil And Natural Gas Producing Activities Details Narrative
Non-cash asset retirement obligations incurred for development costs	$51,290
Discounting factor for future net cash flows	10.00%

Supplemental_information_relat3

Supplemental information relating to oil and natural gas producing activities (unaudited) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Costs incurred for oil and gas property acquisition, development and exploration activities
Development costs	$4,360,946	$8,312,662	[1]
Total costs incurred	$4,360,946	$8,312,662
[1]	For the years ended December 31, 2013 and 2012, development costs included $51,290 and $383,481, respectively, in non-cash, asset retirement obligations.

Supplemental_information_relat4

Supplemental information relating to oil and natural gas producing activities (unaudited) (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Results of operations from oil and gas properties
Revenues	$12,352,299	$13,125,960
Production costs	2,287,908	2,300,899
Depletion and impairment	9,154,536	4,941,614
Accretion Expense	185,773	148,364
Natural gas marketing	102,736	78,211
Production taxes	999,395	1,246,153
Results of operations	($378,049)	$4,410,719

Supplemental_information_relat5

Supplemental information relating to oil and natural gas producing activities (unaudited) (Details 2)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	MMBbls	MMBbls
Oil (MBbls)
Oil and Natural Gas:
Balance, beginning of year	1,530	1,271
Extensions and discoveries	250	371
Revisions in previous estimates	43	11
Production	-128	1,530
Balance, end of year	1,695	1,530
Proved Developed Reserves, end of year	916	804
Proved Undeveloped Reserves, end of year	780	726
Natural Gas (MMcf)
Oil and Natural Gas:
Balance, beginning of year	3,740	1,695
Extensions and discoveries	477	817
Revisions in previous estimates	503	906
Production	-375	-283
Balance, end of year	3,740	3,740
Proved Developed Reserves, end of year	2,691	2,215
Proved Undeveloped Reserves, end of year	1,050	920
Oil Equivalents (MBoe)
Oil Equivalents:
Balance, beginning of year	2,052
Extensions and discoveries	330	507
Revisions in previous estimates	127	161
Production	-190	-170
Balance, end of year	2,319	2,052
Proved Developed Reserves, end of year	879	1,173
Proved Undeveloped Reserves, end of year	955	879

Supplemental_information_relat6

Supplemental information relating to oil and natural gas producing activities (unaudited) (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Standardized measure of discounted future net cash flows
Future cash inflows	$172,561,969	$153,544,250
Future production costs	-48,818,696	-41,381,543
Future development costs	-18,080,062	-18,821,422
Future income tax expense	-26,902,690	-20,243,102
Future net cash flows	78,760,521	73,098,179
10% annual discount for estimated timing of cash flows	-41,988,630	-36,817,148
Standardized measure of discounted future net cash flows	$36,771,891	$36,281,031	$28,147,572

Supplemental_information_relat7

Supplemental information relating to oil and natural gas producing activities (unaudited) (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Supplemental Information Relating To Oil And Natural Gas Producing Activities Details 4
Balance, beginning of year	$36,281,031	$28,147,572
Net change in sales and transfer prices and in production (lifting) costs related to future production	1,728,874	9,374,986
Changes in estimated future development costs	5,076,840	4,042,730
Sales and transfers of oil and natural gas produced during the period	-8,692,260	-10,825,061
Net change due to extensions and discoveries	8,255,840	12,107,955
Net change due to revisions in quantity estimates	3,182,507	3,883,464
Previously estimated development costs incurred during the period	-4,360,946	-8,312,662
Accretion of discount	4,899,710	2,747,142
Other	-2,791,193	-672,750
Net change in income taxes	-6,358,512	-4,212,345
Balance, end of year	$36,771,891	$36,281,031

Income_taxes_Details

Income taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income tax reconciliation:
Income taxes at U.S. statutory rate	($838,000)	$1,140,000
State taxes, net of federal impact	-65,000	88,000
Change in valuation allowance	937,000	-1,229,000
Permanent differences	0	1,000
Other differences	-34,000	0
Total	$0	$0

Income_taxes_Details_1

Income taxes (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets and liabilities
Derivatives	$0	($34,000)
Valuation allowance	-6,909,000	-5,972,000
Difference in depreciation and capitalization methods- natural gas and oil properties	-8,826,000	-3,444,000
Accrued expenses	776,000	765,000
Net operating losses	$14,959,000	$8,685,000

Assets_and_Liabilities_Held_Fo2

Assets and Liabilities Held For Sale (Details Narrative) (Assets Sales [Member], USD $)	0 Months Ended
	Apr. 21, 2015
Assets Sales [Member]
Description of Buyer information	RMR Operating, LLC (“RMR Operating”), Black Rock Capital, Inc. (“Black Rock”), RMR KS Holdings, LLC (“RMR KS”) and Black Shale Minerals, LLC (“Buyer”).
Percentage of oil and natural gas leasehold interests, wells, contracts	50.00%
Aggregate purchase price	$25,000,000

Assets_and_Liabilities_Held_Fo3

Assets and Liabilities Held For Sale (Details) (Assets Sales [Member], USD $)	Dec. 31, 2014
Assets Sales [Member]
Composition of assets included in assets held for sale:
Oil and Gas Properties, Net	$15,617,472
Composition of liabilities included in liabilities held for sale:
Asset Retirement Obligations	$1,594,711

Subsequent_Events_Details_Narr

Subsequent Events (Details Narrative) (Subsequent Event [Member], USD $)	0 Months Ended
	Apr. 01, 2015
Subsequent Event [Member]
Interests in oil and gas	-50.00%
Purchase price of oil and natural gas	$25,000,000