Hydrocarb Energy (HECCQ) 10-K/A 10 Jun 15 2014 FY Annual report (amended) Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Jul. 31, 2014	Oct. 22, 2014	Jan. 31, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	HYDROCARB ENERGY CORP
Entity Central Index Key	1425808
Current Fiscal Year End Date	-24
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$22,570,168
Entity Common Stock, Shares Outstanding		21,186,602
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	TRUE
Amendment Description	On November 13, 2014, Hydrocarb Energy Corporation (the “Company”) filed its Annual Report on Form 10-K for its fiscal year ended July 31, 2014 (the “Original Form 10-K”). Subsequent to the filing of the Original Form 10-K, the Company became aware of various issues (described in greater detail below) relating to such filing and, the Company is hereby amending its Original Form 10-K. Revisions to the Original Form 10-K are made in the following areas. Revisions to the Original Form 10-K are made in Items 1, 7, 8 and 15. In Note 15 – Subsequent Events, added language relating to termination of oil and gas activities in the U.A.E. In Note 16 - Supplemental Oil and Gas Information (Unaudited), expanded disclosure related to reasons and circumstances for changes in “Revisions of previous estimates” for the years ended July 31, 2014 and 2013, respectively. Also expanded disclosure to explain differences between total proved undiscounted future net income shown in the reserve report and the disclosure in Note 16 of future cash inflows less the future production and future development costs for each of the periods ending July 31, 2014 and 2013, respectively.
Document Period End Date	31-Jul-14

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Jul. 31, 2014	Jul. 31, 2013
Current assets:
Cash and cash equivalents	$144,258	$354,829
Oil and gas revenues receivable	372,120	725,691
Accounts receivable - related party	58,014	201,284
Other current assets	446,320	345,942
Other receivables, net	38,455	312,997
Total current assets	1,059,167	1,940,743
Oil and Gas Property, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $3,491,420 and $2,617,478, respectively; and accumulated impairment of $373,335 and $373,335, respectively	15,288,370	16,867,029
Unevaluated property	2,119,769	1,124,805
Restricted cash	6,877,944	6,920,739
Other assets	219,942	180,726
Property and equipment, net of accumulated depreciation of $135,590 and $116,945, respectively	166,963	58,053
TOTAL ASSETS	25,732,155	27,092,095
Current liabilities:
Accounts payable and accrued expenses	2,795,675	2,816,084
Current portion of notes payable	334,688	259,644
Asset retirement obligations - short term	1,133,690	724,374
Advances	195,904	180,804
Due to related parties	165,542	301,378
Total current liabilities	4,625,499	4,282,284
Notes payable	0	142,992
Notes payable - related party	600,000	0
Asset retirement obligations - long term	10,582,540	10,209,024
Total liabilities	15,808,039	14,634,300
Stockholders' Deficit:
Common stock: $001 par value; 333,333,333 shares authorized; 20,963,759 and 4,427,071 shares issued and outstanding as of July 31, 2014 and 2013, respectively	21,082	4,427
Receivable for common stock	-2,184,879	0
Additional paid in capital	78,953,599	75,137,401
Accumulated deficit	-70,106,351	-63,522,775
Treasury stock	0	-822,250
Total stockholders' equity	9,958,651	12,486,803
Noncontrolling interests	-34,535	-29,008
Total equity	9,924,116	12,457,795
TOTAL LIABILITIES AND EQUITY	25,732,155	27,092,095
Series A 7% Convertible Preferred Stock [Member]
Stockholders' Deficit:
Preferred stock	3,275,200	0
HCN Series 7% Convertible Preferred Stock [Member]
Stockholders' Deficit:
Preferred stock	$0	$1,690,000

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Accumulated depletion on evaluated oil and gas property accounted for using the full cost method of accounting	$3,491,420	$2,617,478
Accumulated impairment on evaluated oil and gas property accounted for using the full cost method of accounting	373,355	373,355
Accumulated depreciation recorded for property and equipment	$135,590	$116,945
Equity [Abstract]
Preferred stock, shares issued (in shares)	4,225
Common stock, par value (in dollars per share)	$0.00	$0.00
Common stock, shares authorized (in shares)	333,333,333	333,333,333
Common stock, shares issued (in shares)	21,081,602	4,427,071
Common stock, shares outstanding (in shares)	21,081,602	4,427,071
Series A 7% Convertible Preferred Stock [Member]
Equity [Abstract]
Preferred Stock, par value (in dollars per share)	$400	$400
Preferred stock, shares authorized (in shares)	10,000
Preferred stock, shares issued (in shares)	8,188
Preferred stock, shares outstanding (in shares)	8,188
HCN Series 7% Convertible Preferred Stock [Member]
Equity [Abstract]
Preferred Stock, par value (in dollars per share)	$400	$400

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS [Abstract]
Revenues	$5,065,096	$7,070,540
Operating expenses
Lease operating expense	4,913,313	4,560,201
Depreciation, depletion, and amortization	910,837	1,121,018
Accretion	1,043,928	1,056,508
Consulting fees - related party	6,754	196,384
Acquisition-related costs - related party	0	34,834,752
General and administrative expense	4,585,450	4,198,747
Total operating expenses	11,460,282	45,967,610
Loss from operations	-6,395,186	-38,897,070
Consulting and other income (expense)	23,134	1,145,997
Interest expense, net	-132,955	-149,131
Loss on sale of available for sale securities	0	-517,920
Impairment of available for sale securities	0	-275,327
Gain on derivative warrant liability	0	1,056,224
Loss on disposal of assets	-23,990	-14,054
Foreign currency transaction gain (loss)	-21,253	-5,884
Net loss before income taxes	-6,550,250	-37,657,165
Income tax provision	-4,599	122,949
Net loss	-6,554,849	-37,534,216
Less: Net loss attributable to noncontrolling interests	-5,527	-8,483
Net loss attributable to Hydrocarb Corporation	-6,549,322	-37,525,733
Dividend on preferred stock	-34,254	-69,920
Deemed dividend on preferred stock	-150,548	0
Accretion dividend - Beneficial Cash Feature on preferred stock	-949,808	0
Net loss attributable to Hydrocarb Energy Corp after dividends	($7,683,932)	($37,595,653)
Basic and diluted loss per common share: (in dollars per share)	($0.51)	($8.66)
Weighted average shares outstanding (basic and diluted) (in shares)	15,150,782	4,342,864

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Common Stock [Member]	Common Stock [Member]	Preferred Stock [Member]	Preferred Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Other Comprehensive Income [Member]	Stock Subscription Receivable [Member]	Accumulated Deficit [Member]	Total
	HCN [Member]	HEC [Member]	HCN [Member]	HEC [Member]
Balance at Jul. 31, 2012	$0	$3,597	$0	$0	$38,342,757	$0	($743,082)	$0	($25,927,122)	$11,676,150
Balance, (in shares) at Jul. 31, 2012	0	3,597,071	0	0
Acquisition		830			35,395,970					35,396,800
Acquisition, (in shares)		830,000
Issuance of HCN preferred stock			1,690,000							1,690,000
Issuance of HCN preferred stock (in shares)			4,225
HCN purchase of HEC common stock						-822,250				-822,250
Share-based compensation:
Amortization of fair value of stock options					933,126					933,126
Warrants granted to related party					196,384					196,384
Expiration of derivative warrant liability					269,164					269,164
Unrealized loss on available for sale securities							743,082			743,082
Dividend on HCN preferred stock									-69,920	-69,920
Net loss attributable to HEC									-37,525,733	-37,525,733
Balance at Jul. 31, 2013	0	4,427	1,690,000	0	75,137,401	-822,250	0	0	-63,522,775	12,486,803
Balance, (in shares) at Jul. 31, 2013	0	4,427,071	4,225	0						4,427,071
Issuance of HCN preferred stock	6,560				24,511					31,071
Issuance of HCN preferred stock (in shares)	6,559,257
Issuance of HCN preferred stock to settle debt and accounts payable			1,585,200							1,585,200
Issuance of HCN preferred stock to settle debt and accounts payable (in shares)			3,963
HCN sale of HEC common stock for receivable					177,750	822,250		-1,000,000		0
HCN sale of HEC common stock for receivable					-1,729,688	3,589,567		-1,859,879		0
HEC preferred stock exchanged in connection with HCN acquisition			-3,275,200	3,275,200						0
HEC preferred stock exchanged in connection with HCN acquisition (in shares)			-8,188	8,188
HEC common stock exchanged in connection with HCN acquisition	-6,560	8,397			-1,837					0
HEC common stock exchanged in connection with HCN acquisition (in shares)	-6,559,257	8,396,667
HEC Common stock issued to satisfy contingently-issued rights from NEI Acquisition		7,470			-7,470					0
HEC Common stock issued to satisfy contingently-issued rights from NEI Acquisition (in shares)		7,470,000
HEC common stock issued to settle debt		620			3,588,947	-3,589,567				0
HEC common stock issued to settle debt (in shares)		619,960
Deemed Dividend on Preferred Stock					949,808					949,908
Deemed Dividend on Preferred Stock					-949,808					-949,908
Share-based compensation:
Amortization of fair value of stock options					943,572					943,572
Warrants granted to related party					6,754					6,754
Stock issued to employees and directors		168			813,659					813,827
Stock issued to employees and directors (in shares)		167,904
Expiration of derivative warrant liability										0
Dividend on HCN preferred stock									-34,254	-34,254
Cash collection on stock subscription receivable								675,000		675,000
Net loss attributable to HEC									-6,549,322	-6,549,322
Balance at Jul. 31, 2014	$0	$21,082	$0	$3,275,200	$78,953,599	$0	$0	($2,184,879)	($70,106,351)	$9,958,651
Balance, (in shares) at Jul. 31, 2014	0	21,081,602	0	8,188						21,081,602

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	($6,554,849)	($37,534,216)
Adjustments to reconcile net income loss to net cash used in operating activities:
Depreciation, depletion, and amortization	910,837	1,121,018
Accretion	1,043,928	1,056,508
(Gain) loss on sale of available for sale securities	0	517,920
Impairment of available for sale securities	0	275,327
Loss on disposal of assets	23,990	14,054
Change in allowance for doubtful accounts	11,948	57,491
Warrants granted to related party	6,754	196,384
Share based compensation	1,757,399	933,126
Acquisition-related costs - related party	0	34,834,752
Gain on derivative warrant liability	0	-1,056,224
Changes in operating assets and liabilities:
Accounts receivable	353,571	168,096
Other receivables	262,594	0
Accounts receivable - related party	143,270	-68,620
Other assets	263,510	-89,829
Accounts payable and accrued expenses	184,900	299,246
Accounts payable related party	1,244,054	125,021
Advances	15,100	125,643
Settlement of asset retirement obligation	-123,664	-318,225
NET CASH USED IN OPERATIONS	-456,658	657,472
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of oil and gas properties	-1,052,679	-1,564,490
Purchases of property and equipment	-169,794	-13,648
Proceeds from sale of oil and gas properties	625,000	195,563
Change in restricted cash	42,795	-30,739
Purchase of available for sale securities	0	-24,593
Proceeds from sale of available for sale securities	0	287,874
CASH USED IN INVESTING ACTIVITIES	-554,678	-1,150,033
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on notes payable	-471,052	-271,972
Proceeds from note payable to related party	600,000	0
Proceeds from collections on receivable for stock sale	675,000	0
Proceeds from HCN issuance of common stock	31,071	0
Dividend on HCN preferred stock	-34,254	-69,920
CASH PROVIDED BY FINANCING ACTIVITIES	800,765	-341,892
NET CHANGE IN CASH AND CASH EQUIVALENTS	-210,571	-834,453
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	354,829	1,189,282
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$144,258	$354,829

Description_of_Business_and_Su

Description of Business and Summary of Significant Accounting Policies	12 Months Ended
	Jul. 31, 2014
Description of Business and Summary of Significant Accounting Policies [Abstract]
Description of Business and Summary of Significant Accounting Policies	Note 1 – Description of Business and Summary of Significant Accounting Policies
	Description of business and basis of presentation
	We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States and onshore in Namibia, Africa.  We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.  On April 4, 2012 we completed a one new share for twenty-five old share (1:25) reverse stock split and as a result our authorized capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock.  Also, effective April 4, 2012, we changed our name to “Duma Energy Corp.”  Effective May 16, 2012, we increased our authorized capital from 20,000,000 shares to 500,000,000 shares of common stock.  Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 500,000,000 to 1,000,000,000 shares of common stock.    Effective February 18, 2014, we changed our name from Duma Energy Corp. to Hydrocarb Energy Corp.  Effective May 8, 2014, we effected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split. Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.  Our common stock is quoted under the symbol “HECC” on the OTCBB.
	The acquisition of HCN, an entity under common control, on December 9, 2013 (See Note 2 – HCN Acquisition) has resulted in a change in the reporting entity. The consolidated financial statements presented for the periods subsequent to the acquisition include the accounts of HCN and its subsidiaries. As HEC and HCN are under the common control of same shareholder group, the acquired assets and liabilities were recorded at the historical carrying value and the consolidated financial statements were retroactively restated to reflect the Company as if HCN had been owned since the beginning of the earliest period presented.
	We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, (iv) Namibia Exploration, Inc., a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation, (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited, a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC, a UAE limited liability corporation.
	As of July 31, 2014, we maintain developed and undeveloped acreage offshore in Texas.  As of July 31, 2014, we were producing oil and gas from our working interest in four offshore fields in Galveston Bay, Texas.  During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated working interest in a concession located onshore in Namibia, Africa.  During December 2013, with our acquisition of Hydrocarb Corporation, we acquired 51% working interest in this onshore Namibia, Africa concession and now own 90% working interest (100% cost responsibility) in the Namibia, Africa concession.
	Reclassifications
	Certain prior year amounts have been reclassified to conform with the current presentation.
	Principles of consolidation
	The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”).  The accompanying consolidated financial statements include the accounts of Hydrocarb Energy Corp., our wholly owned subsidiaries Penasco Petroleum Corporation (“Penasco”), SPE Navigation I, LLC (“SPE”), Galveston Bay Energy, LLC (“GBE”), Namibia Exploration, Inc. (“NEI”), Hydrocarb Corporation (“HCN”), Hydrocarb Texas Corporation, and Hydrocarb Namibia Energy (Pty) Limited.  In addition, these financials include our 95% ownership interest in Otaiba Hydrocarb LLC.  All significant intercompany accounts and transactions have been eliminated in consolidation.
	Use of estimates
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.
	Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments, estimates of the costs and timing of asset retirement obligations, and oil and natural gas proved reserve quantities.  Oil and natural gas proved reserve quantities form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.
	Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.
	Cash and cash equivalents
	Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value.
	Our functional currency is the United States dollars.  Transactions denominated in foreign currencies are translated into their United States dollar equivalents using current exchange rates.  Monetary assets and liabilities are translated using exchange rates that prevailed as of the balance sheet date.  Non-monetary assets and liabilities are translated using exchange rates that prevailed as of the transaction date.  Revenue, if applicable and expenses are translated using average exchange rates over the accounting period.  We have had no revenue denominated in foreign currencies. Gains or losses resulting from foreign currency transactions are included in results of operations.
	Receivables and allowance for doubtful accounts
	Oil and gas revenues receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.
	Accounts receivable – related party includes the oil and gas revenue receivable from our Barge Canal properties, which, up until September 1, 2013, were operated by a company owned by one of our former officers who was also a director, and joint interest billings receivable from two working interest partners who are related to our former Chief Financial Officer, the former Chief Executive Officer and the current Chief Executive Officer. This balance also includes an oil and gas receivable from Lifestream, LLC, a company owned by the brother of our current CEO.
	Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.
	We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.  As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.
	Available for sale securities
	We invest in marketable equity securities which are classified as available for sale. The first in first out method is used to determine the cost basis of our equity securities sold. Available-for-sale securities are marked to market based on the fair values of the securities determined in accordance with ASC Section 820 (Fair Value Measurement), with the unrealized gains and losses, net of tax, reported as a component of accumulated other comprehensive income (loss).
	Other current assets
	Other current assets consist primarily of prepaid insurance, prepaid interest expense, prepayments made towards properties not operated by us, and accrued interest on our deposits.
	Concentrations
	Our operations are concentrated in Texas and the majority of our operations are conducted offshore in Galveston Bay.  We operate in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry as a whole were adversely affected, for example by weather, supply shortages, or other factors, we would also experience adverse effects. Because our properties are offshore, we are also vulnerable to adverse weather.
	For the year ended July 31, 2014, 83% of our revenue was attributable to one purchaser.  At July 31, 2014, this same purchaser accounted for 88% of our accounts receivable. For the year ended July 31, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable.
	We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.
	Oil and natural gas properties
	We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
	Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.
	We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.
	Capitalized costs included in the amortization base are depleted using the unit of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
	Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
	Impairment
	The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.  During the years ended July 31, 2014 and July 31, 2013, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.
	Asset retirement obligation
	We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.
	Restricted cash
	Restricted cash consists of certificates of deposit that have been posted as collateral for letters of credit supporting bonds guaranteeing remediation of our oil and gas properties in Texas and escrow funds deposited directly with regulatory authorities. As of July 31, 2014 and 2013, restricted cash totaled $6,877,944 and $6,920,739, respectively.
	Other assets
	Other assets at July 31, 2014 and 2013 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases.  These are paid as they come due on an ongoing basis and amortized over the rental period.  In addition, other assets also include a domain name for $30,267, which is an intangible asset with an indefinite life due to the fact that it is renewable annually for nominal cost.  We evaluate intangible assets with an indefinite life for possible impairment at least annually by comparing the fair value of the asset with its carrying value.
	Property and equipment, other than oil and gas
	Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.
	Impairment of long-lived assets
	We periodically review our long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment on our non-oil and gas long-lived assets during the years ended July 31, 2014 and 2013, respectively.
	Advances
	Advances consist of prepayments received from working interest partners pertaining to their share of the costs of drilling oil and gas wells.  Partners are billed in advance for the estimated cost to drill a well and as the work proceeds, the prepayment is applied against their share of the actual drilling cost.  As of July 31, 2014 and 2013, advances totaled $195,904 and $180,804, respectively.
	Revenue recognition
	We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned.  Severance and ad valorem taxes are reflected as a component of lease operating expense.
	Income taxes
	We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
	Fair value
	Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.
	Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.
	The three-level hierarchy is as follows:
	●	Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.
	●	Level 2 inputs consist of quoted prices for similar instruments.
	●	Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.
	Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging – Contracts in an Entity’s Own Stock.” (See Note 8 – Fair Value).
	The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain on derivative warrant liability.”
	Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.
We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2014 or July 31, 2013. The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable – related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.
Stock-based compensation
ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.
We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.”  ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete.  Generally, our awards do not entail performance commitments.  When an award vests over time such that performance occurs over multiple reporting periods, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date.  When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the vesting date, which is presumed to be the date performance is complete.
We recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.
Stock Split
On May 8, 2014, we affected a 1-for-3 reverse stock split.  All share and per share amounts have been retroactively restated to reflect the reverse split. This presentation is consistent with the guidance in ASC 260-10-55-12, Earnings Per Share, which requires retroactive restatement of earnings per share if a capital structure change due to a stock dividend, stock split or reverse split occurs after the date of the latest balance sheet, but before the release of the financial statements or the effective date of the registration statement, whichever is later.
Earnings per share
We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2014 and 2013, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.
Contingencies
Legal
We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.  See Note 13 - Commitments and Contingencies for more information on legal proceedings.
Environmental
We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.
Accumulated Other Comprehensive Income (Loss), net of tax
We follow the provisions of ASC 220, "Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net loss, comprehensive loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company.
Recent accounting pronouncements
In March 2013, the FASB amended ACS 830, Foreign Currency Matters, to clarify the appropriate accounting when a parent ceases to have a controlling interest in a subsidiary or group of assets that is a business within a foreign entity. This clarification provides that the cumulative translation adjustment should only be released into net income if the loss of controlling interest represents complete or substantially complete liquidation of the foreign entity in which the subsidiary or asset group had resided. This amendment is effective for us starting with our first quarter of fiscal year 2015 and adoption would impact our consolidated financial condition and results of operations if we dispose of a foreign entity.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU No. 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance when it becomes effective. This new standard is effective for us starting with our first quarter of fiscal year 2018.  Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.
Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on our financial position or results from operations.

Acquisitions

Acquisitions	12 Months Ended
	Jul. 31, 2014
Acquisitions [Abstract]
Acquisitions	Note 2 – Acquisitions
	HCN Acquisition
	On December 9, 2013 (“Acquisition Date”), we acquired HCN (“HCN Acquisition”) pursuant to a Share Exchange Agreement (“HCN Agreement”) dated November 27, 2013.  The purchase price was 8,396,667 shares of HEC’s common stock to HCN’s shareholders in exchange for 100% of the outstanding equity interest in HCN and 8,188 shares of HEC Series A Preferred Stock to a holder of convertible preferred stock in HCN in exchange of 100% of the holder’s preferred stock in HCN. At date of closing the 8,396,667 shares of common stock issued had a market valuation of $64,990,200 (based on market close of $7.74 on December 9, 2013) and the preferred stock issued had a value of $3,275,200 (8,188 shares at par value of $400).
	In addition, the HCN Agreement provided that HEC would issue 7,470,000 shares of its common stock to the holders of certain rights to acquire HEC stock.  These rights were previously issued by HEC as contingent consideration in connection with the acquisition of NEI.  The rights had been convertible into HEC common stock based upon HEC market capitalization milestones.  The rights were issued to entities deemed related parties to HEC.
	In anticipation of the HCN Acquisition, HEC issued 619,960 shares of its common stock to HCN as full payment for HEC’s indebtedness to HCN in the amount of $3,589,567.  A condition to the Agreement closing was that HCN would sell the 619,960 shares before closing of the acquisition, which it did (see Note 10 – Capital Stock – Receivables for Common Stock).
	With HCN, we acquired its 100% owned subsidiaries: Hydrocarb Namibia Energy (Pty) Limited, a Namibia Company and Hydrocarb Texas Corporation, a Texas Corporation; and its 95% owned subsidiary Otaiba Hydrocarb LLC, a UAE Limited Liability Company.
	Prior to the HCN Acquisition, HCN was directly and indirectly majority-owned and controlled by HEC’s Chairman of the Board and entities related to him and his family.  Since HEC and HCN were under common control of a controlling party both before and after the completion of the share exchange, the transaction was accounted for as a business acquired from an entity under common control and the assets and liabilities acquired were recorded at HCN’s historical cost at Acquisition Date following ASC 805-50-30, Business Combinations.  Under this accounting treatment, the results of operations for the year ended July 31, 2014 and assets and liabilities of HCN are included in these financial statements as if the transaction had occurred at the beginning of the reporting period.  Prior reporting periods in these financial statements have been retroactively adjusted to include HCN and its subsidiaries.
	According to ASC 805-50-30, the net assets of HCN are to be recorded at historical cost, therefore, the value of the 8,396,667 common shares and 8,188 preferred shares are deemed to be the same as the historical value of HCN net assets of $1,398,127 with excess of $599,409 recorded as additional paid in capital by HEC.
	Summary of the accounting entry to record this acquisition in December 2013 is as follows:
	Assets acquired		$	1,529,246
	Liabilities assumed			(161,599	)
	Noncontrolling interest in 95% owned HCN subsidiary			30,480
			$	1,398,127
	Series A 7% Preferred Stock, par $400		$	3,275,200
	Common stock, at par			8,397
	Receivable for common stock			(2,484,879	)
	Additional paid-in capital			599,409
			$	1,398,127
	HCN had 51% working-interest rights in and operated an unevaluated onshore petroleum Namibian concession measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy. (“Namibian Concession”) described in Note 5 – Oil and Gas Properties, below, and provided international oilfield consulting services.  Prior to this acquisition, HEC owned a 39% working-interest right in this concession see NEI Acquisition below).  With the HCN acquisition, we now own a 90% working interest (100% cost responsibility) in the concession.  This 5.3 million-acre concession is located in northern Namibia in Africa.  The concession specifies the following minimum cost responsibilities on an 8/8ths basis:
	-1	Initial Exploration Period (expires September 2015): Perform a hydrocarbon potential study, gather and review existing technical data including reprocessing of available seismic lines, and acquire and process 750 kilometers of new 2D seismic data.  The minimum expenditure is $4,505,000.
	-2	First Renewal Exploration Period (two years from end of the Initial Exploration Period):  Acquire 200 square kilometers of 3D seismic data, interpret and map the data, design a drilling program, drill one well, conduct an environmental study, and relinquish 25% of the exploration license area.  The minimum expenditure is $17,350,000.
	-3	Second Renewal (Production License) Exploration Period (25 years):  Report on reserves and production and conduct an environmental study.  The minimum expenditure is $300,000.
	In conjunction with the HCN acquisition, the HEC Board of Directors authorized the immediate issuance of 7,470,000 shares of our common stock to the former owners of NEI.  We previously acquired NEI on August 7, 2012 and these 7,470,000 shares had been contingently-issuable consideration for the acquisition of NEI. We issued these shares on December 9, 2013.  The original agreement contained market conditions for the issuance of this stock.
	Namibia Exploration, Inc. (“NEI”) Acquisition
	On August 7, 2012, we entered into a Share Exchange Agreement (the “NEI Agreement”), which was closed on September 6, 2012, under which we purchased NEI, a corporation organized under the laws of the state of Nevada for the issuance of 8,396,667 shares of our common stock as described below (the “NEI Acquisition”).  Prior to the acquisition, NEI was directly and indirectly owned and controlled by HEC’s then-Chief Executive Officer, his brother-in-law, and his father-in-law.
	NEI was formed in February 2012 and its sole asset was a 39% working interest (43.33% cost responsibility) in the Namibian Concession. With the acquisition of HCN, the Company now has a 90% working interest (100% cost responsibility) in the Namibian Concession.  HEC now holds working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. ("NPC Namibia").
	As NEI had no operations other than the ownership of the Namibian Concession, the transaction was accounted for as an asset purchase from an entity under common control and the asset was recorded at NEI’s historical cost of $562,048 with additional amounts paid considered compensatory and thus an expense of the acquisition.  The consideration included stock granted at the closing of the transaction as well as a series of stock grants that were contingent upon the achievement of certain market conditions.   The value of the total consideration, including contingent stock and the liabilities assumed in excess of NEI’s assets, was computed as described below.  $34,834,752 was reflected in our statement of operations as Acquisition-related costs – related party in conjunction with this transaction.
	NEI originally acquired its interests in the Namibian Concession from Hydrocarb Namibia (a subsidiary of HCN) in exchange for a farm-in fee, totaling $2,400,000, payable over two years. At that time HCN was partly owned by the uncle of HEC’s then-Chief Executive Officer’s wife and brother-in-law.  Because the $2,400,000 fee was a related party transaction, and accordingly presumed not to be arms-length, and because there was substantial uncertainty about the realizability of the fees paid to HCN given that the concession was unproved, management concluded that HCN’s historical expenditures of $562,048 (which consists primarily of fees paid to the Namibian government for the concession) represented the fair value of the asset and NEI’s cost basis in the asset. The farm-in agreement also provided for preferential offerings of other international oil and gas opportunities similar to the concession in Namibia.  With the Company’s acquisition of HCN and its accounting for the HCN transaction as the acquisition of a business from an entity under common control, the $2,400,000 fee has been eliminated in consolidation, since these financial statements have been retroactively adjusted to include HCN and its subsidiaries since the beginning of the reporting period herein.
	Consideration for the acquisition of NEI
	Pursuant to the terms of the Agreement, HEC issued 830,000 shares of common stock in September 2012 at the closing.  An additional 2,490,000 shares were contingently issuable as consideration for the NEI Acquisition, in accordance with the following milestones which were to have been reached within 10 years after the closing of the acquisition:
	●	a further 830,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $82,000,000;
	●	a further 2,490,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $196,000,000; and
	●	a further and final 4,150,000 of the Shares will be issued when and if HEC's 10-day volume-weighted average market capitalization reaches $434,000,000.
	NEI’s cost basis in the Namibia Concession was $562,048.   The assets and liabilities were recorded at NEI’s carrying value on the date of the acquisition and the excess purchase price over the net assets acquired was recorded as an acquisition-related expense (compensation) because this was a related party transaction.   The purchase price consisted of the 830,000 shares that were awarded at closing, which were valued using the closing market price of the stock on the date of grant, and the 7,470,000 shares of the contingent stock grant.  The fair value of contingent stock grant was valued in accordance with ASC 820 – Fair Value Measurements.  The determination of fair value used a market approach weighted at 75% and the income approach (discounted cash flows) weighted at 25%.  The computations included consideration of projections of the future results of HEC and NEI, using multiple probability-weighted scenarios, and projections of HEC’s capital structure.  As of July 31, 2013, we had recognized $34,834,752 of expense associated with the acquisition of NEI, which consisted of the assumption of NEI’s net liability of $1,837,952, $3,784,800 associated with the 2,490,000 shares issued at the closing date of the acquisition and $29,212,000 associated with the contingent consideration.
	In conjunction with the HCN acquisition in December 2013, the HEC Board of Directors authorized the immediate issuance of these contingently issuable 7,470,000 shares of our common stock to the former owners of NEI.  We issued these shares on December 9, 2013.
	Hydrocarb agreement
	In conjunction with the execution of the NEI Agreement, and as a condition of Closing, HEC entered into a Consulting Services Agreement with HCN (the "Consulting Agreement"), whereby HCN would provide various consulting services with respect to HEC's business ventures in Namibia and whereby HCN acknowledged and agreed that the obligations of NEI under its existing Farmin Opportunity Report with HCN (the "FOR") would be satisfied in exchange for HEC paying a consulting fee (the "Fee") to HCN of $2,400,000.  As a result of HEC’s acquisition of HCN, this Consulting Agreement and its related income/expense and receivable/payable have been eliminated in consolidation.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Jul. 31, 2014
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information [Text Block]	Note 3 – Supplemental Cash Flow Information
	As of and For the year ended July 31,	2014			2013
	SUPPLEMENTAL CASH FLOW INFORMATION
	Cash paid during the period for:
	Income taxes	$	10,000		$	42,483
	Interest	$	21,497		$	207,269
	NONCASH INVESTING AND FINANCING ACTIVITIES
	Issuance of HEC common stock to setle notes payable	$	3,589,567			-
	Preferred stock exchanged for HCN preferred stock for acquisition of HCN	$	3,275,200		$	-
	Receivable for common stock	$	1,859,879		$	-
	Settlement of HCN debt with HCN preferred stock	$	1,585,200		$	1,690,000
	Receivable for common stock - related party	$	1,000,000		$	-
	Note payable for prepaid insurance	$	403,104		$	260,905
	Asset retirement obligation sold	$	33,195		$	438
	Common stock exchanged for HCN common stock for acquisition of HCN	$	8,397		$	-
	Common stock issued to satisfy contingently issuable shares from 2012 acquisition of Namibia Exploration , Inc.	$	7,470		$	-
	Asset retirement obligations - change in estimate	$	(104,237	)	$	786,120
	Treasury stock acquired via note receivable	$	-		$	822,250
	Acquisition of Namibia Exploration, Inc.	$	-		$	562,048
	Expiration of derivative warrant liability	$	-		$	269,164
	Accounts payable for oil and gas properties	$	-		$	188,607
	Asset retirement obligations incurred	$	-		$	26,500

Available_for_Sale_Securities

Available for Sale Securities	12 Months Ended
	Jul. 31, 2014
Available for Sale Securities [Abstract]
Available for Sale Securities	Note 4 – Available for Sale Securities
	During the year ended July 31, 2012, we purchased securities at a market price of $702,959 and reclassified $6,383 unrealized loss from other comprehensive loss into earnings.
	During September 2012, we received cash proceeds of $145,237 from sales of securities with a cost basis of $607,201; thus, we had a realized loss on sale of available for sale securities of $461,964. In October 2012, we recognized an other than temporary impairment of $275,327 resulting in a new cost basis in the stock of $174,000.
	During December 2012, we received cash proceeds of $142,637 from sales of securities with a cost basis of $198,593; thus, we had a realized loss on sale of available for sale securities of $55,956. We reclassified $743,082 unrealized loss from other comprehensive loss into earnings in conjunction with these sales and the impairment.
	As of July 31, 2014 and July 31, 2013, we do not hold any available for sale securities.

Oil_and_Gas_Properties

Oil and Gas Properties	12 Months Ended
	Jul. 31, 2014
Oil and Gas Properties [Abstract]
Oil and Gas Properties	Note 5 – Oil and Gas Properties
	Oil and natural gas properties consisted of the following:
	For the year ended July 31,		2014			2013
	Evaluated Properties
	Costs subject to depletion		$	19,153,125		$	19,857,842
	Accumulated impairment			(373,335	)		(373,335	)
	Accumulated depletion			(3,491,420	)		(2,617,478	)
	Total evaluated properties			15,288,370			16,867,029
	Unevaluated properties			2,119,769			1,124,805
	Net oil and gas properties		$	17,408,139		$	17,991,834
	Evaluated properties
	Additions to evaluated oil and gas properties during the year ended July 31, 2014 and 2013 consisted mainly of exploration costs, geological and geophysical costs of $34,029 and $157,818, respectively.
	Effective September 1, 2013, we conveyed our interest in the Dix, Melody, Curlee, Palacios and Illinois properties to Carter E&P, LLC in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities of $4,381. In accordance with full cost rules, we recognized no gain or loss on the sale.
	Effective March 25, 2014, we conveyed our interest in the Barge Canal Welder properties to Winright Oil Company, LLC.  We received net proceeds of $625,000 for this conveyance.  In accordance with full cost rules, we recognized no gain or loss on the sale.
	Unevaluated Properties
	Namibia, Africa
	In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa.  In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa. With our acquisition of HCN in December 2013, we acquired an additional 51% (56.67% cost responsibility) and we now own 90% (100% cost responsibility) of this concession, as described above in Note 2 –Acquisitions.  This property is a 5.3 million-acre concession in northern Namibia in Africa.
	For the year ended July 31, 2014 we have incurred total costs of $1,406,114, including NEI’s cost basis incurred upon acquisition of the property, which was $562,048.  For the year ended July 31, 2013 we incurred total costs of $713,655, including NEI’s cost basis incurred upon acquisition of the property, which was $562,048. The concession specifies the following minimum cost responsibilities on an 8/8ths basis:
	-1	Initial Exploration Period (expires September 2015): Perform a hydrocarbon potential study, gather and review existing technical data including reprocessing of seismic lines,  and acquire and process 750 kilometers of new 2D seismic data.  The minimum expenditure is $4,505,000.
	-2	First renewal exploration period (two years from end of the initial exploration period): Acquire 200 square kilometers of 3D seismic data, interpret and map the data, design a drilling program, drill one well, conduct an environmental study, and relinquish 25% of the Exploration license area.  The minimum expenditure is $17,350,000.
	-3	Second Renewal (Production License) Exploration Period (25 years): report on reserves and production, and conduct an environmental study. The minimum expenditure is $300,000.
	As of July 31, 2014, approximately $2.1 million has been expended towards the initial exploration period.  As of July 31, 2013, approximately $900,000 has been expended towards the initial exploration period.
	Additions to unevaluated properties for the year ended July 31, 2014 consisted primarily of:
	-1	Approximately $800,000 of exploration costs associated with the acquisition of aerial gravity and magnetic data over the Namibia concession, and
	-2	Approximately $129,000 of leasehold costs, specifically payment of the annual concession fee to the Government of Namibia.
	Offshore property
	Our subsidiary, GBE, has interests in multiple leases with the State of Texas General Land Office in Galveston Bay. Through GBE, our primary operations are offshore in Galveston Bay. Significant changes to our offshore assets in Galveston Bay during the year ended July 31, 2014 include:
	●	Cost for a recompletion of Fisher Reef 2-3A#1;
	●	Cost for plugging/abandonment of two onshore wells;
	●	Costs for workover of Point Barrow salt water disposal well #1;
	●	Infrastructure enhancements; and
	●	Increase in asset retirement obligations primarily due to changes in timing and in estimated costs for the gathering systems located in Galveston Bay.
	Sales of properties
	In September 2012, we sold our 6.25% overriding royalty interests in properties located in Franklin and Richard parishes in Louisiana, the “Holt” and “Strahan” properties, to the operator of the properties and released the operator from any further liability from the note receivable in exchange for $50,000 cash.  We allocated the cash proceeds between an outstanding, and fully reserved, note receivable we held on the property and the overriding royalty interests based on the relative fair value of the balance on the note and the projected present value of the income streams from the royalty interests.  The portion attributable to the overriding royalty interest, $32,146, was treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
	In December 2012, we sold our 3% working interest in the producing Janssen lease located in Karnes County, Texas. We received $2,500 as cash proceeds in conjunction with the sale. The buyer assumed the asset retirement obligation for the well, which was $438. In accordance with full cost rules, we recognized no gain or loss on the sale.
	Effective September 1, 2013, we conveyed our full interest in the Illinois, Palacios, Curlee, Dix, and Melody properties to Carter E&P in conjunction with our termination of Steven Carter as Vice President of Operations for $0 cash proceeds and the assumption of the abandonment liabilities.
	Effective March 25, 2014, we conveyed our interest in the Barge Canal Welder properties to Winright Oil Company, LLC.  We received net proceeds of $625,000 for this conveyance.  In accordance with full cost rules, we recognized no gain or loss on the sale.

Impairment

Impairment	12 Months Ended
	Jul. 31, 2014
Impairment [Abstract]
Impairment	Note 6 - Impairment
	We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center.
	We evaluated our capitalized costs using the full cost ceiling test as prescribed by the Securities and Exchange Commission at the end of each reporting period. As of July 31, 2014 and July 31, 2013, the net book value of oil and gas properties did not exceed the ceiling amount and thus, no impairment of the properties was required.  Changes in production rates, levels of reserves, future development costs, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Jul. 31, 2014
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	Note 7 – Asset Retirement Obligation
	The following is a reconciliation of our asset retirement obligation liability as of July 31, 2014 and 2013, respectively.
		2014			2013
	czReconciliation of asset retirement obligation balance
	Liability for asset retirement obligation, beginning of period	$	10,933,398		$	9,382,933
	Asset retirement obligations sold		(33,195	)		(438	)
	Asset retirement obligations incurred on properties drilled		-			26,500
	Accretion		1,043,928			1,056,508
	Revisions in estimated cash flows		(104,237	)		786,120
	Costs incurred		(123,664	)		(318,225	)
	Liability for asset retirement obligation, end of period	$	11,716,230		$	10,933,398
	Current portion of asset retirement obligation	$	1,133,690		$	724,374
	Noncurrent portion of asset retirement obligation		10,582,540			10,209,024
	Total liability for asset retirement obligation	$	11,716,230		$	10,933,398
	Estimated Timing of asset retirement obligation payments:
	Fiscal Year	Pipelines			Easements			Wellbores		Facilities		Total
	2015	$	126,290		$	-		$	997,400	$	10,000	$	1,133,690
	2016	$	60,000		$	27,516		$	639,725	$	-	$	727,241
	2017	$	99,938		$	66,006		$	191,476	$	837,436	$	1,194,856
	2018	$	55,040		$	14,475		$	548,700	$	-	$	618,215
	2019	$	52,621		$	10,429		$	572,337	$	221,757	$	857,144
	2020 to 2024	$	980,713		$	193,283		$	2,269,781	$	848,211	$	4,291,988
	2025 to 2029	$	236,898		$	67,089		$	1,356,391	$		$	1,660,378
	2030 to 2034	$	44,439		$	145,197		$	143,578	$	899,504	$	1,232,718
	Thereafter	$	-		$	-		$	-	$	-	$	-
	Total	$	1,655,939		$	523,995.06		$	6,719,388	$	2,816,908	$	11,716,230
	The above dismantlement, restoration or abandonment obligations relate to the Company's following properties: (1) a combined total of 45 pipelines located in Chambers County, Texas and Galveston County, Texas (2) a combined total of 135 surface or right of way easements located in Chambers County. Texas and Galveston County, Texas (3) a combined total of 143 wellbores located in Chambers County, Texas and Galveston County, Texas and (4) a combined total of 8 facilities located in Chambers County, Texas and Galveston County, Texas.
	The Company's ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
	As of July 31, 2014, the Company does not have any active dismantlement, restoration or abandonment activities in progress or underway. During the year ended July 31, 2014, the Company plugged 3 wells reducing its wellbore retirement obligations from those previously reported for the year ended July 31, 2013. The Company historically conducts all such remediation activities during the winter or spring periods, which have yet to be determined as of the date of this filing. "

Notes_Payable

Notes Payable	12 Months Ended
	Jul. 31, 2014
Notes Payable [Abstract]
Notes Payable	Note 8 – Notes Payable
	Line of Credit
	On March 17, 2011, GBE secured a one year revolving line of credit of up to $5 million with a commercial bank. The note specified interest at a rate of prime + 1% with a minimum interest rate of 5% per annum. The initial interest rate was 6%, and interest is payable monthly. Proceeds from the line of credit were used solely to enhance our Galveston Bay properties.  The note was collateralized by our Galveston Bay properties and substantially all of GBE’s assets. HEC also executed a parental guarantee of payment. The note was extended several times during fiscal 2013 and finally replaced by a term loan note in June 2013.  We held no balance outstanding on our line of credit for the years ended July 31, 2014 and July 31, 2013, respectively.  During the year ended July 31, 2014, we closed our LOC with the commercial bank and replaced it with an installment note payable.  See below for further details.
	HCN Note Payable
	During September 2012, in conjunction with the acquisition of NEI, HEC entered into a Consulting Services Agreement with HCN (the "Consulting Agreement”) which obligated HEC to pay a consulting fee (the "Fee") to HCN of $2,400,000 as follows:
	(a) $800,000 on September 6, 2012, which was 15 days from the date that the Minister of Mines and Energy consented to the assignment of a 39% working interest in the Namibian concession to HEC, and
	(b) $1,600,000 note payable, with principal payments of $800,000 each due on August 7, 2013 and August 7, 2014.
	Interest accrued on the principal amount at the rate of 5% per annum, calculated semi-annually and payable in arrears. At HEC’s sole discretion, it could pay the first tranche of the Fee and principal associated with the note payable using HEC common stock. HEC was required to pay a late fee of 10% per quarter for any outstanding balance of the Fee under the Consulting Agreement which  commenced 30 calendar days from the date that the Fee or portion of the Fee is due, which by the terms of the Consulting Agreement may only be paid in cash.  The Consulting Agreement is more fully described in our audited financial statements for the year ended July 31, 2013, contained in our Annual Report filed with the SEC on Form 10-K.
	In October 2013, prior to our acquisition of HCN, HEC settled the then-outstanding $2,400,000 Fee and $553,630 of interest and late fees associated with the Fee by issuance of HEC common stock (See Note 7 - Capital Stock). Further, $25,000 of the related interest and fees was settled in cash.  As the acquisition of HCN is accounted for as an acquisition of an entity under common control and prior reporting periods in these financial statements have been appropriately adjusted as if the acquisition had occurred at the beginning of the comparative periods, this note and related amounts have been removed from these financial statements.
	Installment Notes Payable
	In May 2012, we entered into a note payable of $18,375 to purchase a vehicle. The note carries an interest rate of 6.93% and is payable beginning in June 2012, in 36 installments of $567 per month. The principal balance owed on the note payable was $5,530 and $11,678 as of July 31, 2014 and July 31, 2013, respectively.
	In March 2013, we financed our commercial insurance program using a note payable for $260,905. Under the note, we were obligated to make nine payments of $29,591 per month, which include principal and interest, beginning in March 2013. The principal balance owed on the note payable as of July 31, 2013, was $115,958.  No amounts were owed on the note payable as of July 31, 2014.
	In February 2014, we financed our commercial insurance program using a note payable for $403,104. Under the note, we are obligated to make nine payments of $45,718 per month, which include principal and interest, beginning in March 2014. As of July 31, 2014, the note payable balance was $179,158.
	As noted above, in June 2013, the outstanding balance on our line of credit of $300,000 was replaced by a term loan that matures on June 22, 2015. Under the term loan, we are obligated to make twenty four monthly payments of $12,500 representing principal reduction plus interest per month. The note accrues annual interest at prime + 1%, currently totaling 6%.  As of July 31, 2014 and July 31, 2013, the balance outstanding related to this note was $150,000 and $275,000, respectively.  The July 2014 payment of $12,500 was not made and as a result, the Company incurred $663 in late fees and interest.  In August 2014, the Company paid off the outstanding balance of $150,000 plus accrued interest and fees, in connection with entering into the Credit Agreement with Shadow Tree Capital Management (see Note 15 - Subsequent Events, below).
	Maturities of our long term debt obligation at July 31, 2014 are as follows:
	Year ending July 31,	2015		Thereafter		Total
	Operating and capital leases	$	-	$	-	$	-
	Notes payable		334,688		-		334,688
	Total	$	334,688	$	-	$	334,688

Fair_Value

Fair Value	12 Months Ended
	Jul. 31, 2014
Fair Value [Abstract]
Fair Value	Note 9 – Fair Value
	Fair value is defined as the amount that would be received for selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company categorizes financial assets and liabilities into the three levels of the fair value hierarchy. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value and bases categorization within the hierarchy on the lowest level of input that is available and significant to the fair value measurement.
		●	Level 1 — Quoted prices in active markets for identical assets or liabilities;
		●	Level 2 — Observable inputs other than Level 1, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities; and
		●	Level 3 — Significant unobservable inputs that are supported by little or no market activity or that are based on the reporting entity’s assumptions about the inputs.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	At July 31, 2014 and 2013 we had no financial assets and liabilities requiring measurement at fair value on a recurring basis.  We had no transfers in or out of either Level 1 or Level 2 fair value measurements during the years ended July 31, 2014 and 2013. During the annual 2013 period, we did recognize changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013.  No fair value measurement Level 3 derivative warrant liabilities existed during the year ended July 31, 2014.
	Derivative Warrant Liabilities
	Warrants – Third Party
	During the year ended July 31, 2010 we issued certain warrants which contained a down-ratchet provision on the exercise price of the warrants.  In accordance with accounting guidance we utilize FASB ASC Topic No. 815-40 to determine whether an instrument (or embedded feature) is indexed to an entity’s own stock. This literature specifies when a contract would otherwise meet the definition of a derivative but that both (a) indexed to our stock and (b) classified in stockholders’ equity in our statement of financial position, would not be considered a derivative financial instrument.  The guidance provides a two-step model to be applied in determining whether a financial instrument or embedded feature is indexed to an issuer’s own stock and thus able to qualify for the scope exception.
	Based upon this guidance the warrants issued during the year ended July 31, 2010 were not afforded equity treatment due to the down-ratchet provision on the exercise price.  As a result, the warrants were not considered indexed to our own stock, and as such, the fair value of the embedded derivative liability was reflected on the balance sheet and all future changes in the fair value of these warrants were recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on warrant derivative liability” until such time as the warrants are exercised or the down-ratchet provision expires.
	The warrants were fair valued using a multi-nominal lattice model with the following assumptions:
	●	The stock price on the valuation date would fluctuate with our projected volatility;
	●	Warrant holders would exercise at target price multiples of the market price trigger prices.  The target price multiple reduces as the warrants approach maturity;
	●	Warrant holders would exercise the warrant at maturity if the stock price was above two times the reset exercise price;
	●	An annual reset event would occur at 65% discount to market price; and
	●	The projected volatility was based on historical volatility.  Because we did not have sufficient trading history to determine our own historical volatility, we used the volatility of a group of comparable companies combined with our own historical volatility from May 2009, when we began trading.
	The unrealized gain on changes in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.  The warrant agreement provides that the antidilution provisions expire three years after the grant of the warrants.  Accordingly, the provision for warrants to purchase 206,400 shares of commons stock expired on November 13, 2012 and the warrants were determined to no longer be derivatives.  The outstanding warrant liability, as a result, was reclassified to additional-paid-in-capital and the fair value was determined for a final mark-to-market adjustment.
	The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability as follows:
	As of July 31,		2014		2013
	Beginning of period		$	-	$	1,325,388
	Expiration of derivative warrant feature			-		(269,164	)
	Unrealized gain on changes in fair value of derivative liability			-		(1,056,224	)
	End of period		$	-	$	-
	Warrants – Related Party
	During the year ended July 31, 2011, we entered into a consulting agreement with Geoserve marketing, LLC (“Geoserve”), a company controlled by Michael Watts, who is a related party as described in Note 11 – Related Party Transactions. Under the terms of the agreement, we granted warrants to purchase 400,000 shares of common stock that have a market condition.  If our common stock attains a five day average closing price of $22.50 per share, warrants to purchase 200,000 shares with an exercise price of $7.50 per share and an expiration date of February 15, 2016 shall be exercisable (“Warrant B”). If our common stock attains a five day average closing price of $45.00 per share, warrants to purchase 200,000 shares with an exercise price of $7.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant C”).
	The fair value of warrants that vest upon the attainment of a market condition must be estimated and amortized over the lower of the implicit or derived service period of the warrants. Previously recognized expense is not reversed in the event of a subsequent decline in the fair value of market condition equity based compensation.  The fair value of the warrants and the derived service period were valued using a lattice model that values the liability of the warrants based on a probability weighted discounted cash flow model. This model is based on future projections of the various potential outcomes. Warrant B and Warrant C were amortized over the derived service periods of 2.08 years and 2.49 years, respectively.  As of July 31, 2014, the expense for the warrants was fully amortized.
	In accordance with accounting guidance, the fair value of the warrants that vest upon the attainment of a market condition is expensed and amortized over the lower of the implicit or derived service period of the warrants.  Any previously recognized expense is not reversed in the event of a subsequent decline in the fair value of market condition equity based compensation. During the year ended July 31, 2013, $1,056,224 of unrealized non-cash gains were recognized as fair value adjustments within Level 3 of the fair value measurement hierarchy and were recorded as a reduction of the derivative warrant liability and an unrealized gain on the change in fair value of the liability in our statement of operations. (See Note 10 – Capital Stock, for further details surrounding our warrant liability.

Capital_Stock

Capital Stock	12 Months Ended
	Jul. 31, 2014
Capital Stock [Abstract]
Capital Stock	Note 10 – Capital Stock
	The following reflects the fair value at the end of the derived service period for each of the warrants.
			Warrant B				Warrant C
	Fair Value		$	266,017			$	206,245
	The following table reflects information regarding Warrant B and Warrant C during the year ended July 31, 2014 and 2013.
			31-Jul-14				31-Jul-13
			Warrant B				Warrant C
	Compensation Expense recognized		$	6,754			$	196,384
	Stock Split
	Effective on May 8, 2014, we affected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split.
	Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 166,666,667 shares, par value $0.001 per share to 333,333,334 authorized common shares with a par value of $0.001 per share.
	Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.
	Series A Preferred Stock
	On December 2, 2013, we filed a Certificate of Designation that created a new class of stock: Series A 7% Convertible Voting Preferred Stock (“Series A Preferred”).  Up to 10,000 shares of Series A Preferred are authorized. The stock has a stated value of $400 per share, pays annual dividends at 7%, and is convertible into HEC common stock, at the holder’s option, at a conversion rate of $6.00 per share. The Series A Preferred is neither redeemable nor is it callable. Series A Preferred shareholders may vote their common stock equivalent voting power. We analyzed the Series A Preferred using the guidance contained in ASC 815-40, Derivatives and Hedging, and concluded that the instrument was indexed to our own stock and qualified to be included in stockholders’ equity.
	In connection with the acquisition of HCN on December 9, 2013, HEC issued 8,188 shares of our Series A Preferred Stock to a former Preferred Stock shareholder of HCN, as described in Note 2 – Acquisitions, above.  The value of the preferred stock at issuance was $3,275,200 (8,188 shares at par value of $400).  These shares were recorded in equity at par of $3,275,200.  Because the Series A preferred stock is immediately convertible, the value of a beneficial conversion feature of $949,808 was immediately recognized as a dividend.  During the year ended July 31, 2014, the holder of the Series A Preferred Stock received dividends of $34,254.  As of July 31, 2014, additional dividends have not been accrued as liabilities since they were not declared by the Company.
	Common Stock Issuances
	During September 2012, we issued 2,830,000 shares of common stock to the owners of Namibia Exploration, Inc. (“NEI”) for the acquisition of NEI.  The shares were valued at $3,784,800, based on the quoted market price of our stock on the date of the acquisition. Additionally, $31,612,000 was recognized in conjunction with our commitment to issue additional stock if certain market conditions are achieved. (See Note 2 – Acquisitions – Namibia Exploration, Inc.)
	On October 31, 2013, we issued 619,960 shares of common stock to HCN to settle the $2,400,000 Fee as described in Note 8 – Notes Payable, $553,630 of interest and late fees associated with the Fee, and $635,937 of joint interest billings payable to HCN for its work on the Namibian concession.  The shares were valued and recorded at $3,589,567, based on the value of the obligations settled.
	In connection with the acquisition of HCN on December 9, 2013, we issued 8,396,667 shares of our common stock, as described in Note 2 – Acquisitions, above.  These common stock shares were recorded in equity at par of $8,397 partially offset by additional paid-in capital of $1,837, as described above in Note 2 – Acquisitions.
	In conjunction with the HCN acquisition, we issued 7,470,000 shares of our common stock to the former owners of NEI.  These shares were contingently-issuable consideration for the acquisition of NEI and we valued them at $31,612,000 and recorded it as Acquisition-related costs - related party expense in September 2012.
	During the year ended July 31, 2014, we issued 167,904 shares of common stock, to employees and directors for services performed.  In conjunction with the issuance of these shares we recognized $813,827 in compensation expense.
	HCN Series A Preferred Stock
	On December 3, 2013, before the HEC acquisition of HCN, HCN issued 3,963 shares of its Series A Preferred Stock to Kent Watts, HCN CEO, in order to cancel amounts owed to him for advances he made to the Company in the amount of $1,379,891 plus accrued interest and dividends owed to him of $205,309, totaling $1,585,200.  The HCN Series A Preferred Stock provided for cash dividends of 7% per year, payable in either cash or shares of stock, at the Company’s option.  During the year ended July 31, 2014, the HCN preferred stock accrued dividends of $39,230, which was satisfied through the issuance of the HCN preferred stock on December 3, 2013.  These 3,963 shares of preferred stock plus the previously outstanding 4,225 shares were exchanged for 8,188 shares HEC Series A Preferred Stock, as described above in the acquisition of HCN.
	Receivables for Common Stock
	On September 6, 2013, HCN sold 191,667 shares of HEC common stock to an employee of HCN in exchange for a note receivable in the amount of $1,000,000. This HCN employee is the nephew of our current CEO. HEC acquired this receivable upon its acquisition of HCN.  The note is non-interest bearing and is payable only upon the sale of the common stock to a third party or HEC stock being listed on either the NASDAQ market or NYSE stock exchange. We will receive 95% of the proceeds up to $1,000,000 if the underlying stock is sold to a third party. Within 90 days of HEC stock being listed on a major market or stock exchange, we will receive up to $1,000,000, or the note can be paid earlier at the discretion of the other party. We collected $675,000 in cash on this note receivable through July 31, 2014.  At July 31, 2013, these shares were classified as treasury stock within equity at the cost HCN obtained them from outside entities for services performed following the consolidation of comparative periods for acquired entities under common control (See Note 2 –Acquisitions).  These shares of common stock are held in the name of the investors and are beneficially owned by the investors and the shares are not retrievable by the Company.
	On December 4, 2013 HCN sold 619,960 shares of unregistered and restricted HEC common stock in return for a $1,859,879 non-interest bearing note receivable from an unrelated entity in which Michael Watts has a minority interest.  HEC acquired this receivable upon its acquisition of HCN.  The 619,960 HEC common stock shares were previously issued by HEC to HCN to settle liabilities due by HEC related to the consulting services agreement described below in Note 6 – Notes Payable.  The receivable from the individual is due to HEC upon the following conditions: 1) 100% of the proceeds payable from the sale of all or part of the shares by the owner of the shares to a third party; 2) within sixty days of the six month anniversary of the December 4, 2013 stock sale    or within sixty days from the date that the shares become unrestricted (whichever is first); or 3) 100% of any remaining balance due within 90 days of HEC being listed on a major stock exchange and whereby the share price is above $6.00 per share.  As with the above receivable for common stock, this receivable for the sale of HEC common stock is classified as a receivable for common stock within equity.  These shares of common stock are held in the name of the investors and are beneficially owned by the investors and the shares are not retrievable by the Company.
	This note receivable was extended on August 4, 2014, for an extension fee of $50,000, payable in the future, with $750,000 due to be repaid by December 31, 2014, with the remaining balance to be repaid by March 31, 2015.  These repayment terms may be changed if the Company is successful in being up-listed to either the NYSE or NASDAQ.  If this occurs, the entire balance is due within 60 days after an up-listing occurs.
	Stock Compensation Plans
	As of July 31, 2014, HEC could grant up to 570,136 shares of common stock under the 2013 Stock Incentive Plan (“2013 Plan”). The Plan is administered by the Compensation Committee of the Board of Directors, or in the absence of a Compensation Committee, the full Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.
	A new 2013 Stock Incentive Plan (2013 Plan) was approved by the Board during February 2013. The 2013 Plan replaced our prior stock incentive plans. HEC may grant up to 883,333 shares of common stock under the 2013 Plan. The Plan is administered by the Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.
	The fair value of each option is estimated using the Black-Scholes valuation model. Expected volatility is based solely on historical volatility because we do not have traded options. Prior to May 2009, the volatility was determined by referring to the average historical volatility of a peer group of public companies because we did not have sufficient trading history to determine our own historical volatility.  Beginning with computations after May 2009, when there was an active trading market for our stock, we have included our own historical volatility in determining the volatility used.  As of October 2013, we determined that 4.5 years of trading history was sufficient to determine historical volatility; accordingly valuations from October 2013 onwards will be performed without using a peer group.
	The expected term calculation for stock options is based on the simplified method as described in the Securities and Exchange Commission Staff Accounting Bulletin number 107. We use this method because we do not have sufficient historical information on exercise patterns to develop a model for expected term. The risk-free interest rate is based on the U. S. Treasury yield in effect at the time of grant for an instrument with a maturity that is commensurate with the expected term of the stock options. The dividend yield rate of zero is based on the fact that we have never paid cash dividends on our common stock and we do not intend to pay cash dividends on our common stock.
	Options granted to non-employees
	We account for options granted to non-employees under the provisions of ASC 505-50 and record the associated expense at fair value on the final measurement date.  Because there is no disincentive for nonperformance for these awards, the final measurement date occurs when the services are complete, which is the vesting date. For the options granted to non-employees on a graded vesting schedule, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date.  When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the vesting date, which is presumed to be the date the performance is complete.
	In February 2013, options to purchase an aggregate of 200,000 shares of common stock with an exercise price of $6.60 per share and a term of ten years were granted to our three independent directors.  The options vest at the rate of 20% of such options each six months over the first 30 months following the grant date. The fair value of the total option award on the date of grant was $1,196,589. The fair market value of this award was estimated using the Black-Sholes option pricing model.
	In August 2013, 13,333 of the 200,000 options granted to our independent directors became vested and the remainder of the previously unamortized fair value of these options, $16,184, was recognized on the vesting date. The fair value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.01%, a dividend yield of 0%, and a volatility factor of 144.01%.
	In October 2013, the board accelerated the vesting of the remaining 53,333 options so that they became fully and immediately vested.  The fair value of the options on the date of vesting of $810,738 was recognized immediately as an expense. The fair value was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 2.09%, a dividend yield of 0%, and a volatility factor of 117.31%.
	In addition, during October 2013, the final tranche of certain options that had originally been granted to non-employees in April 2011 vested, for which we recognized $60,622 in expense.
	The following table provides information about options granted to non-employees under our stock incentive plans during the years ended as follows:
	As of July 31,		2014				2013
	Number of options granted			-				200,000
	Compensation expense recognized		$	887,544			$	679,174
	Weighted average exercise price of options granted			N/A			$	6.6
	The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended as follows:
	As of July 31,						2014										2013
	Risk-free interest rate			N/A				-				N/A				1.11%		-	2.00%
	Dividend yield											0%							0%
	Volatility factor			N/A				-				N/A				140.30%		-	144.00%
	Expected life (in years)											N/A							6.5
	Based on the fair value of the options as of July 31, 2014, there was no unrecognized compensation costs related to non-vested share based compensation arrangements granted to non-employees.
	Options granted to employees
	The following table provides information about options granted to employees under our stock incentive plans.
	For the year end July 31,		2014				2013
	Number of options granted			-				-
	Compensation expense recognized		$	56,028			$	253,952
	Weighted average exercise price of options granted			N/A				N/A
	During the year ended July 31, 2011, options to purchase 86,667 shares of common stock with an exercise price of $7.50 per share and a term of ten years were granted to five employees.  The options vest at the rate of 20% of such option each six months over the first 30 months following the grant date. Because the grantees were employees, the awards are accounted for under the provisions of ASC 718.  Accordingly, they are measured at fair value on the date of grant and the expense associated with the grant will be amortized over the 30 month vesting period on a straight line basis.  As of July 31, 2014, we had no unamortized compensation expense associated with options granted to employees, as shares were either cancelled or accelerated as of July 31, 2014.
	No options were granted to employees during the years ended July 31, 2014 or 2013.
	Summary information regarding stock options issued and outstanding as follows:
			Options				Weighted				Aggregate				Weighted
							average share				intrinsic value				average
							price								remaining
															contractual life
															(in years)
Outstanding at July 31, 2012		$	348,000			$	7.5				-				7.22
Granted			200,000				6.6
Exercised			-				-
Expired or forfeited			(36,000	)			7.5
Outstanding at July 31, 2013			512,000				6.81				-				7.98
Granted			-				-
Exercised			-				-
Expired or forfeited			(246,667	)			7.5
Outstanding at July 31, 2014		$	265,333			$	6.81				-				7.95
Exercisable at July 31, 2014		$	265,333			$	6.81				-				7.95
Options outstanding and exercisable as of July 31, 2014 as follows:
Exercise Price				Outstanding Number of				Remaining Life				Exercisable Number of
				Shares								Shares
$	6.6				200,000				8.54				200,000
$	7.5				53,333				6.73				53,333
$	7.5				4,000				4.81				4,000
$	7.5				8,000				2.93				8,000
					265,333								265,333
Summary information regarding nonvested stock options as of July 31, 2013 is as follows:
Exercise Price				Outstanding Number of				Remaining Life				Exercisable Number of
				Shares								Shares
$	6.6				200,000				9.54				-
$	7.5				265,333				7.73				212,267
$	7.5				20,000				3.93				20,000
$	7.5				8,000				5.81				8,000
$	7.5				18,667			Less than 1 year					18,667
					512,000								258,933
Summary information regarding nonvested stock options as of July 31, 2014 is as follows:
		Number of shares				Weighted average grant
						date fair value
Nonvested at July 31, 2013			253,067			$	7.41
Granted			-			$	-
Vested			(6,400	)		$	7.5
Forfeited			(246,667	)		$	7.5
Nonvested at July 31, 2014			-			$	-
Warrants
Warrants granted to related party
During the year ended July 31, 2011, we entered into a consulting agreement with Geoserve Marketing, LLC (“Geoserve”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a former Director and our former Chief Executive Officer and the brother of our current CEO. Under the terms of the agreement, we granted warrants to purchase 400,000 shares of common stock that have a market condition.  If our common stock attains a five day average closing price of $22.50 per share, warrants to purchase 200,000 shares with an exercise price of $7.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant B”). If our common stock attains a five day average closing price of $45.00 per share, warrants to purchase 200,000 shares with an exercise price of $7.50 and an expiration date of February 15, 2016 shall be exercisable (“Warrant C”). See Note 9 – Fair Value, for details regarding the fair value measurement and fair value methodology related to these warrants.
Summary information regarding common stock warrants issued and outstanding as of July 31, 2014, is as follows:
		Warrants				Weighted Average				Aggregate intrinsic				Weighted average
						Share Price				value				remaining
														contractual life (in
														years)
Outstanding at year ended July 31, 2012			1,252,152			$	7.74			$	-				2.83
Granted			-				-				-				-
Exercised			-				-				-				-
Expired			(15,193	)			28.02				-				-
Outstanding at year ended July 31, 2013			1,236,959			$	7.5			$	-				1.87
Granted			-				-				-				-
Exercised			-				-				-				-
Expired			(152,375	)			7.5				-				-
Outstanding at year ended July 31, 2014			1,084,584			$	7.5			$	-				1.04
Warrants outstanding and exercisable as of July 31, 2014:
Exercise Price				Outstanding Number			Remaining Life		Exercisable Number
				of Shares					of Shares
$	7.5				666,667		2 years or less			666,667
$	7.5				349,117		1 year or less			349,117
$	7.5				68,800		1 year or less			68,800
					1,084,584					1,084,584
Warrants outstanding and exercisable as of July 31, 2013:
Exercise Price				Outstanding Number			Remaining Life		Exercisable Number
				of Shares					of Shares
$	7.5				666,667		3 years or less			266,667
$	7.5				417,919		2 years or less			417,919
$	7.5				152,373		1 year or less			152,373
					1,236,959					836,959

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Jul. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Note 11 – Related Party Transactions
	During the year ended July 31, 2013, a company controlled by one of our former officers, Carter E & P, LLC (“Carter”) operated several properties onshore in South Texas, including our Barge Canal properties. Although he was not a related party after September 2013, we considered the transactions with his company during his tenure as an officer of Hydrocarb as related party transactions because they were not compensation or ordinary course of business, and because he was a related party at the time they occurred.
	Revenues generated, lease operating costs, and contractual overhead charges, which are included in lease operating costs incurred from these properties, were as follows:
	Year Ended July 31,	2013		2014
	Revenue generated from Barge Canal properties	$	643,203	$	39,274
	Lease operating cost incurred from Barge Canal properties	$	224,047	$	23,259
	Overhead costs incurred	$	28,038	$	-
	Outstanding accounts receivable at period end	$	91,967	$	-
	Outstanding accounts payable at year end	$	-	$	-
	During the quarter ended October 2012, we purchased NEI for up to  8,396,667 shares of Duma common stock, as described in Note 2 – Acquisitions – Namibia Exploration, Inc.
	In February 2013, we sold a 2% working interest in a 366.85 acre tract of unevaluated property, the Dix prospect, in San Patricio County, Texas to Carter. Carter paid cash of $1,541, the proportional share of the land acquisition costs.
	In August 2013, we closed our Corpus Christi office and terminated this officer.  In conjunction with the office closure and termination, we assumed operatorship of the Barge Canal properties effective September 1, 2013.  In addition, we conveyed multiple properties located in the South Texas and Illinois area to this officer for $0 cash consideration and assumption of the associated asset retirement obligations. (See Note 5– Oil and Gas Properties)
	The father of the former Chief Financial Officer and a company controlled by the father-in-law of the former Chief Executive Officer and brother to the current CEO, each purchased a 5% working interest in the ST 9-12A #4 well.  As of July 31, 2014 and 2013, the company controlled by the father-in-law of the former Chief Executive Officer owed us $58,014 and  $84,806, respectively. We also had an advance outstanding from the father of the former Chief Financial Officer, which was reflected in the caption “Due to related parties”, of $0 and $15,046 for the year ended July 31, 2014 and 2013, respectively.
	During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our former Chief Executive Officer and a former Director and the brother of our current CEO, as detailed in Note 10 – Capital Stock.  We recognized expense of $196,384 from this contract during the year ended July 31, 2013.  The contract terminated in 2014 but was extended by the board of directors indefinitely with zero additional compensation.  $6,754 was recognized in the year ended July 31, 2014.
	In September 2013, before the HEC acquisition of HCN, HCN sold 191,667 shares of HEC common stock to an HCN employee, our Chairman’s nephew, in exchange for a $1,000,000 note receivable. The company arranged the sales of these shares in anticipation of a possible business combination, in an effort to ensure that the shares would remain as part of public float and therefore continue to be properly included in calculations for exchange-listing criteria and provide a source of funding for company operations. It was anticipated that the purchaser of these shares would, at a subsequent date, sell the referenced shares and attain the ability to pay the receivable. We collected $675,000 on the referenced note receivable through April 30, 2014. Of that amount, $275,000 was derived from the sales of the referenced shares; $400,000 was derived from the proceeds of a loan made to the purchaser of the referenced shares by our Chairman.
	In October 2013, prior to our acquisition of HCN, we settled our obligations to HCN under the HCN Consulting Agreement through the issuance of 619,960 shares of HEC. These obligations consisted of the then-outstanding $2,400,000 Fee and $533,630 of interest and late fees associated with the Fee. (See Note 10 – Capital Stock). Further, $25,000 of the related interest and fees was settled in cash. Prior to HEC’s acquisition of HCN, HCN sold these shares to an unrelated entity, in which Michael Watts has a minority interest, for a note receivable of $1,859,879. The company arranged the sales of these shares in anticipation of a possible business combination, in an effort to ensure that the shares would remain as part of public float and therefore continue to be properly included in calculations for exchange-listing criteria and provide a source of funding for company operations. It is anticipated that these shares will eventually be sold and the proceeds of their sales used to pay the receivable. As HCN is now our wholly-owned subsidiary, this receivable for the sale of HEC common stock is classified as receivable for common stock within equity. See discussion of this receivable in Note 10 – Capital Stock – Receivables for Common Stock. On August 8, 2014 our board of Directors resolved to extend this note receivable with [                ] $750,000 to be paid by December 31, 2014 and the balance by March 31, 2015.
	In November 2013, we issued a promissory note for funds received from Mr. Kent Watts, Our Chairman, of $100,000. Under the terms of the note, principal on the note was due after one year and incurred interest at 5% per annum payable on a monthly basis. In April 2014, the Company entered into a new debt agreement whereby Mr. Watts agreed to loan the Company up to $600,000 at an interest rate of 6.25%. The previous debt of $100,000 was rolled into this new note. Additonally, we borrowed $200,000 from Mr. Watts during April 2014 and $300,000 from Mr. Watts in May 2014. The total balance on the note was $600,000 as of July 31, 2014. Accrued interest is pavable monthly beginning in May 2014, and beginning in August 2014 the principal is due in 36 monthly payments through July 2017. The note is secured by the Company’s assets owned by GBE, subject to any other lien holder's superior rights, if any. As part of the financing agreement with Shadow Tree, this note has been subordinated, and no payments will be made until the Shadow Tree debt has been repaid.

Income_Taxes

Income Taxes	12 Months Ended
	Jul. 31, 2014
Income Taxes [Abstract]
Income Taxes	Note 12- Income Taxes
	Our net loss before income taxes totaled $(7,683,932) and $(37,595,653) for the years ended July 31, 2014 and 2013, respectively. We recognized an income tax benefit during the years ended July 31. 2014 and 2013 because the estimated tax liability for the respective previous years exceeded the actual tax liability.
	The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:
	As of and For the Year ended July 31,	2014			2013
	U.S statutory federal rate		35 00	%		35	%
	State income tax rate		0.58	%		0.58	%
	Equity-based compensation		(5.16	)%		(33.62	)%
	Gain on derivative warrants		-	%		0.93	%
	Gain on sale of securities		-	%		(0.33	)%
	Other		(6.64	)%		(0.50	)%
	Net operating loss		(23.70	)%		(1.75	)%
	Effective statutory rate		0.08	%		0.31	%
	Our deferred income taxes reflect the net tax effects of operating loss, tax credit carry forwards and temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible.
	Components of deferred tax assets as of July 31, 2014 and 2013 are as follows:
	As of and For the Year ended July 31.	2014			2013
	Stock based compensation	$	338,078		$	713,867
	Property. including depreciable property		(3,122,873	)		(2,980,005	)
	Asset retirement obligation		4,168,049			3,942,918
	Net operating loss carry-forward		5,596,732			3,846,783
	Other		20,860			42,368
			7,000,846			5,565,931
	Valuation allowance for deferred tax assets		(7,000,846	)		(5,565.931	)
	Total deferred tax assets	$	-		$	-
	The valuation allowance is evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. At that time, the allowance will either be increased or reduced; reduction could result in the complete elimination of the allowance if positive evidence indicates that the value of the deferred tax assets is no longer impaired and the allowance is no longer required.
	We have no positions for which it is reasonable that the total amounts of unrecognized tax benefits at July 31. 2014 will significantly increase or decrease within 12 months.
	Generally, our income tax years 2010 through 2014 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where we have our principal operations. No material amounts of the unrecognized income tax benefits have been identified to date that would impact our effective income tax rate.
	As of July 31, 2014, we had approximately $15,732,204 of U.S. federal and state net operating loss carry-forward (“NOLs”) available to offset future taxable income, which begins expiring in 2027, if not utilized. Future tax benefits that may arise as a result of these losses have not been recognized in these financial statements.  The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty we will be able to realize the benefit from it.
	In conjunction with the merger with HCN, we believe we incurred an ownership change within the meaning of Section 382 of the Internal Revenue Code. As a result, applicable federal and state tax law places an annual limitation on the amount of NOLs that may be used. As of the filig date of this report, we have not completed our Section 382 analysis in connection with the merger.
	If we were to have taxable income in excess of the 382 Limitation following a Section 382 “ownership change,” we would not be able to offset tax on the excess income with the NOLs. Although any loss carryforwards not used as a result of any Section 382 Limitation would remain available to offset income in future years (again, subject to the Section 382 Limitation) until the NOLs expire, the “ownership change” could significantly defer the utilization of the loss carryforwards, accelerate payment of federal income tax and may cause some of the NOLs to expire unused.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Jul. 31, 2014
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 13 – Commitments and Contingencies
	Contingencies
	Legal
	We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.
	As of July 31, 2014, we were party to the following legal proceedings:
	Cause No. 2011-37552; Strategic American Oil Corporation v. ERG Resources, LLC, et al.; In the 55th District Court, Harris County, Texas. The Company is a plaintiff in this suit. In this case, Company brought claims for injunctive relief, breach of contract and fraudulent inducement against the defendant regarding the purchase of Galveston Bay Energy, LLC from ERG. The Company intends to prosecute its claims and defenses vigorously. As of the date of filing of this report, the Company is no longer seeking injunctive relief. Additionally, the below listed case has been consolidated into this case since the subject matter of the below case is subsumed within the subject matter of this case. From this point forward, there will be only this one piece of litigation. The trial was held in October 2013. The judge ruled in favor of ERG and that Hydrocarb is liable to pay the charges in the below-mentioned case and a portion of ERG’s attorney fees. The Company is in the process of post-trial motions and no judgment has been entered as of this date.  As of July 31, 2013, the Company had accrued $232,974 for this cause.
	Cause No. 2011-54428; ERG Resources, LLC v. Galveston Bay Energy, LLC, in the 125th Judicial District Court, Harris County, Texas. This case deals with the operating agreements for the processing of product by the entities owned by ERG. It is an action seeking payments of charges and expenses by ERG that are refuted by GBE. The Company intends to prosecute its claims and defenses vigorously. As indicated above, this case has been consolidated into the case listed above. As such, the claims in this case will be decided in cause No. 2011-37552, which was tried in October 2013.
	Settlement negotiations on both these matters have been concluded.  Galveston Bay has paid $35,000 in cash and Hydrocarb Energy will issue $65,000 in common stock to settle.  More than this amount has been accrued previously and no further adjustments will be made to our financial statements.
	A state regulator has requested that we renew certain pipeline easements located in Galveston Bay. The easements in question were originally obtained by another company whose successor filed for bankruptcy protection.  Our subsidiary, Galveston Bay Energy, LLC purchased certain assets from the bankruptcy estate; however, based on the bankruptcy court’s order and the purchase and sale agreement, we believe the pipelines and easements in question were not included in assets purchased. The easements in question were scheduled to renew at various dates between 2012 and 2021.  Based on current posted rates, the cost of renewal of all of the easements would be approximately $400,000.  We have engaged legal counsel to dispute the regulator’s claim.  If we are obligated to renew these easements, they would be part of the asset retirement obligation that was acquired with our subsidiary, Galveston Bay Energy, LLC. As such, the potential liability for these easements is factored into the computation of the asset retirement obligation (See Note 7 – Asset Retirement Obligation) that is estimated using the guidance in ASC 410-20, Asset Retirement and Environmental Obligations.  On August 29, 2014, we filed a lawsuit in the state district court in Chambers County, Texas asking the Court to reform an assignment and assumption agreement in the property records of Chambers County.  The General Land Office has asserted claims against us under various miscellaneous easements, claiming we are obligated to either renew the easement or remove any pipeline laid in the easement.  We have disclaimed any obligations under these easements.
	Environmental
	We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.
	There is soil contamination at a tank facility owned by GBE. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $900,000. We cannot determine a most likely scenario, thus we have recognized the lower end of the range. We have submitted a remediation plan to the appropriate authorities and have not yet received a response. For the year ended July 31, 2014 and July 31, 2013, $150,000 has been recognized and is included in the balance sheet caption “Accounts payable and accrued expenses.”
	Commitments
	In March 2011, we executed a lease for office space in Houston, Texas.  The lease term was three years and we had an option to extend the lease for an additional three years.  Our scheduled rent was $6,406 per month plus common area maintenance cost for the first year, $6,673 plus common area maintenance cost for the second year, and $6,940 per month plus common area maintenance cost for the third year.  We did not extend this lease, but entered into a sublease arrangement with Greenshale LLC for office space in the same building.  During September 2013, we terminated our lease for office space in Corpus Christi, Texas.
	In April 2012, we executed a Compression and Handling Agreement (the “PHA”) with another operator. Under the terms of the PHA, oil, natural gas, and salt water from one of our fields would be disposed of through the operator’s facility. Under the agreement, we are responsible for approximately a flat fee of $1,000 per month as a gauging fee, our pro-rata share of repairs at the facility, and compression, salt water disposal, and other charges based on the volumes disposed of through the facility.
	Rent expense during the years ended July 31, 2014 and 2013 was $186,463 and $211,346, respectively. See Note 8 – Notes Payable for details regarding our commitments related to our future obligations.
	Letters of Credit
	Oil and gas operators in the State of Texas are required to obtain a letter of credit in favor of the Railroad Commission of Texas as security that they will meet their obligations to plug and abandon the wells they operate. We have two letters of credit in the amount of $6,610,000 and $120,000 issued by Green Bank. These letters of credit are collateralized by a certificate of deposit held with the bank for the same amount. We pay a 1.5% per annum fee in conjunction with these letters of credit.
	During the year ended July 31, 2014 and 2013 we prepaid the fees associated with the Greenbank letters of credit for the respective year interest upfront and amortized these fees on a straight-line basis over their respective annual periods. The following table reflects the prepaid balances as follows:
	July 31,	2014			2013
	Prepaid letter of credit feees	$	101,251		$	101,850
	Amortization		(8,488	)		(8,488	)
	Net prepaid letter of credit fees	$	92,763		$	93,362

Additional_Financial_Statement

Additional Financial Statement Information	12 Months Ended
	Jul. 31, 2014
Additional Financial Statement Information [Abstract]
Additional Financial Statement Information	Note 14 – Additional Financial Statement Information
	Other receivables
	Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.  We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.
	Other current assets
	Other current assets consisted of the following:
	As of July July 31,		2014				2013
	Prepaid letter of credit fees			92,763				93,362
	Prepaid insurance			287,743				184,138
	Other prepaid expenses			63,143				11,101
	Cash call paid to operator			-				24,225
	Prepaid land use fees			-				28,728
	Accrued interest income			2,671				4,388
	Other current assets			446,320				345,942
	Property and Equipment
	Property and equipment consisted of the following:
	As of July 31,			2014				2013
	Furniture and fixtures	5 years		$	24,085			$	8,814
	Marine vessels	5 years			109,742				17,614
	Vehicles	5 years			40,496				65,807
	Computer equipment and software	2 years			126,143				82,466
	Leasehold improvements	2 years			2,087				-
	Other depreciable property	2 years			-				297
	Total property and equipment				302,553				174,998
	Less accumulated depreciation				(135,590	)			(116,945	)
	Net book value			$	166,963			$	58,053
	Depreciation expense			$	36,894			$	61,215
	Accounts payable and accrued expenses
	Accounts payable and accrued expenses consisted of the following:
	As of July 31,		2014				2013
	Trade payables			2,567,324				2,503,820
	Accrued payroll			43,578				151,577
	Accrued interest and fees			37,853				500
	Revenue payable			5,790				4,717
	Local taxes and royalty payable			111,699				128,470
	Federal and state income taxes payable			29,431				27,000
	Total accounts payable and accrued expenses			2,795,675				2,816,084

Subsequent_Events

Subsequent Events	12 Months Ended
	Jul. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Note 15 – Subsequent Events
	Effective August 15, 2014, we entered into a Credit Agreement (the “Credit Agreement”) as borrower, along with Shadow Tree Capital Management, LLC, as agent (the “Agent”), and certain lender parties thereto (the “Lenders”).  Pursuant to the Credit Agreement, the Lenders loaned us $4 million, which was represented by Term Loan Notes in an aggregate amount of $4,545,454 (the “Notes”), representing an original issue discount of 12%.  We also paid the Lenders a structuring fee of $90,909 equal to 2% of the principal amount of the Notes (the “Structuring Fee”) and agreed to reimburse the Lenders for all reasonable and documented fees, costs and expenses associated with the Credit Agreement, which totaled $172,824 in aggregate.  Finally, we paid ROTH Capital Partners, LLC, a placement fee of 5% of the total value of the Loans ($227,273), as placement agent and Gary W. Vick, a consulting fee of 1% of the face value of the Loans ($45,455) for consulting services rendered.  As a result of the payments above, the net amount of funding received from the Loans was $3,463,539.
	Effective November 6, 2014, settlement negotiations with respect to the ERG Resources lawsuit have been concluded. Galveston Bay Energy has paid $35,000 in cash and Hydrocarb Energy will issue 65,000 shares in restricted common stock to settle. More than this amount has been accrued previously and no further adjustments will be made to our financial statements.
	Pursuant to the Credit Agreement, we have the right, at any time prior to the one year anniversary of the Credit Agreement, to borrow up to an additional $1,000,000 under the Credit Agreement (the “Additional Loan”), subject to certain pre-requisites and requirements as set forth in the Credit Agreement, including, but not limited to us raising $750,000 through the sale of equity subsequent to the closing of the transactions contemplated by the Credit Agreement (which we agreed to obtain within 150 days of the date of the Credit Agreement).  We also agreed to pay a 2% Structuring Fee on the Additional Loan. The proceeds of the Additional Loan may only be used for the Oil and Gas Activities.
	The amount owed pursuant to the Notes (and any amount borrowed pursuant to the Additional Loan) is guaranteed by our wholly-owned subsidiary, Hydrocarb Corporation (“HC”) and its subsidiaries, and our other wholly-owned subsidiaries and is secured by a first priority security interest in substantially all of our assets (including, but not limited to the securities of our subsidiaries and HC and its subsidiaries) evidenced by a Guarantee and Collateral Agreement, various pledge agreements and a deed of trust providing the Agent, as agent for the Lenders, a security interest over our oil and gas assets and rights.
	The Notes do not accrue any interest for the first nine months after their issuance date (August 15, 2014), provided thereafter they accrue interest at the rate of (a) 16% per annum where the average net monthly oil and gas production revenues of Galveston Bay Energy LLC, our wholly-owned subsidiary, for the trailing three month period (the “Trailing Three Month Revenues”) is less than $900,000; or (b) 14% per annum, where the Trailing Three Month Revenues are equal to or greater than $900,000, payable monthly in arrears through the maturity date of such Notes, August 15, 2016.  The Additional Loan, if any, will bear interest at the rate of 14% per annum, payable monthly in arrears, and will have the same maturity date as the Notes.  Upon the occurrence of an event of default, the Notes (and any amount outstanding under the Additional Loan) will bear interest at the rate of 24% per annum until paid in full.
	Pursuant to the Credit Agreement, we agreed to issue the Lenders their pro rata share of (a) 60,000 restricted shares of common stock on the effective date of the Credit Agreement, August 15, 2014 (the “Effective Date”); (b) 32,500 restricted shares in the event any amount of the Loans (or other obligations outstanding under agreements entered into in connection with the Loans, the “Loan Documents”) are outstanding on the 12 month anniversary of the Effective Date; (c) 32,500 restricted shares in the event any amount is outstanding under the Loan Documents on the 18 month anniversary of the Effective Date; and (d) 25,000 restricted shares in the event any amount is outstanding under the Loan Documents on the 21 month anniversary of the Effective Date.  The shares are to be issued pursuant to the terms and conditions of a Stock Grant Agreement, pursuant to which each of the Lenders made certain representations to the Company regarding their financial condition and other items in order for the Company to confirm that an exemption from registration existed and will exist for such issuances.
	The Credit Agreement contains customary representations, warranties, covenants and requirements for the Company to indemnify the Lenders, Agent and their affiliates.  The Credit Agreement also includes various covenants (positive and negative) binding upon the Company (and its subsidiaries), including but not limited to, requiring that the Company comply with certain reporting requirements, and provide notices of material corporate events and forecasts to Agent, and prohibiting us from (i) incurring any additional debt; (ii) creating any liens; (iii) making any investments; (iv) materially changing our business; (v) repaying outstanding debt; (vi) affecting a business combination, sale or transfer; (vii) undertaking transactions with affiliates; (viii) amending our organizational documents; (ix) forming subsidiaries; or (x) taking any action not in the usual course of business, in each case except as set forth in the Credit Agreement.
	The Credit Agreement includes customary events of default for facilities of a similar nature and size as the Credit Agreement, including, but not limited to, if any breach or default occurs under the Loan Documents, the failure of the Company to pay any amount when due under the Loan Documents, if the Company (or its subsidiaries) is subject to any judgment in excess of $250,000 which is not discharged or stayed within 30 days, or if a change in control of the Company, any subsidiary or any guarantor should occur, defined for purposes of the Credit Agreement as any transfer of 25% or more of the voting stock of such entity.
	Subsequent to the issuance of the original Annual Report on Form 10-K, it was determined that our subsidiary, Otaiba Hydrocarb LLC in Abu Dhabi, United Arab Emirates, would be shut down. All expenses of operating have been realized on an ongoing basis, so the accounting effect of this shutdown is immaterial.

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Jul. 31, 2014
Supplemental Oil And Gas Information Unaudited [Abstract]
Supplemental Oil and Gas Information (Unaudited)	Note 16 – Supplemental Oil and Gas Information (Unaudited)
	The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and ASC 932, Extractive Activities —Oil and Gas, (ASC 932).
	Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
	Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. The oil price as of July 31, 2014 and 2014 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) posted price which equates to $100.11 and $92.52 per barrel, respectively. The gas price as of July 31, 2014 and 2013 is based on the 12-month un-weighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) spot price which equates to $4.10 and $3.51 per MMbtu, respectively. The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States; specifically, primarily in on-shore and off-shore Texas.
	The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers. Our proved reserves are located in the United States of America, our home country.
	Proved Reserves
			Oil			Gas			Total
			(Barrels)			(Mcf)			(Mcfe)
	Balance – July 31, 2012			1,388,250			14,737,960			23,067,460
	Revisions of previous estimates			(667,307	)		(1,830,745	)		(5,834,587	)
	Sale of reserves in place			(1	)		(2	)		(8	)
	Production			(61,242	)		(176,823	)		(544,275	)
	Balance – July 31, 2013			659,700			12,730,390			16,688,590
	Revisions of previous estimates			422,261			4,477			2,538,043
	Sale of reserves in place			(17,750	)		(529,937	)		(636,437	)
	Production			(42,436	)		(173,569	)		(428,185	)
	Balance – July 31, 2014			1,021,775			12,031,361			18,162,011
	During the year ended July 31, 2013, the Company decreased estimated reserves reported under the line items “Revisions of previous estimates” due to the decrease of previously estimated reserves related to the wells located in the Fishers Reef field located in Galveston Bay, Texas. As a result, during the year ended July 31, 2013, the Company plugged and abandoned these wells. During the year ended July 31, 2014, the Company increased estimated reserves reported under the line items “Revisions of previous estimates” due to an increase in certain previously estimated reserves in the Galveston Bay, Texas properties. When we acquired Galveston Bay Energy LLC in 2011, the Company had over 100 well-bores that had been shut in and scheduled for potential plugging and abandonment. Since the date of the acquisition, our technical staff undertook a review of the old well logs and other technical data associated with such review to identify additional undeveloped oil reserves in these leases. All increases in proved undeveloped reserves are due to the re-evaluation of previously available technical data associated with such review. We have not obtained new technical data. We believe that the new interpretations and reevaluations better reflect the underlying technical data. For the year ended July 31, 2014, this increase related primarily to revaluations associated with the Trinity Bay Field.
			Oil			Gas			Total
	Proved Reserves as of July 31, 2014		(Barrels)			(Mcf)			(Mcfe)
	Proved developed producing			200,981			969,940			2,175,826
	Proved developed non-producing			212,320			4,813,192			6,087,112
	Proved undeveloped			608,474			6,248,229			9,899,073
	Total proved reserves			1,021,775			12,031,361			18,162,011
			Oil			Gas			Total
	Proved Reserves as of July 31, 2013		(Barrels)			(Mcf)			(Mcfe)
	Proved developed producing			256,290			1,554,420			3,092,160
	Proved developed non-producing			229,290			5,000,960			6,376,700
	Proved undeveloped			174,120			6,175,010			7,219,730
	Total proved reserves			659,700			12,730,390			16,688,590
	Proved developed producing and proved developed non-producing reserves decreased from July 31, 2014 to July 31, 2013 as a result of changes in estimates, based on current information.  The increase in proved undeveloped reserves was a result of an increase in certain previously estimated reserves in the Galveston Bay, Texas property.
	The reserves in the report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.
	Capitalized Costs Related to Oil and Gas Activities
	The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.
	For the year ended July 31,		2014			2013
	Unevaluated properties		$	2,119,769		$	713,655
	Evaluated properties			19,153,124			19,857,842
	Less impairment			(373,335	)		(373,335	)
				20,899,558			20,609,312
	Less depreciation, depletion, and amortization			(3,491,420	)		(2,617,478	)
	Net capitalized cost		$	17,408,139		$	17,580,684
	Costs Incurred in Oil and Gas Activities
	Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2014 were as follows.
			Total			Namibia			USA
	Property acquisition
	Unproved		$	1,232,815		$	1,232,815		$	-
	Proved			13			-			13
	Exploration			238,112			173,299			64,813
	Development			-			-			-
	Cost recovery			(658,195	)		-			(658,195	)
	Total costs incurred		$	812,745		$	1,406,114		$	(593,369	)
	Costs incurred in property acquisition, exploration, and development activities for the year ended July 31, 2013 were all incurred in the USA.  The following table provides information about the costs incurred:
			Total			Namibia			USA
	Property acquisition
	Unproved		$	808,307		$	677,795		$	130,512
	Proved			3,000			-			3,000
	Exploration			404,265			35,860			368,405
	Development			1,732,451			-			1,732,451
	Cost recovery			(196,001	)		-			(196,001	)
	Total costs incurred		$	2,752,022		$	713,655		$	2,038,367
	Costs Excluded
	Our excluded costs as of July 31, 2014 and 2013 relate to costs incurred in the concession acquired in Namibia, Africa. The concession provides for a multi-year exploration program as described in Note 4 – Oil and Gas Properties.  The program provides that an initial well be drilled by September 2017.  Accordingly, we anticipate including the excluded costs in the amortization base within the next four to five years.  All costs that were excluded as of July 31, 2014 and 2013 were as follows, and were incurred during the respective years noted below.
	Costs Excluded by Year Incurred
	As of July 31,		2014			2013
Property acquisition		$	1,232,815		$	677,795
Exploration			173,299			35,860
Total		$	1,406,114		$	713,655
Costs excluded as of July 31, 2013 consisted of acquisition and drilling costs associated with a project onshore in Texas, the Chapman Ranch prospect.  During the year ended July 31, 2013, we incurred additional acquisition and exploration costs for this project as well as other projects onshore in Texas.  All such costs were classified as evaluated as of July 31, 2013 because they were not successful in discovering oil and gas reserves.
Changes in Costs Excluded by Country
		Namibia			USA
Balance at July 31, 2012		$	-		$	265,639
Additional Cost Incurred			713,655			278,090
Cost recovery			-			(132,662	)
Costs Transferred to DD&A Pool			-			(411,067	)
Balance at July 31, 2013			713,655			-
Additional Cost Incurred			1,406,114			-
Balance at July 31, 2014		$	2,119,769.00		$	-
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities —Oil and Gas, (ASC 932) procedures and based on estimated oil and natural gas reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate us or our performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of our current value.
We believe that the following factors should be taken into account when reviewing the following information:
	●	future costs and selling prices will probably differ from those required to be used in these calculations;
	●	due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
	●	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
	●	future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, the future cash inflows were estimated by applying the un-weighted 12-month average of the first day of the month cash price quotes, except for volumes subject to fixed price contracts, to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.  All proved reserves are located in the United States of America.
The Standardized Measure is as follows:
For the year ended July 31,		2014			2013
Future cash inflows		$	159,283,690		$	113,603,450
Future production costs			(54,437,098	)		(55,897,070	)
Future development costs			(43,054,816	)		(41,794,284	)
Future income tax expenses			(21,627,122	)		(5,569,234	)
			40,164,654			10,342,862
10% annual discount for estimated timing of cash flows			(15,807,988	)		(3,990,069	)
Future net cash flows at end of year		$	24,356,666		$	6,352,793
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2014:
		2014			2013
Standardized measure of discounted future net cash flows at beginning of year		$	6,352,793		$	33,663,886
Net changes in prices and production costs			20,980,014			(37,623,010	)
Changes in estimated future development costs			(764,412	)		4,205,045
Sales of oil and gas produced, net of production costs			(151,783	)		(2,510,339	)
Discoveries and extensions			-			-
Purchases of minerals in place			-			-
Sales of minerals in place			(2,228,023	)		(17	)
Revisions of previous quantity estimates			8,885,117			(12,391,911	)
Development costs incurred			-			1,124,107
Change in income taxes			(9,694,393	)		14,705,973
Accretion of discount			977,353			5,179,059
Standardized measure of discounted future net cash flows at year end		$	24,356,666		$	6,352,793
The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.
Results of Operations for Producing Activities
For the year ended July 31,		2014			2013
Net revenues from production		$	5,065,096		$	7,070,540
Expenses
Lease operating expense			4,913,313			4,560,201
Accretion			1,043,928			1,056,508
Operating expenses			5,957,241			5,616,709
Depreciation, depletion and amortization			873,942			1,059,803
Total expenses			6,831,183			6,676,512
Income before income tax			(1,766,087	)		394,028
Income tax expense			-			(137,910	)
Results of operations		$	(1,766,087	)	$	256,118
Depreciation, depletion and amortization rate per net equivalent MCFE		$	2.04		$	1.95

Description_of_Business_and_Su1

Description of Business and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Jul. 31, 2014
Description of Business and Summary of Significant Accounting Policies [Abstract]
Description of business and basis of presentation	Description of business and basis of presentation
	We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States and onshore in Namibia, Africa.  We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.  On April 4, 2012 we completed a one new share for twenty-five old share (1:25) reverse stock split and as a result our authorized capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock.  Also, effective April 4, 2012, we changed our name to “Duma Energy Corp.”  Effective May 16, 2012, we increased our authorized capital from 20,000,000 shares to 500,000,000 shares of common stock.  Effective November 29, 2013, the Company increased the number of its authorized shares of common stock from 500,000,000 to 1,000,000,000 shares of common stock.    Effective February 18, 2014, we changed our name from Duma Energy Corp. to Hydrocarb Energy Corp.  Effective May 8, 2014, we effected a 1:3 reverse split of our authorized common stock and a corresponding 1:3 reverse split of our outstanding common stock.  All share and per share amounts for all periods in this report have been retroactively restated to reflect the reverse split. Our capitalization at July 31, 2014 was 333,333,334 authorized common shares with a par value of $0.001 per share.  Our common stock is quoted under the symbol “HECC” on the OTCBB.
	The acquisition of HCN, an entity under common control, on December 9, 2013 (See Note 2 – HCN Acquisition) has resulted in a change in the reporting entity. The consolidated financial statements presented for the periods subsequent to the acquisition include the accounts of HCN and its subsidiaries. As HEC and HCN are under the common control of same shareholder group, the acquired assets and liabilities were recorded at the historical carrying value and the consolidated financial statements were retroactively restated to reflect the Company as if HCN had been owned since the beginning of the earliest period presented.
	We own 100% of the issued and outstanding share capital of (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas limited liability company, (iii) SPE Navigation I, LLC, a Nevada limited liability company, (iv) Namibia Exploration, Inc., a Nevada corporation, (v) Hydrocarb Corporation, a Nevada corporation, (vi) Hydrocarb Texas Corporation, a Texas corporation, and (vii) Hydrocarb Namibia Energy (Pty) Limited, a company chartered in the Republic of Namibia.  In addition, we own 95% of the issued and outstanding share capital of Otaiba Hydrocarb LLC, a UAE limited liability corporation.
	As of July 31, 2014, we maintain developed and undeveloped acreage offshore in Texas.  As of July 31, 2014, we were producing oil and gas from our working interest in four offshore fields in Galveston Bay, Texas.  During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated working interest in a concession located onshore in Namibia, Africa.  During December 2013, with our acquisition of Hydrocarb Corporation, we acquired 51% working interest in this onshore Namibia, Africa concession and now own 90% working interest (100% cost responsibility) in the Namibia, Africa concession.
Reclassifications	Reclassifications
	Certain prior year amounts have been reclassified to conform with the current presentation.
Principles of consolidation	Principles of consolidation
	The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission (“SEC”).  The accompanying consolidated financial statements include the accounts of Hydrocarb Energy Corp., our wholly owned subsidiaries Penasco Petroleum Corporation (“Penasco”), SPE Navigation I, LLC (“SPE”), Galveston Bay Energy, LLC (“GBE”), Namibia Exploration, Inc. (“NEI”), Hydrocarb Corporation (“HCN”), Hydrocarb Texas Corporation, and Hydrocarb Namibia Energy (Pty) Limited.  In addition, these financials include our 95% ownership interest in Otaiba Hydrocarb LLC.  All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of estimates	Use of estimates
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.
	Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments, estimates of the costs and timing of asset retirement obligations, and oil and natural gas proved reserve quantities.  Oil and natural gas proved reserve quantities form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.
	Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.
Cash and cash equivalents	Cash and cash equivalents
	Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value.
	Our functional currency is the United States dollars.  Transactions denominated in foreign currencies are translated into their United States dollar equivalents using current exchange rates.  Monetary assets and liabilities are translated using exchange rates that prevailed as of the balance sheet date.  Non-monetary assets and liabilities are translated using exchange rates that prevailed as of the transaction date.  Revenue, if applicable and expenses are translated using average exchange rates over the accounting period.  We have had no revenue denominated in foreign currencies. Gains or losses resulting from foreign currency transactions are included in results of operations.
Receivables and allowance for doubtful accounts	Receivables and allowance for doubtful accounts
	Oil and gas revenues receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.
	Accounts receivable – related party includes the oil and gas revenue receivable from our Barge Canal properties, which, up until September 1, 2013, were operated by a company owned by one of our former officers who was also a director, and joint interest billings receivable from two working interest partners who are related to our former Chief Financial Officer, the former Chief Executive Officer and the current Chief Executive Officer. This balance also includes an oil and gas receivable from Lifestream, LLC, a company owned by the brother of our current CEO.
	Other receivables consist of joint interest billings due to us from participants holding a working interest in oil and gas properties that we operate.
	We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.  As of July 31, 2014 and 2013, we have reserved $70,742 and $58,585, respectively, for potentially uncollectable other receivables.
Available for sale securities	Available for sale securities
	We invest in marketable equity securities which are classified as available for sale. The first in first out method is used to determine the cost basis of our equity securities sold. Available-for-sale securities are marked to market based on the fair values of the securities determined in accordance with ASC Section 820 (Fair Value Measurement), with the unrealized gains and losses, net of tax, reported as a component of accumulated other comprehensive income (loss).
Other current assets	Other current assets
	Other current assets consist primarily of prepaid insurance, prepaid interest expense, prepayments made towards properties not operated by us, and accrued interest on our deposits.
Concentrations	Concentrations
	Our operations are concentrated in Texas and the majority of our operations are conducted offshore in Galveston Bay.  We operate in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry as a whole were adversely affected, for example by weather, supply shortages, or other factors, we would also experience adverse effects. Because our properties are offshore, we are also vulnerable to adverse weather.
	For the year ended July 31, 2014, 83% of our revenue was attributable to one purchaser.  At July 31, 2014, this same purchaser accounted for 88% of our accounts receivable. For the year ended July 31, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable.
	We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.
Oil and natural gas properties	Oil and natural gas properties
	We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.
	Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.
	We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.
	Capitalized costs included in the amortization base are depleted using the unit of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
	Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.
Impairment	Impairment
	The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.  During the years ended July 31, 2014 and July 31, 2013, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.
Asset retirement obligation	Asset retirement obligation
	We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will update our assessment accordingly. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gathering systems as these obligations are incurred.
Restricted cash	Restricted cash
	Restricted cash consists of certificates of deposit that have been posted as collateral for letters of credit supporting bonds guaranteeing remediation of our oil and gas properties in Texas and escrow funds deposited directly with regulatory authorities. As of July 31, 2014 and 2013, restricted cash totaled $6,877,944 and $6,920,739, respectively.
Other assets	Other assets
	Other assets at July 31, 2014 and 2013 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases.  These are paid as they come due on an ongoing basis and amortized over the rental period.  In addition, other assets also include a domain name for $30,267, which is an intangible asset with an indefinite life due to the fact that it is renewable annually for nominal cost.  We evaluate intangible assets with an indefinite life for possible impairment at least annually by comparing the fair value of the asset with its carrying value.
Property and equipment, other than oil and gas	Property and equipment, other than oil and gas
	Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.
Impairment of long-lived assets	Impairment of long-lived assets
	We periodically review our long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment on our non-oil and gas long-lived assets during the years ended July 31, 2014 and 2013, respectively.
Advances	Advances
	Advances consist of prepayments received from working interest partners pertaining to their share of the costs of drilling oil and gas wells.  Partners are billed in advance for the estimated cost to drill a well and as the work proceeds, the prepayment is applied against their share of the actual drilling cost.  As of July 31, 2014 and 2013, advances totaled $195,904 and $180,804, respectively.
Revenue recognition	Revenue recognition
	We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned.  Severance and ad valorem taxes are reflected as a component of lease operating expense.
Income taxes	Income taxes
	We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Fair value	Fair value
	Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.
	Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.
	The three-level hierarchy is as follows:
	●	Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.
	●	Level 2 inputs consist of quoted prices for similar instruments.
	●	Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.
	Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  We have determined that certain warrants outstanding during the period covered by these financial statements qualify as derivative financial instruments under the provisions of FASB ASC Topic No. 815-40, “Derivatives and Hedging – Contracts in an Entity’s Own Stock.” (See Note 8 – Fair Value).
	The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain on derivative warrant liability.”
	Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.
	We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2014 or July 31, 2013. The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable – related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.
Stock-based compensation	Stock-based compensation
	ASC 718, “Compensation-Stock Compensation” requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.
	We account for non-employee share-based awards based upon ASC 505-50, “Equity-Based Payments to Non-Employees.”  ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete.  Generally, our awards do not entail performance commitments.  When an award vests over time such that performance occurs over multiple reporting periods, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date.  When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the vesting date, which is presumed to be the date performance is complete.
	We recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.
Stock Split	Stock Split
	On May 8, 2014, we affected a 1-for-3 reverse stock split.  All share and per share amounts have been retroactively restated to reflect the reverse split. This presentation is consistent with the guidance in ASC 260-10-55-12, Earnings Per Share, which requires retroactive restatement of earnings per share if a capital structure change due to a stock dividend, stock split or reverse split occurs after the date of the latest balance sheet, but before the release of the financial statements or the effective date of the registration statement, whichever is later.
Earnings per share	Earnings per share
	We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2014 and 2013, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.
Contingencies	Contingencies
	Legal
	We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.  See Note 13 - Commitments and Contingencies for more information on legal proceedings.
	Environmental
	We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.
Accumulated Other Comprehensive Income (Loss), net of tax	Accumulated Other Comprehensive Income (Loss), net of tax
	We follow the provisions of ASC 220, "Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net loss, comprehensive loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company.
Recent accounting pronouncements	Recent accounting pronouncements
	In March 2013, the FASB amended ACS 830, Foreign Currency Matters, to clarify the appropriate accounting when a parent ceases to have a controlling interest in a subsidiary or group of assets that is a business within a foreign entity. This clarification provides that the cumulative translation adjustment should only be released into net income if the loss of controlling interest represents complete or substantially complete liquidation of the foreign entity in which the subsidiary or asset group had resided. This amendment is effective for us starting with our first quarter of fiscal year 2015 and adoption would impact our consolidated financial condition and results of operations if we dispose of a foreign entity.
	In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU No. 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance when it becomes effective. This new standard is effective for us starting with our first quarter of fiscal year 2018.  Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.
	Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on our financial position or results from operations.

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Jul. 31, 2014
Acquisitions [Abstract]
Summary of Pro Forma Information	Summary of the accounting entry to record this acquisition in December 2013 is as follows:
	Assets acquired	$	1,529,246
	Liabilities assumed		(161,599	)
	Noncontrolling interest in 95% owned HCN subsidiary		30,480
		$	1,398,127
	Series A 7% Preferred Stock, par $400	$	3,275,200
	Common stock, at par		8,397
	Receivable for common stock		(2,484,879	)
	Additional paid-in capital		599,409
		$	1,398,127

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Jul. 31, 2014
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	As of and For the year ended July 31,	2014			2013
	SUPPLEMENTAL CASH FLOW INFORMATION
	Cash paid during the period for:
	Income taxes	$	10,000		$	42,483
	Interest	$	21,497		$	207,269
	NONCASH INVESTING AND FINANCING ACTIVITIES
	Issuance of HEC common stock to setle notes payable	$	3,589,567			-
	Preferred stock exchanged for HCN preferred stock for acquisition of HCN	$	3,275,200		$	-
	Receivable for common stock	$	1,859,879		$	-
	Settlement of HCN debt with HCN preferred stock	$	1,585,200		$	1,690,000
	Receivable for common stock - related party	$	1,000,000		$	-
	Note payable for prepaid insurance	$	403,104		$	260,905
	Asset retirement obligation sold	$	33,195		$	438
	Common stock exchanged for HCN common stock for acquisition of HCN	$	8,397		$	-
	Common stock issued to satisfy contingently issuable shares from 2012 acquisition of Namibia Exploration , Inc.	$	7,470		$	-
	Asset retirement obligations - change in estimate	$	(104,237	)	$	786,120
	Treasury stock acquired via note receivable	$	-		$	822,250
	Acquisition of Namibia Exploration, Inc.	$	-		$	562,048
	Expiration of derivative warrant liability	$	-		$	269,164
	Accounts payable for oil and gas properties	$	-		$	188,607
	Asset retirement obligations incurred	$	-		$	26,500

Oil_and_Gas_Properties_Tables

Oil and Gas Properties (Tables)	12 Months Ended
	Jul. 31, 2014
Oil and Gas Properties [Abstract]
Schedule of Oil and Natural Gas Properties	Oil and natural gas properties consisted of the following:
	For the year ended July 31,	2014			2013
	Evaluated Properties
	Costs subject to depletion	$	19,153,125		$	19,857,842
	Accumulated impairment		(373,335	)		(373,335	)
	Accumulated depletion		(3,491,420	)		(2,617,478	)
	Total evaluated properties		15,288,370			16,867,029
	Unevaluated properties		2,119,769			1,124,805
	Net oil and gas properties	$	17,408,139		$	17,991,834

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Jul. 31, 2014
Asset Retirement Obligation [Abstract]
Reconciliation of Asset Retirement Obligation	The following is a reconciliation of our asset retirement obligation liability as of July 31, 2014 and 2013, respectively.
		2014			2013
	czReconciliation of asset retirement obligation balance
	Liability for asset retirement obligation, beginning of period	$	10,933,398		$	9,382,933
	Asset retirement obligations sold		(33,195	)		(438	)
	Asset retirement obligations incurred on properties drilled		-			26,500
	Accretion		1,043,928			1,056,508
	Revisions in estimated cash flows		(104,237	)		786,120
	Costs incurred		(123,664	)		(318,225	)
	Liability for asset retirement obligation, end of period	$	11,716,230		$	10,933,398
	Current portion of asset retirement obligation	$	1,133,690		$	724,374
	Noncurrent portion of asset retirement obligation		10,582,540			10,209,024
	Total liability for asset retirement obligation	$	11,716,230		$	10,933,398
Estimated Timing of asset retirement obligation payments	Estimated Timing of asset retirement obligation payments:
	Fiscal Year	Pipelines			Easements			Wellbores		Facilities		Total
	2015	$	126,290		$	-		$	997,400	$	10,000	$	1,133,690
	2016	$	60,000		$	27,516		$	639,725	$	-	$	727,241
	2017	$	99,938		$	66,006		$	191,476	$	837,436	$	1,194,856
	2018	$	55,040		$	14,475		$	548,700	$	-	$	618,215
	2019	$	52,621		$	10,429		$	572,337	$	221,757	$	857,144
	2020 to 2024	$	980,713		$	193,283		$	2,269,781	$	848,211	$	4,291,988
	2025 to 2029	$	236,898		$	67,089		$	1,356,391	$		$	1,660,378
	2030 to 2034	$	44,439		$	145,197		$	143,578	$	899,504	$	1,232,718
	Thereafter	$	-		$	-		$	-	$	-	$	-
	Total	$	1,655,939		$	523,995.06		$	6,719,388	$	2,816,908	$	11,716,230

Notes_Payable_Tables

Notes Payable (Tables)	12 Months Ended
	Jul. 31, 2014
Notes Payable [Abstract]
Maturities of long term debt obligation	Maturities of our long term debt obligation at July 31, 2014 are as follows:
	Year ending July 31,	2015		Thereafter		Total
	Operating and capital leases	$	-	$	-	$	-
	Notes payable		334,688		-		334,688
	Total	$	334,688	$	-	$	334,688

Fair_Value_Tables

Fair Value (Tables)	12 Months Ended
	Jul. 31, 2014
Fair Value [Abstract]
Reconciliation of the Changes in Fair Value Measurement of Level 3 Derivative Warrant Liabilities	The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability as follows:
	As of July 31,	2014		2013
	Beginning of period	$	-	$	1,325,388
	Expiration of derivative warrant feature		-		(269,164	)
	Unrealized gain on changes in fair value of derivative liability		-		(1,056,224	)
	End of period	$	-	$	-

Capital_Stock_Tables

Capital Stock (Tables)	12 Months Ended
	Jul. 31, 2014
Capital Stock [Abstract]
Warrants Granted to Related Parties	The following reflects the fair value at the end of the derived service period for each of the warrants.
			Warrant B				Warrant C
	Fair Value		$	266,017			$	206,245
	The following table reflects information regarding Warrant B and Warrant C during the year ended July 31, 2014 and 2013.
			31-Jul-14				31-Jul-13
			Warrant B				Warrant C
	Compensation Expense recognized		$	6,754			$	196,384
Stock Options Granted to Nonemployees Under Stock Incentive Plans	The following table provides information about options granted to non-employees under our stock incentive plans during the years ended as follows:
	As of July 31,		2014				2013
	Number of options granted			-				200,000
	Compensation expense recognized		$	887,544			$	679,174
	Weighted average exercise price of options granted			N/A			$	6.6
Assumptions Used to Estimate Fair Value of Stock Option Awards	The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended as follows:
	As of July 31,						2014										2013
	Risk-free interest rate			N/A				-				N/A				1.11%		-	2.00%
	Dividend yield											0%							0%
	Volatility factor			N/A				-				N/A				140.30%		-	144.00%
	Expected life (in years)											N/A							6.5
Stock Options Granted to Employees Under Stock Incentive Plans	The following table provides information about options granted to employees under our stock incentive plans.
	For the year end July 31,		2014				2013
	Number of options granted			-				-
	Compensation expense recognized		$	56,028			$	253,952
	Weighted average exercise price of options granted			N/A				N/A
Stock Option Activity Under Stock Option and Incentive Plans	Summary information regarding stock options issued and outstanding as follows:
			Options				Weighted				Aggregate				Weighted
							average share				intrinsic value				average
							price								remaining
															contractual life
															(in years)
	Outstanding at July 31, 2012		$	348,000			$	7.5				-				7.22
	Granted			200,000				6.6
	Exercised			-				-
	Expired or forfeited			(36,000	)			7.5
	Outstanding at July 31, 2013			512,000				6.81				-				7.98
	Granted			-				-
	Exercised			-				-
	Expired or forfeited			(246,667	)			7.5
	Outstanding at July 31, 2014		$	265,333			$	6.81				-				7.95
	Exercisable at July 31, 2014		$	265,333			$	6.81				-				7.95
Schedule of Stock Options Outstanding and Exercisable	Options outstanding and exercisable as of July 31, 2014 as follows:
	Exercise Price				Outstanding Number of				Remaining Life				Exercisable Number of
					Shares								Shares
	$	6.6				200,000				8.54				200,000
	$	7.5				53,333				6.73				53,333
	$	7.5				4,000				4.81				4,000
	$	7.5				8,000				2.93				8,000
						265,333								265,333
	Summary information regarding nonvested stock options as of July 31, 2013 is as follows:
	Exercise Price				Outstanding Number of				Remaining Life				Exercisable Number of
					Shares								Shares
	$	6.6				200,000				9.54				-
	$	7.5				265,333				7.73				212,267
	$	7.5				20,000				3.93				20,000
	$	7.5				8,000				5.81				8,000
	$	7.5				18,667			Less than 1 year					18,667
						512,000								258,933
Schedule of Nonvested Share Activity	Summary information regarding nonvested stock options as of July 31, 2014 is as follows:
			Number of shares				Weighted average grant
							date fair value
	Nonvested at July 31, 2013			253,067			$	7.41
	Granted			-			$	-
	Vested			(6,400	)		$	7.5
	Forfeited			(246,667	)		$	7.5
	Nonvested at July 31, 2014			-			$	-
Warrant Activity	Summary information regarding common stock warrants issued and outstanding as of July 31, 2014, is as follows:
			Warrants				Weighted Average				Aggregate intrinsic				Weighted average
							Share Price				value				remaining
															contractual life (in
															years)
	Outstanding at year ended July 31, 2012			1,252,152			$	7.74			$	-				2.83
	Granted			-				-				-				-
	Exercised			-				-				-				-
	Expired			(15,193	)			28.02				-				-
	Outstanding at year ended July 31, 2013			1,236,959			$	7.5			$	-				1.87
	Granted			-				-				-				-
	Exercised			-				-				-				-
	Expired			(152,375	)			7.5				-				-
	Outstanding at year ended July 31, 2014			1,084,584			$	7.5			$	-				1.04
Schedule of Warrants Outstanding and Exercisable	Warrants outstanding and exercisable as of July 31, 2014:
	Exercise Price				Outstanding Number			Remaining Life		Exercisable Number
					of Shares					of Shares
	$	7.5				666,667		2 years or less			666,667
	$	7.5				349,117		1 year or less			349,117
	$	7.5				68,800		1 year or less			68,800
						1,084,584					1,084,584
	Warrants outstanding and exercisable as of July 31, 2013:
	Exercise Price				Outstanding Number			Remaining Life		Exercisable Number
					of Shares					of Shares
	$	7.5				666,667		3 years or less			266,667
	$	7.5				417,919		2 years or less			417,919
	$	7.5				152,373		1 year or less			152,373
						1,236,959					836,959

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Jul. 31, 2014
Related Party Transactions [Abstract]
Schedule of Revenues and Costs from Facility Controlled by Related Party	Revenues generated, lease operating costs, and contractual overhead charges, which are included in lease operating costs incurred from these properties, were as follows:
	Year Ended July 31,	2013		2014
	Revenue generated from Barge Canal properties	$	643,203	$	39,274
	Lease operating cost incurred from Barge Canal properties	$	224,047	$	23,259
	Overhead costs incurred	$	28,038	$	-
	Outstanding accounts receivable at period end	$	91,967	$	-
	Outstanding accounts payable at year end	$	-	$	-

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Jul. 31, 2014
Income Taxes [Abstract]
Reconciliation of Income Tax Provision at the Statutory Rate	The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:
	As of and For the Year ended July 31,	2014			2013
	U.S statutory federal rate		35 00	%		35	%
	State income tax rate		0.58	%		0.58	%
	Equity-based compensation		(5.16	)%		(33.62	)%
	Gain on derivative warrants		-	%		0.93	%
	Gain on sale of securities		-	%		(0.33	)%
	Other		(6.64	)%		(0.50	)%
	Net operating loss		(23.70	)%		(1.75	)%
	Effective statutory rate		0.08	%		0.31	%
Summary of Deferred Tax Assets	Components of deferred tax assets as of July 31, 2014 and 2013 are as follows:
	As of and For the Year ended July 31.	2014			2013
	Stock based compensation	$	338,078		$	713,867
	Property. including depreciable property		(3,122,873	)		(2,980,005	)
	Asset retirement obligation		4,168,049			3,942,918
	Net operating loss carry-forward		5,596,732			3,846,783
	Other		20,860			42,368
			7,000,846			5,565,931
	Valuation allowance for deferred tax assets		(7,000,846	)		(5,565.931	)
	Total deferred tax assets	$	-		$	-

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Jul. 31, 2014
Commitments and Contingencies [Abstract]
Schedule of Prepaid Balances	During the year ended July 31, 2014 and 2013 we prepaid the fees associated with the Greenbank letters of credit for the respective year interest upfront and amortized these fees on a straight-line basis over their respective annual periods. The following table reflects the prepaid balances as follows:
	July 31,	2014			2013
	Prepaid letter of credit feees	$	101,251		$	101,850
	Amortization		(8,488	)		(8,488	)
	Net prepaid letter of credit fees	$	92,763		$	93,362

Additional_Financial_Statement1

Additional Financial Statement Information (Tables)	12 Months Ended
	Jul. 31, 2014
Additional Financial Statement Information [Abstract]
Schedule of Other Current Assets	Other current assets consisted of the following:
	As of July July 31,		2014				2013
	Prepaid letter of credit fees			92,763				93,362
	Prepaid insurance			287,743				184,138
	Other prepaid expenses			63,143				11,101
	Cash call paid to operator			-				24,225
	Prepaid land use fees			-				28,728
	Accrued interest income			2,671				4,388
	Other current assets			446,320				345,942
Schedule of Property and Equipment	Property and equipment consisted of the following:
	As of July 31,			2014				2013
	Furniture and fixtures	5 years		$	24,085			$	8,814
	Marine vessels	5 years			109,742				17,614
	Vehicles	5 years			40,496				65,807
	Computer equipment and software	2 years			126,143				82,466
	Leasehold improvements	2 years			2,087				-
	Other depreciable property	2 years			-				297
	Total property and equipment				302,553				174,998
	Less accumulated depreciation				(135,590	)			(116,945	)
	Net book value			$	166,963			$	58,053
	Depreciation expense			$	36,894			$	61,215
Schedule of Accounts Payables and Accrued Expenses	Accounts payable and accrued expenses consisted of the following:
	As of July 31,		2014				2013
	Trade payables			2,567,324				2,503,820
	Accrued payroll			43,578				151,577
	Accrued interest and fees			37,853				500
	Revenue payable			5,790				4,717
	Local taxes and royalty payable			111,699				128,470
	Federal and state income taxes payable			29,431				27,000
	Total accounts payable and accrued expenses			2,795,675				2,816,084

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Jul. 31, 2014
Supplemental Oil And Gas Information Unaudited [Abstract]
Schedule of Net Proved Reserves	The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers. Our proved reserves are located in the United States of America, our home country.
	Proved Reserves
		Oil			Gas			Total
		(Barrels)			(Mcf)			(Mcfe)
	Balance – July 31, 2012		1,388,250			14,737,960			23,067,460
	Revisions of previous estimates		(667,307	)		(1,830,745	)		(5,834,587	)
	Sale of reserves in place		(1	)		(2	)		(8	)
	Production		(61,242	)		(176,823	)		(544,275	)
	Balance – July 31, 2013		659,700			12,730,390			16,688,590
	Revisions of previous estimates		422,261			4,477			2,538,043
	Sale of reserves in place		(17,750	)		(529,937	)		(636,437	)
	Production		(42,436	)		(173,569	)		(428,185	)
	Balance – July 31, 2014		1,021,775			12,031,361			18,162,011
	During the year ended July 31, 2013, the Company decreased estimated reserves reported under the line items “Revisions of previous estimates” due to the decrease of previously estimated reserves related to the wells located in the Fishers Reef field located in Galveston Bay, Texas. As a result, during the year ended July 31, 2013, the Company plugged and abandoned these wells. During the year ended July 31, 2014, the Company increased estimated reserves reported under the line items “Revisions of previous estimates” due to an increase in certain previously estimated reserves in the Galveston Bay, Texas properties. When we acquired Galveston Bay Energy LLC in 2011, the Company had over 100 well-bores that had been shut in and scheduled for potential plugging and abandonment. Since the date of the acquisition, our technical staff undertook a review of the old well logs and other technical data associated with such review to identify additional undeveloped oil reserves in these leases. All increases in proved undeveloped reserves are due to the re-evaluation of previously available technical data associated with such review. We have not obtained new technical data. We believe that the new interpretations and reevaluations better reflect the underlying technical data. For the year ended July 31, 2014, this increase related primarily to revaluations associated with the Trinity Bay Field.
		Oil			Gas			Total
	Proved Reserves as of July 31, 2014	(Barrels)			(Mcf)			(Mcfe)
	Proved developed producing		200,981			969,940			2,175,826
	Proved developed non-producing		212,320			4,813,192			6,087,112
	Proved undeveloped		608,474			6,248,229			9,899,073
	Total proved reserves		1,021,775			12,031,361			18,162,011
		Oil			Gas			Total
	Proved Reserves as of July 31, 2013	(Barrels)			(Mcf)			(Mcfe)
	Proved developed producing		256,290			1,554,420			3,092,160
	Proved developed non-producing		229,290			5,000,960			6,376,700
	Proved undeveloped		174,120			6,175,010			7,219,730
	Total proved reserves		659,700			12,730,390			16,688,590
Schedule of Capitalized Costs	The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.
	For the year ended July 31,	2014			2013
	Unevaluated properties	$	2,119,769		$	713,655
	Evaluated properties		19,153,124			19,857,842
	Less impairment		(373,335	)		(373,335	)
			20,899,558			20,609,312
	Less depreciation, depletion, and amortization		(3,491,420	)		(2,617,478	)
	Net capitalized cost	$	17,408,139		$	17,580,684
Schedule of Costs Incurred	Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2014 were as follows.
		Total			Namibia			USA
	Property acquisition
	Unproved	$	1,232,815		$	1,232,815		$	-
	Proved		13			-			13
	Exploration		238,112			173,299			64,813
	Development		-			-			-
	Cost recovery		(658,195	)		-			(658,195	)
	Total costs incurred	$	812,745		$	1,406,114		$	(593,369	)
	Costs incurred in property acquisition, exploration, and development activities for the year ended July 31, 2013 were all incurred in the USA.  The following table provides information about the costs incurred:
		Total			Namibia			USA
	Property acquisition
	Unproved	$	808,307		$	677,795		$	130,512
	Proved		3,000			-			3,000
	Exploration		404,265			35,860			368,405
	Development		1,732,451			-			1,732,451
	Cost recovery		(196,001	)		-			(196,001	)
	Total costs incurred	$	2,752,022		$	713,655		$	2,038,367
Schedule of Costs Excluded by Year	Costs Excluded by Year Incurred
	As of July 31,	2014			2013
	Property acquisition	$	1,232,815		$	677,795
	Exploration		173,299			35,860
	Total	$	1,406,114		$	713,655
Schedule of Costs Excluded by Country	Changes in Costs Excluded by Country
		Namibia			USA
	Balance at July 31, 2012	$	-		$	265,639
	Additional Cost Incurred		713,655			278,090
	Cost recovery		-			(132,662	)
	Costs Transferred to DD&A Pool		-			(411,067	)
	Balance at July 31, 2013		713,655			-
	Additional Cost Incurred		1,406,114			-
	Balance at July 31, 2014	$	2,119,769.00		$	-
Schedule of Standardized Measure	The Standardized Measure is as follows:
	For the year ended July 31,	2014			2013
	Future cash inflows	$	159,283,690		$	113,603,450
	Future production costs		(54,437,098	)		(55,897,070	)
	Future development costs		(43,054,816	)		(41,794,284	)
	Future income tax expenses		(21,627,122	)		(5,569,234	)
			40,164,654			10,342,862
	10% annual discount for estimated timing of cash flows		(15,807,988	)		(3,990,069	)
	Future net cash flows at end of year	$	24,356,666		$	6,352,793
Schedule of Changes in Standardized Measure	The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2014:
		2014			2013
	Standardized measure of discounted future net cash flows at beginning of year	$	6,352,793		$	33,663,886
	Net changes in prices and production costs		20,980,014			(37,623,010	)
	Changes in estimated future development costs		(764,412	)		4,205,045
	Sales of oil and gas produced, net of production costs		(151,783	)		(2,510,339	)
	Discoveries and extensions		-			-
	Purchases of minerals in place		-			-
	Sales of minerals in place		(2,228,023	)		(17	)
	Revisions of previous quantity estimates		8,885,117			(12,391,911	)
	Development costs incurred		-			1,124,107
	Change in income taxes		(9,694,393	)		14,705,973
	Accretion of discount		977,353			5,179,059
	Standardized measure of discounted future net cash flows at year end	$	24,356,666		$	6,352,793
Schedule of Results of Operations for Producing Activities	For the year ended July 31,	2014			2013
	Net revenues from production	$	5,065,096		$	7,070,540
	Expenses
	Lease operating expense		4,913,313			4,560,201
	Accretion		1,043,928			1,056,508
	Operating expenses		5,957,241			5,616,709
	Depreciation, depletion and amortization		873,942			1,059,803
	Total expenses		6,831,183			6,676,512
	Income before income tax		(1,766,087	)		394,028
	Income tax expense		-			(137,910	)
	Results of operations	$	(1,766,087	)	$	256,118
	Depreciation, depletion and amortization rate per net equivalent MCFE	$	2.04		$	1.95

Description_of_Business_and_Su2

Description of Business and Summary of Significant Accounting Policies (Details) (USD $)	0 Months Ended	12 Months Ended		0 Months Ended
	8-May-14	Jul. 31, 2014	Jul. 31, 2013	Apr. 04, 2012	8-May-14	Dec. 09, 2013	Nov. 29, 2013	Jul. 19, 2005	Oct. 18, 2005	16-May-12
		Partner
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)		333,333,333	333,333,333				166,666,667
Common stock par value per share		$0.00	0.001				$0.00
Reverse stock split conversion ratio	3
Working interest rights (in hundredths)		90.00%				39.00%
Cost responsibility rate (in hundredths)		100.00%
Revenue, Major Customer [Line Items]
Number of working interest partners		2
Other receivables, allowance for doubtful accounts		$70,742	58,585
Discount percentage on current prices (in hundredths)		10.00%
Restricted cash		6,877,944	6,920,739
Prepaid land use fees, term		10 years
Purchase of domain name		30,267
Advances		$195,904	180,804
Reverse stock split	1:3 reverse split
Minimum [Member]
Revenue, Major Customer [Line Items]
Approximate Life		3 years
Maximum [Member]
Revenue, Major Customer [Line Items]
Approximate Life		5 years
Purchaser One [Member] | Revenues [Member]
Revenue, Major Customer [Line Items]
Risk percentage (in hundredths)		83.00%	85.00%
Purchaser One [Member] | Accounts receivable [Member]
Revenue, Major Customer [Line Items]
Risk percentage (in hundredths)		88.00%	76.00%
Penasco Petroleum Inc [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Galveston Bay, LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Number of offshore fields having working interest		4
SPE Navigation I, LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Namibia Exploration, Inc [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Cost responsibility rate (in hundredths)		100.00%
Nevada Gold Corp [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)								100,000,000
Gulf States Energy, Inc [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)									500,000,000
Common stock par value per share									$0.00
Duma Energy Corp [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)				20,000,000			1,000,000,000			500,000,000
Reverse stock split conversion ratio				25
Hydrocarb Energy Corp [Member]
Subsidiary or Equity Method Investee [Line Items]
Common stock, shares authorized (in shares)		333,333,333
Common stock par value per share		$0.00
Reverse stock split conversion ratio					3
Hydrocarb Corporation, HCN [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Working interest rights (in hundredths)						51.00%
Hydrocarb Texas Corporation [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Hydrocarb Namibia Energy [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		100.00%
Otaiba Hydrocarb LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Ownership interest (in hundredths)		95.00%

Acquisitions_HCN_Details

Acquisitions, HCN (Details) (USD $)	0 Months Ended
	Dec. 09, 2013	Dec. 02, 2013	Jul. 31, 2014	Jul. 31, 2013	Dec. 31, 2013
	Well
	acre
Summary of the accounting entry to record the acquisition [Abstract]
Common stock, at par			$21,082	$4,427
Receivable for common stock			-2,184,879	0
Additional paid-in capital			78,953,599	75,137,401
Recorded Unconditional Purchase Obligation [Line Items]
Working interest rights (in hundredths)	39.00%		90.00%
Cost responsibility rate (in hundredths)			100.00%
Concession area	5,300,000
Number of wells required to be drilled under the purchase obligation	1
Initial Exploration Period [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Area of seismic data required by purchase obligation	750
Minimum required expenditure	4,505,000
First Renewal Exploration Period [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Duration of commitment period	2 years
Area of seismic data required by purchase obligation	200
Minimum required expenditure	17,350,000
Percentage of exploration license area relinquish requirement (in hundredths)	25.00%
Second Renewal Exploration Period [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Duration of commitment period	25 years
Minimum required expenditure	300,000
Common Stock [Member]
Summary of the accounting entry to record the acquisition [Abstract]
Common stock, at par			168
Series A Preferred Stock [Member]
Summary of the accounting entry to record the acquisition [Abstract]
Series A 7% Preferred Stock, par $400	3,275,200
Dividend rate of preferred stock (in hundredths)	7.00%	7.00%
Preferred stock stated value (in dollars per share)	400	$400
HCN [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Shares reserved for issuance to certain stock holders with certain rights (in shares)	7,470,000
Shares issued and sold to extinguish debt (in shares)	619,960
Value of shares issued to extinguish debt	3,589,567
Summary of the accounting entry to record the acquisition [Abstract]
Assets acquired	1,529,246
Liabilities assumed	-161,599
Noncontrolling interest in 95% owned HCN subsidiary	30,480
Total	1,398,127
Common stock, at par	8,397
Receivable for common stock	-2,484,879
Additional paid-in capital	599,409				1,837
Recorded Unconditional Purchase Obligation [Line Items]
Working interest rights (in hundredths)	51.00%
HCN [Member] | Series A Preferred Stock [Member]
Summary of the accounting entry to record the acquisition [Abstract]
Series A 7% Preferred Stock, par $400	3,275,200
HCN [Member] | Common Stock [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Number of shares exchanged (in shares)	8,396,667
Value of shares issued for acquisition	64,990,200
HCN [Member] | Preferred Stock [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Number of shares exchanged (in shares)	8,188
Value of shares issued for acquisition	3,275,200
Per share value of shares issued for acquisition (in dollars per share)	400
Hydrocarb Namibia Energy (Pty) Limited [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Percentage ownership in subsidiaries (in hundredths)	100.00%
Otaiba Hydrocarb LLC [Member]
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
Percentage ownership in subsidiaries (in hundredths)	95.00%

Acquisitions_Namibia_Explorati

Acquisitions, Namibia Exploration, Inc. (Details) (USD $)	0 Months Ended		12 Months Ended
	Dec. 09, 2013	Sep. 06, 2012	Jul. 31, 2014	Jul. 31, 2013	Sep. 30, 2012	Sep. 06, 2012
Business Acquisition [Line Items]
Acquisition-related costs - related party			$0	$34,834,752
Ownership percentage (in hundredths)	39.00%		90.00%
Stock issued during period for acquisition				35,396,800
Namibia Exploration, Inc. [Member]
Business Acquisition [Line Items]
Stock issued during period for acquisition, shares (in shares)		8,396,667
Acquisition-related costs - related party		34,834,752
Amount of farm-in fee paid by original owners for payment of concession		2,400,000
Farm in fee of concession property payable period		2 years
Cost basis in working interest in oil and gas property		562,048	562,048	562,048
Ownership percentage (in hundredths)		39.00%				39.00%
Cost responsibility percentage (in hundredths)		43.33%			43.33%	43.33%
Contingent shares to be issued upon achievement of milestone one (in shares)		830,000				830,000
Period within which milestones must be reached after the closing of acquisition		10 years
Contingent shares to be issued upon achievement of milestone two (in shares)		2,490,000				2,490,000
Contingent shares to be issued upon achievement of milestone three (in shares)		4,150,000				4,150,000
The minimum ten day volume-weighted average market capitalization to achieve milestone one		82,000,000				82,000,000
Volume-weighted average market capitalization period		10 days
The minimum ten day volume-weighted average market capitalization to achieve milestone two		196,000,000				196,000,000
The minimum ten day volume-weighted average market capitalization to achieve milestone three		434,000,000				434,000,000
Total consulting fee per consulting services agreement		2,400,000				2,400,000
Fair value of contingent equity grant		29,212,000
Liabilities assumed in business acquisition		1,837,952				1,837,952
Stock issued during period for acquisition		$3,784,800
Shares reserved for issuance to certain stock holders with certain rights (in shares)	7,470,000
Namibia Exploration, Inc. [Member] | Hydrocarb Namibia [Member]
Business Acquisition [Line Items]
Ownership percentage (in hundredths)		90.00%				90.00%
Cost responsibility percentage (in hundredths)		100.00%				100.00%
Namibia Exploration, Inc. [Member] | Market Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair value measurement discount rate (in hundredths)		75.00%
Namibia Exploration, Inc. [Member] | Income Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair value measurement discount rate (in hundredths)		25.00%

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Cash paid during the period for [Abstract]
Income taxes	$10,000	$42,483
Interest	21,497	207,269
NONCASH INVESTING AND FINANCING ACTIVITIES
Issuance of HEC common stock to settle notes payable	3,589,567	0
Preferred stock exchanged for HCN preferred stock for acquisition of HCN	3,275,200	0
Receivable for common stock	1,859,879	0
Settlement of HCN debt with HCN preferred stock	1,585,200	1,690,000
Receivable for common stock - related party	1,000,000	0
Note payable for prepaid insurance	403,104	260,905
Asset retirement obligation sold	33,195	438
Common stock exchanged for HCN common stock for acquisition of HCN	8,397	0
Common stock issued to satisfy contingently issuable shares from 2012 acquisition of Namibia Exploration , Inc.	7,470	0
Asset retirement obligations - change in estimate	-104,237	786,120
Treasury stock acquired via note receivable	0	822,250
Acquisition of Namibia Exploration, Inc.	0	562,048
Expiration of derivative warrant liability	0	269,164
Accounts payable for oil and gas properties	0	188,607
Asset retirement obligations incurred	$0	$26,500

Available_for_Sale_Securities_

Available for Sale Securities (Details) (USD $)	1 Months Ended			12 Months Ended
	Dec. 31, 2012	Oct. 31, 2012	Sep. 30, 2012	Jul. 31, 2014	Jul. 31, 2013	Jul. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Proceeds from sale of available for sale securities	$142,637		$145,237	$0	$287,874
Cost basis of available for sale securities sold	198,593	174,000	607,201
Impairment of available for sale securities		275,327		0	275,327
Unrealized loss reclassified from other comprehensive loss into earnings	-743,082					6,383
Market value of available-for-sale securities				0	24,593	702,959
(Gain) loss on sale of available for sale securities	$55,956		$461,964	$0	$517,920

Oil_and_Gas_Properties_Schedul

Oil and Gas Properties (Schedule of Oil and Gas Properties) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Evaluated Properties [Abstract]
Costs subject to depletion	$19,153,125	$19,857,842
Accumulated impairment	-373,335	-373,335
Accumulated Depletion	-3,491,420	-2,617,478
Total evaluated properties	15,288,370	16,867,029
Unevaluated properties	2,119,769	1,124,805
Net capitalized cost	$17,408,139	$17,991,834

Oil_and_Gas_Properties_Details

Oil and Gas Properties (Details) (USD $)	12 Months Ended		1 Months Ended		0 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Sep. 06, 2012	Dec. 31, 2013
Oil And Gas Properties [Line Items]
Geological And Geophysical Costs	$34,029	$157,818
Cash proceeds on termination of employment	0
Assumption of abandonment liabilities	4,381
Recognized gain (loss) on sale	0
Proceeds from sale of oil and gas properties	625,000	195,563
Asset retirement obligation sold	33,195	438
Exploration costs	238,112	404,265
Janssen lease [Member]
Oil And Gas Properties [Line Items]
Proceeds from sale of working interest			2,500
Percentage of working interest sold (in hundredths)			3.00%
Asset retirement obligation sold			438
Welder Lease [Member]
Oil And Gas Properties [Line Items]
Number of productive wells on the property	2
Holt And Strahan Properties [Member]
Oil And Gas Properties [Line Items]
Ownership percentage (in hundredths)				6.25%
Proceeds from sale of working interest				50,000
Portion of overriding royalty interest treated as reduction of capitalized costs				32,146
Namibia Exploration, Inc. [Member]
Oil And Gas Properties [Line Items]
Acquisition related costs, cash paid	1,406,114	713,655
Ownership percentage (in hundredths)				39.00%
Number of acres included in oil and gas property				5,300,000
Cost responsibility percentage (in hundredths)				43.33%	43.33%
Cost basis in working interest in oil and gas property	562,048	562,048			562,048
Minimum cost responsibilities during initial exploration period	4,505,000
Minimum cost responsibilities during the first renewal exploration period	17,350,000
Percentage of relinquish exploration license area during the first renewal exploration period (in hundredths)	25.00%
Minimum cost responsibilities during the second renewal exploration period	300,000
Second renewal exploration period	25 years
The cumulative amount expended toward costs for the initial exploration period	2,100,000	900,000
Exploration costs	800,000
Leasehold costs	$129,000
HCN [Member]
Oil And Gas Properties [Line Items]
Ownership percentage (in hundredths)	90.00%					51.00%
Cost responsibility percentage (in hundredths)	100.00%					56.67%

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
	Well
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, beginning of period	$10,933,398	$9,382,933
Asset retirement obligations sold	-33,195	-438
Asset retirement obligation incurred on properties drilled	0	26,500
Accretion	1,043,928	1,056,508
Revisions in estimated cash flows	-104,237	786,120
Costs incurred	-123,664	-318,225
Liability for asset retirement obligation, end of period	11,716,230	10,933,398
Current portion of asset retirement obligation	1,133,690	724,374
Noncurrent portion of asset retirement obligation	10,582,540	10,209,024
Total liability for asset retirement obligation	11,716,230	10,933,398
Estimated Timing of asset retirement obligation payments [Abstract]
2015	1,133,690
2016	727,241
2017	1,194,856
2018	618,215
2019	857,144
2020 to 2024	4,291,988
2025 to 2029	1,660,378
2030 to 2034	1,232,718
Thereafter	0
Total liability for asset retirement obligation	11,716,230	10,933,398
Number of wells plugged	3
Pipelines [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	1,655,939
Total liability for asset retirement obligation	1,655,939
Estimated Timing of asset retirement obligation payments [Abstract]
2015	126,290
2016	60,000
2017	99,938
2018	55,040
2019	52,621
2020 to 2024	980,713
2025 to 2029	236,898
2030 to 2034	44,439
Thereafter	0
Total liability for asset retirement obligation	1,655,939
Number of dismantlement, restoration or abandonment obligations	45
Easements [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	523,995
Total liability for asset retirement obligation	523,995
Estimated Timing of asset retirement obligation payments [Abstract]
2015	0
2016	27,516
2017	66,006
2018	14,475
2019	10,429
2020 to 2024	193,283
2025 to 2029	67,089
2030 to 2034	145,197
Thereafter	0
Total liability for asset retirement obligation	523,995
Number of dismantlement, restoration or abandonment obligations	135
Wellbores [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	6,719,388
Total liability for asset retirement obligation	6,719,388
Estimated Timing of asset retirement obligation payments [Abstract]
2015	997,400
2016	639,725
2017	191,476
2018	548,700
2019	572,337
2020 to 2024	2,269,781
2025 to 2029	1,356,391
2030 to 2034	143,578
Thereafter	0
Total liability for asset retirement obligation	6,719,388
Number of dismantlement, restoration or abandonment obligations	143
Facilities [Member]
Reconciliation of asset retirement obligation balance [Abstract]
Liability for asset retirement obligation, end of period	2,816,908
Total liability for asset retirement obligation	2,816,908
Estimated Timing of asset retirement obligation payments [Abstract]
2015	10,000
2016	0
2017	837,436
2018	0
2019	221,757
2020 to 2024	848,211
2030 to 2034	899,504
Thereafter	0
Total liability for asset retirement obligation	$2,816,908
Number of dismantlement, restoration or abandonment obligations	8

Notes_Payable_Lines_of_Credit_

Notes Payable, Lines of Credit (Details) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Mar. 17, 2011
Notes Payable [Abstract]
Revolving line of credit period with commercial bank	1 year
Line of credit, interest rate spread over prime rate (in hundredths)	1.00%
Debt instrument, minimum interest rate (in hundredths)	5.00%
Line of credit, interest rate (in hundredths)	6.00%
Line of credit, amount outstanding	$5

Notes_Payable_Details

Notes Payable (Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

Sep. 30, 2012

31-May-12

Mar. 17, 2011

Jul. 31, 2014

Jul. 31, 2013

Jun. 30, 2013

Feb. 28, 2014

Mar. 31, 2013

Oct. 31, 2012

Oct. 31, 2013

Dec. 09, 2013

Sep. 06, 2012

Aug. 31, 2014

Payment

Payment

Debt Instrument [Line Items]

Consulting fee

$2,400,000

Working interest rights (in hundredths)

90.00%

39.00%

Debt instrument, face amount

18,375

Periodic installments amount

567

Debt instrument, interest rate (in hundredths)

6.93%

Variable interest rate (in hundredths)

1.00%

Interest

21,497

207,269

Line of credit facility, amount outstanding

5,000,000

Number of required periodic payments

36

Maturities of long term debt obligation [Abstract]

2015

334,688

Thereafter

0

Total

334,688

Prime Rate [Member]

Debt Instrument [Line Items]

Variable interest rate

prime + 1%

Commercial Insurance Program Renewal [Member]

Debt Instrument [Line Items]

Principal balance

0

Notes Payable For Vehicle Purchase [Member]

Debt Instrument [Line Items]

Principal balance

5,530

11,678

Note Payable For Commercial Insurance Program [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

403,104

260,905

Periodic installments amount

45,718

29,591

Principal balance

179,158

Number of required periodic payments

9

Note Payable - Hydrocarb Corporation [Member]

Debt Instrument [Line Items]

Debt instrument, face amount

1,600,000

Debt instrument, interest rate (in hundredths)

5.00%

Rate of late fee (in hundredths)

10.00%

Period of commencing late fees

30 days

Interest and late fees on notes payable

553,630

Interest

25,000

Note Payable - Hydrocarb Corporation - Payment One [Member]

Debt Instrument [Line Items]

Partial consulting fee payment

800,000

Number of days to the assignment of working interest

15 days

Working interest rights (in hundredths)

39.00%

Periodic installments amount

800,000

Note Payable - Hydrocarb Corporation - Payment Two [Member]

Debt Instrument [Line Items]

Periodic installments amount

800,000

Operating and capital leases [Member]

Maturities of long term debt obligation [Abstract]

2015

0

Thereafter

0

Total

0

Line of Credit [Member]

Debt Instrument [Line Items]

Periodic installments amount

12,500

Debt instrument, interest rate (in hundredths)

6.00%

Variable interest rate (in hundredths)

1.00%

Principal balance

150,000

275,000

Line of credit facility, amount outstanding

300,000

Number of required periodic payments

24

Line of Credit [Member] | Subsequent Event [Member]

Debt Instrument [Line Items]

Principal balance

150,000

Notes Payable [Member]

Maturities of long term debt obligation [Abstract]

2015

334,688

Thereafter

0

Total

334,688

Term Loan [Member]

Debt Instrument [Line Items]

Amount incurred of late fees

$663

Maturity date of term loan

22-Jun-15

Fair_Value_Narrative_Details

Fair Value (Narrative) (Details) (USD $)	1 Months Ended	12 Months Ended
	Oct. 31, 2009	Jul. 31, 2011	Jul. 31, 2014	Jul. 31, 2013	Nov. 13, 2012	Jul. 31, 2012
Fair Value [Abstract]
Discount to market price (in hundredths)	65.00%
Number of warrants expired (in shares)					206,400
Antidilution provisions expire term for the warrant agreement (in years)	3 years
Warrants Granted To Related Party [Line Items]
Exercise price (in dollars per share)			$7.50	$7.50		$7.74
Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$22.50
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$7.50
Expiration date		15-Feb-16
Term of warrants		2 years 0 months 29 days
Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$45
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$7.50
Expiration date		15-Feb-16
Term of warrants		2 years 5 months 26 days
Geoserve Marketing, LLC [Member]
Warrants Granted To Related Party [Line Items]
Total shares of common stock issuable under warrants (in shares)		400,000
Geoserve Marketing, LLC [Member] | Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$22.50
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$7.50
Expiration date		15-Feb-16
Geoserve Marketing, LLC [Member] | Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price		5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)		$45
Number of warrants exercisable upon attaining target average closing price (in shares)		200,000
Exercise price (in dollars per share)		$7.50
Expiration date		15-Feb-16

Fair_Value_Schedule_of_the_Cha

Fair Value (Schedule of the Changes in Fair Value of the Warrant Liability) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Fair Value [Abstract]
Beginning of the period	$0	$1,325,388
Expiration of derivative warrant feature	0	-269,164
Unrealized gain on changes in fair value of derivative liability	0	-1,056,224
End of the period	$0	$0

Capital_Stock_Stock_Split_Pref

Capital Stock, Stock Split, Preferred Stock and Common Stock (Details) (USD $)

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

8-May-14

Dec. 04, 2013

Sep. 06, 2013

Oct. 31, 2013

Aug. 31, 2013

Jul. 31, 2014

Jul. 31, 2013

Aug. 04, 2014

Sep. 06, 2013

Dec. 09, 2013

Dec. 02, 2013

Dec. 03, 2013

Oct. 31, 2014

Nov. 29, 2013

Feb. 28, 2013

Dec. 31, 2013

Sep. 30, 2012

Class of Stock [Line Items]

Reverse stock split

1:3 reverse split

Stock split conversion ratio

3

Common stock, shares authorized (in shares)

333,333,333

333,333,333

166,666,667

Common stock, par value (in dollars per share)

$0.00

$0.00

$0.00

Preferred stock, shares issued (in shares)

4,225

Dividends earned

$150,548

$0

Common stock, shares issued (in shares)

21,081,602

4,427,071

Par value of common stock issued

21,082

4,427

Additional Paid in Capital

78,953,599

75,137,401

Stock issued, business acquisition

35,396,800

Advances from affiliates cancelled

1,379,891

Interest and dividends settled

205,309

Settlement of HCN debt with HCN preferred stock

1,585,200

1,690,000

Maximum percentage of proceeds to be received upon sale of stock to third party (in hundredths)

100.00%

95.00%

95.00%

Maximum proceeds to be received upon sale of stock to third party

1,000,000

1,000,000

Period of stock listing on major stock exchange within which the Company will receive proceeds from sale of stock

90 days

90 days

Period of six month anniversary of stock sale within which the Company will receive proceeds from sale of stock

60 days

Period from date that shares become unrestricted within which the Company will receive proceeds from sale of stock

60 days

Percentage of remaining receivable balance is due within stock listing period (in hundredths)

100.00%

Minimum share price for note receivable to be due to company (in dollars per share)

$6

Expected life

6 years 6 months

6 years 6 months

2013 Stock Incentive Plan [Member]

Class of Stock [Line Items]

Shares authorized for issuance (in share)

570,136

883,333

Expected life

4 years 6 months

Subsequent Event [Member]

Class of Stock [Line Items]

Period of stock listing on major stock exchange within which the Company will receive proceeds from sale of stock

60 days

Note receivable extension fee

50,000

Note payble remaining balance repaid in future

750,000

HCN [Member]

Class of Stock [Line Items]

Interest and late fees

553,630

Par value of common stock issued

8,397

Additional Paid in Capital

599,409

1,837

Number of shares of common stock issued in exchange for note receivable (in shares)

619,960

191,667

Value of common stock issued in exchange for note receivable

1,859,879

1,000,000

Proceeds from collection of note receivable

675,000

NEI [Member]

Class of Stock [Line Items]

Common stock, shares issued (in shares)

2,830,000

Commitment to issue additional stock

31,612,000

Par value of common stock issued

3,784,800

Series A Preferred Stock [Member]

Class of Stock [Line Items]

Dividend rate (in hundredths)

7.00%

7.00%

Preferred stock, shares authorized (in shares)

10,000

Preferred stock stated value (in dollars per share)

$400

$400

Preferred stock, conversion rate (in dollars per share)

$6

Preferred stock, shares issued (in shares)

3,963

8,188

Preferred stock

3,275,200

Preferred Stock, Value, Beneficial Conversion Feature

949,808

Dividends earned

34,254

39,230

Series A Preferred Stock [Member] | HCN [Member]

Class of Stock [Line Items]

Preferred stock

3,275,200

Common Stock [Member]

Class of Stock [Line Items]

Stock issued for notes payable and joint interest billings (in shares)

619,960

Consulting fee payable

2,400,000

Joint interest billings payable

635,937

Stock issued for notes payable and joint interest billings

3,589,567

Par value of common stock issued

168

Shares issued for services rendered (in shares)

167,907

Compensation expense for shares issued for services

813,827

Common Stock [Member] | NEI [Member]

Class of Stock [Line Items]

Stock issued during period for acquisition, shares (in shares)

7,470,000

8,396,667

Stock issued, business acquisition

$31,612,000

Capital_Stock_Options_Granted_

Capital Stock, Options Granted (Details) (USD $)	1 Months Ended		12 Months Ended				1 Months Ended	12 Months Ended
	Oct. 31, 2013	Aug. 31, 2013	Jul. 31, 2014		Jul. 31, 2013		Feb. 28, 2013	Jul. 31, 2011	Jul. 31, 2012
							Person	Person
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options vested (in shares)	53,333
Fair value of options vested	$810,738
Assumptions used in estimating fair value of options [Abstract]
Risk free interest rate (in hundredths)	2.09%	2.01%
Dividend yield (in hundredths)	0.00%	0.00%
Volatility factor (in hundredths)	117.31%	144.01%
Expected life	6 years 6 months	6 years 6 months
Information about options granted to non-employees under stock incentive plans [Abstract]
Compensation expense recognized			1,757,399		933,126
Options [Roll Forward]
Outstanding, beginning balance (in shares)		512,000	512,000
Outstanding, ending balance (in shares)			265,333		512,000
Exercisable, ending balance (in shares)			265,333		258,933
Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate number of options granted (in shares)							200,000
Weighted average exercise price of options granted (in dollars per share)							$6.60
Vesting period							10 years
Options granted to number of directors and employee							3
Vesting percentage of options after each six months (in hundredths)							20.00%
Period in which vesting of options should be complete							30 months
Fair value of options granted							1,196,589
Information about options granted to non-employees under stock incentive plans [Abstract]
Weighted average exercise price of options granted (in dollars per share)							$6.60
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)							$6.60
Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate number of options granted (in shares)								86,667
Weighted average exercise price of options granted (in dollars per share)								$7.50
Vesting period								10 years
Options granted to number of directors and employee								5
Vesting percentage of options after each six months (in hundredths)								20.00%
Period in which vesting of options should be complete								30 months
Unrecognized compensation cost related to stock options								0
Information about options granted to non-employees under stock incentive plans [Abstract]
Weighted average exercise price of options granted (in dollars per share)								$7.50
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)								$7.50
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price of options granted (in dollars per share)			$0		$6.60
Assumptions used in estimating fair value of options [Abstract]
Risk free interest rate, minimum (in hundredths)				[1]	1.11%
Risk free interest rate, maximum (in hundredths)				[1]	2.00%
Dividend yield (in hundredths)			0.00%		0.00%
Volatility factor, minimum (in hundredths)				[1]	140.30%
Volatility factor, maximum (in hundredths)				[1]	144.00%
Expected life			0 years	[1]	6 years 6 months
Information about options granted to non-employees under stock incentive plans [Abstract]
Number of options granted (in shares)			0		200,000
Weighted average exercise price of options granted (in dollars per share)			$0		$6.60
Options [Roll Forward]
Outstanding, beginning balance (in shares)		512,000	512,000		348,000
Granted (in shares)			0		200,000
Exercised (in shares)			0		0
Expired or forfeited (in shares)			-246,667		-36,000
Outstanding, ending balance (in shares)			265,333		512,000				348,000
Exercisable, ending balance (in shares)			265,333
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)		6.81	$6.81		$7.50
Granted (in dollars per share)			$0		$6.60
Exercised (in dollars per share)			$0		$0
Expired or forfeited (in dollars per share)			$7.50		$7.50
Outstanding, ending balance (in dollars per share)			$6.81		$6.81				$7.50
Exercisable, ending balance (in dollars per share)			$6.81
Aggregate intrinsic value, beginning balance		0	0		0
Aggregate intrinsic value, ending balance			0		0				0
Aggregate intrinsic value, Exercisable			0
Weighted average remaining contractual life, beginning balance			7 years 11 months 12 days		7 years 11 months 23 days				7 years 2 months 19 days
Weighted average remaining contractual life, ending balance			7 years 11 months 12 days		7 years 11 months 23 days				7 years 2 months 19 days
Weighted average remaining contractual life, Exercisable			7 years 11 months 12 days
Stock Option [Member] | Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options vested (in shares)		13,333	666,666
Fair value of options vested		16,184
Stock Option [Member] | Non Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price of options granted (in dollars per share)				[1]	$6.60
Unrecognized compensation cost related to stock options			0
Information about options granted to non-employees under stock incentive plans [Abstract]
Number of options granted (in shares)			0		200,000
Compensation expense recognized	60,622		887,544		679,174
Weighted average exercise price of options granted (in dollars per share)				[1]	$6.60
Options [Roll Forward]
Granted (in shares)			0		200,000
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)				[1]	$6.60
Stock Option [Member] | Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price of options granted (in dollars per share)				[1]		[1]
Unrecognized compensation cost related to stock options			0		0
Information about options granted to non-employees under stock incentive plans [Abstract]
Number of options granted (in shares)			0		0
Compensation expense recognized			$56,028		$253,952
Weighted average exercise price of options granted (in dollars per share)				[1]		[1]
Options [Roll Forward]
Granted (in shares)			0		0
Weighted Average Exercise Price [Roll Forward]
Granted (in dollars per share)				[1]		[1]
2013 Stock Incentive Plan [Member]
Assumptions used in estimating fair value of options [Abstract]
Expected life			4 years 6 months
[1]	N/A

Capital_Stock_Options_Outstand

Capital Stock, Options Outstanding and Exercisable (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Options Outstanding and Exercisable [Line Items]
Outstanding Number of Shares (in shares)	265,333	512,000
Exercisable Number of Shares (in shares)	265,333	258,933
Exercise Price 6.60 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$6.60	$6.60
Outstanding Number of Shares (in shares)	200,000	200,000
Remaining Life	8 years 6 months 14 days	9 years 6 months 14 days
Exercisable Number of Shares (in shares)	200,000	0
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50
Outstanding Number of Shares (in shares)	53,333	265,333
Remaining Life	6 years 8 months 23 days	7 years 8 months 23 days
Exercisable Number of Shares (in shares)	53,333	212,267
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50
Outstanding Number of Shares (in shares)	4,000	20,000
Remaining Life	4 years 9 months 22 days	3 years 11 months 5 days
Exercisable Number of Shares (in shares)	4,000	20,000
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50
Outstanding Number of Shares (in shares)	8,000	8,000
Remaining Life	2 years 11 months 5 days	5 years 9 months 22 days
Exercisable Number of Shares (in shares)	8,000	8,000
Exercise Price 7.50 [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price (in dollars per share)		$7.50
Outstanding Number of Shares (in shares)		18,667
Remaining Life		1 year
Exercisable Number of Shares (in shares)		18,667

Capital_Stock_Schedule_of_Nonv

Capital Stock, Schedule of Nonvested Share Activity (Details) (USD $)	12 Months Ended
	Jul. 31, 2014
Number of shares [Abstract]
Nonvested at July 31, 2013 (in shares)	253,067
Granted (in shares)	0
Vested (in shares)	-6,400
Forfeited (in shares)	-246,667
Nonvested at July 31, 2014 (in shares)	0
Weighted average grant date fair value [Abstract]
Nonvested at July 31, 2013 (in dollars per shares)	$7.41
Granted (in dollars per shares)	$0
Vested (in dollars per shares)	$7.50
Forfeited (in dollars per shares)	$7.50
Nonvested at July 31, 2014 (in dollars per shares)	$0

Capital_Stock_Warrants_Granted

Capital Stock, Warrants Granted (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2011
Warrants Granted To Related Party [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50	$7.74
Compensation expense recognized	$1,757,399	$933,126
Warrants [Roll Forward]
Outstanding, beginning balance (in shares)	1,236,959	1,252,152
Granted (in shares)	0	0
Exercised (in shares)	0	0
Expired (in shares)	-152,375	-15,193
Outstanding, beginning balance (in shares)	1,084,584	1,236,959	1,252,152
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)	$7.50	$7.74
Granted (in dollars per share)	$0	$0
Exercised (in dollars per share)	$0	$0
Expired (in dollars per share)	$7.50	$28.02
Outstanding, beginning balance (in dollars per share)	$7.50	$7.50	$7.74
Aggregate intrinsic value	0	0	0
Weighted average remaining contractual life	1 year 0 months 14 days	1 year 10 months 13 days	2 years 9 months 29 days
Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$22.50
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$7.50
Expiration date				15-Feb-16
Fair value	266,017
Compensation expense recognized	6,754
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$7.50
Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$45
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$7.50
Expiration date				15-Feb-16
Fair value	206,245
Compensation expense recognized		$196,384
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$7.50
Geoserve Marketing, LLC [Member]
Warrants Granted To Related Party [Line Items]
Total shares of common stock issuable under warrants (in shares)				400,000
Geoserve Marketing, LLC [Member] | Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$22.50
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$7.50
Expiration date				15-Feb-16
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$7.50
Geoserve Marketing, LLC [Member] | Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Period for calculating average closing price				5 days
Average closing stock price that will trigger issuance of additional warrants (in dollars per share)				$45
Number of warrants exercisable upon attaining target average closing price (in shares)				200,000
Exercise price (in dollars per share)				$7.50
Expiration date				15-Feb-16
Weighted Average Exercise Price [Roll Forward]
Outstanding, beginning balance (in dollars per share)				$7.50

Capital_Stock_Warrants_Outstan

Capital Stock, Warrants Outstanding and Exercisable (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Jul. 31, 2012
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50	$7.74
Outstanding Number of Shares (in shares)	1,084,584	1,236,959	1,252,152
Remaining Life	1 year 0 months 14 days	1 year 10 months 13 days	2 years 9 months 29 days
Exercisable Number of Shares (in shares)	1,084,584	836,959
Exercise Price 7.50 [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50
Outstanding Number of Shares (in shares)	666,667	666,667
Remaining Life	2 years	3 years
Exercisable Number of Shares (in shares)	666,667	266,667
Exercise Price 7.50 [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50
Outstanding Number of Shares (in shares)	349,117	417,919
Remaining Life	1 year	2 years
Exercisable Number of Shares (in shares)	349,117	417,919
Exercise Price 7.50 [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise price (in dollars per share)	$7.50	$7.50
Outstanding Number of Shares (in shares)	68,800	152,373
Remaining Life	1 year	1 year
Exercisable Number of Shares (in shares)	68,800	152,373

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended		0 Months Ended	1 Months Ended				3 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	Sep. 06, 2012	Oct. 31, 2013	Feb. 28, 2013	Oct. 31, 2012	Aug. 31, 2013	Apr. 30, 2014	Oct. 31, 2013	Sep. 30, 2013
					acre
Related Party Transaction [Line Items]
Revenue generated from Barge Canal properties	$39,274	$643,203
Lease operating costs incurred from Barge Canal properties	23,259	224,047
Overhead costs incurred	0	28,038
Outstanding accounts receivable at period end	0	91,967
Outstanding accounts payable at year end	0	0
Due to related parties	165,542	301,378
Namibia Exploration, Inc. [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)			8,396,667
HCN [Member]
Related Party Transaction [Line Items]
Interest and late fees				553,630
Father-In-Law of Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Expense recognized from consulting contract with related party		196,384
Interst expense	0
Carter E&P [Member]
Related Party Transaction [Line Items]
Percentage of working interest sold (in hundredths)					2.00%
Number of acre tract of unevaluated property (in acres)					366.85
Land acquisition costs					1,541
Galveston Bay Energy, LLC [Member] | Namibia Exploration, Inc. [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)						8,396,667
Father Of Chief Financial Officer [Member]
Related Party Transaction [Line Items]
Percentage working interest purchased (in hundredths)	5.00%
Outstanding billed and unbilled joint interest billings owed by related party	58,014	84,806
Due to related parties	0	15,046
Terminated Officer in Corpus Christi Office [Member]
Related Party Transaction [Line Items]
Cash consideration associated with conveying properties to terminated officer							0
Chairman' Nephew [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)									191,667
Due from employee										1,000,000
Proceeds from Related Party Debt								-675,000
Chairman' Nephew [Member] | Proceeds From Sale Of Stock [Member]
Related Party Transaction [Line Items]
Proceeds from Related Party Debt								-275,000
Chairman' Nephew [Member] | Proceeds from loan [Member]
Related Party Transaction [Line Items]
Proceeds from Related Party Debt								-400,000
Unrelated party in which Michael Watts has minority interest [Member]
Related Party Transaction [Line Items]
Due from employee				1,859,879					1,859,879
Unrelated party in which Michael Watts has minority interest [Member] | Settled with a receivable [Member]
Related Party Transaction [Line Items]
Proceeds from Related Party Debt									750,000
HCN obligation [Member]
Related Party Transaction [Line Items]
Stock issued during period for acquisition, shares (in shares)									619,960
Due to related parties				2,400,000					2,400,000
Interest and late fees									553,630
HCN obligation [Member] | Settled with cash [Member]
Related Party Transaction [Line Items]
Interest and late fees									25,000

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Income Taxes [Abstract]
Net loss before income taxes	($6,550,250)	($37,657,165)
Net operating loss carry forwards	$15,732,204
Beginning year of expiration of operating loss carry forwards	1-Jan-27

Income_Taxes_Reconciliation_of

Income Taxes (Reconciliation of Income Tax Provision at the Statutory Rate) (Details)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Income Taxes [Abstract]
US statutory federal rate (in hundredths)	35.00%	35.00%
State income tax rate (in hundredths)	0.58%	0.58%
Equity-based compensation (in hundredths)	-5.16%	-33.62%
Gain on derivative warrants (in hundredths)	0.00%	0.93%
Gain on sale of securities (in hundredths)	0.00%	-0.33%
Other (in hundredths)	-6.64%	-0.50%
Net operating loss (in hundredths)	-23.70%	-1.75%
Effective income tax rate (in hundredths)	0.08%	0.31%

Income_Taxes_Schedule_of_Defer

Income Taxes (Schedule of Deferred Tax Assets) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Income Taxes [Abstract]
Stock based compensation	$338,078	$713,867
Property, including depreciable property	-3,122,873	-2,980,005
Asset retirement obligation	4,168,049	3,942,918
Net operating loss carry-forward	5,596,732	3,846,783
Other	20,860	42,368
Deferred tax assets, gross	7,000,846	5,565,931
Valuation allowance for deferred tax assets	-7,000,846	-5,565,931
Total deferred tax assets	$0	$0

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013	31-May-12
	LetterofCredit
Commitments And Contingencies [Line Items]
Contingency accrued		$232,974
Cash settlement to be paid by Galveston Bay	35,000
Stock settlement to be paid by Hydrocarb	65,000
Cost of renewal easements	400,000
Rent expense	186,463	211,346
Monthly compression and handling fees	1,000
Number of letters of credit in favor of the Railroad Commission of Texas	2
Debt instrument, face amount			18,375
Schedule of prepaid balances [Abstract]
Prepaid letter of credit fees	101,251	101,850
Amortization	-8,488	-8,488
Net prepaid letter of credit fees	92,763	93,362
Letter of Credit One [Member]
Commitments And Contingencies [Line Items]
Debt instrument, face amount	6,610,000
Debt instrument, fee percentage (in hundredths)	1.50%
Letter Of Credit Two [Member]
Commitments And Contingencies [Line Items]
Debt instrument, face amount	120,000
Debt instrument, fee percentage (in hundredths)	1.50%
Houston, Texas Office [Member]
Commitments And Contingencies [Line Items]
Operating lease, term of lease	3 years
Operating lease, term of lease extension	3 years
Monthly rental payments	6,406
Monthly rental payments, year two	6,673
Monthly rental payments, year three	6,940
Accounts payable and accrued expenses [Member]
Commitments And Contingencies [Line Items]
Environmental remediation expense	150,000	150,000
Minimum [Member]
Commitments And Contingencies [Line Items]
Loss contingency, estimate	150,000
Maximum [Member]
Commitments And Contingencies [Line Items]
Loss contingency, estimate	$900,000

Additional_Financial_Statement2

Additional Financial Statement Information (Schedule of Other Current Assets) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Additional Financial Statement Information [Abstract]
Prepaid letter of credit fees	$92,763	$93,362
Prepaid insurance	287,743	184,138
Other prepaid expenses	63,143	11,101
Cash call paid to operator	0	24,225
Prepaid land use fees	0	28,728
Accrued interest income	2,671	4,388
Total other current assets	446,320	345,942
Other receivables, allowance for doubtful accounts	$70,742	$58,585

Additional_Financial_Statement3

Additional Financial Statement Information (Schedule of Property and Equipment) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Property, Plant and Equipment [Line Items]
Total property and equipment	$302,553	$174,998
Less accumulated depreciation	-135,590	-116,945
Net book value	166,963	58,053
Depreciation expense	36,894	61,215
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	24,085	8,814
Marine vessels [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	109,742	17,614
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	40,496	65,807
Computer equipment and software [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	2 years
Total property and equipment	126,143	82,466
Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	2 years
Total property and equipment	2,087	0
Other Depreciable Property [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	2 years
Total property and equipment	$0	$297

Additional_Financial_Statement4

Additional Financial Statement Information (Schedule of Accounts Payable and Accrued Expenses) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Additional Financial Statement Information [Abstract]
Trade payables	$2,686,966	$2,503,820
Accrued payroll	-76,064	151,577
Accrued interest and fees	37,853	500
Revenue payable	5,790	4,717
Local taxes and royalty payable	111,699	128,470
Federal and state income taxes payable	29,431	27,000
Total accounts payable and accrued expenses	$2,795,675	$2,816,084

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	0 Months Ended
	Nov. 06, 2014	Aug. 15, 2014	31-May-12
Subsequent Event [Line Items]
Term Loan face amount			$18,375
Subsequent Event [Member]
Subsequent Event [Line Items]
Interest rate in case of default (in hundredths)		24.00%
Voting stock percentage (in hundredths)		25.00%
Common stock issued in settlement (in shares)	65,000
Subsequent Event [Member] | Galveston Bay, LLC [Member]
Subsequent Event [Line Items]
Cash payment settlement	35,000
Subsequent Event [Member] | Term Loan [Member]
Subsequent Event [Line Items]
Term Loan face amount		4,000,000
Term Loan amount outstanding		4,545,454
Discount rate (in hundredths )		12.00%
Structuring fee		90,909
Structuring fee (in hundredths)		2.00%
Debt Issuance Cost		172,824
Placement fee (in hundredths)		5.00%
Placement fee		227,273
Consulting fee (in hundredths)		1.00%
Consulting Fee		45,455
Proceed from long term debt		3,463,539
Additional borrowing capacity		1,000,000
Sale of equity		750,000
Credit agreement period sale of equity		150 days
Structuring Fee on additional borrowings (in hundredths)		2.00%
Threshold Revenues		900,000
Interest rate under condition one (in hundredths)		16.00%
Interest rate under condition two (in hundredths)		14.00%
Restricted shares issued		60,000
Restricted shares issued after 12 months from effective date (in shares)		32,500
Restricted shares issued after 18 months from effective date (in shares)		32,500
Restricted shares issued after 21 months from effective date (in shares)		25,000
Credit agreement effective date		15-Aug-14
Payables in case of default		250,000
Period of default		30 days

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Unaudited) (Narrative) (Details)	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Average oil and gas price per barrel	100.11	92.52
Average gas price per MMbtu	4.1	3.51

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Unaudited) (Schedule of Net Proved Reserves) (Details)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
	MMcf	MMcf
Reserve Quantities [Line Items]
Beginning Balance	16,688,590	23,067,460
Revisions of previous estimates	2,538,043	-5,834,587
Sale of reserves in place	-636,437	-8
Production	-428,185	-544,275
Ending Balance	18,162,011	16,688,590
Proved developed producing	2,175,826	3,092,160
Proved developed non-producing	6,087,112	6,376,700
Proved undeveloped	9,899,073	7,219,730
Total Proved reserves	18,162,011	16,688,590
Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	659,700	1,388,250
Revisions of previous estimates	422,261	-667,307
Sale of reserves in place	-17,750	-1
Production	-42,436	-61,242
Ending Balance	1,021,775	659,700
Proved developed producing	200,981	256,290
Proved developed non-producing	212,320	229,290
Proved undeveloped	608,474	174,120
Total Proved reserves	1,021,775	659,700
Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	12,730,390	14,737,960
Revisions of previous estimates	4,477	-1,830,745
Sale of reserves in place	-529,937	-2
Production	-173,569	-176,823
Ending Balance	12,031,361	12,730,390
Proved developed producing	969,940	1,554,420
Proved developed non-producing	4,813,192	5,000,960
Proved undeveloped	6,248,229	6,175,010
Total Proved reserves	12,031,361	12,730,390

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) (Schedule of Capitalized Costs) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Unevaluated properties	$2,119,769	$1,124,805
Evaluated properties	19,153,124	19,857,842
Less impairment	-373,335	-373,335
Gross capitalized costs	20,899,558	20,609,312
Less depreciation, depletion and amortization	-3,491,420	-2,617,478
Net capitalized cost	$17,408,139	$17,991,834

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Incurred) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Property acquisition [Abstract]
Unproved	$1,232,815	$808,307
Proved	13	3,000
Exploration	238,112	404,265
Development	0	1,732,451
Cost recovery	-658,195	-196,001
Total costs incurred	812,745	2,752,022
Namibia [Member]
Property acquisition [Abstract]
Unproved	1,232,815	677,795
Proved	0	0
Exploration	173,299	35,860
Development	0	0
Cost recovery	0	0
Total costs incurred	1,406,114	713,655
Unites States [Member]
Property acquisition [Abstract]
Unproved	0	130,512
Proved	13	3,000
Exploration	64,813	368,405
Development	0	1,732,451
Cost recovery	-658,195	-196,001
Total costs incurred	($593,369)	$2,038,367

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Excluded by Year) (Details) (USD $)	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Property Acquisition	$1,232,815	$677,795
Exploration	173,299	35,860
Total	$1,406,114	$713,655

Supplemental_Oil_and_Gas_Infor7

Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Excluded by Country) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Ending Balance	$1,406,114	$713,655
Namibia [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Beginning Balance	713,655	0
Additional Cost Incurred	1,406,114	713,655
Cost Recovery		0
Costs Transferred to DD&A Pool		0
Ending Balance	2,119,769	713,655
Unites States [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Beginning Balance	0	265,639
Additional Cost Incurred	0	278,090
Cost Recovery		-132,662
Costs Transferred to DD&A Pool		-411,067
Ending Balance	$0	$0

Supplemental_Oil_and_Gas_Infor8

Supplemental Oil and Gas Information (Unaudited) (Schedule of Standardized Measure) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Future cash inflows	$159,283,690	$113,603,450
Future production costs	-54,437,098	-55,897,070
Future development costs	-43,054,816	-41,794,284
Future income tax expenses	-21,627,122	-5,569,234
Future net cash flows	40,164,654	10,342,862
10% annual discount for estimated timing of cash flows	-15,807,988	-3,990,069
Future net cash flows at end of year	$24,356,666	$6,352,793

Supplemental_Oil_and_Gas_Infor9

Supplemental Oil and Gas Information (Unaudited) (Schedule of Changes in Standardized Measure) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Standardized measure of discounted future net cash flows at beginning of year	$6,352,793	$33,663,886
Net changes in prices and production costs	20,980,014	-37,623,010
Changes in estimated future development costs	-764,412	4,205,045
Sales of oil and gas produced, net of production costs	-151,783	-2,510,339
Discoveries and extensions	0	0
Purchases of minerals in place	0	0
Sales of minerals in place	-2,228,023	-17
Revisions of previous quantity estimates	8,885,117	-12,391,911
Development costs incurred	0	1,124,107
Change in income taxes	-9,694,393	14,705,973
Accretion of discount	977,353	5,179,059
Standardized measure of discounted future net cash flows at year end	$24,356,666	$6,352,793

Recovered_Sheet1

Supplemental Oil and Gas Information (Unaudited) (Schedule of Results of Operations for Producing Activities) (Details) (USD $)	12 Months Ended
	Jul. 31, 2014	Jul. 31, 2013
Supplemental Oil And Gas Information Unaudited [Abstract]
Net revenues from production	$5,065,096	$7,070,540
Expenses [Abstract]
Lease operating expense	4,913,313	4,560,201
Accretion	1,043,928	1,056,508
Operating expenses	5,957,241	5,616,709
Depreciation, depletion, and amortization	873,942	1,059,803
Total expenses	6,831,183	6,676,512
Income before income tax	-1,766,087	394,028
Income tax expenses	0	-137,910
Results of operations	-1,766,087	256,118
Depreciation, depletion and amortization rate per net equivalent MCFE	$2.04	$1.95