Breitling Energy (BECC) 10-KT 31 Mar 14 2013 FY Annual report (with FYE transition) Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 15, 2014	Jun. 30, 2013
Document Information [Line Items]	'	'	'
Document Type	'10-KT	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'BECC	'	'
Entity Registrant Name	'BREITLING ENERGY CORP	'	'
Entity Central Index Key	'0001229089	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Common Stock, Shares Outstanding	'	498,883,626	'
Entity Public Float	'	'	$2,828,454

CONSOLIDATED_AND_COMBINED_STAT

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current assets	'	'
Cash	$606,715	$4,668,839
Related party receivable	898	1,850
Total current assets	607,613	4,670,689
Other assets	'	'
Equity (payable) investment	3,561	12,205
Other property and equipment, net of depreciation	153,621	128,258
Total other assets	157,182	140,463
Total assets	764,795	4,811,152
Current liabilities	'	'
Accounts payable and accrued liabilities	2,953,727	2,617,761
Joint interest revenues payable	151,153	51,559
Deferred revenue from turnkey contracts	4,609,041	6,562,426
Current asset retirement obligations	16,495	22,905
Total current liabilities	7,730,416	9,254,651
Long-term liabilities	'	'
Asset retirement obligations	20,842	20,842
Commitments and contingencies	166,000	166,000
Stockholders' deficit	'	'
Common stock, $.001 par value; 500,000,000 shares authorized; 498,884,626, 461,863,084, and 461,863,084, respectively; shares issued and outstanding	498,884	461,863
Additional paid in capital	'	'
Accumulated deficit	-7,651,347	-5,092,204
Total stockholders' deficit	-7,152,463	-4,630,341
Total liabilities and stockholders' deficit	$764,795	$4,811,152

CONSOLIDATED_AND_COMBINED_STAT1

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Common Stock, par value	$0.00	$0.00
Common Stock, shares authorized	500,000,000	500,000,000
Common Stock, shares issued	498,884,626	461,863,084
Common Stock, shares outstanding	498,884,626	461,863,084

COMBINED_STATEMENTS_OF_OPERATI

COMBINED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Revenues	'	'
Turnkey drilling	$14,914,114	$13,085,714
Gain on sale of oil & natural gas royalties	11,275,402	192,093
Oil, natural gas, and related product sales	461,772	130,314
Total revenues	26,651,288	13,408,121
Expenses	'	'
Turnkey drilling and completion	5,437,880	6,009,535
General and administrative	9,512,523	5,559,976
Marketing	7,681,013	5,135,122
Professional fees	6,060,103	2,083,811
Lease operating	130,072	117,459
Depreciation and amortization	143,388	14,817
Total expenses	28,964,979	18,920,720
Operating loss	-2,313,691	-5,512,599
Other expense	'	'
Interest expense	117,415	70,460
Loss before income taxes	-2,431,106	-5,583,059
Income tax expense	'	'
Current taxes	91,016	101,838
Net loss	($2,522,122)	($5,684,897)
Net loss per basic and diluted common share	($0.01)	($0.01)
Weighted average basic and diluted common shares outstanding	498,883,626	461,863,084

CONSOLIDATED_AND_COMBINED_STAT2

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN STOCKHOLDERS' DEFICIT (USD $)	Total	Common Stock($.001 Par Value)	Net Deficit
Beginning balance at Dec. 31, 2011	$1,054,556	$461,863	$592,693
Beginning balance, Shares at Dec. 31, 2011	'	461,863,084	'
Net loss	-5,684,897	'	-5,684,897
Ending balance at Dec. 31, 2012	-4,630,341	461,863	-5,092,204
Beginning balance, Shares at Dec. 31, 2012	'	461,863,084	'
Net loss	-2,522,122	'	-2,522,122
Recapitalization with Bering, Shares	'	37,020,542	'
Recapitalization with Bering	0	37,021	-37,021
Ending balance at Dec. 31, 2013	($7,152,463)	$498,884	($7,651,347)
Ending balance, Shares at Dec. 31, 2013	'	498,883,626	'

CONSOLIDATED_AND_COMBINED_STAT3

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities	'	'
Net loss	($2,522,122)	($5,684,897)
Adjustments to reconcile net loss to net cash used in operating activities:	'	'
Depreciation and amortization	143,388	14,817
Accretion of asset retirement obligation	2,294	3,058
Net loss from equity investment	40,394	32,164
Increase (decrease) in cash attributable to changes in operating assets and liabilities:	'	'
Related party receivable	952	-1,850
Accounts payable and other adjustments	335,966	1,810,332
Joint interest revenues payable	99,594	51,559
Deferred revenues	-1,953,385	4,722,686
Net cash used in operating activities	-3,861,623	947,869
Cash flows from investing activities	'	'
Acquisition of other property and equipment	-168,751	-124,906
Investment in equity investment	-31,750	-35,000
Net cash provided by investing activities	-200,501	-159,906
Net increase in cash	-4,062,124	787,963
Cash, beginning of period	4,668,839	3,880,876
Cash, end of period	$606,715	$4,668,839

Organization_and_Nature_of_Ope

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2013
Organization and Nature of Operations	'
	1. Organization and nature of operations
	Breitling Energy Corporation, (formerly, Bering Exploration Inc., formerly, Oncolin Therapeutics, Inc., formerly, Edgeline Holdings, Inc., formerly, Dragon Gold Resources, Inc., formerly Folix Technologies, Inc.) (“we”, “our” or the “Company”) was incorporated in the state of Nevada on December 13, 2000 under the name “Folix Technologies, Inc.” On August 18, 2004, the Company changed its name to Dragon Gold Resources, Inc. On June 22, 2007, the Company changed its name to Edgeline Holdings, Inc. and on March 11, 2008 to Oncolin Therapeutics, Inc. On September 7, 2010, the Company changed its name to Bering Exploration, Inc. and on January 20, 2014, to Breitling Energy Corporation.
	On December 9, 2013 (the “Acquisition Date”), the Company entered into an Asset Purchase Agreement (the “Purchase Agreement”) with Breitling Oil and Gas Corporation, a Texas corporation (“O&G”) and Breitling Royalties Corporation, a Texas corporation (“Royalties,” and collectively with O&G, the “Predecessors”). Pursuant to the Purchase Agreement, the Company issued to the Predecessors 461,863,084 shares of Common Stock, in exchange for substantially all of the oil and gas assets owned by the Predecessors (the “Transaction”). In connection with the closing of the Transaction, all of the Company’s outstanding convertible notes were converted into Common Stock. The shares of Common Stock issued to the Predecessors represent approximately 92.5% of the shares of Common Stock outstanding following the closing of the Transaction (the “Closing”). The Transaction results in the owners of the Company (the “accounting acquirer”) having actual or effective operating control of Bering after the transaction, with the shareholders of Bering (the “legal acquirer”) continuing only as passive investors. The closing of the Transaction did not affect the number of shares of Common Stock held by the Company’s existing public stockholders.
	Due to the previous transaction, the Predecessors’ accounting records will be the accounting records of the Company.
	We have incurred losses of $2,522,000 and $5,685,000 in the years ended December 31, 2013 and 2012, respectively, and have negative working capital of $7,123,000 and $4,584,000 at December 31, 2013 and 2012 respectively. The majority of our negative working capital position at December 31, 2013 in the amount of $4,609,000 was comprised of amounts due to deferred revenue. The net loss for the years ended December 31, 2013 and 2012 of $2,522,000 and $5,685,000 would have been eliminated if the Company had recognized the deferred revenue of $4,609,041 and $6,562,426, respectively. The negative working capital in each period includes the short term liability for deferred revenue that will be reversed upon the completion of certain wells that the Company has recognized the expense for. Working capital as of December 31, 2012 had a deficit of $4,583,962 and would have been decreased by $6,562,426 to positive working capital of $1,978,464. The Company has multiple options available to meet this obligation when due, summarized as follows:
	We will complete the items necessary so that we can recognize our deferred revenue by the end of the first quarter of 2014, that will provide additional revenues in excess of $4 million. There were no additional expenses necessary to recognize the deferred revenue.
	Continue to sell turnkey drilling, as well as interests in oil and gas royalties as they have done historically and at margins they have been able to achieve in the prior two years. Our current reserves with a PV-10 value in excess of $20 million could be sold in our normal course of business in excess of $40 million.
	Reduce expenses related to marketing, professional fees, as well as eliminate one-time expenses incurred in the transition to a public company.
	Our current working capital should be positive in the first quarter of 2014.
	Our financial statements were prepared assuming that the Company will continue as a going concern which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
	2. Summary of significant accounting policies
	Basis of Presentation
	The consolidated and combination financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).
	These consolidated and combined financial statements were approved by management and available for issuance on March 31, 2013. Subsequent events have been evaluated through this date.
	Principles of Consolidation and Combination
	The financial statements reflect the historical combined results of O&G and Royalties prior to the reverse recapitalization completed on December 9, 2013, and the consolidated results of the Company thereafter. All intercompany and interentity transactions have been eliminated in the consolidation and combination.
	The accompanying combined financial statements include the accounts of O&G. These accounts have also been combined with the accounts of Royalties, an entity under common ownership. All intercompany transactions and balances have been eliminated in combination.
	Fair Value Measurements
	The Company has adopted and follows ASC 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:
	Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
	Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
	Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.
	As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash and cash equivalents, oil and natural gas sales receivable, and accounts payable and accrued liabilities, approximate their fair values because of the short maturity of these instruments.
	Cash
	The Company considers all highly-liquid debt instruments with original maturities of three months or less to be cash equivalents. As of December 31, 2013 and 2012, the Company did not hold any cash equivalents.
	Cash and equivalents include time deposits, certificates of deposits and all highly liquid debt instruments with original maturities of three months or less when purchased. As of December 31, 2013, and 2012, the Company held approximately $606,715, $4,668,839, respectively, in cash.
	The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). The interest bearing cash accounts maintain FDIC coverage of up to $250,000 per institution. As of December 31, 2013 and 2012, the Company did not have any amounts in excess of its FDIC coverage.
	Oil and Gas Natural Gas Properties
	The Company uses the full-cost method of accounting for its oil and natural gas producing activities as further defined under ASC 932, Extractive Activities -Oil and natural gas. Under these provisions, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and natural gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred.
	Proved properties are amortized using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced at year end by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and natural gas property, less related salvage value.
	The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved properties. Unproved properties and properties under development are reviewed for impairment at least quarterly. Where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. As of December 31, 2013 and 2012, no unproved properties or properties under development were included in the oil and natural gas properties of the accompanying combined financial statements.
	Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10 percent per annum based on industry standards and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying combined statements of operations. For the years ended December 31, 2013, and 2012, no impairment charge occurred.
	Other Property and Equipment
	Other property and equipment, which includes furniture, vehicles, software, and office equipment, is stated at cost less accumulated depreciation and amortization. Depreciation and amortization is computed using the straight-line method over the estimated useful lives of the assets. Furniture and office equipment are generally depreciated over a useful life of ten years, vehicles over a useful life of five years, and software over a useful life of three years.
	Impairment of Long-Lived Assets
	The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the years ended December 31, 2013, and 2012, no circumstances indicated an unrecoverable carrying value of the long-lived assets.
	Asset Retirement Obligations
	The Company follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.
	Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
	Revenue Recognition and Natural Gas Imbalances
	Generally, the Company will acquire properties for development and will look to other investors to acquire interests in these properties for the purpose of development; although circumstances could arise where we may elect to re-balance its portfolio by selling or trading lesser producing properties in order to redeploy capital to a better opportunity in other areas of activity. We expect that drilling projects for the foreseeable future will be financed by issuing interests in the development with additional investors in the property.
	The Company holds working interests in its oil and gas properties and is, therefore, responsible with other working interest owners, if any, for the payment of its proportionate share of the operating expenses of the wells. Working interest owners are typically responsible for all lease operating and production expenses. Royalty owners and over-riding royalty owners receive a percentage of gross oil and gas production revenue for a particular lease and are not responsible for the costs of operating the lease.
	The Company recognizes revenue when title to developed oil and gas interests are completed. The Company recognizes gains or losses from the sales of its interests in oil and natural gas properties as title passes to the buyer. These amounts are recognized as income. If the project is not complete the Company will defer the revenue until the project is complete.
	During the year ended December 31, 2013, and 2012 the Company deferred revenues of $4,609,041, $6,562,426, and $3,699,156, respectively. The Company anticipates completion of the projects associated with these deferrals in 2014.
	The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. The Company will also enter into physical contract sale agreements through its normal operations. Revenue from the sale of natural gas and crude oil is recognized when title to the commodities passes. These contracts are not considered derivative contracts by the Company in accordance with the normal purchases and normal sales provision of ASC 815-10-15.
	Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.
	Sales-Based Taxes
	The Company incurs severance tax on the sale of its production which is generated in Texas, North Dakota, and Oklahoma. These taxes are reported on a gross basis and are included in lease operating expense within the accompanying combined statements of operations. Sales-based taxes for the years ended December 31, 2013 and 2012 were approximately $4,000 and $34,000. respectively.
	Lease Operating Expenses
	Lease operating expenses represents severance and production taxes, field personnel salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, and other operating expenses. Lease operating expenses are expensed as incurred.
	General and Administrative Expense
	General and administrative expenses are reported net of recoveries from owners in properties operated by the Company and net of amounts related to lease operating activities or capitalized pursuant to the full-cost method of accounting.
	Income Taxes
	Prior to the Acquisition Date, the Company elected to be treated as an “S” corporation under Subchapter S of the Internal Revenue Code. As such, income or loss of the Company, in general, is allocated to the shareholders for inclusion in their income tax return. Accordingly, the Company has not provided for federal, state, or local income taxes prior to this date. Texas does have a “margin tax” that remains with the corporate entity; therefore the Company has reflected any expense associated with the Texas margin tax as income taxes for financial statement purposes.
	Subsequent to the Acquisition Date, income taxes are recorded in accordance with FASB ASC 740, “Income Taxes”. This statement requires the recognition of deferred tax assets and liabilities to reflect the future tax consequences of events that have been recognized in the financial statements or tax returns. Measurement of the deferred items is based on enacted tax laws. In the event the future consequences of differences between financial reporting bases and tax bases of the Company’s assets and liabilities result in a deferred tax asset, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance related to a deferred tax asset is recorded when it is more likely than not that some portion or the entire deferred tax asset will not be realized.
	The Company has filed all of their tax returns. As of December 31, 2013, there is approximately $14 million in accumulated losses for tax purposes. These losses will give rise to deferred tax assets, a significant portion of which are likely to be net operating loss carry forwards. Due to the transaction of December 9, 2013, these net operating loss deferred tax assets may be subject to limitations. Current tax laws limit the amount of loss available to be offset against future taxable income when a substantial change in ownership occurs. Therefore, the amount available to offset future taxable income may be limited. Because of these potential limitations, the Company has not recognized any deferred tax asset and has placed a full valuation allowance on such assets.
	In accordance with GAAP, the Company is required to determine whether a tax position of the Company is more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit to be recognized is measured as the largest amount of benefit that is greater than fifty percent likely of being realized upon ultimate settlement. De-recognition of a tax benefit previously recognized could result in the Company recording a tax liability that would reduce stockholders equity. Based on its analysis, the Company has accrued a liability relating to uncertain tax positions for amounts totaling approximately $728,000 and $309,000 as of December 31, 2013 and 2012 respectively. This policy also provides guidance on thresholds, measurement, de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different entities. Management’s conclusions regarding this policy may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof.
	The Company may be subject to potential examination by U.S. federal, U.S. states or foreign jurisdiction authorities in the areas of income taxes. These potential examinations may include questioning the timing and amount of deductions, the nexus of income among various tax jurisdictions and compliance with U.S. federal, U.S. state and foreign tax laws. The Company’s management does not expect that the total amount of unrecognized tax benefits will materially change over the next twelve months.
	Net Income (Loss) per Common Share
	Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from stock options, nonvested share appreciation rights and non-vested restricted shares. For the years ended December 31, 2013 and 2012, there were no potentially dilutive shares.
	Use of Estimates
	The preparation of combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.
	New Accounting Pronouncements
	In January 2013, the Financial Accounting Standards Board (“FASB”) issued ASC Update No. 2013-01 (“ASC No. 2013-01”), The objective of ASC No. 2013-01 is to clarify that the scope of Accounting Standards Update No. 2011-11 , Disclosures about Offsetting Assets and Liabilities (“ASC No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASC No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The amendments are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The disclosures required by the amendments are required to be applied retrospectively for all comparative periods presented. The Company does not believe the adoptions of this update will have a material impact on the Company’s combined financial statements.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements	'
	3. Fair Value Measurements
	As of December 31, 2013, and 2012, the Company had no assets which were measured at fair value.
	The following tables present information about the Company’s liabilities measured at fair value as of December 31, 2013, and 2012
		Level 1	Level 2	Level 3		Balance as of
		(unaudited)	(unaudited)	(unaudited)		December 31, 2013
	Liabilities (at fair value):
	Asset retirement obligations	$	$	$	46,041	$	46,041
						Balance as of
		Level 1	Level 2	Level 3		December 31, 2012
	Liabilities (at fair value):
	Asset retirement obligations	$	$	$	43,747	$	43,747

Other_Equipment

Other Equipment	12 Months Ended
	Dec. 31, 2013
Other Equipment	'
	4. Other equipment
	The following table presents a summary of the Company’s other equipment:
		December 31,
		2013			2012
	Other equipment
	Furniture	$	194,275		$	112,565
	Vehicles		25,708			25,708
	Software		21,047			6,017
	Office equipment		71,627			5,434
	Less: Accumulated depreciation		(159,036	)		(21,466	)
	Total other equipment, net of accumulated deprecation	$	153,621		$	128,258

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
	5. Asset retirement obligations
	The Company has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of the end of each period. At December 31, 2013 and 2012, the Company evaluated 213 and 210 wells, and has determined a range of abandonment dates between December 2012 and December 2051. As of December 31, 2013, and 2012, the Company realized $10,500 in Asset retirement obligations.
		Year Ended December 31,
		2013			2012
	Asset retirement obligations, beginning of period	$	43,747		$	40,689
	Additions to asset retirement obligation
	Liabilities settled during the period
	Accretion of discount		2,294			3,058
	Revision of estimate		(8,704	)
	Asset retirement obligations, end of period	$	37,337		$	43,747

Stockholders_Deficit

Stockholders' Deficit	12 Months Ended
	Dec. 31, 2013
Stockholders' Deficit	'
	6. Stockholders’ Deficit [NEED TO CONSIDER ADDING SOMETHING ON THE REVERSE MERGER]

Commitment_and_Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitment and Contingencies	'
	4. Commitment and Contingencies
	Legal
	From time-to-time, the Company may become subject to proceedings, lawsuits and other claims in the ordinary course of business including working interest rescissions and operator disputes. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance. As of December 31, 2013 and 2012, the Company accrued $146,000 to settle working interest rescissions.
	Oil and Natural Gas Regulations
	The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.
	Office Lease
	The Company leases its primary office space under an operating lease which expires in 2020. Lease expense was approximately $110,000 for the year ended December 31, 2013 and approximately $83,000 for the year ended December 31, 2012.
	Aggregate future minimum annual rental payments in the years subsequent to December 31, 2013 are as follows:
	Year ending December 31,
	2014		136,000
	2015		139,000
	2016		143,000
	2017		147,000
	Thereafter		386,000
	Total future minimum rental payments	$	951,000

Supplemental_Information

Supplemental Information	12 Months Ended
	Dec. 31, 2013
Supplemental Information	'
	SUPPLEMENTAL INFORMATION
	Costs Incurred
	The following table summarizes costs incurred in oil and natural gas property acquisition, exploration, and development activities. Property acquisition costs those incurred to purchase lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing oil and natural gas.
	Costs incurred (capitalized and charged to expense) in oil and natural gas activities for the years ended December 31, 2013 and 2012 were as follows:
		Year ended			Year ended
		December 31,			December 31,
		2013			2012
	Acquisitions	$	3,806,516		$	16,321,566
	Exploration
	Development		1,631,364			3,447,611
	Total costs incurred	$	5,437,880		$	19,769,177
	Oil and Natural Gas Operating Results
	Results of operations from oil and natural gas producing activities for the years ended December 31, 2012 and 2011, excluding Company overhead and interest costs, were as follows:
		Year ended			Year ended
		December 31,			December 31,
		2013			2012
	Oil, natural gas and related product sales	$	461,772		$	130,314
	Lease operating costs		(121,892	)		(83,446	)
	Production taxes		(8,180	)		(34,013	)
	Results of operations from oil and natural gas producing activities	$	331,700		$	12,855
	Proved Reserves Methodology
	The Company’s estimated proved reserves, as of December 31, 2013 and 2012, are made in accordance with the SEC’s final rule, Modernization of Oil and Gas Reporting, which amended Rule 4-10 of Regulation S-X (the “Final Rule”). As defined by the Final Rule, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods, and government regulations. Projects to extract the hydrocarbons must have commenced or an operator must be reasonably certain that it will commence the projects within a reasonable time. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the projects. Further requirements for assignment of estimated proved reserves include the following:
	The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by natural gas, oil, and/or water contacts, if any; and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons and highest known oil seen in well penetrations unless geoscience, engineering, or performance data and reliable technology establishes a lower or higher contact with reasonable certainty. Reliable technologies are any grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
	Reserves which can be produced economically through applications of improved recovery techniques (including, but not limited to fluid injections) are included in the proved classification when successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, and other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based.
	Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The prices used are the average crude oil and natural gas prices during the twelve month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
	Reserves engineering is a subjective process of estimating underground accumulations of crude oil, condensate, natural gas, and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserves estimate is a function of the quality of available date and of engineering and geological interpretation and judgment. The reserves actually recovered, the timing of production of those reserves, as well as operating costs and the amount and timing of development expenditures may be substantially different from original estimates. Revisions result primarily from new information obtained from development drilling, production history, field tests, and data analysis and from changes in economic factors including expectation and assumptions as to availability of financing for development projects.
	Reserve Quantity Information
	The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The estimates have been prepared with the assistance of Mire & Associates Inc., an independent petroleum consultant. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.
		Crude			Natural
		Oil (Bbl)			Gas (Mcf)
	PROVED-DEVELOPED AND UNDEVELOPED RESERVES
	December 31, 2011		16,810			232,880
	Revisions of previous estimates		12,178			(44,220	)
	Extensions and discoveries		—			—
	Acquisitions of reserves		66,230			63,660
	Sales of reserves		(5,663	)		(7,271	)
	Production
	December 31, 2012		106,630			308,850
	Revisions of previous estimates		(18,847	)		4,201
	Extensions and discoveries		48,080			158,100
	Acquisitions of reserves		20,750			62,050
	Sales of reserves
	Production		(5,863	)		(7,271	)
	December 31, 2013		150,750			525,930
	PROVED DEVELOPED RESERVES
	December 31, 2013		84,580			373,130
	December 31, 2012		66,460			129,310
	Approximately $24,000 was spent during 2013 related to proved undeveloped reserves that were transferred to proved developed reserves. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $32,500 for 2014. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2015. Future cash flows are computed by applying a first-day-of-the-month 12-month average price of natural gas (Henry Hub) and oil (West Texas Intermediate) to year end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. For the year ended December 31, 2013, the oil and natural gas prices were applied at $96.91/Bbl and $3.67/MMBtu, respectively, in the standardized measure. For the year ended December 31, 2012, the oil and natural gas prices were applied at $94.71/Bbl and $2.85/MMBtu, respectively, in the standardized measure.
	Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves
	The following tables, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil and gas reserves as of December 31, 2013 and 2012, for the years ended December 31, 2013 and 2012, is presented pursuant to ASC 932. In computing this data, assumptions other than those required by the Financial Accounting Standards Board could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Company’s proved oil and gas reserves.
	A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement costs or fair value of the Company’s natural gas and oil properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations. There have been no estimates for future plugging and abandonment costs.
	Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2013
	Future cash inflows	$	18,149,790
	Less: Future production costs		(2,588,090	)
	Future development costs		(32,500	)
	Future income tax expense		(5,279,928	)
	Future net cash flows		10,249,272
	10% discount factor		(5,339,501	)
	Standardized measure of discounted future net cash inflows	$	4,909,771
	Estimated future development cost anticipated for following two years on existing properties	$	32,500
	Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2013
	Beginning of year	$	4,485,462
	Sales of oil and natural gas, net of production costs		(331,700	)
Net changes in prices and production costs		(86,294	)
Development costs incurred during the year		(24,000	)
Changes in future development costs		0
Extensions, discoveries, and improved recoveries		2,624,270
Revisions of previous quantity estimates		(531,051	)
Accretion of discount		467,842
Net change in income taxes		(3,148,534	)
Purchases and sale of mineral interests		1,104,390
Timing and other		349,386
End of year	$	4,909,771
Future cash inflows	$	12,053,050
Less: Future production costs		(1,561,000	)
Future development costs		(56,500	)
Future income tax expense		(104,355	)
Future net cash flows		10,331,195
10% discount factor		(5,845,733	)
Standardized measure of discounted future net cash inflows	$	4,485,462
Estimated future development cost anticipated for following two years on existing properties	$	56,500
Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2012
Beginning of year	$	1,535,467
Sales of oil and natural gas, net of production costs		(12,855	)
Net changes in prices and production costs		(216,011	)
Development costs incurred during the year		42,000
Changes in future development costs		(51,118	)
Extensions, discoveries, and improved recoveries
Revisions of previous quantity estimates		182,078
Accretion of discount		271,027
Net change in income taxes		22,584
Purchases and sale of mineral interests		2,954,880
Timing and other		(242,590	)
End of year	$	4,485,462
Significant Changes in Reserves for the Year Ended December 31, 2013
Extensions, discoveries, and improved recoveries: During the year ended December 31, 2013, the Company had extensions and discoveries of 48,080 Bbl of crude oil and 158,100 Mcf of natural gas from primarily newly identified drilling opportunities in the oil and natural gas reservoirs.
Net change in income taxes: During the year ended December 31, 2013, the Company became a taxable entity under the federal government. The future net cash flows were estimated to be taxed at a regulatory rate of 34%.
Purchases and Sale of Mineral Interests: During the year ended December 31, 2013, the Company acquired 20,750 Bbl of crude oil and 62,050 Mcf of natural gas through the purchase of undeveloped properties.
Significant Changes in Reserves for the Year Ended December 31, 2012
Net changes in Prices and Production Costs: For the year ended December 31, 2012, the oil and natural gas prices were applied at $94.68/Bbl and $2.76/MMBtu, respectively, in the standardized measure. At December 31, 2011, the oil and natural gas prices were applied at $95.84/Bbl and $4.15/MMBtu, respectively, in the standardized measure. The decrease in oil and natural gas prices resulted in a significant decrease in future expected cash flows and reserves.
Purchases and Sale of Mineral Interests: During the year ended December 31, 2012, the Company acquired 66,230 Bbl of crude oil and 63,660 Mcf of natural gas through the purchase of undeveloped properties.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Basis of Presentation	'
	Basis of Presentation
	The consolidated and combination financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).
	These consolidated and combined financial statements were approved by management and available for issuance on March 31, 2013. Subsequent events have been evaluated through this date.
Principles of Consolidation and Combination	'
	Principles of Consolidation and Combination
	The financial statements reflect the historical combined results of O&G and Royalties prior to the reverse recapitalization completed on December 9, 2013, and the consolidated results of the Company thereafter. All intercompany and interentity transactions have been eliminated in the consolidation and combination.
	The accompanying combined financial statements include the accounts of O&G. These accounts have also been combined with the accounts of Royalties, an entity under common ownership. All intercompany transactions and balances have been eliminated in combination.
Fair Value Measurements	'
	Fair Value Measurements
	The Company has adopted and follows ASC 820, Fair Value Measurements and Disclosures, for measurement and disclosures about fair value of its financial instruments. ASC 820 establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. To increase consistency and comparability in fair value measurements and related disclosures, ASC 820 establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy defined by ASC 820 are:
	Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
	Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
	Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.
	As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash and cash equivalents, oil and natural gas sales receivable, and accounts payable and accrued liabilities, approximate their fair values because of the short maturity of these instruments.
Cash	'
	Cash
	The Company considers all highly-liquid debt instruments with original maturities of three months or less to be cash equivalents. As of December 31, 2013 and 2012, the Company did not hold any cash equivalents.
	Cash and equivalents include time deposits, certificates of deposits and all highly liquid debt instruments with original maturities of three months or less when purchased. As of December 31, 2013, and 2012, the Company held approximately $606,715, $4,668,839, respectively, in cash.
	The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). The interest bearing cash accounts maintain FDIC coverage of up to $250,000 per institution. As of December 31, 2013 and 2012, the Company did not have any amounts in excess of its FDIC coverage.
Oil and Gas Natural Gas Properties	'
	Oil and Gas Natural Gas Properties
	The Company uses the full-cost method of accounting for its oil and natural gas producing activities as further defined under ASC 932, Extractive Activities -Oil and natural gas. Under these provisions, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and natural gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred.
	Proved properties are amortized using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced at year end by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and natural gas property, less related salvage value.
	The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved properties. Unproved properties and properties under development are reviewed for impairment at least quarterly. Where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. As of December 31, 2013 and 2012, no unproved properties or properties under development were included in the oil and natural gas properties of the accompanying combined financial statements.
	Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10 percent per annum based on industry standards and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying combined statements of operations. For the years ended December 31, 2013, and 2012, no impairment charge occurred.
Other Property and Equipment	'
	Other Property and Equipment
	Other property and equipment, which includes furniture, vehicles, software, and office equipment, is stated at cost less accumulated depreciation and amortization. Depreciation and amortization is computed using the straight-line method over the estimated useful lives of the assets. Furniture and office equipment are generally depreciated over a useful life of ten years, vehicles over a useful life of five years, and software over a useful life of three years.
Impairment of Long-Lived Assets	'
	Impairment of Long-Lived Assets
	The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the years ended December 31, 2013, and 2012, no circumstances indicated an unrecoverable carrying value of the long-lived assets.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	The Company follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.
	Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.
Revenue Recognition and Natural Gas Imbalances	'
	Revenue Recognition and Natural Gas Imbalances
	Generally, the Company will acquire properties for development and will look to other investors to acquire interests in these properties for the purpose of development; although circumstances could arise where we may elect to re-balance its portfolio by selling or trading lesser producing properties in order to redeploy capital to a better opportunity in other areas of activity. We expect that drilling projects for the foreseeable future will be financed by issuing interests in the development with additional investors in the property.
	The Company holds working interests in its oil and gas properties and is, therefore, responsible with other working interest owners, if any, for the payment of its proportionate share of the operating expenses of the wells. Working interest owners are typically responsible for all lease operating and production expenses. Royalty owners and over-riding royalty owners receive a percentage of gross oil and gas production revenue for a particular lease and are not responsible for the costs of operating the lease.
	The Company recognizes revenue when title to developed oil and gas interests are completed. The Company recognizes gains or losses from the sales of its interests in oil and natural gas properties as title passes to the buyer. These amounts are recognized as income. If the project is not complete the Company will defer the revenue until the project is complete.
	During the year ended December 31, 2013, and 2012 the Company deferred revenues of $4,609,041, $6,562,426, and $3,699,156, respectively. The Company anticipates completion of the projects associated with these deferrals in 2014.
	The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. The Company will also enter into physical contract sale agreements through its normal operations. Revenue from the sale of natural gas and crude oil is recognized when title to the commodities passes. These contracts are not considered derivative contracts by the Company in accordance with the normal purchases and normal sales provision of ASC 815-10-15.
	Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.
Sales-Based Taxes	'
	Sales-Based Taxes
	The Company incurs severance tax on the sale of its production which is generated in Texas, North Dakota, and Oklahoma. These taxes are reported on a gross basis and are included in lease operating expense within the accompanying combined statements of operations. Sales-based taxes for the years ended December 31, 2013 and 2012 were approximately $4,000 and $34,000. respectively.
Lease Operating Expense	'
	Lease Operating Expenses
	Lease operating expenses represents severance and production taxes, field personnel salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, and other operating expenses. Lease operating expenses are expensed as incurred.
General and Administrative Expense	'
	General and Administrative Expense
	General and administrative expenses are reported net of recoveries from owners in properties operated by the Company and net of amounts related to lease operating activities or capitalized pursuant to the full-cost method of accounting.
Income Taxes	'
	Income Taxes
	Prior to the Acquisition Date, the Company elected to be treated as an “S” corporation under Subchapter S of the Internal Revenue Code. As such, income or loss of the Company, in general, is allocated to the shareholders for inclusion in their income tax return. Accordingly, the Company has not provided for federal, state, or local income taxes prior to this date. Texas does have a “margin tax” that remains with the corporate entity; therefore the Company has reflected any expense associated with the Texas margin tax as income taxes for financial statement purposes.
	Subsequent to the Acquisition Date, income taxes are recorded in accordance with FASB ASC 740, “Income Taxes”. This statement requires the recognition of deferred tax assets and liabilities to reflect the future tax consequences of events that have been recognized in the financial statements or tax returns. Measurement of the deferred items is based on enacted tax laws. In the event the future consequences of differences between financial reporting bases and tax bases of the Company’s assets and liabilities result in a deferred tax asset, ASC 740 requires an evaluation of the probability of being able to realize the future benefits indicated by such assets. A valuation allowance related to a deferred tax asset is recorded when it is more likely than not that some portion or the entire deferred tax asset will not be realized.
	The Company has filed all of their tax returns. As of December 31, 2013, there is approximately $14 million in accumulated losses for tax purposes. These losses will give rise to deferred tax assets, a significant portion of which are likely to be net operating loss carry forwards. Due to the transaction of December 9, 2013, these net operating loss deferred tax assets may be subject to limitations. Current tax laws limit the amount of loss available to be offset against future taxable income when a substantial change in ownership occurs. Therefore, the amount available to offset future taxable income may be limited. Because of these potential limitations, the Company has not recognized any deferred tax asset and has placed a full valuation allowance on such assets.
	In accordance with GAAP, the Company is required to determine whether a tax position of the Company is more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit to be recognized is measured as the largest amount of benefit that is greater than fifty percent likely of being realized upon ultimate settlement. De-recognition of a tax benefit previously recognized could result in the Company recording a tax liability that would reduce stockholders equity. Based on its analysis, the Company has accrued a liability relating to uncertain tax positions for amounts totaling approximately $728,000 and $309,000 as of December 31, 2013 and 2012 respectively. This policy also provides guidance on thresholds, measurement, de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different entities. Management’s conclusions regarding this policy may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof.
	The Company may be subject to potential examination by U.S. federal, U.S. states or foreign jurisdiction authorities in the areas of income taxes. These potential examinations may include questioning the timing and amount of deductions, the nexus of income among various tax jurisdictions and compliance with U.S. federal, U.S. state and foreign tax laws. The Company’s management does not expect that the total amount of unrecognized tax benefits will materially change over the next twelve months.
Net Income (Loss) per Common Share	'
	Net Income (Loss) per Common Share
	Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net income per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from stock options, nonvested share appreciation rights and non-vested restricted shares. For the years ended December 31, 2013 and 2012, there were no potentially dilutive shares.
Use of Estimates	'
	Use of Estimates
	The preparation of combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.
New Accounting Pronouncements	'
	New Accounting Pronouncements
	In January 2013, the Financial Accounting Standards Board (“FASB”) issued ASC Update No. 2013-01 (“ASC No. 2013-01”), The objective of ASC No. 2013-01 is to clarify that the scope of Accounting Standards Update No. 2011-11 , Disclosures about Offsetting Assets and Liabilities (“ASC No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASC No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The amendments are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. The disclosures required by the amendments are required to be applied retrospectively for all comparative periods presented. The Company does not believe the adoptions of this update will have a material impact on the Company’s combined financial statements.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Liabilities Measured at Fair Value	'
	The following tables present information about the Company’s liabilities measured at fair value as of December 31, 2013, and 2012
		Level 1	Level 2	Level 3		Balance as of
		(unaudited)	(unaudited)	(unaudited)		December 31, 2013
	Liabilities (at fair value):
	Asset retirement obligations	$	$	$	46,041	$	46,041
						Balance as of
		Level 1	Level 2	Level 3		December 31, 2012
	Liabilities (at fair value):
	Asset retirement obligations	$	$	$	43,747	$	43,747

Other_Equipment_Tables

Other Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Company's Other Equipment	'
	The following table presents a summary of the Company’s other equipment:
		December 31,
		2013			2012
	Other equipment
	Furniture	$	194,275		$	112,565
	Vehicles		25,708			25,708
	Software		21,047			6,017
	Office equipment		71,627			5,434
	Less: Accumulated depreciation		(159,036	)		(21,466	)
	Total other equipment, net of accumulated deprecation	$	153,621		$	128,258

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
		Year Ended December 31,
		2013			2012
	Asset retirement obligations, beginning of period	$	43,747		$	40,689
	Additions to asset retirement obligation
	Liabilities settled during the period
	Accretion of discount		2,294			3,058
	Revision of estimate		(8,704	)
	Asset retirement obligations, end of period	$	37,337		$	43,747

Commitment_and_Contingencies_T

Commitment and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Aggregate Future Minimum Annual Rental Payments	'
	Aggregate future minimum annual rental payments in the years subsequent to December 31, 2013 are as follows:
	Year ending December 31,
	2014		136,000
	2015		139,000
	2016		143,000
	2017		147,000
	Thereafter		386,000
	Total future minimum rental payments	$	951,000

Supplemental_Information_Table

Supplemental Information (Tables)	12 Months Ended
	Dec. 31, 2013
Costs Incurred (Capitalized and Charged to Expense) In Oil and Natural Gas Activities	'
	Costs incurred (capitalized and charged to expense) in oil and natural gas activities for the years ended December 31, 2013 and 2012 were as follows:
		Year ended			Year ended
		December 31,			December 31,
		2013			2012
	Acquisitions	$	3,806,516		$	16,321,566
	Exploration
	Development		1,631,364			3,447,611
	Total costs incurred	$	5,437,880		$	19,769,177
Results of Operations from Oil and Natural Gas Producing Activities	'
	Results of operations from oil and natural gas producing activities for the years ended December 31, 2012 and 2011, excluding Company overhead and interest costs, were as follows:
		Year ended			Year ended
		December 31,			December 31,
		2013			2012
	Oil, natural gas and related product sales	$	461,772		$	130,314
	Lease operating costs		(121,892	)		(83,446	)
	Production taxes		(8,180	)		(34,013	)
	Results of operations from oil and natural gas producing activities	$	331,700		$	12,855
Estimate of Proved Oil and Gas Reserves	'
	The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The estimates have been prepared with the assistance of Mire & Associates Inc., an independent petroleum consultant. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.
		Crude			Natural
		Oil (Bbl)			Gas (Mcf)
	PROVED-DEVELOPED AND UNDEVELOPED RESERVES
	December 31, 2011		16,810			232,880
	Revisions of previous estimates		12,178			(44,220	)
	Extensions and discoveries		—			—
	Acquisitions of reserves		66,230			63,660
	Sales of reserves		(5,663	)		(7,271	)
	Production
	December 31, 2012		106,630			308,850
	Revisions of previous estimates		(18,847	)		4,201
	Extensions and discoveries		48,080			158,100
	Acquisitions of reserves		20,750			62,050
	Sales of reserves
	Production		(5,863	)		(7,271	)
	December 31, 2013		150,750			525,930
	PROVED DEVELOPED RESERVES
	December 31, 2013		84,580			373,130
	December 31, 2012		66,460			129,310
Standardized Measure of Discounted Future Net Cash Flows	'
	Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2013
	Future cash inflows	$	18,149,790
	Less: Future production costs		(2,588,090	)
	Future development costs		(32,500	)
	Future income tax expense		(5,279,928	)
	Future net cash flows		10,249,272
	10% discount factor		(5,339,501	)
	Standardized measure of discounted future net cash inflows	$	4,909,771
	Estimated future development cost anticipated for following two years on existing properties	$	32,500
	Future cash inflows	$	12,053,050
	Less: Future production costs		(1,561,000	)
	Future development costs		(56,500	)
	Future income tax expense		(104,355	)
	Future net cash flows		10,331,195
	10% discount factor		(5,845,733	)
	Standardized measure of discounted future net cash inflows	$	4,485,462
	Estimated future development cost anticipated for following two years on existing properties	$	56,500
Changes in Standardized Measure of Discounted Future Net Cash Flows	'
	Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2013
	Beginning of year	$	4,485,462
	Sales of oil and natural gas, net of production costs		(331,700	)
	Net changes in prices and production costs		(86,294	)
	Development costs incurred during the year		(24,000	)
	Changes in future development costs		0
	Extensions, discoveries, and improved recoveries		2,624,270
	Revisions of previous quantity estimates		(531,051	)
	Accretion of discount		467,842
	Net change in income taxes		(3,148,534	)
	Purchases and sale of mineral interests		1,104,390
	Timing and other		349,386
	End of year	$	4,909,771
	Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2012
	Beginning of year	$	1,535,467
	Sales of oil and natural gas, net of production costs		(12,855	)
	Net changes in prices and production costs		(216,011	)
	Development costs incurred during the year		42,000
	Changes in future development costs		(51,118	)
	Extensions, discoveries, and improved recoveries
	Revisions of previous quantity estimates		182,078
	Accretion of discount		271,027
	Net change in income taxes		22,584
	Purchases and sale of mineral interests		2,954,880
	Timing and other		(242,590	)
	End of year	$	4,485,462

Organization_and_Nature_of_Ope1

Organization and Nature of Operations - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
	Dec. 09, 2013	Dec. 31, 2013	Dec. 31, 2012
Organization And Nature Of Operations [Line Items]	'	'	'
Common Stock, shares issued	461,863,084	498,884,626	461,863,084
Common stock shares issued, percentage of stock outstanding	92.50%	'	'
Incurred losses	'	($2,522,122)	($5,684,897)
Negative working capital	'	7,123,000	4,584,000
Deferred Revenue, current	'	4,609,041	6,562,426
Working capital surplus if deferred revenue has been recognized	'	'	1,978,464
Minimum [Member]	'	'	'
Organization And Nature Of Operations [Line Items]	'	'	'
Estimated PV-10 value of turnkey drilling and completion, reserve value	'	20,000,000	'
Estimated PV-10 value of turnkey drilling and completion, revenue	'	40,000,000	'
Minimum [Member] | To be recognized by the end of the first quarter of 2014 [Member]	'	'	'
Organization And Nature Of Operations [Line Items]	'	'	'
Deferred Revenue, current	'	$4,000,000	'

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Cash and equivalents	$606,715	$4,668,839	$3,880,876
Federal Deposit Insurance Corporation coverage limit per institution	250,000	'	'
Impairment charge	0	0	'
Impairment of long-lived assets	0	0	'
Deferred revenue	4,609,041	6,562,426	'
Severance tax	4,000	34,000	'
Net operating loss carry forwards	14,000,000	'	'
Accrued liability related to uncertain tax positions	$728,000	$309,000	'
Furniture and Fixtures [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'10 years	'	'
Vehicles [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'5 years	'	'
Software Development [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'3 years	'	'

Information_about_Liabilities_

Information about Liabilities Measured at Fair Value (Detail) (Asset retirement obligations, USD $)	Dec. 31, 2013	Dec. 31, 2012
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]	'	'
Liabilities (at fair value)	$46,041	$43,747
Fair Value, Inputs, Level 3 [Member]	'	'
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]	'	'
Liabilities (at fair value)	$46,041	$43,747

Summary_of_Companys_Other_Equi

Summary of Company's Other Equipment (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Other equipment	'	'
Less: Accumulated depreciation	($159,036)	($21,466)
Total other equipment, net of accumulated deprecation	153,621	128,258
Furniture and Fixtures [Member]	'	'
Other equipment	'	'
Other equipment	194,275	112,565
Vehicle [Member]	'	'
Other equipment	'	'
Other equipment	25,708	25,708
Software Development [Member]	'	'
Other equipment	'	'
Other equipment	21,047	6,017
Office Equipment [Member]	'	'
Other equipment	'	'
Other equipment	$71,627	$5,434

Asset_Retirement_Obligations_A

Asset Retirement Obligations - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	Well	Well
Asset Retirement Obligations [Line Items]	'	'
Asset retirement obligation realized	$10,500	$10,500
Evaluated wells	213	210

Asset_retirement_obligations_D

Asset retirement obligations (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Asset retirement obligations, beginning of period	$43,747	$40,689
Additions to asset retirement obligation	'	'
Liabilities settled during the period	'	'
Accretion of discount	2,294	3,058
Revision of estimate	-8,704	'
Asset retirement obligations, end of period	$37,337	$43,747

Commitment_and_Contingencies_A

Commitment and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]	'	'
Amount accrued to settle working interest rescissions	$146,000	$146,000
Operating lease expense	$110,000	$83,000

Future_Minimum_Annual_Rental_P

Future Minimum Annual Rental Payments (Detail) (USD $)	Dec. 31, 2013
Operating Leased Assets [Line Items]	'
2014	$136,000
2015	139,000
2016	143,000
2017	147,000
Thereafter	386,000
Total future minimum rental payments	$951,000

Schedule_of_Capitalized_and_Ch

Schedule of Capitalized and Charged Expenses (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'
Acquisitions	$3,806,516	$16,321,566
Exploration Development	1,631,364	3,447,611
Total costs incurred	$5,437,880	$19,769,177

Schedule_of_Results_of_Operati

Schedule of Results of Operation from Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]	'	'
Oil, natural gas and related product sales	$461,772	$130,314
Lease operating costs	-121,892	-83,446
Production taxes	-8,180	-34,013
Results of operations from oil and natural gas producing activities	$331,700	$12,855

Estimate_of_its_Proved_Oil_and

Estimate of its Proved Oil and Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	MMcf	MMcf
Natural Gas [Member]	'	'
Reserve Quantities [Line Items]	'	'
PROVED-DEVELOPED AND UNDEVELOPED RESERVES, beginning balance	308.85	232.88
Revisions of previous estimates	4.201	-44.22
Extensions and discoveries	158.1	'
Acquisitions of reserves	62.05	63.66
Sales of reserves	'	-7.271
Production	-7.271	'
PROVED-DEVELOPED AND UNDEVELOPED RESERVES, ending balance	525.93	308.85
PROVED DEVELOPED RESERVES	373.13	129.31
Crude Oil [Member]	'	'
Reserve Quantities [Line Items]	'	'
PROVED-DEVELOPED AND UNDEVELOPED RESERVES, beginning balance	106.63	16.81
Revisions of previous estimates	-18.847	12.178
Extensions and discoveries	48.08	'
Acquisitions of reserves	20.75	66.23
Sales of reserves	'	-5.663
Production	-5.863	'
PROVED-DEVELOPED AND UNDEVELOPED RESERVES, ending balance	150.75	106.63
PROVED DEVELOPED RESERVES	84.58	66.46

Supplemental_Information_Addit

Supplemental Information - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcf	MMcf
Oil and Gas In Process Activities [Line Items]	'	'	'
Cost incurred during period for proved undeveloped reserves that were transferred to proved developed reserves	$24,000	'	'
Estimated future development costs relating to the development of proved undeveloped reserves	($32,500)	($56,500)	'
Future Cash flow tax rate	34.00%	'	'
Crude Oil [Member]	'	'	'
Oil and Gas In Process Activities [Line Items]	'	'	'
Extensions, discoveries and Improved recoveries - Crude Oil	48.08	'	'
Purchase of undeveloped properties	20.75	66.23	'
Natural Gas [Member]	'	'	'
Oil and Gas In Process Activities [Line Items]	'	'	'
Oil and natural gas prices	3.67	2.85	'
Extensions, discoveries and Improved recoveries - Crude Oil	158.1	'	'
Purchase of undeveloped properties	62.05	63.66	'
Average production cost of oil and gas	'	2.76	4.15
Crude Oil [Member]	'	'	'
Oil and Gas In Process Activities [Line Items]	'	'	'
Oil and natural gas prices	96.91	94.71	'
Average production cost of oil and gas	'	94.68	95.84

Standardized_Measure_of_Discou

Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'
Future cash inflows	$18,149,790	$12,053,050
Less: Future production costs	-2,588,090	-1,561,000
Future development costs	-32,500	-56,500
Future income tax expense	-5,279,928	-104,355
Future net cash flows	10,249,272	10,331,195
10% discount factor	-5,339,501	-5,845,733
Standardized measure of discounted future net cash inflows	4,909,771	4,485,462
Estimated future development cost anticipated for following two years on existing properties	$32,500	$56,500

Changes_in_Standardized_Measur

Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'
Beginning of year	$4,485,462	$1,535,467
Sales of oil and natural gas, net of production costs	-331,700	-12,855
Net changes in prices and production costs	-86,294	-216,011
Development costs incurred during the year	-24,000	42,000
Changes in future development costs	0	-51,118
Extensions, discoveries, and improved recoveries	2,624,270	182,078
Revisions of previous quantity estimates	-531,051	'
Accretion of discount	467,842	271,027
Net change in income taxes	-3,148,534	22,584
Purchases and sale of mineral interests	1,104,390	2,954,880
Timing and other	349,386	-242,590
End of year	$4,909,771	$4,485,462