10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended July 31, 2013

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ________________.

Commission file number 000-53313

DUMA ENERGY CORP.

(Exact name of registrant as specified in its charter)

Nevada	30-0420930
(State or other jurisdiction of incorporation of organization)	(I.R.S. Employer Identification No.)

800 Gessner, Suite 200, Houston, Texas	77024
(Address of Principal Executive Offices)	(Zip Code)

(281) 408-4880

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, Par Value $0.001

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o   No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of Section 15(d) of the Act.  Yes o   No o

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x   No o

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x   No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer o (do not check if a smaller reporting company)	Smaller reporting company x

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o   No x 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed by reference to the price at which the registrant’s common equity was last sold, as of January 31, 2013 (the last day of the registrant’s most recently completed second fiscal quarter) was approximately $15,400,000.

The registrant had 15,140,882 shares of common stock outstanding as of November 12, 2013. 

FORWARD LOOKING STATEMENTS

This annual report contains forward-looking statements that involve risks and uncertainties. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “should”, “expect”, “plan”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential” or “continue”, the negative of such terms or other comparable terminology. In evaluating these statements, you should consider various factors, including the assumptions, risks and uncertainties outlined in this annual report under “Risk Factors”. These factors or any of them may cause our actual results to differ materially from any forward-looking statement made in this annual report. Forward-looking statements in this annual report include, among others, statements regarding:

● our capital needs;

● business plans; and

● expectations.

While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding future events, our actual results will likely vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested herein. Some of the risks and assumptions include, but are not limited to:

● our need for additional financing;

● our exploration activities may not result in commercially exploitable quantities of oil and gas on our properties;

● the risks inherent in the exploration for oil and gas such as weather, accidents, equipment failures and governmental restrictions;

● our limited operating history;

● our history of operating losses;

● the potential for environmental damage;

● the competitive environment in which we operate;

● the level of government regulation, including environmental regulation;

● changes in governmental regulation and administrative practices;

● our dependence on key personnel;

● conflicts of interest of our directors and officers;

● our ability to fully implement our business plan;

● our ability to effectively manage our growth; and

● other regulatory, legislative and judicial developments.

We advise the reader that these cautionary remarks expressly qualify in their entirety all forward-looking statements attributable to us or persons acting on our behalf. Important factors that you should also consider, include, but are not limited to, the factors discussed under “Risk Factors” in this annual report.

The forward-looking statements in this annual report are made as of the date of this annual report and we do not intend or undertake to update any of the forward-looking statements to conform these statements to actual results, except as required by applicable law, including the securities laws of the United States.

AVAILABLE INFORMATION

Duma Energy Corp. files annual, quarterly and current reports, proxy statements, and other information with the Securities and Exchange Commission (the “SEC”). You may read and copy documents referred to in this Annual Report on Form 10-K that have been filed with the SEC at the SEC’s Public Reference Room, 450 Fifth Street, N.W., Washington, D.C. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You can also obtain copies of our SEC filings by going to the SEC’s website at http://www.sec.gov.

REFERENCES

As used in this annual report: (i) the terms “we”, “us”, “our”, “Duma” and the “Company” mean Duma Energy Corp.; (ii) “SEC” refers to the Securities and Exchange Commission; (iii) “Securities Act” refers to the United States Securities Act of 1933, as amended; (iv) “Exchange Act” refers to the United States Securities Exchange Act of 1934, as amended; and (v) all dollar amounts refer to United States dollars unless otherwise indicated.

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TABLE OF CONTENTS

ITEM 1.	BUSINESS	4
ITEM 1A.	RISK FACTORS	12
ITEM 1B.	UNRESOLVED STAFF COMMENTS	15
ITEM 2.	PROPERTIES	15
ITEM 3.	LEGAL PROCEEDINGS	16
ITEM 4.	MINE SAFETY DISCLOSURE	16
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	17
ITEM 6.	SELECTED FINANCIAL DATA	18
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	24
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	25
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	57
ITEM 9A.	CONTROLS AND PROCEDURES	57
ITEM 9B.	OTHER INFORMATION	57
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	58
ITEM 11.	EXECUTIVE COMPENSATION	62
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	66
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	67
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	68
ITEM 15.	EXHIBITS	70

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PART I

ITEM 1.  BUSINESS

Corporate History and Organization

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.

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, and (iv) Namibia Exploration, Inc., a Nevada corporation.

Our principal offices are located at 800 Gessner, Suite 200, Houston, Texas, 77024. Our telephone number is (281) 408-4880 and our fax number is (281) 408-4879.

General

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.  As of July 31, 2013, we maintain developed acreage both onshore and offshore in Texas and Illinois.  As of July 31, 2013, we were producing oil and gas from our working interest in three wells onshore in Texas and 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.  

As part of our ongoing business strategy, we continue to review and evaluate acquisition opportunities in the continental United States and internationally.

Exploration and Production Activities

Our oil and gas interests as of July 31, 2013 were as follows:

Producing properties

Galveston Bay, Texas

Through our subsidiary, Galveston Bay Energy, LLC (“GBE”), we hold majority interests (approximately 93% working interest) and operate four fields in the shallow waters of Galveston Bay which is Southeast of Houston, Texas. Currently, we are producing the four fields that were acquired with GBE. The fields were shut-in in September 2008 due to a direct hit from Hurricane Ike. The then-owner went into bankruptcy and the properties were purchased out of bankruptcy by a private seller who performed reconstruction work on the fields and later sold them to us.

The Welder Lease (Barge Canal), Texas

We own 100% working interest (72.5% net revenue interest) in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas. As of the date of this annual report, two wells are producing gas and oil from the property. One of the wells is an oil well requiring gas lift to produce and the other well is a naturally flowing gas well. A third well is utilized for salt water disposal.

Palacios Prospect, Texas

In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas.  Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area.  Our net revenue interest in the prospect is 4.125%. In April 2012, the operator successfully completed the Palacios #1 well, which produces primarily natural gas.

4

Illinois

In January 2011, we entered into a farmout agreement covering our 10% working interest in multiple leases in or near Markham City, Illinois.  Core Minerals Management II, LLC (“Core”) operates the properties in accordance with this farmout agreement. After payout of the property, $1,350,000 or 29,000 barrels, whichever comes first, provided that we hold less than 25% working interest in the property at payout, our working interest will be adjusted to 25%. During fiscal 2012, the operator drilled wells in the contract area and commenced a pilot waterflood project to re-pressurize the reservoir and enhance recovery of oil from the area. The wells in the project area produce oil.

In September 2013, we conveyed our interest in the Illinois and Palacios properties to Carter E & P, LLC, a company owned by our former Vice President of Operations.

Unproved properties – USA

Chapman Ranch II Prospect, Texas

In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas. The well was drilled in June 2012; however, all attempts to bring the well into production failed. Abandonment operations will commence in the near future when scheduled by the operator pending rig availability. We will share 25% of the abandonment cost.

Curlee, Melody, and Dix Prospects, Texas

During August 2012, we leased approximately 190 acres of land in Bee County, Texas.  The operator of the project is Carter E&P, a company owned by our former Vice President of Operations.  We acquired a 50% working interest in the project. We drilled the first well on the prospect during the year ended July 31, 2013.  The well was not successful and it was plugged and abandoned.

In December 2012, we acquired 23% working interest in a 366.85 acre tract of property, the Dix Prospect, in San Patricio County, Texas. The operator of the project is Carter E&P, a company owned by our former Vice President of Operations.  The initial well was drilled in May 2013, but it was determined that the well could not produce economically. Accordingly, the well was plugged and abandoned.

During April 2013, we purchased a 12.5% working interest in a 260.12 acre tract of property, the Melody Prospect, in Bee County, Texas.  The operator of the project is Carter E&P, a company owned by our former Vice President of Operations.  The well was drilled in June 2013 and it was a dry hole. Accordingly, the well was plugged and abandoned.

In September 2013, we conveyed our interest in the Curlee, Dix, and Melody prospects as well as our interest in the Illinois properties to Carter E & P, LLC, a company owned by our former Vice President of Operations.

Unproved property – Namibia

Through our subsidiary, Namibia Exploration, Inc. (“NEI”), we hold the rights to a 39% working interest (43.33% cost responsibility) in an onshore petroleum concession (the “Concession”), located in the Republic of Namibia, 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. We hold our working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. (“NPC Namibia”) and Hydrocarb Namibia Energy Corporation (“Hydrocarb Namibia”), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation (“Hydrocarb”), a company organized under the laws of the State of Nevada.  Hydrocarb Namibia, as operator of the Concession, holds a 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now a 10% carried working interest in the Concession.  

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, conduct and environmental study. The minimum expenditure is $300,000.

5

Oil and Gas Reserves

The following table illustrates provides a summary of our oil and gas reserves as of our fiscal year ended July 31, 2013, as estimated by third party reservoir engineers.

Summary of Oil and Gas Reserves as of July 31, 2013 Based on Average Fiscal-Year Prices

Reserves Category	Oil (Mbls)	Natural Gas (MMcf)	Equivalent (MMcfe)
PROVED
Developed	485.58	6,555.38	9,468.86
Undeveloped	174.12	6,175.01	7,219.73
TOTAL PROVED	659.70	12,730.39	16,688.59

Estimates of proved reserves at July 31, 2013 and 2012 were prepared by Ralph E. Davis Associates, Inc. (“RED”), our independent consulting petroleum engineers. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. Although the SEC’s reserves rules allow probable and possible reserves to be disclosed separately, we have elected not to disclose probable and possible reserves in this report.

Internal Controls Over Reserves Estimates Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Our internal controls over reserve estimates also include the following:

· Utilization of an independent consulting petroleum engineer for the preparation of reserves estimates for 100% of our reserves and

· Involvement of personnel with appropriate background and experience to oversee the reserves estimate process and provide the requested data to the independent petroleum engineer.

Our Vice President, Craig Alexander, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Mr. Alexander has a Bachelor of Science degree in Petroleum Engineering and over 22 years of industry experience with positions of increasing responsibility in production and completion engineering and operations management. Mr. Alexander reports directly to our Chief Executive Officer.

Technologies Used in Reserves Estimation  

The SEC’s updated rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates.

RED used the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance. In the conduct of the reserve study, RED did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the reserve study something came to the attention of RED which brought into question the validity or sufficiency of any such information or data, RED did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.  RED did not perform a personal field inspection of our properties.

6

Changes in Proved Undeveloped Reserves

As of July 31, 2013, we reported 7,219.73 MMcfe of proved undeveloped reserves, which represents a decrease of 6,055.74 MMcfe from July 31, 2012.  The following table shows of the changes in total proved undeveloped reserves for 2013:

Beginning of year	13,275.47
Revisions of previous estimates	(6,055.74	)
End of year	7,219.73

Before our acquisition of GBE during the year ended July 31, 2011, we had no proved undeveloped reserves.  Accordingly, we have no proved undeveloped reserves that have been undeveloped for five years since their original disclosure as proved undeveloped reserves.  

During the year ended July 31, 2012, we began our development program with the drilling of the State Tract 9-12A#4 well in the Tex2 Sand.  During the year ended July 31, 2013, we determined that the well was not successful.  Operations for this well held acreage that was lost because of the inability to establish production prior to the end of the lease term.  Based on the results of this well, and the loss of a portion of the acreage in the reservoir, the reserves ascribed to this drilling location and other locations were removed from the 2013 reserve report.  This adjustment accounts for 76% of the decrease in estimated undeveloped reserves.

In addition, based upon further geologic interpretation, we determined that the reserves for a fourth drilling location did not justify the drilling of the well. This accounted for 23% of the decrease in estimated undeveloped reserves.

Production and Price History

The table below sets forth the net quantities of oil and gas production, net of royalties, attributable to us in the years ended July 31, 2013, 2012 and 2011. For the purposes of this table, the following terms have the following meanings: (i) “Bbl” means one stock tank barrel or 42 U.S. gallons liquid volume; (ii) “MBbls” means one thousand barrels of oil; (iii) “Mcf” means one thousand cubic feet; (iv) “Mcfe” means one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil; (v) “MMcfe/d” means one million cubic feet equivalent per day, determined by using the ratio of six Mcf of natural gas to one Bbl of oil; and (vi) “MMcf” means one million cubic feet.

	For the Year Ended July 31, 2013		For the Year Ended July 31, 2012		For the Year Ended July 31, 2011
Production Data
Oil (MBbls)		61.2		61.0		28.2
Natural gas (MMcf)		176.8		223.0		59.5
Total (MMcfe)		544.0		589.0		228.6
Average Prices:
Oil (per Bbl)	$	105.63	$	106.29	$	110.65
Natural gas (per Mcf)	$	3.40	$	3.05	$	4.95
Total (per Mcfe)	$	12.99	$	12.16	$	14.93
Average Costs (per Mcfe):
Lease operating expenses (per Mcfe)(1)	$	8.38	$	6.81	$	7.43

(1)  Taxes, transportation and production-related administrative expenditures are included in lease operating expenses.

Net production includes only production that is owned by us, whether directly or beneficially, and produced to our interest, less royalties and production due to others. Production of natural gas includes only marketable production of gas on an “as sold” basis. Production of natural gas includes only dry, residue and wet gas, depending on whether liquids have been extracted before we passed title, and does not include flared gas, injected gas and gas consumed in operations. Recovered gas, lift gas and reproduced gas are not included until sold.

7

Drilling and Other Exploratory Development Activities

The following tables set forth information regarding (i) the number of net productive and dry exploratory wells drilled and (ii)  the number of net productive and dry development wells drilled during the years indicated, expressed separately for oil and gas. For the purposes of this subsection:

(1) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

(2) A productive well is an exploratory, development, or extension well that is not a dry well.

(3) Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

(4) The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated.  A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.

For the purposes of this subsection (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.

	Number of Wells Drilled During Year Ended July 31, 2013
	Oil								Gas
	Net productive exploratory wells		Net dry exploratory wells		Net productive development wells		Net dry development wells		Net productive exploratory wells		Net dry exploratory wells		Net productive development wells		Net dry development wells
Texas		0		1.00		0		0.25		0		0		0		0
Total		0		1.00		0		0.25		0		0		0		0

	Number of Wells Drilled During Year Ended July 31, 2012
	Oil								Gas
	Net productive exploratory wells		Net dry exploratory wells		Net productive development wells		Net dry development wells		Net productive exploratory wells		Net dry exploratory wells		Net productive development wells		Net dry development wells
Illinois		.30		0		0		0		0		0		0		0
Texas		0		.10		0		0		.06		0		0		0
Total		.30		.10		0		0		.06		0		0		0

	Number of Wells Drilled During Year Ended July 31, 2011
	Oil								Gas
	Net productive exploratory wells		Net dry exploratory wells		Net productive development wells		Net dry development wells		Net productive exploratory wells		Net dry exploratory wells		Net productive development wells		Net dry development wells
Illinois		0		0		0		0		0		0		0		0
Texas		0		0		0		0		0		0		0		0
Total		0		0		0		0		0		0		0		0

Present Activities

We own a 25% non-operated interest in a well that was drilled onshore in Nueces County, Texas beginning in June 2012.  The well was originally completed to a non-economic zone.  We conducted a series of recompletions and reworks during the year ended July 31, 2013.  The operations were not successful, and the well will be plugged and abandoned during the year ended July 31, 2014.  

Delivery Commitments

None.

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Productive Wells

The following table sets forth information regarding the total gross and net productive wells as of November 12, 2013, expressed separately for oil and gas. All of our productive oil and gas wells were located in Texas. For the purposes of this subsection: (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.

	Number of Operating Wells
	Oil				Gas
	Gross		Net		Gross		Net
Texas		23.00		21.81		10.00		9.32

A productive well is an exploratory well, development well, producing well or well capable of production, but does not include a dry well. A dry well, or a dry hole, is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

A gross well is a well in which a working interest is owned, and a net well is the result obtained when the sum of fractional ownership working interests in gross wells equals one. The number of gross wells is the total number of wells in which a working interest is owned, and the number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. The “completion” of a well means the installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency.

Acreage

The following table sets forth information regarding our gross and net developed and undeveloped oil and natural gas acreage under lease as of November 12, 2013.

	Gross (1)		Net
Developed Acreage
Texas		18,456.74		18,255.05
Undeveloped Acreage
Texas		240.00		60.00
Total		18,696.74		18,315.05

(1) The gross acreage cited includes leasehold acreage to be earned under the farm-out agreements.

A developed acre is an acre spaced or assignable to productive wells, a gross acre is an acre in which a working interest is owned, and a net acre is the result that is obtained when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves, but does not include undrilled acreage held by production under the terms of a lease. As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the lease or by payment of delay rentals during the remaining primary term of the lease. The oil and natural gas leases in which we have an interest are for varying primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as oil or natural gas is produced in commercial quantities or operations are commenced to restore production.

Plan of Operations

Our Plan of Operations is described in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Government Regulation

General

The availability of a ready market for oil and gas production depends upon numerous factors beyond our control. These factors include local, state, federal and international regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels. State and federal regulations are generally intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, and control contamination of the environment.

Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and a consequent increase in the cost of doing business and decrease in profitability. Numerous federal and state departments and agencies issue rules and regulations imposing additional burdens on the oil and gas industry that are often costly to comply with and carry substantial penalties for non-compliance. Our production operations may be affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.

9

The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations. Many states have statutes and regulations governing various environmental and conservation matters, including the establishment of maximum rates of production from oil and gas wells, and restricting production to the market demand for oil and gas. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced. Most states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. State production taxes are generally applied as a percentage of production or sales.

Oil and gas rights may be held by individuals and corporations, and, in certain circumstances, by governments having jurisdiction over the area in which such rights are located. As a general rule, parties holding such rights grant licenses or leases to third parties, such as us, to facilitate the exploration and development of these rights. The terms of the licenses and leases are generally established to require timely development. Notwithstanding the ownership of oil and gas rights, the government of the jurisdiction in which the rights are located generally retains authority over the manner of development of those rights.

Environmental

General.  Our activities are subject to local, state and federal laws and regulations governing environmental quality and pollution control in the United States. The exploration, drilling and production from wells, natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing natural gas and other products, are subject to stringent environmental laws and regulations by state and federal authorities, including the Environmental Protection Agency (“EPA”). These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Such regulation can increase our cost of planning, designing, installing and operating such facilities.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Moreover, some environmental laws provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances, such as oil and gas related products.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

Waste Disposal.  We currently lease, and intend in the future to own or lease, additional properties that have been used for production of oil and gas for many years. Although we and our operators utilize operating and disposal practices that are standard in the industry, previous owners or lessees may have disposed of or released hydrocarbons or other wastes on or under the properties that we currently own or lease or properties that we may in the future own or lease. In addition, many of these properties have been operated in the past by third parties over whom we had no control as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and gas wastes and properties may require us to remediate property, including ground water, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

We may generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA has limited the disposal options for certain wastes that are designated as hazardous under RCRA. Furthermore, it is possible that certain wastes generated by our oil and gas projects that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating and disposal requirements.

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CERCLA.  The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons or so-called potentially responsible parties include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of the hazardous substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may in the future be an owner of facilities on which hazardous substances have been released by previous owners or operators of our properties that are named as potentially responsible parties related to their ownership or operation of such property.

Air Emissions.  Our projects are subject to local, state and federal regulations for the control of emissions of air pollution. Major sources of air pollutants are subject to more stringent, federally imposed permitting requirements, including additional permits. Producing wells, gas plants and electric generating facilities generate volatile organic compounds and nitrogen oxides. Some of our producing wells may be in counties that are designated as non-attainment for ozone and may be subject to restrictive emission limitations and permitting requirements. If the ozone problems in the applicable states are not resolved by the deadlines imposed by the federal Clean Air Act, or on schedule to meet the standards, even more restrictive requirements may be imposed, including financial penalties based upon the quantity of ozone producing emissions. If we fail to comply strictly with air pollution regulations or permits, we may be subject to monetary fines and be required to correct any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources.

Clean Water Act.  The Clean Water Act imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. Permits must be obtained to discharge pollutants into federal waters. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.

Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act, and similar legislation enacted in Texas, Louisiana and other coastal states, impose certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in United States waters and adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility or vessel that is a source of an oil discharge or poses the substantial threat of discharge, or the lessee or permittee of the area in which a facility covered by OPA is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs, remediation of environmental damage and a variety of public and private damages. OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs of a potential spill. Few defenses exist to the liability imposed by OPA. In the event of an oil discharge, or substantial threat of discharge from our properties, vessels and pipelines, we may be liable for costs and damages.

We believe that we are in substantial compliance with current environmental laws and regulations in each of the jurisdictions in which we operate. Although we have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

Competition

The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources.

Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and other countries, as well as factors that we cannot control, including international political conditions, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources. Intense competition occurs with respect to marketing, particularly of natural gas.

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Employees

We currently have twelve full-time employees and one part-time employee.

Subsidiaries

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, and (iv) Namibia Exploration, Inc., a Nevada corporation.

ITEM 1A. RISK FACTORS

An investment in our common stock involves a number of very significant risks. You should carefully consider the following risks and uncertainties in addition to other information in this annual report in evaluating our company and its business before purchasing shares of our common stock. Our business, operating results and financial condition could be seriously harmed due to any of the following risks. The risks described below may not be all of the risks facing our company. Additional risks not presently known to us or that we currently consider immaterial may also impair our business operations. You could lose all or part of your investment due to any of these risks.

Risks Related to Our Company

Because we have only recently commenced business operations, we face a high risk of business failure.

We were incorporated on April 12, 2005 and originally planned to explore for gold and other minerals, but we soon shifted our focus to oil and gas exploration. Revenues were limited until our acquisition of GBE in 2011 and to date, we have not achieved profitability. Potential investors should be aware of the difficulties normally encountered by companies in the early stages of their life cycle and the high rate of failure of such enterprises. These potential problems include, but are not limited to, unanticipated problems relating to costs and expenses that may exceed current estimates. We have no actual company history upon which to base any assumption as to the likelihood that our business will prove successful, and it is possible, although not anticipated, that we may never achieve profitable operations.

We may not be able to effectively manage the demands required of a new business in our industry, such that we may be unable to successfully implement our business plan or achieve profitability.

We have earned limited revenues until recently (the past two years) and we have never achieved annual profitability. We may not be able to effectively execute our business plan or manage any growth, if any, of our business. Future development and operating results will depend on many factors, including access to adequate capital, the demand for oil and gas, price competition, and whether we can control costs. Many of these factors are beyond our control. In addition, our future prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a new business in the oil and gas industry, which is characterized by intense competition, rapid technological change, highly litigious competitors and significant regulation. If we are unable to address these matters, or any of them, then we may not be able to successfully implement our business plan or achieve profitability.

Because we have earned limited revenues from operations, most of our capital requirements have been met through financing and we may not be able to continue to find financing to meet our operating requirements.

We may need to obtain additional financing in order to pursue our business plan. As of July 31, 2013, we had cash and cash equivalents of $317,881 and a working capital deficit of $4,182,058. As such, unless our cash flow from operations is sufficient, we will need additional financing to pursue the exploration and development of our properties and pay for corporate overhead.  We may not be able to obtain such financing at all or in amounts that would be sufficient for us to meet our current and expected working capital needs. Furthermore, in the event that our plans change or our assumptions change or prove inaccurate, we could be required to seek additional financing in greater amounts than is currently anticipated. Any inability to obtain additional financing when needed would have a material adverse effect on us, including possibly requiring us to significantly curtail or possibly cease our operations. In addition, any future equity financing may involve substantial dilution to our existing stockholders.

Because we have a history of losses and anticipate continued losses unless and until we are able to generate sufficient revenues to support our operations, we may lack the financial stability required to continue operations.

Since inception we have suffered recurring losses. We have funded our operations largely through the issuance of common stock in order to meet our strategic objectives. Our current level of oil and gas production is not sufficient to completely fund our exploration and development budget, such that we anticipate that we may need additional financing in order to pursue our plan of operations. We anticipate that our losses will continue until such time, if ever, as we are able to generate sufficient revenues to support our operations.

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Costs of drilling, completing and operating wells is uncertain, and we may not achieve sufficient production to cover such costs.

The cost of drilling, completing and operating wells is often uncertain. We may not be able to achieve commercial production of oil and gas to pay such costs. Drilling operations on our properties or on properties we may acquire in the future may be curtailed, delayed or cancelled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit or a recovery of drilling, completion and operating costs. As a result, our business, results of operations and financial condition may be materially adversely affected.

Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, which could have a material adverse effect on our business, results of operations and financial condition.

There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from prepared by different engineers or by the same engineers but at different times may vary substantially, and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, when and if made, and such variances may be material, which could have a material adverse effect on our business, results of operations and financial condition.

Our future oil and natural gas production is highly dependent upon our ability to find or acquire reserves.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves, if any, will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring reserves in the future. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. The failure of an operator of our wells to adequately perform operations, or such operator’s breach of the applicable agreements, could adversely impact us. In addition, we may not obtain additional proved reserves or be able to drill productive wells at acceptable costs, in which case our business would fail.

Oil and gas resources may contain certain hazards which may, in turn, create certain liabilities or prevent the resources from being commercially viable.

Our properties may contain hazards such as unusual or unexpected formations and other conditions. Our projects may become subject to liability for pollution, fire, explosion, blowouts, cratering and oil spills, against which we cannot insure or against which we may decide to not insure. Such events could result in substantial damage to oil and gas wells, producing facilities and other property and/or result in personal injury. Costs or liabilities related to those events would have a material adverse effect on our business, results of operations, financial condition and cash flows.

Oil and gas prices are highly volatile, and a decline in oil and gas prices could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Oil and gas prices and markets are highly volatile. Prices for oil and gas are subject to significant fluctuation in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and a variety of additional factors. Our profitability will be substantially dependent on prevailing prices for natural gas and oil. The amounts of and prices obtainable for our oil and gas production may be affected by market factors beyond our control, such as:

● the extent of domestic production;

● the amount of imports of foreign oil and gas;

● the market demand on a regional, national and worldwide basis;

● domestic and foreign economic conditions that determine levels of industrial production;

● political events in foreign oil-producing regions; and

● variations in governmental regulations and tax laws or the imposition of new governmental requirements upon the oil and gas industry.

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These factors or any one of them could result in the decline in oil and gas prices, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

As a result of our intensely competitive industry, we may not gain enough market share to be profitable.

We compete in the sale of oil and natural gas on the basis of price and on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators in the United States and elsewhere. Because we are pursuing potentially large markets, our competitors include major, multinational oil and gas companies. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources. If we are unable to compete successfully, we may never be able to sell enough product at a price sufficient to permit us to generate profits.

The oil and natural gas market is heavily regulated, and existing or subsequently enacted laws or regulations could limit our production, increase compliance costs or otherwise adversely impact our operations or revenues.

We are subject to various federal, state and local laws and regulations. These laws and regulations govern safety, exploration, development, taxation and environmental matters that are related to the oil and natural gas industry. To conserve oil and natural gas supplies, regulatory agencies may impose price controls and may limit our production. Certain laws and regulations require drilling permits, govern the spacing of wells and the prevention of waste and limit the total number of wells drilled or the total allowable production from successful wells. Other laws and regulations govern the handling, storage, transportation and disposal of oil and natural gas and any by-products produced in oil and natural gas operations. These laws and regulations could materially adversely impact our operations and our revenues.

Laws and regulations that affect us may change from time to time in response to economic or political conditions. Thus, we must also consider the impact of future laws and regulations that may be passed in the jurisdictions where we operate. We anticipate that future laws and regulations related to the oil and natural gas industry will become increasingly stringent and cause us to incur substantial compliance costs.

 The nature of our operations exposes us to environmental liabilities.

Our operations create the risk of environmental liabilities. We may incur liability to governments or to third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. We could potentially discharge oil or natural gas into the environment in any of the following ways:

● from a well or drilling equipment at a drill site;

● from a leak in storage tanks, pipelines or other gathering and transportation facilities;

● from damage to oil or natural gas wells resulting from accidents during normal operations; or

● from blowouts, cratering or explosions.

Environmental discharges may move through the soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to obtain the proper permits for, to control the use of, or to notify the proper authorities of a hazardous discharge. Such liability could have a material adverse effect on our financial condition and our results of operations and could possibly cause our operations to be suspended or terminated on such property.

We may also be liable for any environmental hazards created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. Such liability would affect the costs of our acquisition of those properties. In connection with any of these environmental violations, we may also be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable.

We could lose or fail to attract the personnel necessary to run our business.

Our success depends, to a large extent, on our ability to attract and retain key management and operating personnel. As we develop additional capabilities and expand the scope of our operations, we will require more skilled personnel. Recruiting personnel for the oil and gas industry is highly competitive. We may not be able to attract and retain qualified executive, managerial and technical personnel needed for our business. Our failure to attract or retain qualified personnel could delay or result in our inability to complete our business plan.

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Our directors may experience conflicts of interest which may detrimentally affect our profitability.

Certain directors and officers may be engaged in, or may in the future be engaged in, other business activities on their own behalf and on behalf of other companies and, as a result of these and other activities, such directors and officers may become subject to conflicts of interest, which could have a material adverse effect on our business.

Risks Related to Our Common Stock

The trading price of our common stock may be volatile.

The price of our common shares may increase or decrease in response to a number of events and factors, including: trends in the oil and gas markets in which we operate; changes in the market price of oil and gas; current events affecting the economic situation in North America; changes in financial estimates; our acquisitions and financings; quarterly variations in our operating results; the operating and share price performance of other companies that investors may deem comparable; and purchase or sale of blocks of our common shares. These factors, or any of them, may materially adversely affect the prices of our common shares regardless of our operating performance.

A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.

A decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise additional capital for our operations. Because our operations to date have been largely financed through the sale of equity securities, a decline in the price of our common stock could have an adverse effect upon our liquidity and our continued operations. A reduction in our ability to raise equity capital in the future could have a material adverse effect upon our business plan and operations, including our ability to continue our current operations.

Our stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations and FINRA’s sales practice requirements, which may limit a stockholder’s ability to buy and sell our stock.

Our common stock will be subject to the “Penny Stock” Rules of the SEC, which will make transactions in our common stock cumbersome and may reduce the value of an investment in our common stock.

Our common stock is quoted on the OTC Bulletin Board, which is generally considered to be a less efficient market than markets such as NASDAQ or the national exchanges, and which may cause difficulty in conducting trades and difficulty in obtaining future financing. Further, our securities will be subject to the “penny stock rules” adopted pursuant to Section 15(g) of the Exchange Act. The penny stock rules apply generally to companies whose common stock trades at less than $5.00 per share, subject to certain limited exemptions. Such rules require, among other things, that brokers who trade “penny stock” to persons other than “established customers” complete certain documentation, make suitability inquiries of investors and provide investors with certain information concerning trading in the security, including a risk disclosure document and quote information under certain circumstances. Many brokers have decided not to trade “penny stock” because of the requirements of the “penny stock rules” and, as a result, the number of broker-dealers willing to act as market makers in such securities is limited. In the event that we remain subject to the “penny stock rules” for any significant period, there may develop an adverse impact on the market, if any, for our securities. Because our securities are subject to the “penny stock rules”, investors will find it more difficult to dispose of our securities. Further, it is more difficult: (i) to obtain accurate quotations, (ii) to obtain coverage for significant news events because major wire services, such as the Dow Jones News Service, generally do not publish press releases about such companies, and (iii) to obtain needed capital.

In addition to the “penny stock” rules promulgated by the SEC, FINRA has adopted rules that require a broker-dealer to have reasonable grounds for believing that an investment is suitable for a customer when recommending the investment to that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

We hold certain oil and gas interests, as described in Item 1 hereto. In addition, we rent office space at 800 Gessner, Suite 200, Houston, Texas, 77024 for $6,900 per month and at 545 N. Upper Broadway, Suite 900, Corpus Christi, Texas, 78401 for $3,200 per month.  In September 2013, we terminated our lease in Corpus Christi.

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ITEM 3.  LEGAL PROCEEDINGS

As of July 31, 2013, we were party to the following legal proceedings:

1.         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 Duma is liable to pay the charges in the below-mentioned case and a portion of ERG’s attorney fees. Duma is in the process of post-trial motions and no judgment has been entered as of this date.

2.         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. 

ITEM 4.  MINE SAFETY DISCLOSURE

Not applicable. 

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Shares of our common stock became quoted on the OTC Bulletin Board under the symbol “SGCA” on August 14, 2008.  On May 17, 2012, in connection with our name change, our symbol changed to “DUMA”.

The following tables set forth the high and low bid price per share of our common stock, as quoted on the OTC Bulletin Board, for fiscal 2012 and OTCQB, a marketplace for U.S. reporting companies operated by OTC Markets Group, for fiscal 2013. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not represent actual transactions.  We do not have any securities that are currently traded on any other exchange or quotation system.

Quarter Ended	High		Low
July 31, 2013	$	2.75	$	1.86
April 30, 2013	$	2.25	$	1.95
January 31, 2013	$	2.25	$	1.52
October 31, 2012	$	2.49	$	1.41
July 31, 2012	$	2.50	$	1.27
April 30, 2012	$	3.95	$	1.73
January 31, 2012	$	2.98	$	1.88
October 31, 2011	$	3.50	$	2.00

Holders

As of November 12, 2013, we had 88 shareholders of record.

Dividend Policy

No dividends have been declared or paid on our common stock. We have incurred recurring losses and do not currently intend to pay any cash dividends in the foreseeable future.

Securities Authorized For Issuance Under Compensation Plans

The following table sets forth information as of July 31, 2013:

Equity Compensation Plan Information

	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
(a)     Equity compensation plans approved by security holders		N/A	$	N/A		N/A
(b)     Equity compensation plans not approved by security holders
1.     2013 Stock Incentive Plan		1,536,000	$	2.38		1,410,407
2.     Compensation Warrants		2,544,520	$	2.50		N/A

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2013 Stock Incentive Plan

During February 2013, the Board of Directors authorized and approved the adoption of the 2013 Stock Incentive Plan (2013 Plan). An aggregate of 2,650,000 shares of common stock may be issued under the 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.

An award may not be exercised after the termination date of the award and may be exercised following the termination of an eligible participant’s continuous service only to the extent provided by the administrator under the 2013 Plan. If the administrator under the 2013 Plan permits a participant to exercise an award following the termination of continuous service for a specified period, the award terminates to the extent not exercised on the last day of the specified period or the last day of the original term of the award, whichever occurs first. In the event an eligible participant’s service has been terminated for “cause”, he or she shall immediately forfeit all rights to any of the awards outstanding.

The foregoing summary of the 2013 Plan is not complete and is qualified in its entirety by reference to the 2013 Plan, a copy of which is filed herewith.

During the year ended July 31, 2013, we granted 600,000 options to purchase shares of our common stock under the 2013 Plan.  During the year ended July 31, 2013, 108,000 options to purchase shares of our common stock expired unexercised, which increased the number of shares available to be issued under the 2013 Plan.

Recent Sales of Unregistered Securities

Other than listed below, we have previously disclosed in our Quarterly Reports on Form 10-Q and/or Current Reports on Form 8-K all unregistered equity securities that we issued during our fiscal year ended July 31, 2013.

On February 11, 2013, we granted stock options to purchase an aggregate of 600,000 shares of our common stock to three of our directors.  The options are exercisable at a price of $2.20 per share for a period of ten years, expiring on February 11, 2023.  When granted, the options were subject to the following vesting schedule:  1/5 of such options to vest on each day that is six, 12, 18, 24 and 30 months from February 11, 2013.  The grant of options was exempt from the registration requirements under the Securities Act pursuant to Rule 506 of Regulation D.  In October 2013, we determined to accelerate the vesting of such options, such that all such options that had not yet vested became fully vested in October 2013.

Subsequent to our fiscal year ended July 31, 2013, as disclosed in our Current Report on Form 8-K as filed with the SEC on November 5, 2013, we issued 1,859,879 common shares to one creditor in connection with debt settlement.  This issuance was exempt from the registration requirements under the Securities Act pursuant to Rule 506 of Regulation D.

ITEM 6. SELECTED FINANCIAL DATA

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition, changes in financial condition, plan of operations and results of operations should be read in conjunction with (i) our audited consolidated financial statements as at July 31, 2013 and 2012 and (ii) the section entitled “Business”, included in this annual report. The discussion contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under “Risk Factors” and elsewhere in this annual report.

Executive Summary

To put into context the accomplishments of the last fiscal year, the following table shows the comparison for the last four years in certain key areas. Our focus, managerially, is on building revenue and cash flow. Our acquisition strategy will be driven by these same two criteria. We believe that shareholder returns and value will be most enhanced, at least in the short term, by focusing on increasing both revenue and cash flow.

(in 1,000,000’s)	2010			2011			2012			2013
Revenue		0.53			3.41			7.17			7.07
Cash Flow From Operations		(2.63	)		(2.27	)		0.63			0.44
Total Assets		2.53			16.94			25.78			26.28
Net Loss		(3.49	)		(10.29	)		(4.58	)		(40.47	)
Total Stockholders’ Equity		0.28			6.63			12.30			9.37

Recent Highlights:

• Acquired new aerial gravity magnetic survey data over entire 5.3 million acre concession in Namibia, Africa.

• Partially completed first project of multi-well development program in Galveston Bay, averaging between approximately 60 barrels of oil per day.

• Eliminated more than $3 million of liability from the books by issuing stock to Hydrocarb.

• Hired Chuck Dommer as President to spearhead the operations and exploration efforts domestically and internationally.

• Shut-down offices in Corpus Christi and eliminated redundant personnel. Cost savings are estimated to be approximately $30,000 monthly.

Near Term Focus and Plans:

• Continue multi-well development program in Galveston Bay to enhance production, cash flow and reserves.

• Seek new partner to assist in financing new 2D seismic acquisition program in Namibia.

• Add new independent directors that can enhance our growth opportunities and expand the Company’s influence.

• Up-list to either NASDAQ or NYSE MKT stock markets to maximize liquidity and access to capital.

• Negotiate acquisition of Hydrocarb in order to better maximize shareholder value and gain operational synergy.

Plan of Operations

In Galveston Bay, Texas we plan to continue enhancing the production from our four productive fields. Our development program includes primarily reworking, infrastructure improvements, and recompletions, as well drilling, as to exploit the known reserves in at least 18 wells. Internal estimates show the projects, if successful, can almost quadruple current production enhancing cash flow significantly. Due to the fact that a large proportion of current operating costs in Galveston Bay are fixed it is expected that as production grows an increasing percentage of the revenue will contribute to positive cash flow. We plan to fund these projects as long as working capital and cash-flow permits and pending success of previous projects. If we are able to secure either bank or equity financing in the near future, this development plan can be accelerated.

In Namibia, Africa, in conjunction with the operator, Hydrocarb Energy Corp., we plan to interpret the newly acquired aerial gravity magnetic survey data and develop the acquisition plan for new 2D seismic data over the concession. This will include seeking a new partner that will, at least partially, carry us through the seismic acquisition program. 3D seismic will later be utilized for those identified structures which appear most prospective. Drilling of the first well is several years away. In the meanwhile, our goals are to increase the value and decrease the risk profile of our concession acreage in Namibia. Along these lines, Hydrocarb has engaged Netherland Sewell and Associates to conduct a resource estimate to confirm our belief that the concession could contain at least one billion barrels of oil.

19

Results of Operations

The following table sets out our consolidated losses for the periods indicated:

	Year Ended July 31,						Increase/			2012%
	2013			2012			(Decrease)			change
Revenues	$	7,070,540		$	7,165,233		$	(94,693	)	$	(1	)%
Operating expenses
Lease operating expense		4,560,201			4,013,083			547,118			14	%
Depreciation, depletion, and amortization		1,085,980			1,021,981			63,999			6	%
Accretion		1,056,508			943,508			113,000			12	%
Consulting fees – related party		196,384			189,372			7,012			4	%
Acquisition-related costs – related party		37,234,752			4,367,750			32,867,002			752	%
General and administrative expense		3,298,376			3,852,722			(554,346	)		(14	)%
Total operating expenses		47,432,201			14,388,416			33,043,785			230	%
Loss from operations		(40,361,661	)		(7,223,183	)		(33,138,478	)		459	%
Interest expense, net		(499,360	)		(157,964	)		(341,396	)		216	%
Net gain (loss) on sale of available-for-sale securities		(793,247	)		463,117			(1,256,364	)		(271	)%
Gain on derivative warrant liability		1,056,224			1,217,835			(161,611	)		(13	)%
Net loss before income tax		(40,598,044	)		(5,700,195	)		(34,897,849	)		612	%
Income tax benefit		122,949			1,120,471			(997,522	)		(89	)%
Net loss	$	(40,475,095	)	$	(4,579,724	)	$	(35,895,371	)		784	%

We recorded a net loss of $40,475,095, or $3.11 per basic and diluted common share, during the fiscal year ended July 31, 2013, as compared to a net loss of $4,579,724, or $0. 45 per basic and diluted common share, during the fiscal year ended July 31, 2012.

The changes in results were predominantly due to the factors below:

· Revenues decreased due to lower oil prices and to lower gas volumes produced in the current fiscal year in comparison to fiscal 2012.

· Lease operating expenses increased primarily due to the resumption of operations in one of our fields in Galveston Bay at the end of April 2012.  Because it was shut in during the majority of the year ended July 31, 2012 and it was operating during the entire year ended July 31, 2013, costs were lower in 2012.

· Depreciation, depletion, and amortization increased because of an increase in the amortization rate, which was attributable to a reduction in estimated reserves in our reserve study dated July 31, 2013.

· Accretion increased because of an increase in the estimated asset retirement obligation due to change in estimates which occurred during the year ended July 31, 2013.

· Consulting fees – related party pertain to warrants granted as compensation to a company for investor relations and public relations services.  This company is a related party, as it is controlled by the father-in-law of our CEO, Jeremy Driver.  The warrant grant occurred in April 2011 and consisted of immediately vesting warrants and warrants that vest in accordance with a market condition. The warrants that vested immediately were valued using the Black-Sholes option pricing method and the expense was recognized on the vesting date.  The warrants with a market condition are valued using a lattice model and the expense is amortized over the service period.  See Note 9 – Capital Stock for more information about these warrants.

· Acquisition related costs – related party: During the year ended July 31, 2013, we incurred $37,234,752 of expense in conjunction with our acquisition of NEI. The transaction, which is a related party transaction, is discussed in detail in Note 2 of our Consolidated Financial Statements. This charge is the most significant difference in the results of operations from the comparable period in fiscal 2012. 2,490,000 shares of common stock were issued to the sellers of NEI and up to 22,410,000 additional shares of Duma common stock may be issued based on the achievement of certain market conditions over the next ten years. The estimated fair value of our commitment to issue the 22,410,000 shares was charged to expense as of the date of the transaction as required by relevant accounting standards. The estimated fair value of the contingently issuable shares was $31,612,000, the bulk of the charge. During the year ended July 31, 2012, we incurred an expense of $4,367,750 due to the excess of the fair value of the purchase price of SPE over the carrying value in the net assets acquired in the SPE acquisition, which was a separate related party transaction involving similar parties.

· Our decrease in general and administrative expenses is primarily attributable to a one-time stock grant, which resulted in approximately $600,000 of expense, which occurred during the year ended July 31, 2012.   In addition, we experienced a decrease in legal, compliance, and professional expenses due to a general decrease in litigation during the current year. The decrease in expense was offset by an approximately $300,000 increase in the expenses associated with a compensation package, which included stock option grants and cash compensation, for independent directors that was adopted in February 2013.

20

· We incurred a loss on the sale of securities during the year ended July 31, 2013 due to the sale of securities that had declined in value since the time of acquisition. During the comparable year in 2012, we sold securities at a gain.

· We re-measured our derivative warrants at fair value at every reporting date until the derivative feature expired in October and November 2012. Change in the fair value of the derivative warrants, as determined using a lattice model, during the year ending July 31, 2013 was lower compared to the change in fair value for year ended July 31, 2012, which resulted in a minor decrease in the gain recognized.

 · We recognized an income tax benefit during the year ended July 31, 2012 due to the ability to use tax assets, which had previously been reserved, because of a tax gain generated by the gain on sale of securities that had been acquired with the purchase of SPE and which had a significant built in capital gain when they were acquired.  Our actual tax expense for fiscal 2012, based on tax returns completed during fiscal 2013, was lower than our estimate, which caused a further tax benefit in 2013.  Since the tax benefit arose because we had acquired deferred tax liability in a business combination, we do not expect to reflect future tax benefits.

We consider the increase in acquisition-related costs-related party to be one time and non-recurring. We do not hold available of sale securities as of the year ended July 31, 2013 and as such we do not expect any further gains or losses attributable to available for sale securities. We consider the rest of the elements to be ongoing and part of our normal operations.

The following table sets forth our cash and working capital as of July 31, 2013 and July 31, 2012:

	July 31, 2013			July 31, 2012
Cash reserves	$	317,881		$	1,102,987
Working capital (deficit)	$	(4,182,058	)	$	(1,865,472	)

Subject to the availability of additional financing, in order to maximize production from our Galveston Bay properties, we plan approximately $2.4 million in capital expenditures in the next 12 months on the properties to include upgrading production facilities, new flowlines, recompletion of existing shut-in wells, and other projects aimed specifically at increasing production.

At July 31, 2013, we had $317,881 of cash on hand and a working capital deficit of $4,182,058. As such, our working capital alone on July 31, 2013 was insufficient to enable us to pay our lease operating costs, to pay our general and administrative expenses, and to also pursue our plan of operations over the next 12 months. Subsequent to July 2013, we settled approximately $1.8 million of the current liabilities then outstanding with the issuance of common stock.  Additionally, our cash flow from operations has improved due to the partial completion of the first project in our multi-well development plan, and we believe it, in conjunction with the possible sale of some of our producing properties, will support the payment of outstanding obligations as well as our general and administrative expenses.

Our plan of operations over the next twelve months is dependent, at least in part, upon one or more of the following occurring:

1. Raising capital through the sale of equity;

2. Raising capital through the sale of working interest in our producing properties;

3. Borrowing money from lenders to perform the work;

4. Freeing up previously restricted cash (State bonding requirement) as shut-in wells are brought back into production and/or as wells are plugged;

5. Performing work one project at a time (capital permitting) and using the increased cash flow to fund the next projects.

Our plan of operations over the next twelve months will always be subject to available capital which will be determined by the success of projects that are currently in progress or will begin soon. It is even possible that given a high degree success in recently initiated projects and upcoming projects we could actually exceed our planned operations and have more internally-derived funds available for capital expenditures for the next 12 months. As management, we will determine the best use of our capital given the circumstances at the time.

Various conditions outside of our control may detract from our ability to raise the capital needed to execute our plan of operations, including the price of oil as well as the overall market conditions in the international and domestic economies. We recognize that the United States economy and others have suffered through a period of uncertainty during which the capital markets have been highly volatile, and that there is no certainty that these markets will stabilize or improve. We also recognize that the price of oil decreased from approximately $140 per barrel in 2008 to under $40 per barrel in February of 2009. If the price of oil drops to levels seen in previous years, we recognize that it will adversely affect our cash flow from operations and our ability to raise additional capital. Any of these factors could have a material adverse impact upon our ability to raise capital or obtain financing and, as a result, upon our short-term or long-term liquidity.

21

Net Cash Provided by Operating Activities

During the year ended July 31, 2013, net cash provided by operating activities was $438,707 compared to net cash provided by operating activities of $626,076 during the year ended July 31, 2012.

Net Cash Provided by (Used in) Investing Activities

During the year ended July 31, 2013, we used cash of $951,841in investing activities compared to cash provided of $858,287 during the year ended July 31, 2012. . The use of cash in 2013 primarily consisted of investment in oil and gas assets. Investing activities during fiscal 2012 consist primarily of proceeds from the sale of available for sale securities, offset by the purchase of oil and gas properties.

Net Cash Used in Financing Activities

Financing activities during the year ended July 31, 2013 used cash of $271,972 compared to $1,463,475 used during the year ended July 31, 2012.  This was primarily attributable to repayments of notes payable during the both these years.

Critical Accounting Policies

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 preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.

We regularly evaluate the accounting policies and estimates that we use to prepare our consolidated financial statements. In general, our estimates are based on historical experience, on information from third party professionals, and on various other assumptions that are believed to be reasonable under the facts and circumstances. Actual results could differ from those estimates made by management.

We believe that our critical accounting policies and estimates include the accounting for oil and gas properties, long-lived assets reclamation costs, the fair value of our warrant derivative liability, and accounting for stock-based compensation.

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.

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, 2013 and 2012, the ceiling exceeded the net book value of the property and it was not necessary to record an impairment charge.

22

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.

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.

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.” These warrant agreements include provisions designed to protect holders from a decline in the stock price (‘down-round’ provision) by reducing the exercise price in the event we issue equity shares at a price lower than the exercise price of the warrants.  As a result of this down-round provision, the exercise price of these warrants could be modified based upon a variable that is not an input to the fair value of a ‘fixed-for-fixed’ option as defined under FASB ASC Topic No. 815-40 and consequently, these warrants must be treated as a liability and recorded at fair value at each reporting date.

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 (loss) 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, 2013.

The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013 and 2012:

	2013			2012
Beginning of the period	$	1,325,388		$	2,543,223
Expiration of derivative warrant feature		(269,164	)		—
Unrealized gain on changes in fair value of derivative liability		(1,056,224	)		(1,217,835	)
End of the period	$	—		$	1,325,388

23

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 anti-dilution provisions expire three years after the issuance of the warrants. Accordingly, the provision for warrants to purchase 408,065 and 206,400 shares of common stock expired on October 15, 2012 and November 13, 2012, respectively. As of each those dates, the fair value of the warrant was determined for a final mark to market adjustment and the outstanding warrant derivative liability was reclassified to additional paid-in capital, as the warrants were no longer derivatives.

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 date the 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.

See Note 1 of our Consolidated Financial Statements for our year ended July 31, 2013 for a summary of other significant accounting policies.

Off-Balance Sheet Arrangements

We have not entered into any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes of financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.  See Note 12 of our Consolidated Financial Statements for a description of our multi-year commitments.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.

24

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

DUMA ENERGY CORP.

Index to Consolidated Financial Statements

TABLE OF CONTENTS

Report of Independent Registered Public Accounting Firm	26
Consolidated Balance Sheets as of July 31, 2013  and 2012	27
Consolidated Statements of Operations and Comprehensive Loss for the years ended July 31, 2013 and 2012	28
Consolidated Statements of Changes in Stockholders’ Equity for the years ended July 31, 2013 and 2012	29
Consolidated Statements of Cash Flows for the years ended July 31, 2013 and  2012	30
Notes to Consolidated Financial Statements	32

25

The Board of Directors

Duma Energy Corp.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Duma Energy Corp. and its subsidiaries (collectively, the “Company”) as of July 31, 2013 and 2012 and the related consolidated statements of operations and comprehensive loss, cash flows and changes in stockholders’ equity for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatements. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Duma Energy Corp. and its subsidiaries as of July 31, 2013 and 2012, and the results of their operations and their cash flows for each of the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ MaloneBailey, LLP

www.malone-bailey.com

Houston, Texas

November 12, 2013

26

DUMA ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

	July 31,
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	317,881		$	1,102,987
Oil and gas revenues receivable		725,691			457,567
Accounts receivable – related party		176,773			117,618
Available for sale securities		–			313,446
Other current assets		333,136			256,677
Other receivables, net		23,730			517,441
Total current assets		1,577,211			2,765,736
Oil and gas properties, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $2,617,478 and $1,557,675, respectively; and accumulated impairment of $373,335 and $373,335, respectively		16,867,029			15,622,826
Unevaluated property		713,655			265,639
Restricted cash		6,920,739			6,890,000
Other assets		180,726			190,259
Property and equipment, net of accumulated depreciation of $62,749 and $36,572, respectively		19,792			45,969
Total assets	$	26,279,152		$	25,780,429
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued expenses	$	3,779,401		$	2,298,838
Line of credit		–			300,000
Current portion of notes payable		1,059,644			102,025
Asset retirement obligation – short term		724,374			549,796
Derivative warrant liability		–			1,325,388
Advances		180,804			55,161
Due to related parties		15,046			–
Total current liabilities		5,759,269			4,631,208
Notes payable		942,992			11,678
Asset retirement obligation – long term		10,209,024			8,833,137
Total liabilities		16,911,285			13,476,023
Commitments and contingencies
Stockholders’ equity:
Common stock, $.001 par; 500,000,000 authorized shares; 13,281,003 and 10,791,003 shares issued and outstanding in 2013 and 2012, respectively		13,281			10,791
Additional paid-in capital		75,756,801			38,963,817
Accumulated other comprehensive income		–			(743,082	)
Accumulated deficit		(66,402,215	)		(25,927,120	)
Total stockholders’ equity		9,367,867			12,304,406
Total liabilities and stockholders’ equity	$	26,279,152		$	25,780,429

 The accompanying notes are an integral part of these consolidated financial statements

27

DUMA ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

	Years Ended July 31,
`	2013			2012
Revenues	$	7,070,540		$	7,165,233
Operating expenses
Lease operating expense		4,560,201			4,013,083
Depreciation, depletion, and amortization		1,085,980			1,021,981
Accretion		1,056,508			943,508
Consulting fees – related party		196,384			189,372
Acquisition-related costs – related party		37,234,752			4,367,750
General and administrative expense		3,298,376			3,852,722
Total operating expenses		47,432,201			14,388,416
Loss from operations		(40,361,661	)		(7,223,183	)
Interest expense, net		(499,360	)		(157,964	)
Net gain (loss) on sale of available for sale securities		(793,247	)		463,117
Gain on derivative warrant liability		1,056,224			1,217,835
Net loss before income taxes		(40,598,044	)		(5,700,195	)
Income tax benefit		122,949			1,120,471
Net loss	$	(40,475,095	)	$	(4,579,724	)
Other comprehensive loss, net of tax:
Change in market value of available for sale securities, including unrealized loss and reclassification adjustments to net income, net of  income tax of $0 and $0		–			(743,082	)
Comprehensive Loss	$	(40,475,095	)	$	(5,322,806	)
Basic and diluted loss per common share	$	(3.11	)	$	(0.45	)
Weighted average shares outstanding (basic and diluted)		13,028,592			10,218,355

The accompanying notes are an integral part of these consolidated financial statements

28

DUMA ENERGY CORP.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

	Common Stock				Additional Paid-in		Accumulated Other Comprehensive			Accumulated
	Shares		Amount		Capital		Loss			Deficit			Total
Balance at July 31, 2011		6,790,816	$	6,791	$	27,970,520	$	—		$	(21,347,396	)	$	6,629,915
Common stock issued for:
Services and for investor relations		200,189		200		619,955		—			—			620,155
Acquisition of SPE Navigation I, LLC		3,799,998		3,800		9,496,200		—			—			9,500,000
Share-based compensation:
Amortization of fair value of stock options		—		—		687,770		—			—			687,770
Warrants granted to related party		—		—		189,372		—			—			189,372
Unrealized loss on available for sale securities		—		—		—		(743,082	)		—			(743,082	)
Net loss		—		—		—		—			(4,579,724	)		(4,579,724	)
Balance at July 31, 2012		10,791,003	$	10,791	$	38,963,817	$	(743,082	)	$	(25,927,120	)	$	12,304,406
Common stock issued for:
Acquisition of  Namibia Exploration, Inc,		2,490,000		2,490		35,394,310		—			—			35,396,800
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
Net loss		—		—		—		—			(40,475,095	)		(40,475,095	)
Balance at July 31, 2013		13,281,003	$	13,281	$	75,756,801	$	—		$	(66,402,215	)	$	9,367,867

On April 4, 2012, the Company effected a one-for-25 reverse stock split. All share and per share amounts have been retroactively restated to reflect the reverse split.

The accompanying notes are an integral part of these consolidated financial statements

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DUMA ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended July 31,
	2013			2012
Cash Flows From Operating Activities
Net loss	$	(40,475,095	)	$	(4,579,724	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		1,085,980			1,021,981
Accretion		1,056,508			943,508
Change in allowance for doubtful accounts		57,491			(26,563	)
Change in deferred taxes		—			(130,200	)
(Gain) loss on sale of available for sale securities		517,920			(463,117	)
Impairment of available for sale of securities		275,327			—
Warrants granted to related party		196,384			189,372
Common stock granted for services and for investor relations		—			620,155
Acquisition-related costs – related party		37,234,752			4,367,750
Share based compensation- amortization of the fair value of  stock options		933,126			687,770
Gain on derivative warrant liability		(1,056,224	)		(1,217,835	)
Changes in operating assets and liabilities:
Accounts receivable		168,096			197,885
Advances		125,643			55,161
Accounts payable and accrued expenses		491,956			(948,070	)
Settlement of asset retirement obligations		(318,225	)		(178,539	)
Accounts receivable – related party		(44,109	)		(47,738	)
Other assets		189,177			134,280
Net cash provided by operating activities		438,707			626,076
Cash Flows From Investing Activities
Purchases of oil and gas properties		(1,379,946	)		(2,221,242	)
Purchases of property and equipment		—			(66,847	)
Change in restricted cash		(30,739	)		(160,213	)
Purchase of available for sale securities		(24,593	)		(702,959	)
Proceeds from sale of available for sale securities		287,874			4,009,548
Proceeds from sale of oil and gas properties		195,563			—
Net cash provided by (used in) investment activities		(951,841	)		858,287
Cash Flows From Financing Activities
Proceeds from notes payable		—			300,000
Payments on notes payable		(271,972	)		(1,748,752	)
Payments on notes payable to related parties		—			(14,723	)
Net cash used in financing activities		(271,972	)		(1,463,475	)
Net increase (decrease) in cash		(785,106	)		20,888
Cash at beginning of period		1,102,987			1,082,099
Cash at end of period	$	317,881		$	1,102,987

 The accompanying notes are an integral part of these consolidated financial statements

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DUMA ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

	Years Ended July 31,
	2013		2012
Supplemental Disclosures:
Interest paid in cash	$	207,269	$	38,129
Income taxes paid in cash	$	42,483		4,847
Non-cash investing and financing
Accounts payable for oil and gas assets	$	188,607	$	244,793
Asset retirement obligation purchased		—		97,374
Asset retirement obligation – change in estimate		786,120		1,827,889
Asset retirement obligation incurred		26,500		1,389
Asset retirement obligation sold		438		32,772
Acquisition of SPE Navigation I, LLC for Duma common stock, including asset retirement obligation assumed of $2,268,156		—		5,132,250
Adjustment of purchase price of acquisition: environmental liability acquired		—		112,500
Acquisition of Namibia Exploration, Inc.		562,048		—
Unrealized loss on available for sale securities		—		743,082
Note payable for purchase of vehicle		—		18,027
Note payable for prepaid insurance		260,905		227,912
Expiration of derivative warrant liability		269,164		—

The accompanying notes are an integral part of these consolidated financial statements

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 DUMA ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Description of Business and Summary of Significant Accounting Policies

Description of business and basis of presentation

Duma Energy Corp. (“we”, “us”, “Duma”, the “Company”) was formed for the purpose of oil and gas exploration, development, and production. We own 100% of Penasco Petroleum Inc. (“Penasco”), a Nevada corporation incorporated on November 23, 2005 and 100% of Galveston Bay, LLC, (“GBE”), a Texas limited liability company, 100% of SPE Navigation I, LLC (“SPE”) a Nevada limited liability company and 100% of Namibia Exploration, Inc. (“NEI”) a Nevada corporation.  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”).

Reclassifications

Certain prior year amounts have been reclassified to conform with the current presentation.

Principles of consolidation

The accompanying consolidated financial statements include the accounts of Duma and our wholly owned subsidiaries, Penasco, SPE, GBE and NEI. 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 which 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.

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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 the Chief Financial Officer and the Chief Executive Officer.

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, 2013 and 2012, we have reserved $58,585 and $1,302, 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, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable. For the year ended July 31, 2012, 67% of our revenue was attributable to one purchaser.  At July 31, 2012, this same purchaser accounted for 79% 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.

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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, 2013 and July 31, 2012, 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, 2013 and 2012, restricted cash totaled $6,920,739 and $6,890,000, respectively.

Other assets

Other assets at July 31, 2013 and 2012 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, 2013 and 2012, respectively.

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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, 2013 and 2012, advances totaled $180,804 and $55,161, 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 valorum 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, 2013 and our derivative warrant liability was our only financial asset or liability that was accounted for at fair value, using a Level 3 valuation technique, on a recurring basis as of July 31, 2012. 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.

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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 April 4, 2012, we effected a 1-for-25 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, 2013 and 2012, 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 12 - 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. The components of accumulated other comprehensive loss:

	Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss at July 31, 2012	$	(743,082	)
Reclassification into earnings		743,082
Accumulated other comprehensive loss at July 31, 2013	$	—

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Recent accounting pronouncements

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.

Note 2 – Acquisitions

SPE Navigation I, LLC

On September 23, 2011, Duma acquired SPE, which owned 25% of the working interest in the oil and gas properties originally owned by Galveston Bay Energy, LLC and 1,000,000 shares of Hyperdynamics Corporation, a public company traded on the New York Stock Exchange (NYSE:HDY). The total purchase price consisted of 3,799,998 shares of Duma’s common stock. We acquired 100% of the membership interest in SPE and thus SPE is our wholly owned subsidiary.

The transaction was a related party transaction because SPE was owned by companies controlled by our CEO, his brother-in-law, and his sister-in-law, and SPE was managed by our CEO’s father-in-law. The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition. The assets and liabilities were recorded at fair value on the date of the acquisition, $5,132,250.  The excess purchase price over the net assets acquired was $4,367,750, which was recorded as an acquisition-related expense because this was a related party transaction.  

As of the acquisition date, the working interests previously owned by SPE were conveyed to GBE. Thus, all oil and gas revenues after the SPE acquisition were attributed to GBE.  Our consolidated statements for 2013 include the results of SPE, and accordingly the 100% acquired working interest, for the entire year.  Our consolidated statements for 2012 include the results of SPE after September 23, 2011.

Supplemental pro forma information (unaudited)

The unaudited pro forma results presented below for the year ended July 31, 2012 have been prepared to give effect to the purchase of SPE as if it had been consummated on August 1, 2011.  The unaudited pro forma results do not purport to represent what our results of operations actually would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.

Revenues	$	7,313,232
Loss from operations		(7,419,747	)
Net loss		(4,776,288	)
Loss per share, basic and diluted		(0.47	)

Namibia Exploration, Inc.

On August 7, 2012, we entered into a Share Exchange Agreement (the “Agreement”), which was closed on September 6, 2012, under which we purchased Namibia Exploration, Inc. ("NEI"), a corporation organized under the laws of the state of Nevada for the issuance of up to 24,900,000 shares of our common stock as described below.  Prior to the acquisition, NEI was directly and indirectly owned and controlled by the CEO, his brother-in-law, and his father-in-law. As a result, the acquisition was accounted for as an asset purchase from an entity under common control and the asset was recorded at NEI’s historical cost.  NEI originally acquired the concession from a subsidiary of Hydrocarb Corporation (“Hydrocarb”) in exchange for a farm-in fee, as discussed below, totaling $2,400,000, payable over two years. Hydrocarb is partly owned by the uncle of the 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 Hydrocarb given that the concession was unproved, management concluded that Hydrocarb’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 provides for preferential offerings of other international oil and gas opportunities similar to the concession in Namibia.

NEI was formed in February 2012 and its sole asset was this oil and gas concession in Namibia, Africa. NEI had no operations other than ownership of this oil and gas concession; and accordingly, the transaction was accounted for as an asset purchase.  Duma has assumed payment of the fee, as described below.  Due to the fact that the former owners of NEI had no significant historical cost basis in NEI and the fact that the acquisition is accounted for as a related party transaction, the consideration that Duma paid beyond NEI’s cost basis ($562,048) is considered compensatory and thus an expense of the acquisition.  The consideration included stock granted at the closing of the transaction as well as series of stock grants that are 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.  $37,234,752 is reflected in our statement of operations as Acquisition-related costs – related party in conjunction with this transaction.

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As a result of the completion of the acquisition, NEI became a wholly-owned subsidiary of Duma. NEI holds the rights to 39% working interest (43.33% cost responsibility) in an onshore petroleum concession (the “Concession"), located in the Republic of Namibia, 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.

The assignment of the 39% working interest to NEI from Hydrocarb Namibia, the operator of the concession, is subject to the prior approval of the government of the Republic of Namibia, which was obtained during August 2012. Duma now holds working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. ("NPC Namibia") and Hydrocarb Namibia Energy Corporation ("Hydrocarb Namibia"), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation ("Hydrocarb"), a company organized under the laws of the State of Nevada. Hydrocarb Namibia, as operator of the Concession, now holds at 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now holds a 10% carried working interest in the Concession.  We have entered into a joint operating agreement with Hydrocarb Namibia effective August 29, 2012, that covers operations for the Concession.

Consideration for the acquisition of NEI

Pursuant to the terms of the Agreement, Duma issued 2,490,000 shares of common stock in September 2012 at the closing.  Additional shares are required to be issued as consideration for the Acquisition, in accordance with the following milestones which must be reached within 10 years after the closing of the acquisition:

(a) a further 2,490,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $82,000,000;

(b) a further 7,470,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $196,000,000; and

(c) a further and final 12,450,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $434,000,000.

Duma will maintain 100% ownership of NEI after Closing even if one or more of the market capitalization milestones have not been attained within 10 years from the Closing.  The accounting for this stock award is discussed in the section “Valuation” below.

Hydrocarb agreement

In conjunction with the execution of the Agreement, and as a condition of Closing, Duma has entered into a Consulting Services Agreement with Hydrocarb (the "Consulting Agreement"), whereby Hydrocarb will provide various consulting services with respect to Duma's business ventures in Namibia and whereby Hydrocarb has acknowledged and agreed that the obligations of NEI under its existing Farmin Opportunity Report with Hydrocarb (the "FOR") will be satisfied in exchange for Duma paying a consulting fee (the "Fee") to Hydrocarb of $2,400,000 as follows:

(a) payment on the later of the effective date of the Consulting Agreement or 15 days from the receipt of the working interest assignment under the FOR to be processed by Hydrocarb to be signed by Namibia's Minister of Mines and Energy, by Duma to Hydrocarb of $800,000 in cash or stock (at a deemed conversion price which equates to the then previous 60-day volume-weighted average trading price of Duma's common stock) or a combination of cash and stock.  Duma has the sole and absolute discretion to select the manner of payment.

(b) for the remaining $1,600,000 by way of the issuance of a promissory note in favor of Hydrocarb in the principal amount of $1,600,000 (the "Promissory Note"), with interest accruing on the principal amount at the rate of 5% per annum, calculated semi-annually and payable in arrears, and of which $800,000 of the principal amount plus accrued interest is due on or before the first anniversary of the effective date and the remaining $800,000 of the principal amount plus accrued interest is due on or before the second anniversary of the effective date. Duma has the sole and absolute discretion to select whether payment of the note will be in stock (at a deemed conversion price which equates to the then previous 60-day volume-weighted average trading price of Duma's common stock), cash, or a combination of cash and stock.

Duma is required to pay a late fee of 10% per quarter for any outstanding balance of the Fee under the Consulting Agreement which will commence 30 calendar days from the date that the Fee or portion of the Fee is due, which may only be paid in cash. Duma has not yet paid the first installment as described in (a) above.  Thus, the fee, which totals $320,000 as of July 31, 2013, has been accrued and it is characterized as interest expense. The fee is included in the balance sheet caption “Accounts payable and accrued expenses”.

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Valuation

NEI’s cost basis in the concession is $562,048.  Since Duma acquired the liability due to Hydrocarb, Duma acquired a net liability of $1,837,952.  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 consists of the 2,490,000 shares that were awarded at closing, which were valued using the closing market price of the stock on the date of grant, and the contingent stock grant.  The fair value of equity compensation that vests upon the attainment of a market condition (in this case, market capitalization) must be estimated and recorded on the date of the grant.  The fair value of the 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 Duma and NEI, using multiple probability-weighted scenarios, and projections of Duma’s capital structure.

As of July 31, 2013, we had recognized $37,234,752 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 $31,612,000 associated with the contingent consideration.

Note 3 – Available for Sale Securities

Beginning in the quarter ended October 31, 2011, we owned marketable equity securities, which are classified as available for sale.

We acquired securities with a market value of $3,900,000 in conjunction with our acquisition of SPE. (See Note 2 – Acquisitions – SPE Navigation I, LLC). During the year ended July 31, 2012, we received cash proceeds of $4,009,548 from sales of securities with a cost basis of $3,546,431; thus, we had a realized gain on sale of available for sale securities of $463,117.  During the year ended July 31, 2012, we also 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, 2013, we do not hold any available for sale securities.

Note 4 – Oil and Gas Properties

Oil and natural gas properties as of July 31, 2013 and July 31, 2012 consisted of the following:

	July 31, 2013			July 31, 2012
Evaluated Properties
Costs subject to depletion, net of accumulated impairment of $373,355 and $373,355, respectively	$	19,484,507		$	17,180,501
Accumulated depletion		(2,617,478	)		(1,557,675	)
Total evaluated properties		16,867,029			15,622,826
Unevaluated properties		713,655			265,639
Net oil and gas properties	$	17,580,684		$	15,888,465

Evaluated properties

We incurred geological and geophysical costs of $157,818 during the year ended July 31, 2013.

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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, 2013 include:

● costs associated with a development well, the State Tract 9-12A#4 well in Galveston Bay totaling $447,511;

● costs for a recompletion in Galveston Bay totaling $361,372; and

● increase in asset retirement obligations of $803,788 primarily due to changes in timing and in estimated costs for the gathering systems located in Galveston Bay.

Onshore property

As of July 31, 2013, we owned interests in properties in Texas and Illinois as follows:

Illinois

We owned 10% working interest in multiple leases in or near Markham City, Illinois that are operated by Core Minerals Management II, LLC (“Core”) in accordance with a farmout agreement, which we entered into during January 2011. After payout of the property, $1,350,000 or 29,000 barrels, whichever comes first, provided that we hold less than 25% working interest in the property at payout, our working interest will be adjusted to 25%. During fiscal 2012, the operator drilled wells in the contract area and commenced a pilot waterflood project to re-pressurize the reservoir and enhance recovery of oil from the area. The wells in the project area produce oil.

Texas

We own 100% working interest and a 72.5% net revenue interest in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas.  There are two productive wells on the property, which was operated by a company owned by one of our former officers until September 1, 2013.  Effective September 1, 2013, we took over operations of the lease.

In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas (the “Palacios Lease”).  Under the agreement, the operator commenced drilling a well, the Palacios #1, during November 2011.  Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area.  Our net revenue interest in the prospect is 4.125%.  The well produces primarily gas.

In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas (the “Chapman Prospect”). According to the terms of the agreement, we would pay 31.25% of costs to casing point of the initial well and of the plug and abandonment costs if the initial well is a dry hole and 25% of costs after casing point. For subsequent wells, we would pay 25% of the costs before and after the casing point. The well was drilled in June 2012; however, the first completion zone was non-economic. $265,639 in costs, including acquisition costs of $58,805 and drilling costs of $206,834, were reflected as unevaluated property as of July 31, 2012. During October 2012, we participated in a recompletion operation which resulted in the completion of the well into an upper zone, however commercial production was not established. Another rework operation was attempted in June 2013, which was unsuccessful.  Because of the lack of success, management determined that there would be no reserves ascribed and the prospect is classified as evaluated as of the July 31, 2013.

During August 2012, we leased approximately 190 acres of land in Bee County, Texas (the “Curlee Prospect”).  The operator of the project was Carter E&P, a company owned by our former Vice President of Operations.  We had a 50% working interest in the project, 25% of which was carried to the casing point by the other participants in the initial well.  Because we took a 25% additional interest, the portion of the working interest that we pay, prior to the casing point, is 33.3%.  After the casing point and for all costs in future wells, we will be responsible for 50% of the costs. We paid $45,931 in acquisition and land costs for this prospect. We received a bonus of $51,589 from the other parties in the well, which was reflected as a reduction of capitalized costs in accordance with full cost accounting. During the quarter ended October 31, 2012, we drilled a well on the property, the Curlee No. 1 well, which was plugged and abandoned.

In December 2012, we acquired a 366.85 acre tract of property, the Dix Prospect, in San Patricio County, Texas. We paid $76,938 in acquisition and land costs. In February 2013, we sold 75% working interest in the prospect to partners on a third for a quarter basis, under which the 75% interest holders will carry 25% of the working interest to the casing point of the initial well drilled on the prospect. We also sold 2% of the carried working interest to Carter E&P, a company owned by our former Vice President of Operations. Thus we retained a 23% working interest which is carried to the casing point of the initial well. We received proceeds of $109,328 from the other parties in the prospect, which was reflected as a reduction of capitalized costs in accordance with full cost accounting. The initial well was drilled in May 2013, but it was determined that the well could not produce economically. Accordingly, it was not completed.

During April 2013, we purchased a 12.5% working interest in a 260.12 acre tract of property, the Melody Prospect, in Bee County, Texas.  The operator of the project is Carter E&P, a company owned by our former Vice President of Operations.  We incurred acquisition costs of $7,355 on the prospect. The well was drilled in June 2013 and it was a dry hole.

We incurred $210,588 of exploratory drilling costs during the year ended July 31, 2013 on the Chapman, Curlee, Dix, and Melody prospects.

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Effective September 1, 2013, we conveyed our interest in the Dix, Melody, Curlee, Palacios and Illinois 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.

Sales of properties

As of July 31, 2012, we owned a 6.25% overriding royalty interest in properties located in Franklin and Richland parishes in Louisiana (the “Holt” and “Strahan” properties).  We also had a note receivable from the sale of our working interests in these properties, which had been fully reserved.  In September 2012, we conveyed the overriding royalty interests to the operator and released the operator from any further liability from the note receivable in exchange for $50,000 cash.  We allocated the cash proceeds between the note receivable 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.

During 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.

We received proceeds of $160,917 in conjunction with sales of interest in the Dix and Curlee prospects, as described above.

Unevaluated Properties

Namibia, Africa.

In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa, as discussed in Note 2 – Acquisitions – Namibia Exploration, Inc.  This property is a 5.3 million-acre concession in northern Namibia in Africa.

We have incurred total costs of $713,655, including NEI’s cost basis at the time we acquired 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, conduct and environmental study. The minimum expenditure is $300,000.

As of July 31, 2013, approximately $900,000 has been expended towards the initial exploration period.

Note 5 - 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, 2013 and July 31, 2012, the net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.

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.

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Note 6 – Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2013 and 2012:

	2013			2012
Liability for asset retirement obligation, beginning of period	$	9,382,933		$	4,455,928
Asset retirement obligations assumed		—			2,365,530
Asset retirement obligations sold		(438	)		(32,772	)
Asset retirement obligations incurred on properties drilled		26,500			1,389
Accretion		1,056,508			943,508
Revisions in estimated cash flows		786,120			1,827,889
Costs incurred		(318,225	)		(178,539	)
Liability for asset retirement obligation, end of period	$	10,933,398		$	9,382,933
Current portion of asset retirement obligation	$	724,374		$	549,796
Noncurrent portion of asset retirement obligation		10,209,024			8,833,137
Total liability for asset retirement obligation	$	10,933,398		$	9,382,933

Note 7 – Notes Payable

Installment Notes Payable

In February 2012, we entered into a premium financing arrangement to pay principal of $209,244 in conjunction with our commercial insurance program renewal. We were obligated to make nine payments of $24,578 per month, which include principal and interest, beginning in March 2012. As of July 31, 2012, $96,252 remained unpaid on the note.  As of July 31, 2013, the note payable balance was $0.

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 $17,451 and $11,678 as of July 31, 2012 and July 31, 2013, respectively.

In September 2012, we entered into a note payable of $1,600,000 with Hydrocarb Corporation, as described in Note 2 – Acquisitions – Namibia Exploration, Inc. The note carries interest of 5%; which is calculated semi-annually and payable with principal payments. Principal of $800,000 is due on August 7, 2013 and $800,000 is due on August 7, 2014.  In October 2013, we paid off the note and accrued interest and fees associated with the note.

In March 2013, we financed our commercial insurance program using a note payable for $260,905. Under the note, we are obligated to make nine payments of $29,591 per month, which include principal and interest, beginning in March 2013. As of July 31, 2013, $115,958 remained outstanding on this note.

In June 2013, the outstanding balance on our line of credit, $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 principal reduction plus interest for the month. The note carries interest at prime + 1%, currently 6%. As of July 31, 2013, $275,000 remained outstanding on this note.  As of November 12, 2013, the date of this report, $250,000 remained outstanding on the note.

As of July 31, 2013, future maturities on our notes payable were as follows:

Fiscal year ending:
2014	$	1,059,644
2015		942,992
Total	$	2,002,636

Line of Credit

On March 17, 2011, GBE secured a one year revolving line of credit of up to with a commercial bank. The note specified interest at a rate of prime + 1% with a minimum interest rate of 5%. The initial interest rate was 6%. Interest is payable monthly. We must use proceeds from the line of credit solely to enhance our Galveston Bay properties.  The note is collateralized by our Galveston Bay properties and substantially all GBE’s assets. Duma also executed a parental guarantee of payment. As of July 31, 2012 the amount outstanding under the line of credit was $300,000.  The note was extended several times during fiscal 2013 and finally replaced by a term loan note in June 2013.

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Note 8 – Fair Value

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2013.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2012.

	Carrying Value at		Fair Value Measurement at July 31, 2012
	July 31, 2012		Level 1		Level 2		Level 3
Assets:
Available for sale securities	$	313,446	$	313,446	$	-	$	-
Liabilities:
Derivative warrant liability	$	1,325,388	$	-	$	-	$	1,325,388

Derivative Warrant Liability

Effective July 31, 2009, we adopted FASB ASC Topic No. 815-40 (formerly EITF 07-05) which defines determining whether an instrument (or embedded feature) is indexed to an entity’s own stock. This literature specifies that a contract that would otherwise meet the definition of a derivative but is both (a) indexed to our own stock and (b) classified in stockholders’ equity in the statement of financial position, would not be considered a derivative financial instrument and provides a new two-step model to be applied in determining whether a financial instrument or an embedded feature is indexed to an issuer’s own stock and thus able to qualify for the scope exception.

Certain warrants we issued during the year ended July 31, 2010 were not afforded equity treatment because these warrants had a down-round 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 total fair values of the warrants issued during the year ended July 31, 2010, were determined using a lattice model and have been recognized as a derivative liability as described below.

The warrants were valued using a multi-nomial 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;

 · 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 following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013 and 2012:

	2013			2012
Beginning of the period	$	1,325,388		$	2,543,223
Expiration of derivative warrant feature		(269,164	)		—
Unrealized gain on changes in fair value of derivative liability		(1,056,224	)		(1,217,835	)
End of the period	$	—		$	1,325,388

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 anti-dilution provisions expire three years after the issuance of the warrants. Accordingly, the provision for warrants to purchase 408,065 and 206,400 shares of common stock expired on October 15, 2012 and November 13, 2012, respectively. As of each those dates, the fair value of the warrant was determined for a final mark to market adjustment and the outstanding warrant derivative liability was reclassified to additional paid-in capital, as the warrants were no longer derivatives.

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Note 9 – Capital Stock

On April 4, 2012, we effected a reverse stock split of our authorized, issued and outstanding shares of common stock on a one new share for twenty-five old share basis (1:25). The effect of the reverse stock split has been retroactively applied to all periods presented.

As a result of the reverse split, our authorized share capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock and correspondingly, our issued and outstanding share capital decreased from 269,742,986 shares of common stock to 10,791,003 shares of common stock.

Effective May 16, 2012, Duma increased the number of its authorized shares of common stock from 20,000,000 shares, par value $0.001 per share, to 500,000,000 shares, par value $0.001 per share.

Our capitalization at July 31, 2013 was 500,000,000 authorized common shares with a par value of $0.001 per share.

Common Stock Issuances

During August 2011, we granted 189,585 shares of common stock to certain investors who had participated in our October and November 2009 equity raises, and as a consequence owned derivative warrants. These investors had exercised some of their warrants prior to our equity raise in February 2011, which triggered the down-round ratchet provision in the warrants.  The warrant contracts specify that the ratchet adjustment is not made for warrants that were exercised prior to the repricing event.  As a consequence of their warrant exercises, they had forfeited their contractual right to receive ratchet warrant shares.  However, management granted stock to these investors as a goodwill gesture.  The stock grant was treated as an investor relations expense and valued at $592,452.  The shares were valued using the closing market price on the date of grant.

During December 2011 we granted 13,036 shares of common stock as compensation for services valued at $27,703. The shares were valued using the closing market price on the date of the grant.

During the quarter ended April 30, 2012, we canceled 2,431 shares that had previously been deemed issued to two consultants. No adjustment to compensation was made in conjunction with this settlement.

During September 2011, we issued 3,799,998 shares of common stock to the members of SPE Navigation I, LLC towards acquisition of SPE.  The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition.

During September 2012, we issued 2,490,000 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.)

Stock Compensation Plans

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. Duma may grant up to 2,650,000 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 or warrant award 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.

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Options granted to non-employees

The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended July 31:

	2013	2012
Risk-free interest rate	1.11% - 2.00%	0.12% - 1.66%
Dividend yield	0%	0%
Volatility factor	140.30%-144%	135%-148%
Expected life (years)	6.5 years	1-6.5 years

In February 2013, options to purchase an aggregate of 600,000 shares of common stock with an exercise price of $2.20 per share and a term of ten years were granted to our three independent directors. The options vest 20% each six months over the 30 months following the award. 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.

No options were granted to non-employees during the year ended July 31, 2012.  Expense during 2012 consists of the amortization of options granted prior to July 31, 2012.

The following table provides information about options granted to non-employees under our stock incentive plans during the years ended July 31, 2013 and 2012:

	2013		2012
Number of options granted		600,000		-
Compensation expense recognized	$	679,174	$	424,569
Weighted average exercise price of options  granted	$	2.20	$	N/	A

Based on the fair value of the options as of July 31, 2013, there was $1,011,847 of unrecognized compensation costs related to non-vested share based compensation arrangements 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.

Options granted to employees

The following table provides information about options granted to employees under our stock incentive plans during the years ended July 31, 2013 and 2012:

	2013		2012
Number of options granted		-		-
Compensation expense recognized	$	253,952	$	263,201
Weighted average exercise price of options  granted	$	N/A	$	N/A

During the year ended July 31, 2011, options to purchase 260,000 shares of common stock with an exercise price of $2.50 per share and a term of ten years were granted to five employees.  The options vest 20% each six months over the 30 months following the award. 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, 2013, we had $56,917 in unamortized compensation expense associated with options granted to employees.

No options were granted to employees during the years ended July 31, 2013 or 2012.

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Summary information regarding stock options issued and outstanding as of July 31, 2013 is as follows:

	Options			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at July 31, 2011		1,101,200		$	2.50	$	1,101,200		8.14
Granted		-			-
Exercised		-			-
Expired or forfeited		(57,200	)		2.50
Outstanding at July 31, 2012		1,044,000		$	2.50	$	-		7.22
Granted		600,000			2.20
Exercised		-			-
Expired or forfeited		(108,000	)		2.50
Outstanding at July 31,2013		1,536,000		$	2.38	$	-		7.98
Exercisable at July 31, 2013		776,800		$	2.50	$	-		6.82

Options outstanding and exercisable as of July 31, 2013:
Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.20		600,000	9.54 years		—
	2.50		796,000	7.73 years		636,800
	2.50		60,000	3.93 years		60,000
	2.50		24,000	5.81 years		24,000
	2.50		56,000	Less than 1 year		56,000
			1,536,000			776,800

Options outstanding and exercisable as of July 31, 2012:
Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		800,000	8.72 years		320,000
	2.50		24,000	6.81 years		24,000
	2.50		60,000	4.93 years		60,000
	2.50		56,000	1.04 years		56,000
	2.50		104,000	Less than 1 year		104,000
			1,044,000			564,000

Summary information regarding nonvested stock options as of July 31, 2013 is as follows:

	Number of shares			Weighted average grant date fair value
Nonvested at July 31, 2012		480,000		$	2.47
Granted		600,000		$	1.99
Vested		(319,200	)	$	2.47
Forfeited		(1,600	)	$	2.47
Nonvested at July 31, 2013		759,200		$	2.09

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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 Director and our Chief Executive Officer. Under the terms of the agreement, we granted warrants to purchase 1,200,000 shares of common stock that have a market condition.  If our common stock attains a five day average closing price of $7.50 per share, 600,000 warrants with an exercise price of $2.50 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 $15.00 per share, 600,000 warrants with an exercise price of $2.50 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 will be amortized over the derived service periods of 2.08 years and 2.49 years, respectively.  The following table reflects information regarding Warrant B and Warrant C as of July 31, 2013 and 2012:

	2013		2012
Fair Value of Warrant B as of the end of the derived service period in 2013 and as of July 31, 2012	$	266,017	$	177,150
Fair Value of Warrant C as of July 31, 2013 and 2012, respectively	$	202,127	$	139,491
Compensation expense recognized during the years ended July 31, 2013 and 2012, respectively	$	196,384	$	189,372

Summary information regarding common stock warrants issued and outstanding as of July 31, 2013, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2011		3,758,455		$	2.50	$	3,710,880		3.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(2,000	)		25.00		-		-
Outstanding at year ended July 31, 2012		3,756,455		$	2.58	$	-		2.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(45,578	)		9.34		-		-
Outstanding at year ended July 31,2013		3,710,877		$	2.50	$	-		1.87

 Warrants outstanding and exercisable as of July 31, 2013:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		2,000,000	3 years or less		800,000
	2.50		1,253,757	2 years or less		1,253,757
	2.50		457,120	1 year or less		457,120
			3,710,877			2,510,877

Warrants outstanding and exercisable as of July 31, 2012:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		2,000,000	3.55 years		800,000
	2.50		1,253,757	2.21 years		1,253,757
	2.50		400,000	1.67 years		400,000
	2.50		5,120	1.57 years		5,120
	2.50		52,000	1.55 years		52,000
	6.25		8,000	1 year or less		8,000
	10.00		37,578	1 year or less		37,578
			3,756,455			2,556,455

 Note 10 – Related Party Transactions

During the years ended July 31, 2013 and 2012, a company controlled by one of our former officers, Carter E & P (“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 Duma 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:

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	Year Ended July 31,
	2013		2012
Revenue generated from Barge Canal properties	$	643,203	$	569,476
Lease operating costs incurred from Barge Canal properties	$	224,047	$	181,113
Overhead costs incurred	$	28,038	$	25,087
Outstanding accounts receivable at period end	$	91,967	$	74,972
Outstanding accounts payable at year end	$	-	$	-

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 4 – Oil and Gas Properties)

The father of the Chief Financial Officer and a company controlled by the father-in-law of the Chief Executive Officer each purchased a 5% working interest in the ST 9-12A #4 well.  As of July 31, 2012, these parties owed $42,646 in billed and unbilled joint interest billings. As of July 31, 2013, the company controlled by the father-in-law of the Chief Executive Officer owed us $84,806. We also had an advance outstanding from the father of the Chief Financial Officer, which was reflected in the caption “Due to related parties”, of $15,046.

In November 2011, we paid $6,423 principal on a note payable due to a director.  We also paid the associated accrued interest of $416.

In October 2011, we paid $8,300 of principal on a note payable due to an officer and director of Duma. We also paid the accrued interest associated with the note of $413.

During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our Chief Executive Officer and a Director, as detailed in Note 9 – Capital Stock.  We recognized expense of $196,384 and 189,372 from this contract during the years ended July 31, 2013 and 2012, respectively.

During the quarter ended October 2012, we purchased NEI for up to 24,900,000 shares of Duma common stock, as described in Note 2 – Acquisitions – Namibia Exploration, Inc.

Note 11 –  Income Taxes

Our net loss before income taxes totaled $(40,598,044) and $(5,700,195) for the years ended July 31, 2013 and 2012, respectively.

We recognized an income tax benefit during the year ended July 31, 2013 because the estimated tax liability for 2012 exceeded the actual tax liability.

We recognized a large income tax benefit during the year ended July 31, 2012 primarily due to intangible drilling costs and dry hole costs that resulted in tax losses and the utilization of net operating losses that offset the recognized tax gain on securities sold during the year.  The securities were acquired with SPE (See Note 2 – Acquisitions) and had built-in capital gains on the purchase date, which resulted in the recognition of a deferred tax liability on the date of purchase.  In accordance with purchase accounting, the utilization of the tax losses, which were possible because the gains existed, was recognized as a tax benefit and the purchase price accounting remained unchanged. A portion of the stock acquired in the purchase of SPE was not sold during the year.  We determined that current deferred tax assets existed that are sufficient to offset deferred tax liability on unrecognized tax gain on these available for sale securities  and accordingly we adjusted the valuation allowance for our deferred tax assets, which resulted in a further tax benefit.  

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The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:

	July 31,
	2013			2012
US statutory federal rate		35.00	%		35.00	%
State income tax rate		.58	%		.58	%
Equity-based compensation		(33.62	)%		(36.43	)%
Gain on derivative warrants		.93	%		7.60	%
Gain on sale of securities		(.33	)%		(21.15	)%
Other		(.50	)%		4.02	%
Acquired deferred tax liability		-	%		23.12	%
Net operating loss		(1.75	)%		6.92	%
		.31	%		19.66	%

Our deferred income taxes reflect the net tax effects of operating loss and 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 that 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, 2013 and 2012 are as follows:

	July 31,
	2013			2012
Stock based compensation	$	713,867		$	292,509
Property, including depreciable property		(2,980,005	)		(2,070,809	)
Asset retirement obligation		3,942,918			3,312,358
Net operating loss carry-forward		3,846,783			2,530,532
Other		42,368			318,032
		5,565,931			4,382,622
Valuation allowance for deferred tax assets		(5,565,931	)		(4,382,622	)
	$	—		$	—

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, 2013 will significantly increase or decrease within 12 months.

Generally, our income tax years 2010 through 2013 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, 2013, we had approximately $10,813,165 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.

Our ability to use our NOLs would be limited if it was determined that we underwent an “ownership change” under Section 382 (“Section 382”) of the Internal Revenue Code. Based upon the information available to us, along with our evaluation of various scenarios, we believe that our 2011 private placement caused us to experience an “ownership change”.

In order to determine whether an “ownership change” occurred, we had to compare the percentage of shares owned by each 5.0% shareholder immediately after the close of the testing date to the lowest percentage of shares owned by such 5.0% shareholder at any time during the testing period (which is generally a three year rolling period). The amount of the increase in the percentage of Company shares owned by each 5.0% shareholder whose share ownership percentage has increased is added together with increases in share ownership of other 5.0% shareholders, and an “ownership change” occurs if the aggregate increase in ownership by all such 5.0% shareholders exceeds 50%.  The issuance of our common shares as part of the 2011 private placement caused such threshold to be exceeded.

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As a result of experiencing an “ownership change”, we will only be allowed to use a limited amount of NOLs to offset our taxable income subsequent to the “ownership change.” The annual limit pursuant to Section 382 (the “382 Limitation”) is obtained by multiplying (i) the aggregate value of our outstanding equity immediately prior to the “ownership change” (reduced by certain capital contributions made during the immediately preceding two years and certain other items) by (ii) the federal long-term tax-exempt interest rate in effect for the month of the “ownership change.”  As our ownership change occurred in February 2011, the federal long-term tax-exempt interest rate applicable to our limitation is 4.47%.  Therefore, based on the factors in place at the time of our ownership change, we believe our annual limitation would be an estimated $239,600. On September 6, 2012, we acquired Namibia Exploration, Inc.  We believe the transaction may have resulted in a second “ownership change”, which would further limit the availability of NOLs incurred prior to the transaction.

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” will significantly defer the utilization of the loss carryforwards, accelerate payment of federal income tax and may cause some of the NOLs to expire unused.

Note 12 – 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.

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 6) that is estimated using the guidance in ASC 410-20.

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, 2013 and July 31, 2012, $150,000 has been recognized and is included in the balance sheet caption “Accounts payable and accrued expenses.”

Commitments

We have the following contract obligations:

In March 2011, we executed a lease for office space in Houston, Texas.  The lease term is three years and we have an option to extend the lease for an additional three years.  Our scheduled rent is $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.

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During September 2013, we terminated our lease for office space in Corpus Christi, Texas.

Rent expense during the years ended July 31, 2013 and 2012 was $127,867 and $117,392, respectively.

The following table details our payment obligations related to our operating leases and to our debt that are due during the years ended July 31,

	2014		2015		2016		Total
Operating leases	$	71,047	$	—	$	—	$	71,047
Notes payable		1,135,042		967,295		—		2,102,337
Total	$	1,206,089	$	967,295	$	—	$	2,173,384

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.

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 $180,000 issued by Green Bank. These letters of credit are collateralized by a certificate of deposit held with the bank for the same amount. In addition, we have a letter of credit in the amount of $40,000 issued by a commercial bank in favor of the landowner of the Welder lease as security that we will meet our obligations with regard to the salt water disposal well located on the lease. The letter of credit is 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, 2012, we paid the fees associated with the Greenbank letters quarterly. In June 2013, when we renewed the letters of credit, we prepaid the entire years’ interest upfront. We amortized these fees on a straight-line basis. The following table reflects the prepaid balances as of July 31,

	2013			2012
Prepaid letter of credit fees	$	101,850		$	25,163
Amortization		(8,488	)		(8,596	)
Net prepaid letter of credit fees	$	93,362		$	16,567

Note 13 – 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, 2013 and 2012, we have reserved $58,585 and $1,302, respectively, for potentially uncollectable other receivables.

Other current assets

Other current assets consisted of the following:

	At July 31,
	2013		2012
Prepaid letter of credit fees	$	93,362		16,567
Prepaid insurance		180,433		178,471
Other prepaid expenses		2,000		10,164
Cash call paid to operator		24,225		23,234
Prepaid land use fees		28,728		19,852
Accrued interest income		4,388		8,389
Total other current assets	$	333,136	$	256,677

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Property and Equipment

Property and equipment consisted of the following:

		At July 31,
	Approximate Life	2013			2012
Furniture and fixtures	5 years	$	7,604		$	7,604
Marine vessels	5 years		17,614			17,614
Vehicles	5 years		18,027			18,027
Computer equipment and software	2 years		39,296			39,296
Total property and equipment			82,541			82,541
Less accumulated depreciation			(62,749	)		(36,572	)
Net book value		$	19,792		$	45,969
Depreciation expense		$	26,177		$	31,495

Accounts payable and accrued expenses

Accounts payable and accrued expenses consisted of the following:

	At July 31,
	2013		2012
Trade payables	$	3,068,671	$	1,950,768
Accrued payroll		151,577		40,000
Accrued interest and fees		398,966		—
Revenue payable		4,717		6,690
Local taxes and royalty payable		128,470		108,948
Federal and state income taxes payable		27,000		192,432
Total accounts payable and accrued expenses	$	3,779,401	$	2,298,838

Note 14 – Subsequent Events

In August 2013, 120,000 of the 600,000 options granted to our independent directors became vested and the fair market value of these options on the date of vesting was $16,184. The fair market 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 480,000 options so that they became fully and immediately vested. The fair value of the options on the date of vesting of $851,096 was recognized immediately as an expense. The fair market 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 October 2013, we issued 1,859,879 shares of common stock to Hydrocarb Corporation to settle the $2,400,000 consulting fee described in Note 2 – Acquisitions – Namibia Exploration, Inc., $553,640 of interest and late fees associated with the fee, and $635,937 of joint interest billings payable to Hydrocarb for its work on the Namibian concession.

Note 15 – 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.

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Proved reserves represent estimated quantities of natural gas, crude oil and condensate 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. In the following table, natural gas liquids are included in natural gas reserves. The oil and natural gas liquids price as of July 31, 2013 and 2012 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 $92.52 and $95.07 per barrel, respectively. The gas price as of July 31, 2013 and 2012 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 $3.51and $3.02 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 (Barrels)			Gas (MCF)			Total (MCFE)
Balance – July 31, 2011		1,218,950			12,561,090			19,874,790
Revisions of previous estimates		(88,689	)		(1,404,465	)		(1,936,599	)
New discoveries and extensions		660			11,840			15,800
Purchase of reserves in place		383,070			4,108,360			6,406,780
Sale of reserves in place		(64,730	)		(315,910	)		(704,290	)
Production		(61,011	)		(222,955	)		(589,021	)
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

	Proved Reserves as of July 31, 2013
	Oil (Barrels)		Gas (MCF)		Total (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 Reserves as of July 31, 2012
	Oil (Barrels)		Gas (MCF)		Total (MCFE)
Proved developed producing		308,640		1,785,010		3,636,850
Proved developed non-producing		321,510		4,226,080		6,155,140
Proved undeveloped		758,100		8,726,870		13,275,470
Total proved reserves		1,388,250		14,737,960		23,067,460

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.

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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.

	2013			2012
Unevaluated properties	$	713,655		$	265,639
Evaluated properties		19,857,842			17,553,836
Less impairment		(373,335	)		(373,335	)
		20,198,162			17,446,140
Less depreciation, depletion, and amortization		(2,617,478	)		(1,557,675	)
Net capitalized cost	$	17,580,684		$	15,888,465

Costs Incurred in Oil and Gas Activities

Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2013 were as follows.

	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 incurred in property acquisition, exploration, and development activities for the year ended July 31, 2012 were all incurred in the USA.  The following table provides information about the costs incurred:

	July 31, 2012
Property acquisition
Unproved	$	74,805
Proved		6,988,447
Exploration		420,200
Development		2,033,073
Cost recovery		(32,772	)
Total costs incurred	$	9,483,753

Costs Excluded

Our excluded costs as of July 31, 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, 2013 were incurred during that year.

Costs Excluded by Year Incurred

	As of July 31, 2013
Property Acquisition	$	677,795
Exploration		35,860
Total	$	713,655

Costs excluded as of July 31, 2012 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.

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Changes in Costs Excluded by Country

	Namibia		United States
Balance at July 31, 2011	$	—	$	—
Additional Cost Incurred		—		265,639
Costs Transferred to DD&A Pool		—		—
Balance at July 31, 2012				265,639
Additional Costs Incurred		713,655		278,090
Cost recovery		—		(132,662	)
Costs Transferred to DD&A Pool		—		(411,067	)
Balance at July 31, 2013	$	713,655	$	—

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:

	2013			2012
Future cash inflows	$	113,603,450		$	200,741,090
Future production costs		(55,897,070	)		(60,998,060	)
Future development costs		(41,794,284	)		(48,640,439	)
Future income tax expenses		(5,569,234	)		(31,885,907	)
Future net cash flows		10,342,862			59,216,684
10% annual discount for estimated timing of cash flows		(3,990,069	)		(25,552,798	)
Future net cash flows at end of year	$	6,352,793		$	33,663,886

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, 2013:

	2013			2012
Standardized measure of discounted future net cash flows at beginning of year	$	33,663,886		$	36,116,218
Net changes in prices and production costs		(37,623,010	)		(3,316,394	)
Changes in estimated future development costs		4,205,045			(10,006,008	)
Sales of oil and gas produced, net of production costs		(2,510,339	)		(3,152,150	)
Discoveries and extensions		—			54,414
Purchases of minerals in place		—			16,662,628
Sales of minerals in place		(17	)		(2,042,655	)
Revisions of previous quantity estimates		(12,391,911	)		(6,669,453	)
Development costs incurred		1,124,107			1,085,180
Change in income taxes		14,705,973			1,320,486
Accretion of discount		5,179,059			3,611,622
Standardized measure of discounted future net cash flows at year end	$	6,352,793		$	33,663,886

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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

	2013			2012
Net revenues from production	$	7,070,540		$	7,165,233
Expenses
Lease operating expense		4,560,201			4,013,083
Accretion		1,056,508			943,508
Operating expenses		5,616,709			4,956,591
Depreciation, depletion and amortization		1,059,803			990,486
Total expenses		6,676,512			5,947,077
Income before income tax		394,028			1,218,156
Income tax expense		(137,910	)		(426,355	)
Results of operations	$	256,118		$	791,801
Depreciation, depletion and amortization rate per net equivalent MCFE	$	1.95		$	1.68

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Principal Executive Officer and Principal Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our Principal Executive Officer and Principal Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not effective, due to the deficiencies in our internal control over financial reporting as described below.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.

As of July 31, 2013, we assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and SEC guidance on conducting such assessments. We utilized the original (1992) COSO Framework to conduct our assessment.  Based on that evaluation, we concluded that, as at July 31, 2013, our internal controls and procedures were not effective to detect the inappropriate application of accounting principles generally accepted in the United States of America as more fully described below. This was due to deficiencies that existed at the time in which the internal control procedures were implemented that adversely affected our internal controls and that may be considered to be a material weakness.

The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the Public Company Accounting Oversight Board were: (1) while the Company has implemented written policies and procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements, we have not conducted a formal assessment of whether the policies that have been implemented address the specific risks of misstatement; accordingly, we could not conclude whether the control activities are designed effectively nor whether they operate effectively; and (2) we do not have an effective mechanism for monitoring the system of internal controls.

Management believes that the material weaknesses set forth above did not have a material adverse effect on our financial results for the year ended July 31, 2013.

We are committed to improving our financial organization. Our control weaknesses are largely a function not having sufficient staff.  As resources become available, we plan to augment our staff so that we can devote more effort to addressing our control deficiencies.  Additionally, as financial resources become available, we will consider engaging third party consultants to assist with control activities.

We will continue to monitor and evaluate the effectiveness of our internal controls and procedures over financial reporting on an ongoing basis and are committed to taking further action by implementing additional enhancements or improvements, or deploying additional human resources as may be deemed necessary.

Changes in Internal Control over Financial Reporting

During our fourth quarter of our fiscal year ended July 31, 2013, we implemented and documented entity-level controls, formalized risk assessment processes, and adopted additional policies and procedures that improved our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Officers and Directors

Our directors and executive officers and their respective ages as of the date of this annual report are as follows:

Name	Age	Position with the Company
Jeremy G. Driver	36	Chief Executive Officer and a director
Sarah Berel-Harrop	46	Secretary, Treasurer and Chief Financial Officer
Charles F. Dommer	59	President
Kent P. Watts	55	Chairman and a director
Pasquale Scaturro	60	Director
S. Chris Herndon	53	Director

The following describes the business experience of each of our directors and executive officers, including other directorships held in reporting companies:

Jeremy Glenn Driver, Chief Executive Officer and a director

Mr. Driver has been Chief Executive Officer since December 2009 and a director of the Company since June 2010.  He served as President of the Company from December 2009 until February 15, 2011, and once again became President on April 1, 2011.  Effective October 27, 2013, Mr. Driver resigned as President.  He remains Chief Executive Officer.  He is an oil and gas operations and financial professional with a background in land-based E&P operations with public companies. Prior to joining the Company, Mr. Driver served as President of HYD Resources Corporation (a wholly-owned subsidiary of publicly traded firm Hyperdynamics Corporation) with operations primarily focused in Texas and Louisiana from 2005 to 2008. He was able to lead the operational turnaround of that company and bring it to profitability, later being divested at a profit. Mr. Driver also served as an active duty officer in the United States Air Force until 2005, specializing in foreign intelligence as a Chinese Linguist. Mr. Driver holds a Masters of Business Administration and a Master of Science in Accounting from Northeastern University, Boston, MA. He also earned his Bachelor of Science in Liberal Studies - Chinese Language from Excelsior College.

Sarah Berel-Harrop, Secretary, Treasurer and Chief Financial Officer

Ms. Berel-Harrop has been our Secretary, Treasurer and Chief Financial Officer since May 25, 2011. Ms. Berel-Harrop has approximately 16 years of experience in financial accounting and reporting in both audit and industry positions. She received a B.A. degree from Cornell University and a Master in Business Administration from University of Texas - Austin. From 2006 to 2009, Ms. Berel-Harrop worked with Hyperdynamics Corporation. She was responsible for the company’s financial accounting and reporting, and, from June 2008 through June 2009, served as the company’s Chief Financial Officer. From July 2009 through March 2011, Ms. Berel-Harrop operated an accounting firm as a sole practitioner. From March 1, 2011 through the May 2011, she was Duma Energy Corp.’s Controller. In May 2011, Ms. Berel-Harrop became Duma’s CFO.  Ms. Berel-Harrop is a Certified Public Accountant licensed in the state of Texas. She is a member of the AICPA and the Texas State Board of Public Accountancy, Houston Chapter.

Charles F. Dommer, President

Charles F. Dommer was appointed President on October 27, 2013.  Mr. Dommer is an exploration and development executive with 35 years of managerial positions for international and domestic oil and gas exploitation, exploration and acquisitions.  Mr. Dommer has managed many major projects in the competitive arena of oil and gas exploration and development. From December 2010 until present, Mr. Dommer has served as the Vice President of Exploration and Development for Hydrocarb Corporation.  From January 2000 to December 2010, Mr. Dommer served as President for Trans Global Engineering, Inc., of Denver, Colorado, primarily directing production operations as Chief Geologist (Vice President of Exploration and Production) for Lukoil-AIK in Russia.  Mr. Dommer’s past experience includes Senior Geologist at Phillips Petroleum Company, located in Texas, and the establishment of a Geology and Reservoir Engineering Department in Siberia as Chief Geologist (Vice President of Exploration and Production) for Occidental Petroleum Joint Venture, Vanyoganneft.  Mr. Dommer has a B.S. Geology degree from Arizona State University.

Kent P. Watts, Chairman and a director

Mr. Watts was appointed to the board of directors and as Chairman on October 11, 2013. Mr. Watts is currently and has been Chairman and Chief Executive Officer of Hydrocarb Corporation since November 2009. Hydrocarb owns rights in 21,000 square kilometer oil and gas concession onshore the country of the Republic of Namibia with a northern of Angola. The company has subsidiaries in Windhoek, Namibia and Abu Dhabi, UAE. Its subsidiary, Otaiba Hydrocarb LLC in the UAE, holds an oil field services license approved by the Supreme petroleum council of the UAE.  Between June 1997 and October 2009 he was the founder, Chairman, and Chief Executive Officer for Hyperdynamics Corporation (NYSE:HDY). In 2006 Mr. Watts became the Founder and Chairman of American Friends of Guinea (AFG), a non-profit organization. He remains Chairman of AFG. He holds a BBA from the University of Houston and he is a licensed Certified Public Accountant and Real Estate Broker in the State of Texas. 

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Pasquale Scaturro, Director

Mr. Scaturro was appointed to the board of directors on October 11, 2013. Mr. Scaturro is a geophysicist and geologist with 29 years of experience in the oil and gas industry. His areas of experience include oil and gas exploration and development, prospect evaluation, 2-D and 3-D seismic survey program design, parameter selection, data acquisition, processing, detailed seismic workstation interpretation, prospect evaluation, project planning, and GIS and data base design. Mr. Scaturro's International experience includes projects in the Middle East, Africa, Russia and other former Soviet Union countries, Asia and South America. Mr. Scaturro has substantial training and mentoring experience around the world. From January 2012 to present, Mr. Scaturro has served as President and Chief Operating Officer for Hydrocarb Corporation. From January 1992 to December 2009 he served as president for Exploration Specialists, Inc., Denver, Colorado. Mr. Scaturro also served as a director for Hyperdynamics Corporation (NYSE:HDY) from April 2009 until December 2009. Past experience includes Senior Geophysicist for Amoco Production Company and McMoRan Oil and Gas Company. Mr. Scaturro has a B.S. Geology/Geophysics degree from Northern Arizona State University.

S. Chris Herndon

Mr. Herndon has been a director since October 11, 2012.  Mr. Herndon is an experienced financial and management professional with more than 30 years of experience. Currently, Mr. Herndon serves as Partner of Cyrus Partners, an investment company focusing on the energy, healthcare, and real estate sectors. Beginning in 2002 through 2011, Mr. Herndon served as Chief Financial Officer and Partner of AppOne, a financial technology company designed to serve the auto finance industry. From 1996 to 2001, Mr. Herndon served as CEO and Partner of The Mattress Firm, growing the organization from 100 stores to 275 stores before selling the firm to Bain Capital. Mr. Herndon was also a Registered Investment Advisor with Malachi Financial Services from 1994 to 1996. From 1983 to 1994, Mr. Herndon served as Chief Financial Officer and Controller of Duer Wagner and Co., an oil and gas operator in Texas. From 1982 to 1983 he served as a Public Accountant with Price Waterhouse.

Mr. Herndon is a graduate of Texas Christian University where he earned his Bachelor of Business Administration and Accounting, after which he became a Certified Public Accountant (CPA) in 1985. He is actively involved with several charities locally and internationally.

Term of Office

Our directors are appointed for a one-year term to hold office until the next annual general meeting of our stockholders or until they resign or are removed from the board in accordance with our bylaws. Our officers are appointed by our Board of Directors and hold office until they resign or are removed from office by the Board of Directors.

Significant Employees

Other than Craig Alexander, our Vice President, the Company has no significant employees other than our executive officers.  Mr. Alexander has been with the company since early 2011. Before joining our Company, he was employed by Galveston Bay Energy serving as Operations Manager. Mr. Alexander has more than 21 years of oil and gas experience in production and completion engineering and operations management with Erskine Energy, Millennium Offshore Group, and Amerada Hess Corporation. He is a graduate of the University of Texas at Austin with a B.S. in Petroleum Engineering.

Audit Committee

Our board of directors has established an Audit Committee, which was originally comprised of Leonard Garcia, John Brewster and S. Chris Herndon.  Mr. Garcia and Mr. Brewster resigned from the board of directors prior to the date of this report, and the vacancies created by their resignations have not been filled.  Accordingly, Mr. Herndon is the sole member of the audit committee.  The Audit Committee operates pursuant to a charter adopted by the board.

Mr. Herndon is an “independent” director of the Company as that term is defined in Rule 121 of the NYSE MKT Equities Exchange listing standards.  The Board of Directors of the Company has determined that Mr. Herndon qualifies as an audit committee financial expert pursuant to SEC rules.

Family Relationships

Other than disclosed below, there are no family relationships among our directors and officers.

Kent Watts, who is the Chairman and a director, is the uncle of Jeremy Driver’s wife.  Jeremy Driver is the Chief Executive Officer and a director.

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Involvement in Certain Legal Proceedings

Except as disclosed in this annual report, during the past ten years none of the following events have occurred with respect to any of our directors or executive officers:

1. A petition under the Federal bankruptcy laws or any state insolvency law was filed by or against, or a receiver, fiscal agent or similar officer was appointed by a court for the business or property of such person, or any partnership in which he was a general partner at or within two years before the time of such filing, or any corporation or business association of which he was an executive officer at or within two years before the time of such filing;

2. Such person was convicted in a criminal proceeding or is a named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);

3. Such person was the subject of any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from, or otherwise limiting, the following activities:

i. Acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, any other person regulated by the Commodity Futures Trading Commission, or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliated person, director or employee of any investment company, bank, savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;

ii. Engaging in any type of business practice; or

iii. Engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal commodities laws;

4. Such person was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described in paragraph (3)(i) above, or to be associated with persons engaged in any such activity;

5. Such person was found by a court of competent jurisdiction in a civil action or by the Commission to have violated any Federal or State securities law, and the judgment in such civil action or finding by the Commission has not been subsequently reversed, suspended, or vacated;

6. Such person was found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended or vacated;

7. Such person was the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of:

i.Any Federal or State securities or commodities law or regulation; or

ii. Any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or

iii. Any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

8. Such person was the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

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There are currently no legal proceedings to which any of our directors or officers is a party adverse to us or in which any of our directors or officers has a material interest adverse to us.

Code of Conduct

We have adopted a Code of Conduct that applies to all directors and officers. The code describes the legal, ethical and regulatory standards that must be followed by the directors and officers of the Company and sets forth high standards of business conduct applicable to each director and officer. As adopted, the Code of Conduct sets forth written standards that are designed to deter wrongdoing and to promote, among other things:

1. honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

2. full, fair accurate, timely and understandable disclosure in reports and documents that we file with, or submit to, the SEC and in other public communications made by us;

2. compliance with applicable governmental laws, rules and regulations;

3. the prompt internal reporting of violations of the code to the appropriate person or persons identified in the code; and

4. accountability for adherence to the code.

We revised the Code of Conduct during the year ended July 31, 2013.  A copy of our Code of Conduct is filed as Exhibit 14.1 to this Form 10-K.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than 10% of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that these persons have complied with all applicable filing requirements during the year ended July 31, 2013, except as follows:

Name	Number of forms  filed late	Number of  transactions  reported late
Jeremy Driver	2	5
Leonard Garcia	1	1
John Brewster	1	1
S. Chris Herndon	1	1
Christopher Watts	3	6
CW Navigation Inc.	1	1
KW Navigation Inc.	1	1

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ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation of Named Executive Officers

The following table sets forth the compensation paid to our executive officers (as well as one non-executive officer with respect to whom disclosure would have been provided but for the fact that he was not an executive officer) (collectively, our “Named Executive Officers”) during our fiscal years ended July 31, 2013 and 2012:

Summary Compensation

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)	Option Awards ($)	Non- Equity Incentive Plan Compen- sation ($)	Non- Qualified Deferred Compen- sation Earnings ($)	All Other Comp- en- sation ($)	Total ($)
Jeremy G. Driver President & CEO(1)	2013	175,000	Nil	Nil	Nil	Nil	Nil	Nil	175,000
	2012	188,462	Nil	Nil	Nil	Nil	Nil	Nil	188,462
Sarah Berel-Harrop(2) Secretary, Treasurer & CFO	2013	134,809	Nil	Nil	Nil	Nil	Nil	Nil	134,809
	2012	94,220	Nil	27,703	Nil	Nil	Nil	Nil	121,923
Steven L. Carter(3) Former Vice President, Operations	2013	178,692	Nil	Nil	Nil	Nil	Nil	Nil	178,692
	2012	185,067	Nil	Nil	Nil	Nil	Nil	Nil	185,067
Craig Alexander Vice President	2013	185,000	N/A	N/A	N/A	N/A	N/A	N/A	185,000
	2012	188,846	N/A	N/A	N/A	N/A	N/A	N/A	188,846

(1) Mr. Driver resigned as President on October 27, 2013 but continues to serve as Chief Executive Officer.

(2) During the year ended July 31, 2012, Sarah Berel-Harrop received 13,036 shares of common stock (on a post-stock consolidation basis) valued using the market closing price on the date of grant. 2/3 of the stock grant related to amounts accrued and included as compensation for the year ended July 31, 2011.

(3) Mr. Carter’s employment as Vice President Operations was terminated effective August 30, 2013.

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Outstanding Equity Awards

The following table sets forth information as at July 31, 2013 relating to outstanding equity awards for each Named Executive Officer:

Outstanding Equity Awards at Year End

	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexer- cised Options (#) (exercise- able)	Number of Securities Underlying Unexer- cised Options (#) (unexer- ciseable)	Equity  Incentive Plan Awards: Number of Securities Underlying Unexer- cised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Sarah Berel-Harrop	96,000	24,000	N/A	2.50	04/21/2021	N/A	N/A	N/A	N/A
Steven L. Carter (1)	24,000 56,000 400,000	N/A N/A 100,000	N/A N/A N/A	2.50 2.50 2.50	07/05/2017 08/16/2013 04/21/2021	N/A	N/A	N/A	N/A
Craig Alexander	96,000	24,000	N/A	2.50	04/21/2021	N/A	N/A	N/A	N/A

(1) Mr. Carter’s employment as Vice President Operations was terminated effective August 30, 2013.

Director Compensation

Our directors who are also executive officers receive compensation for management services provided to the Company and thus they do not receive separate compensation for their services as directors.  In February 2013, we adopted a standard compensation package for independent directors as follows:

· $30,000 per year for serving on the board of directors,

· $2,000 per year for serving as a committee chair,

· Meeting fees of $2,000 per meeting for any board meetings other than four quarterly regular meetings, and

· Meeting fees of $1,500 per meeting for any committee meetings other than four quarterly regular meetings.

The following table provides information regarding compensation during the year ended July 31, 2013 earned by directors who are not executive officers.  Our directors who are executive officers do not receive additional compensation for their service as directors and their compensation is disclosed in the “Summary Compensation” Table above.

Name	Year	Fees Earned or Paid in Cash ($)	Stock Awards ($)	Option Awards (1) ($)	Non- Equity Incentive Plan Compen- sation ($)	Non- qualified Deferred Compen- sation Earnings ($)	All Other Compen- sation ($)	Total ($)
Leonard Garcia (2)	2013	22,748	Nil	398,863	N/A	N/A	N/A	421,611
John Brewster (3)	2013	20,667	Nil	398,863	N/A	N/A	N/A	419,530
Chris Herndon	2013	20,667	Nil	398,863	N/A	N/A	N/A	419,530

(1) In February 2013, we granted options to purchase 200,000 shares of common stock with exercise price of $2.20 per share and a 10 year term to each of the independent directors. The options vest 20% each six months over the 30 months following the award. were valued using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 1.35%, a dividend yield of 0%, and a volatility factor of 142.06%. Subsequent to our fiscal year ended July 31, 2013 (in October 2013), we determined to accelerate the vesting of such options, such that all such options that had not yet vested became fully vested in October 2013.

(2) In addition to his independent director compensation, during the year ended July 31, 2013, Leonard Garcia received $2,081 for land work management consulting services provided by Mr. Garcia. Mr. Garcia discontinued providing these services in September 2012.  Subsequent to the Company’s fiscal year ended July 31, 2013 (on October 31, 2013), Mr. Garcia resigned as a director.

(3) Mr. Brewster served as a director of our Company from October 11, 2012 until November 1, 2013.

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Employment, Consulting and Services Agreements

The following summary of certain material terms of the employment, consulting or services agreements we have entered into with certain of our officers or employees is not complete and is qualified in its entirety to the full text of each such agreement, which have been filed with the SEC as described in the list of exhibits to this annual report.

Carter Professional Services Agreement

On December 20, 2006, our Board of Directors authorized and approved the execution of the “Carter Professional Services Agreement”. The initial term of the agreement was two years expiring on November 30, 2008, and the agreement was amended to increase Mr. Carter’s compensation in June 2011. Pursuant to the terms and provisions of the Carter Professional Services Agreement: (i) Steven Carter shall provide duties to us commensurate with his current executive position as our Vice President of Operations; (ii) we would pay to Mr. Carter a monthly fee of $14,583.33; (iii) we approved the issuance of 20,000 shares of our common stock at a price of $0.025 per share (on a post-share consolidation basis); (iv) we approved the granting of an aggregate of not less than 24,000 options to purchase shares of our common stock at $8.75 per share (amended to be $2.50 per share) for a ten year term (on a post-share consolidation basis); and (v) the Carter Professional Services Agreement may be terminated without cause by either of us by providing prior written notice of the intention to terminate at least 90 days (in the case of our Company after the initial term) or 30 days (in the case of Mr. Carter) prior to the effective date of such termination.  In August, 2013, we terminated the agreement.  In accordance with the terms of the agreement, he will receive his fee through the end of November 2013.

Jeremy G. Driver Agreement (2009)

Effective December 1, 2009, we entered into an executive services agreement with Mr. Driver, which was revised in June 2011 to increase his monthly fee, pursuant to which he is to perform such duties and responsibilities as set out in the agreement and as our Board of Directors may from time to time reasonably determine and assign as is customarily performed by a person in an executive position with our Company.  In consideration for his services under the agreement, as amended, we have agreed:

● to pay Mr. Driver a monthly fee of $14,583.33;

● to pay Mr. Driver a one-time signing bonus of $20,000;

● to provide Mr. Driver with industry standard bonuses, from time to time, based, in part, on the performance of the Company and the achievement by Mr. Driver of reasonable management objectives, as determined by the Company’s Board of Directors in good faith;

● to provide Mr. Driver with three weeks paid vacation;

● to provide Mr. Driver with a monthly benefits stipend of $450 together with full participation, at the Company’s expense, in the Company’s current medical services and life insurance benefits programs for management and employees; and

● to grant Mr. Driver incentive stock options to purchase not less than an aggregate of 100,000 common shares of the Company, at an exercise price $5.00 per share (amended to be $2.50 per share), vesting as to one-quarter of said stock options on the date of grant (that being as to 25,000) and on each day which is six months thereafter in succession for each remaining one-quarter of the optioned common shares, and all being exercisable for a period of three years from the date of grant and in accordance with the provisions of the Company’s current Stock Incentive Plan.

The initial term of the agreement was one year ending on December 1, 2010, and the agreement is subject to automatic renewal on a monthly basis unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 30 days prior to the end of the then-current initial term or renewal of the agreement.  In October 2013, this agreement was terminated and we entered into a new employment agreement with Mr. Driver, as described below.

Jeremy G. Driver Agreement (2013)

On October 11, 2013, we entered into a new agreement with Mr. Driver, which was modified on October 27, 2013 and is effective October 1, 2013.  In consideration for his services under the agreement, as amended, we have agreed and to provide Mr. Driver with a monthly salary of $14,583.33, participation in company benefits programs, and four weeks paid vacation.  The agreement provides for Mr. Driver to be paid six months’ salary as severance in the event of

· termination by the Company for other than cause,

· termination by Mr. Driver for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Mr. Driver, or

· termination by Mr. Driver for any reason within 90 days of a change in control of the Company.

The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement.  

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Sarah Berel-Harrop Agreement

On October 11, 2013, we entered into an employment agreement with Ms. Berel-Harrop, which is effective October 1, 2013.  In consideration for her services under the agreement, as amended, we have agreed and to provide Ms. Berel-Harrop with a monthly salary of $12,500, participation in company benefits programs, and three weeks paid vacation.  The agreement provides for Ms. Berel-Harrop to be paid six months’ salary as severance in the event of

· termination by the Company for other than cause,

· termination by Ms. Berel-Harrop for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Ms. Berel-Harrop, or

· termination by Ms. Berel-Harrop for any reason within 90 days of a change in control of the Company.

The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Ms. Berel-Harrop provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement. 

Craig Alexander Agreement

On October 11, 2013, we entered into an employment agreement with Mr. Alexander, which is effective October 1, 2013. In consideration for his services under the agreement, as amended, we have agreed and to provide Mr. Alexander with a monthly salary of $15,417.67, participation in company benefits programs, and three weeks paid vacation.  The agreement provides for Mr. Alexander to be paid six months’ salary as severance in the event of

· termination by the Company for other than cause,

· termination by Mr. Alexander for “Good Reason”, which includes a diminishment of job functions or responsibilities and attempts by the Company to relocate Mr. Alexander, or

· termination by Mr. Alexander for any reason within 90 days of a change in control of the Company.

The initial term of the agreement is one year ending on October 1, 2014, and the agreement is subject to automatic renewal for consecutive one year periods unless either the Company or Mr. Alexander provides written notice of an intention not to renew the agreement not later than 60 days prior to the end of the then-current initial term or renewal of the agreement.  

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth certain information concerning the number of shares of our common stock owned beneficially as of November 12, 2013 by: (i) each person (including any group) known to us to own more than 5% of our shares of common stock; (ii) each of our directors; (iii) each of our officers; and (iv) our officers and directors as a group. To our knowledge, each holder listed possesses sole voting and investment power with respect to the shares shown.

Title of Class	Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Owner	Percent of Class (2)
	Directors and Officers:
Common Stock	Jeremy Glenn Driver 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	3,871,832 (3)	25.6% (8)
Common Stock	Pasquale Scaturro 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	30,000	Less than 1%
Common Stock	Kent Watts 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	4,607	Less than 1%
Common Stock	Sarah Berel-Harrop 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	141,796 (4)	Less than 1%
Common Stock	Charles F. Dommer 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	Nil	N/A
Common Stock	S. Chris Herndon 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	210,300 (5)	1.4%
Common Stock	Directors and officers together (6 persons)	4,258,535 (6)	27.5% (8)
	Major Stockholders:
Common Stock	Christopher Watts 14019 SW Frwy #301-600 Sugar Land, Texas, U.S.A.  77478	3,870,132 (7)	25.6% (8)
Common Stock	Hydrocarb Corporation 3803 Pine Branch Drive Pearland, Texas 77581	1,859,879	12.3%

(1) Under Rule 13d-3 of the Exchange Act a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares, and/or (ii) investment power, which includes the power to dispose or direct the disposition of shares. In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares within 60 days of the date as of which the information is provided.

(2) Based on the 15,140,882 shares of our common stock issued and outstanding as of November 12, 2013.

(3) This figure includes (i) 1,936,416 shares of common stock held by KD Navigation Inc., which is solely owned by Mr. Driver’s wife, and (ii) 1,935,416 shares of common stock held by KW Navigation Inc., which is owned 50% by Mr. Driver’s wife and 50% by Christopher Watts (see footnote 7 below).

(4) This figure includes (i) 21,796 shares of common stock and (ii) vested stock options to purchase 120,000 shares of our common stock.

(5) This figure includes (i) 10,300 shares of common stock and (ii) vested stock options to purchase 200,000 shares of our common stock.

(6) This figure includes (i) 3,938,535 shares of common stock and (ii) vested stock options to purchase 320,000 shares of our common stock.

(7) Represents (i) 1,935,416 shares held by CW Navigation Inc., which is solely owned by Mr. Watts, and (ii) 1,935,416 shares held by KW Navigation Inc., which is owned 50% by Mr. Watts and 50% by the wife of Jeremy Driver (see footnote 3 above).

(8) The 1,935,416 shares held by KW Navigation Inc. (representing 12.8% of the Company’s issued and outstanding stock as of November 12, 2013) is included in the beneficial ownership figures in the table for each of Jeremy Glenn Driver and Christopher Watts (see footnotes 3 and 7 above).

Changes in Control

We are unaware of any contract, or other arrangement or provision, the operation of which may at a subsequent date result in a change of control of our company.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Except as described below, none of the following parties has had any material interest, direct or indirect, in any transaction with us during our last two fiscal years or in any presently proposed transaction that has or will materially affect us:

1. any of our directors or officers;

2. any person who beneficially owns, directly or indirectly, shares carrying more than 5% of the voting rights attached to our outstanding shares of common stock; or

3. any member of the immediate family (including spouse, parents, children, siblings and in-laws) of any of the above persons.

Galveston Bay

Immediately following our acquisition of Galveston Bay Energy, LLC, on February 15, 2011, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. SPE had the right to acquire an additional 10% of our own aggregate working interest in the Galveston Bay fields within 90 days for $1,150,000.

Effective on September 26, 2011, we closed on our acquisition of SPE from CW Navigation Inc., KD Navigation Inc. and KW Navigation Inc., each a Texas corporation (collectively, the “Sellers”). The material assets of SPE consist of certain oil and gas working interests in and to four producing oil and gas fields located in Galveston Bay, Texas, together with one million shares of Hyperdynamics Corporation (NYSE: HDY).  Pursuant to the terms of the Company’s Purchase and Sale Agreement with the Sellers and SPE regarding this matter, the Company acquired the Sellers’ 100% interest in SPE for total consideration consisting of 3,800,000 restricted common shares of the Company issued at a deemed issuance price of $2.50 per share (on a post-share consolidation basis).  CW Navigation Inc. is owned 100% by the brother-in-law of Jeremy Driver, our Chief Executive Officer and a director. KD Navigation Inc. is owned 100% by Mr. Driver’s wife.  KW Navigation Inc. was owned 100% by Mr. Driver’s sister-in-law as of September 26, 2011 and is now 50% owned by Mr. Driver’s wife and 50% owned by Mr. Driver’s brother-in-law.

Namibia Exploration, Inc.

We entered into a Share Exchange Agreement, dated August 7, 2012 (the “Share Exchange Agreement”) with each of Namibia Exploration, Inc. (“NEI”), a company organized under the laws of the state of Nevada, and the shareholders of NEI (each a “Vendor” and collectively, the “Vendors”), whereby we acquired the right to acquire all of the issued and outstanding common shares in the capital of NEI from the Vendors in exchange for the issuance of up to 24,900,000 restricted common shares of Duma to the Vendors (the “Acquisition Shares”) on a pro-rata basis in accordance with each Vendor’s percentage ownership in NEI (the “Acquisition”). NEI holds the rights to a 39% working interest in an onshore petroleum concession (the “Concession”), located in the Republic of Namibia, 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.

We completed the Acquisition on September 6, 2012, and as a result, NEI became a wholly-owned subsidiary of Duma.  As a result, Duma, through NEI, has acquired and been assigned a 39% working interest (43.33% cost responsibility) in and to the Concession.  Duma now holds its indirect working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. (“NPC Namibia”) and Hydrocarb Namibia Energy Corporation (“Hydrocarb Namibia”), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation (“Hydrocarb”), a company organized under the laws of the State of Nevada.  Hydrocarb Namibia, as operator of the Concession, now holds at 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now holds a 10% carried working interest in the Concession.  The assignment of the 39% working interest to NEI from Hydrocarb Namibia received the approval of the government of the Republic of Namibia on August 23, 2012.

Pursuant to the terms of the Share Exchange Agreement, Duma is required to issue the Acquisition Shares, as consideration for the Acquisition, in accordance with the following milestones which must be reached within 10 years after the closing of the Acquisition (the “Closing”):

(a) 2,490,000 of the Acquisition Shares have been issued;

(b) a further 2,490,000 of the Acquisition Shares will be issued when and if Duma’s 10-day volume-weighted average market capitalization reaches $82,000,000;

(c) a further 7,470,000 of the Acquisition Shares will be issued when and if Duma’s 10-day volume-weighted average market capitalization reaches $196,000,000; and

(d) a further and final 12,450,000 of the Acquisition Shares will be issued and if Duma’s 10-day volume-weighted average market capitalization reaches $434,000,000.

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Duma will maintain 100% ownership of NEI after Closing even if one or more of the market capitalization milestones have not been attained within 10 years from the Closing.

The Vendors under the Share Exchange Agreement were Michael Watts (the father-in-law of Jeremy Driver, our Chief Executive Officer and a director), CW Navigation Inc. (which is 100% owned by Mr. Driver’s brother-in-law), KW Navigation Inc. (which is 50% owned by Mr. Driver’s wife and 50% owned by Mr. Driver’s brother-in-law), and KD Navigation Inc. (which is 100% owned by Mr. Driver’s wife).

Carter E & P, LLC

A company controlled by one of our former officers (Steven Carter) operated our Barge Canal properties, the Curlee Prospect in Bee County, Texas and the Dix Prospect in San Patricio County, Texas.  Revenues generated from these properties were $643,203 and $569,476 for the years ended July 31, 2013 and 2012, respectively.  In addition, lease operating costs incurred from these properties were $224,047 and $181,113 for the years ended July 31, 2013 and 2012, respectively.

As of July 31, 2013 and 2012, respectively, we had outstanding accounts receivable associated with these properties of $91,967 and $74,972 and no accounts payable.

Working Interest

During January 2012, we sold half of our working interest in a well, the State Tract 9-12A#4, to third parties.  The father of our Chief Financial Officer, George Bert Harrop, and a company controlled by the father-in-law of the Chief Executive Officer, Lifestream, LLC, each purchased a 5% interest in the well.  The costs associated with the drilling and completion operations on the well through July 31, 2012 were approximately $6.6 million for all participants.  Mr. Harrop’s and Lifestream’s share of the operations were $91,806 and $330,151 each during the years ended July 31, 2013 and July 31, 2012, respectively.

Independent Directors

S. Chris Herndon is an independent director of our Company as provided in the listing standards of the NYSE MKT Equities Exchange.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Our current independent auditor, MaloneBailey, LLP, served as our independent registered public accounting firm and audited our financial statements for the fiscal year ended July 31, 2013 and 2012.  Aggregate fees for professional services rendered to us by our auditor are set forth below:  

	Year Ended July 31, 2013		Year Ended July 31, 2012
Audit Fees	$	103,000	$	114,500
Audit-Related Fees		1,500		-
Other		-		10,000
Tax Fees		19,319		14,000
Total	$	123,819	$	138,500

Audit Fees

Audit fees are the aggregate fees billed for professional services rendered by our independent auditors for the audit of our annual financial statements, the review of the financial statements included in each of our quarterly reports and services provided in connection with statutory and regulatory filings or engagements.

Audit Related Fees

Audit related fees are the aggregate fees billed by our independent auditors for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not described in the preceding category. Specifically, during the year ended July 31, 2013, the independent auditor billed $1,500 for services provided in conjunction with responding to an SEC comment letter.

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Tax Fees

Tax fees are billed by our independent auditors for tax compliance, tax advice and tax planning.

All Other Fees

All other fees include fees billed by our independent auditors for products or services other than as described in the immediately preceding three categories

Policy on Pre-Approval of Services Performed by Independent Auditors

It is our audit committee’s policy to pre-approve all audit and permissible non-audit services performed by the independent auditors. We approved all services that our independent accountants provided to us in the past two fiscal years.

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PART IV

ITEM 15. EXHIBITS

The following exhibits are filed with this Annual Report on Form 10-K:

Exhibit Number	Description of Exhibit
3.1 (1)	Articles of Incorporation and amendments thereto, dated July 19, 2005, October 18, 2005 and September 5, 2006
3.2 (14)	Amended and Restated By-Laws
3.3 (10)	Certificate of Change filed with the Nevada Secretary of State on March 22, 2012
3.4(10)	Articles of Merger filed with the Nevada Secretary of State on March 22, 2012
3.5 (11)	Certificate of Amendment filed with the Nevada Secretary of State on May 16, 2012
4.1 (2)	Form of Warrant Certificate issued to Subscribers pursuant to the October 15, 2009 Private Placement
4.2  (3)	Form of Warrant Certificate issued to Subscribers pursuant to the November 13, 2009 Private Placement
10.1 (1)	Sale Contract for Oil and Gas Leases between Energy Program Accompany, LLC and Penasco Petroleum, Inc., dated August 24, 2006 (regarding the Holt, McKay and Strahan Leases)
10.2 (1)	Letter Agreement between Penasco Petroleum, Inc. and Tradestar Resources Corporation, dated September 1, 2006
10.3 (1)	Assignment, Bill of Sale and Conveyance between OPEX Energy LLC and Penasco Petroleum, Inc., dated effective August 1, 2006 (regarding the Welder Lease)
10.4 (1)	Participation Agreement between Rockwell Energy, LLC and the Company, dated October 2005 (regarding the Janssen Lease)
10.5 (1)	Oil, Gas and Mineral Lease between Henry J. Janssen Jr. and Penasco Petroleum, Inc., dated July 2006 (regarding the Janssen Lease)
10.6 (1)	Assignment and Bill of Sale between Penasco Petroleum, Inc. and ETG Energy Resources, dated October 2006, and Assignment between ETG Energy Resources and Penasco Petroleum, Inc., dated December 2006 (regarding the Janssen Lease)
10.7 (1)	Ratification Letter between Marmik Oil Company and Penasco Petroleum, Inc., dated October 2007 (regarding Little Mule Creek Project)
10.8 (1)	Assignment between Marmik Oil Company and Penasco Petroleum, Inc., dated November 2007 (regarding Little Mule Creek Project)
10.9 (4)	2009 Restated Stock Incentive Plan
10.10 (1)	Professional Services Retainer Contract between the Company and Steven Carter, dated December 2006
10.11 (2)	Form of Securities Purchase Agreement regarding October 15, 2009 Private Placement
10.12 (2)	Form of Registration Rights Agreement regarding October 15, 2009 Private Placement
10.13 (3)	Form of Securities Purchase Agreement regarding November 13, 2009 Private Placement
10.14 (3)	Form of Registration Rights Agreement regarding November 13, 2009 Private Placement
10.15 (5)	Executive Services Consulting Agreement between the Company and Jeremy Glenn Driver dated for reference effective on December 1, 2009
10.16 (6)	Assignment of Oil and Gas Lease between Penasco Petroleum, Inc. and Chinn Exploration Company, dated September 13, 2010
10.17 (7)	Purchase and Sale Agreement by and among ERG Resources, LLC, Galveston Bay Energy, LLC and Strategic American Oil Corporation, dated January 18, 2011, as amended February 14, 2011
10.18(7)	Geoserve Marketing, LLC Agreement, dated February 15, 2011
10.19(7)	SPE Navigation 1, LLC Agreement to acquire work interest., dated February 15, 2011
10.20(8)	Purchase and Sale Agreement among CW Navigation Inc., KD Navigation Inc., and KW Navigation Inc. (as the Seller parties), SPE Navigation I, LLC and Strategic American Oil Corporation, executed September 22, 2011
10.21 (9)	2010 Stock Incentive Plan
10.22 (9)	2011 Stock Incentive Plan
10.23(9)	Farm-Out Agreement with Core Minerals, January 2011, as amended March 9, 2011
10.24 (12)	Share Exchange Agreement dated August 7, 2012
10.25 (12)	Consulting Services Agreement between Duma Energy Corp. and Hydrocarb Corporation, dated August 7, 2012
10.26 (13)	Joint Operating Agreement between Hydrocarb Namibia Energy Corporation and Namibia Exploration, Inc. as fully executed on September 6, 2012
10.27 (13)	Assignment Agreement between the Republic of Namibia Minister of Mines and Energy, Hydrocarb Namibia Energy Corporation (Proprietary) Limited and Namibia Exploration, Inc. as fully executed on August 23, 2012.
10.28*	2013 Stock Incentive Plan
10.29 (15)	Employment Agreement between the Company and Jeremy Glenn Driver effective October 1, 2013
10.30 (15)	Employment Agreement between the Company and Sarah Berel-Harrop effective October 1, 2013
10.31 (15)	Form of Idemnification Agreement
10.32*	Employment Agreement between the Company and William Craig Alexander effective October 1, 2013
14.1*	Code of Conduct
21.1	Subsidiaries of Duma Energy Corp. (all wholly owned by Duma Energy Corp.): (i) Penasco Petroleum Inc., a Nevada corporation, (ii) Galveston Bay Energy, LLC, a Texas corporation, (iii) SPE Navigation I, LLC, a Nevada limited liability corporation, and (iv) Namibia Exploration, Inc., a Nevada corporation.
31.1 *	Certification of Chief Executive Officer pursuant to Securities Exchange Act of 1934 Rule 13a-14(a) or 15d-14(a)
31.2 *	Certification of Chief Financial Officer pursuant to Securities Exchange Act of 1934 Rule 13a-14(a) or 15d-14(a)
32.1 *	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350
99.1 *	Report of Ralph E Davis Associates, Inc., dated October 21, 2013

101.INS *	XBRL INSTANCE DOCUMENT
101.SCH *	XBRL TAXONOMY EXTENSION SCHEMA
101.CAL *	XBRL TAXONOMY EXTENSION CALCULATION LINKBASE
101.DEF *	XBRL TAXONOMY EXTENSION DEFINITION LINKBASE
101.LAB *	XBRL TAXONOMY EXTENSION LABEL LINKBASE
101.PRE *	XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE

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* Filed herewith.

(1) Filed as an exhibit to our registration statement on Form S-1/A (Amendment No.1) filed with the Securities and Exchange Commission on February 8, 2008.

(2) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2009.

(3) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2009.

(4) Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 12, 2009.

(5) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2009.

(6) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 20, 2010.

(7) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on February 22, 2011.

(8) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 22, 2011.

(9) Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 15, 2011.

(10) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on April 4, 2012.

(11) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on May 17, 2012.

(12) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on August 8, 2012.

(13) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 12, 2012.

(14) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 19, 2013.

(15) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2013.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

DUMA ENERGY CORP.

By:	/s/ Jeremy Glenn Driver
	Jeremy Glenn Driver
	Chief Executive Officer and a director
	(Principal Executive Officer)
	Date: November  12, 2013
By:	/s/Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
	Date: November  12, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By:	/s/ Jeremy Glenn Driver
	Jeremy Glenn Driver
	Chief Executive Officer and a director
	(Principal Executive Officer)
	Date: November  12, 2013
By:	/s/Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
	Date: November  12, 2013
By:	/s/ Pasquale Scaturro
	Pasquale Scaturro
	A director
	Date: November  12, 2013
By:	/s/ Kent P. Watts
	Kent P. Watts
	Chairman and a director
	Date: November  12, 2013
By:	/s/ S. Chris Herndon
	S. Chris Herndon
	A director
	Date: November  12, 2013

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EX-10.28

EXHIBIT 10.28

DUMA ENERGY CORP.

2013 STOCK INCENTIVE PLAN

1. PURPOSE

1.1The purpose of this Stock Incentive Plan (the “Plan”) is to advance the interests of Duma Energy Corp. (the “Company”) by encouraging Eligible Participants (as herein defined) to acquire shares of the Company, thereby increasing their proprietary interest in the Company, encouraging them to remain associated with the Company and furnish them with additional incentive in their efforts on behalf of the Company in the conduct of their affairs.

1.2This Plan is specifically designed for Eligible Participants of the Company who are residents of the United States and/or subject to taxation in the United States, although Awards (as herein defined) under this Plan may be issued to other Eligible Participants.

1.3This Plan replaces, in its entirety, each of the Company’s prior stock incentive plans and, in particular, and without limiting the generality of the foregoing, each of the Company’s prior “Restated 2009 Stock Incentive Plan”, dated as originally ratified by the Board of Directors of the Company on July 5, 2007 and as amended on May 21, 2009, the Company’s “2010 Stock Incentive Plan”, dated as ratified by the Board of Directors of the Company on August 16, 2010, and the Company’s “2011 Stock Incentive Plan”, dated as ratified by the Board of Directors of the Company on April 11, 2011.

2. DEFINITIONS

2.1As used herein, the following definitions shall apply:

(a) “Administrator” means the Committee or otherwise the Board;

(b) “Affiliate” and “Associate” have the meanings ascribed to such terms in Rule 12b-2 promulgated under the Exchange Act;

(c) “Applicable Laws” means the legal requirements relating to the administration of stock incentive plans, if any, under applicable provisions of federal securities laws, state corporate laws, state or provincial securities laws, the Code, the rules of any applicable stock exchange or national market system, and the rules of any foreign jurisdiction applicable to Awards granted to residents therein;

(d) “Award” means the grant of an Option, SAR, Restricted Stock, unrestricted Shares, Restricted Stock Unit, Deferred Stock Unit or other right or benefit under this Plan;

(e) “Award Agreement” means the written agreement evidencing the grant of an Award executed by the Company and the Grantee, including any amendments thereto;

(f)“Award Right” means each right to acquire a Share pursuant to an Award;

(g)“Board” means the Board of Directors of the Company;

(h) “Cause” means, with respect to the termination by the Company or a Related Entity of the Grantee’s Continuous Service, that such termination is for “Cause” as such term is expressly defined in a then-effective written agreement between the Grantee and the Company or such Related Entity, or in the absence of such then-effective written agreement and definition, is based on, in the determination of the Administrator, the Grantee’s:

(i) refusal or failure to act in accordance with any specific, lawful direction or order of the Company or a Related Entity;

(ii) unfitness or unavailability for service or unsatisfactory performance (other than as a result of Disability);

(iii) performance of any act or failure to perform any act in bad faith and to the detriment of the Company or a Related Entity;

(iv) dishonesty, intentional misconduct or material breach of any agreement with the Company or a Related Entity; or

(v) commission of a crime involving dishonesty, breach of trust, or physical or emotional harm to any person;

(i) “Change of Control” means, except as provided below, a change in ownership or control of the Company effected through any of the following transactions:

(i) the direct or indirect acquisition by any person or related group of persons (other than an acquisition from or by the Company or by a Company-sponsored employee benefit plan or by a person that directly or indirectly controls, is controlled by, or is under common control with, the Company) of beneficial ownership (within the meaning of Rule 13d-3 of the Exchange Act) of securities possessing more than 50% of the total combined voting power of the Company’s outstanding securities pursuant to a tender or exchange offer made directly to the Company’s shareholders which a majority of the Continuing Directors who are not Affiliates or Associates of the offeror do not recommend such shareholders accept;

(ii) a change in the composition of the Board over a period of 36 months or less such that a majority of the Board members (rounded up to the next whole number) ceases, by reason of one or more contested elections for Board membership, to be comprised of individuals who are Continuing Directors;

(iii) the sale or exchange by the Company (in one or a series of transactions) of all or substantially all of its assets to any other person or entity; or

(iv) approval by the shareholders of the Company of a plan to dissolve and liquidate the Company.

Notwithstanding the foregoing, the following transactions shall not constitute a “Change of Control”:

(i) the closing of any public offering of the Company’s securities pursuant to an effective registration statement filed under the United States Securities Act of 1933, as amended;

(ii) the closing of a public offering of the Company’s securities through the facilities of any stock exchange; or

(iii) with respect to an Award that is subject to Section 409A of the Code, and payment or settlement of such Award is to be accelerated in connection with an event that would otherwise constitute a Change of Control, no event set forth previously in this definition shall constitute a Change of Control for purposes of this Plan or any Award Agreement unless such event also constitutes a “change in the ownership”, a “change in the effective control” or a “change in the ownership of a substantial portion of the assets of the corporation” as defined under Section 409A of the Code and Treasury guidance formulated thereunder, which guidance currently provides that:

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(A) a change in ownership of a corporation shall be deemed to have occurred if any one person or more than one person acting as a group acquires stock of a corporation that constitutes more than 50% of the total Fair Market Value or total voting power of the stock of the corporation. Stock acquired by any person or group of people who already owns more than 50% of such total Fair Market Value or total voting power of stock shall not trigger a change in ownership;

(B) a change in the effective control of a corporation generally shall be deemed to have occurred if within a 12-month period either:

(I) any one person or more than one person acting as a group acquires ownership of stock possessing 35% or more of the total voting power of the stock of the corporation; or

(II) a majority of the members of the corporation’s board of directors is replaced by directors whose appointment or election is not endorsed by a majority of the members of the corporation’s board of directors prior to the date of the appointment or election; and

(C) a change in the ownership of a substantial portion of the corporation’s assets generally is deemed to occur if within a 12-month period any person, or more than one person acting as a group, acquires assets from the corporation that have a total gross fair market value at least equal to 40% of the total gross fair market value of all the corporation’s assets immediately prior to such acquisition.  The gross fair market value of assets is determined without regard to any liabilities;

(j)“Code” means the United States Internal Revenue Code of 1986, as amended;

(k) “Committee” means the Compensation Committee or any other committee appointed by the Board to administer this Plan in accordance with the provisions of this Plan; provided, however, that:

(i) where available, the Committee shall consist of two or more members of the Board;

(ii) where available, the directors appointed to serve on the Committee shall be “non-employee directors” (within the meaning of Rule 16b-3 promulgated under the Exchange Act) and “outside directors” (within the meaning of Section 162(m) of the Code) to the extent that Rule 16b-3 and, if necessary for relief from the limitation under Section 162(m) of the Code and such relief is sought by the Company, Section 162(m) of the Code, respectively, are applicable;

(iii) the mere fact that a Committee member shall fail to qualify under either of the foregoing requirements set forth in Section 2.1(k)(ii) shall not invalidate any Award made by the Committee which Award is otherwise validly made under the Plan; and

(iv) members of the Committee may be appointed from time to time by, and shall serve at the pleasure of, the Board;

(l)“Common Stock” means the common stock of the Company;

(m)“Company” means Duma Energy Corp., a Nevada corporation;

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(n) “Consultant” means any person (other than an Employee) who is engaged by the Company or any Related Entity to render consulting or advisory services to the Company or such Related Entity;

(o) “Continuing Directors” means members of the Board who either (i) have been Board members continuously for a period of at least 36 months, or (ii) have been Board members for less than 36 months and were appointed or nominated for election as Board members by at least a majority of the Board members described in clause (i) who were still in office at the time such appointment or nomination was approved by the Board;

(p) “Continuous Service” means that the provision of services to the Company or a Related Entity in any capacity of Employee, Director or Consultant that is not interrupted or terminated. Continuous Service shall not be considered interrupted in the case of (i) any approved leave of absence, (ii) transfers between locations of the Company or among the Company, any Related Entity, or any successor, in any capacity of Employee, Director or Consultant, or (iii) any change in status as long as the individual remains in the service of the Company or a Related Entity in any capacity of Employee, Director or Consultant (except as otherwise provided in the Award Agreement). An approved leave of absence shall include sick leave, maternity or paternity leave, military leave, or any other authorized personal leave. For purposes of Incentive Stock Options, no such leave may exceed 90 calendar days, unless reemployment upon expiration of such leave is guaranteed by statute or contract;

(q)“Corporate Transaction” means any of the following transactions:

(i) a merger or consolidation in which the Company is not the surviving entity, except for a transaction the principal purpose of which is to change the jurisdiction in which the Company is organized;

(ii) the sale, transfer or other disposition of all or substantially all of the assets of the Company (including the capital stock of the Company’s subsidiary corporations) in connection with the complete liquidation or dissolution of the Company; or

(iii) any reverse merger in which the Company is the surviving entity but in which securities possessing more than 50% of the total combined voting power of the Company’s outstanding securities are transferred to a person or persons different from those who held such securities immediately prior to such merger;

(r) “Covered Employee” means an Employee who is a “covered employee” under Section 162(m)(3) of the Code;

(s) “Deferred Stock Units” means Awards that are granted to Directors and are subject to the additional provisions set out in Subpart A which is attached hereto and which forms a material part hereof;

(t) “Director” means a member of the Board or the board of directors of any Related Entity;

(u) “Disability” or “Disabled” means that a Grantee is unable to carry out the responsibilities and functions of the position held by the Grantee by reason of any medically determinable physical or mental impairment.  A Grantee shall not be considered to have incurred a Disability unless he or she furnishes proof of such impairment sufficient to satisfy the Administrator in its discretion.  Notwithstanding the above, (i) with respect to an Incentive Stock Option, Disability or Disabled shall mean permanent and total disability as defined in Section 22(e)(3) of the Code and (ii) to the extent an Option is subject to Section 409A of the Code, and payment or settlement of the Option is to be accelerated solely as a result of the Eligible Participant’s Disability, Disability shall have the meaning ascribed thereto under Section 409A of the Code and the Treasury guidance promulgated thereunder;

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(v) “Disinterested Shareholder Approval” means approval by a majority of the votes cast by all the Company’s shareholders at a duly constituted shareholders’ meeting, excluding votes attached to shares beneficially owned by Insiders;

(w) “Eligible Participant” means any person who is an Officer, a Director, an Employee or a Consultant, including individuals who are foreign nationals or are employed or reside outside the United States;

(x) “Employee” means any person who is a full-time or part-time employee of the Company or any Related Entity;

(y) “Exchange Act” means the United States Securities Exchange Act of 1934, as amended;

(z) “Fair Market Value” means, as of any date, the value of a Share determined in good faith by the Administrator.  By way of illustration, but not limitation, for the purpose of this definition, good faith shall be met if the Administrator employs the following methods:

(i) Listed Stock.  If the Common Stock is traded on any established stock exchange or quoted on a national market system, Fair Market Value shall be (A) the closing sales price for the Common Stock as quoted on that stock exchange or system for the date the value is to be determined (the “Value Date”) as reported in The Wall Street Journal or a similar publication, or (B) if the rules of the applicable stock exchange require, the volume-weighted average trading price for five days prior to the date the Board approves the grant of the Award.  If no sales are reported as having occurred on the Value Date, Fair Market Value shall be that closing sales price for the last preceding trading day on which sales of Common Stock is reported as having occurred.  If no sales are reported as having occurred during the five trading days before the Value Date, Fair Market Value shall be the closing bid for Common Stock on the Value Date.  If the Common Stock is listed on multiple exchanges or systems, Fair Market Value shall be based on sales or bids on the primary exchange or system on which Common Stock is traded or quoted.  If the rules of any applicable stock exchange or system require a different method of calculating Fair Market Value, then such method as is required by those rules;

(ii) Stock Quoted by Securities Dealer.  If Common Stock is regularly quoted by a recognized securities dealer but selling prices are not reported on any established stock exchange or quoted on a national market system, Fair Market Value shall be the mean between the high bid and low asked prices on the Value Date.  If no prices are quoted for the Value Date, Fair Market Value shall be the mean between the high bid and low asked prices on the last preceding trading day on which any bid and asked prices were quoted;

(iii) No Established Market.  If Common Stock is not traded on any established stock exchange or quoted on a national market system and is not quoted by a recognized securities dealer, the Administrator will determine Fair Market Value in good faith.  The Administrator will consider the following factors, and any others it considers significant, in determining Fair Market Value: (A) the price at which other securities of the Company have been issued to purchasers other than Employees, Directors, or Consultants; (B) the Company’s net worth, prospective earning power, dividend-paying capacity, and non-operating assets, if any; and (C) any other relevant factors, including the economic outlook for the Company and the Company’s industry, the Company’s position in that industry, the Company’s goodwill and other intellectual property, and the values of securities of other businesses in the same industry;

(iv) Additional Valuation.  For publicly traded companies, any valuation method permitted under Section 20.2031-2 of the Estate Tax Regulations; or

(v) Non-Publicly Traded Stock.  For non-publicly traded stock, the Fair Market Value of the Common Stock at the Grant Date based on an average of the Fair Market Values as of such date set forth in the opinions of completely independent and well-qualified experts (the Participant’s status as a majority or minority shareholder may be taken into consideration).

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Regardless of whether the Common Stock offered under the Award is publicly traded, a good faith attempt under this definition shall not be met unless the Fair Market Value of the Common Stock on the Grant Date is determined with regard to nonlapse restrictions (as defined in Section 1.83-3(h) of the Treasury Regulations) and without regard to lapse restrictions (as defined in Section 1.83-3(i) of the Treasury Regulations);

(aa) “Grantee” means an Eligible Participant who receives an Award pursuant to an Award Agreement;

(bb) “Grant Date” means the date the Administrator approves that grant of an Award.  However, if the Administrator specifies that an Award’s Grant Date is a future date or the date on which a condition is satisfied, the Grant Date for such Award is that future date or the date that the condition is satisfied;

(cc) “Incentive Stock Option” means an Option within the meaning of Section 422 of the Code;

(dd)“Insider” means:

(i)a Director or Senior Officer of the Company;

(ii) a Director or Senior Officer of a person that is itself an Insider or Subsidiary of the Company;

(iii)a person that has

(A)direct or indirect beneficial ownership of,

(B)control or direction over, or

(C) a combination of direct or indirect beneficial ownership of and control or direction over,

securities of the Company carrying more than 10% of the voting rights attached to all the Company’s outstanding voting securities, excluding, for the purpose of the calculation of the percentage held, any securities held by the person as underwriter in the course of a distribution; or

(iv) the Company itself, if it has purchased, redeemed or otherwise acquired any securities of its own issue, for so long as it continues to hold those securities;

(ee) “Named Executive Officer” means, if applicable, an Eligible Participant who, as of the date of vesting and/or payout of an Award, is one of the group of Covered Employees as defined;

(ff) “Non-Qualified Stock Option” means an Option which is not an Incentive Stock Option;

(gg) “Officer” means a person who is an officer, including a Senior Officer, of the Company or a Related Entity within the meaning of Section 16 of the Exchange Act and the rules and regulations promulgated thereunder;

(hh) “Option” means an option to purchase Shares pursuant to an Award Agreement granted under the Plan;

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(ii) “Parent” means a “parent corporation”, whether now or hereafter existing, as defined in Section 424(e) of the Code;

(jj) “Performance-Based Compensation” means compensation qualifying as “performance-based compensation” under Section 162(m) of the Code;

(kk)“Plan” means this 2013 Stock Incentive Plan as amended from time to time;

(ll) “Related Entity” means any Parent or Subsidiary, and includes any business, corporation, partnership, limited liability company or other entity in which the Company, a Parent or a Subsidiary holds a greater than 50% ownership interest, directly or indirectly;

(mm) “Related Entity Disposition” means the sale, distribution or other disposition by the Company of all or substantially all of the Company’s interests in any Related Entity effected by a sale, merger or consolidation or other transaction involving that Related Entity or the sale of all or substantially all of the assets of that Related Entity;

(nn) “Restricted Stock” means Shares issued under the Plan to the Grantee for such consideration, if any, and subject to such restrictions on transfer, rights of first refusal, repurchase provisions, forfeiture provisions, and other terms and conditions as, established by the Administrator and specified in the related Award Agreement;

(oo) “Restricted Stock Unit” means a notional account established pursuant to an Award granted to a Grantee, as described in this Plan, that is (i) valued solely by reference to Shares, (ii) subject to restrictions specified in the Award Agreement, and (iii) payable only in Shares;

(pp) “Restriction Period” means the period during which the transfer of Shares of Restricted Stock is limited in some way (based on the passage of time, the achievement of performance objectives, or the occurrence of other events as determined by the Administrator, in its sole discretion) or the Restricted Stock is not vested;

(qq) “SAR” means a stock appreciation right entitling the Grantee to Shares or cash compensation, as established by the Administrator, measured by appreciation in the value of Common Stock;

(rr) “SEC” means the United States Securities Exchange Commission;

(ss)“Senior Officer” means:

(i) the chair or vice chair of the Board, the president, the chief executive officer, the chief financial officer, a vice-president, the secretary, the treasurer or the general manager of the Company or a Related Entity;

(ii) any individual who performs functions for a person similar to those normally performed by an individual occupying any office specified in Section 2.1(ss)(i) above; and

(iii) the five highest paid employees of the Company or a Related Entity, including any individual referred to in Section 2.1(ss)(i) or 2.1(ss)(ii) and excluding a commissioned salesperson who does not act in a managerial capacity;

(tt)“Share” means a share of the Common Stock; and

(uu) “Subsidiary” means a “subsidiary corporation”, whether now or hereafter existing, as defined in Section 424(f) of the Code.

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3. STOCK SUBJECT TO THE PLAN

Number of Shares Available

3.1   (a) Subject to the provisions of Section 18, the maximum aggregate number of Shares which may be issued pursuant to all Awards (including Incentive Stock Options) under this Plan is 2,650,000 (the “Maximum Number”).  See Section 29 for Reservation of Shares.

(b) Shares that have been issued under the Plan pursuant to an Award shall not be returned to the Plan and shall not become available for future issuance under the Plan except that Shares (i) covered by an Award (or portion of an Award) which is forfeited or cancelled, expires or is settled in cash, or (ii) withheld to satisfy a Grantee’s minimum tax withholding obligations, shall be deemed not to have been issued for purposes of determining the Maximum Number of Shares which may be issued under the Plan.  Also, only the net numbers of Shares that are issued pursuant to the exercise of an Award shall be counted against the Maximum Number.

(c) However, in the event that prior to the Award’s cancellation, termination, expiration, forfeiture or lapse, the holder of the Award at any time received one or more elements of beneficial ownership pursuant to such Award (as defined by the SEC, pursuant to any rule or interpretations promulgated under Section 16 of the Exchange Act), the Shares subject to such Award shall not again be made available for regrant under the Plan.

Shares to Insiders

3.2Subject to Section 15.1(b) and 15.1(c), no Insider of the Company is eligible to receive an Award where:

(a)the Insider is not a Director or Senior Officer of the Company;

(b) any Award, together with all of the Company’s other previously established or proposed Awards under the Plan could result at any time in:

(i) the number of Shares reserved for issuance pursuant to Options granted to Insiders exceeding 50% of the outstanding issue of Common Stock; or

(ii) the issuance to Insiders pursuant to the exercise of Options, within a one year period of a number of Shares exceeding 50% of the outstanding issue of the Common Stock;

provided, however, that this restriction on the eligibility of Insiders to receive an Award shall cease to apply if it is no longer required under any Applicable Laws.

Limitations on Award

3.3Unless and until the Administrator determines that an Award to a Grantee is not designed to qualify as Performance-Based Compensation, the following limits (the “Award Limits”) shall apply to grants of Awards to Grantees subject to the Award Limits by Applicable Laws under this Plan:

(a) Options and SARs.  Notwithstanding any provision in the Plan to the contrary (but subject to adjustment as provided in Section 18), the maximum number of Shares with respect to one or more Options and/or Stock Appreciation Rights that may be granted during any one calendar year under the Plan to any one Grantee shall be 1,325,000; all of which may be granted as Incentive Stock Options); and

(b) Other Awards.  The maximum aggregate grant with respect to Awards of Restricted Stock, unrestricted Shares, Restricted Stock Units and Deferred Stock Units (or used to provide a basis of measurement for or to determine the value of Restricted Stock Units and Deferred Stock Units) in any one calendar year to any one Grantee (determined on the date of payment of settlement) shall be 1,325,000.

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4. ADMINISTRATION

Authority of Plan Administrator

4.1Authority to control and manage the operation and administration of this Plan shall be vested in the Administrator.

Powers of the Administrator

4.2Subject to Applicable Laws and the provisions of the Plan or subplans hereof (including any other powers given to the Administrator hereunder), and except as otherwise provided by the Board, the Administrator shall have the exclusive power and authority, in its discretion:

(a) to construe and interpret this Plan and any agreements defining the rights and obligations of  the Company and Grantees under this Plan;

(b) to select the Eligible Participants to whom Awards may be granted from time to time hereunder;

(c)to determine whether and to what extent Awards are granted hereunder;

(d) to determine the number of Shares or the amount of other consideration to be covered by each Award granted hereunder;

(e) to approve forms of Award Agreements for use under the Plan, which need not be identical for each Grantee;

(f) to determine the terms and conditions of any Award granted under the Plan, including, but not limited to, the exercise price, grant price or purchase price based on the Fair Market Value of the same, any restrictions or limitations on the Award, any schedule for lapse of forfeiture restrictions or restrictions on the exercisability of the Award, and acceleration or waivers thereof, based in each case on such considerations as the Committee in its sole discretion determines that is not inconsistent with any rule or regulation under any tax or securities laws or includes an alternative right that does not disqualify an Incentive Stock Option under applicable regulations;

(g) to amend the terms of any outstanding Award granted under the Plan, provided that any amendment that would adversely affect the Grantee’s rights under an existing Award shall not be made without the Grantee’s consent unless as a result of a change in Applicable Law;

(h) to suspend the right of a holder to exercise all or part of an Award for any reason that the Administrator considers in the best interest of the Company;

(i) subject to regulatory approval, amend or suspend the Plan, or revoke or alter any action taken in connection therewith, except that no general amendment or suspension of the Plan, shall, without the written consent of all Grantees, alter or impair any Award granted under the Plan unless as a result of a change in the Applicable Law;

(j) to establish additional terms, conditions, rules or procedures to accommodate the rules or laws of applicable foreign jurisdictions and to afford Grantees favorable treatment under such laws; provided, however, that no Award shall be granted under any such additional terms, conditions, rules or procedures with terms or conditions which are inconsistent with the provisions of the Plan;

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(k)to further define the terms used in this Plan;

(l) to correct any defect or supply any omission or reconcile any inconsistency in this Plan or in any Award Agreement;

(m)to provide for rights of refusal and/or repurchase rights;

(n) to amend outstanding Award Agreements to provide for, among other things, any change or modification which the Administrator could have provided for upon the grant of an Award or in furtherance of the powers provided for herein that does not disqualify an Incentive Stock Option under applicable regulations unless the Grantee so consents;

(o) to prescribe, amend and rescind rules and regulations relating to the administration of this Plan; and

(p) to take such other action, not inconsistent with the terms of the Plan, as the Administrator deems appropriate.

Effect of Administrator’s Decision

4.3All decisions, determinations and interpretations of the Administrator shall be conclusive and binding on all persons.  The Administrator shall not be liable for any decision, action or omission respecting this Plan, or any Awards granted or Shares sold under this Plan.  In the event an Award is granted in a manner inconsistent with the provisions of this Section 4, such Award shall be presumptively valid as of its grant date to the extent permitted by the Applicable Laws.

Action by Committee

4.4Except as otherwise provided by committee charter or other similar corporate governance documents, for purposes of administering the Plan, the following rules of procedure shall govern the Committee.  A majority of the Committee shall constitute a quorum. The acts of a majority of the members present at any meeting at which a quorum is present, and acts approved unanimously in writing by the members of the Committee in lieu of a meeting, shall be deemed the acts of the Committee.  Each member of the Committee is entitled to, in good faith, rely or act upon any report or other information furnished to that member by any officer or other employee of the Company or any Parent or Affiliate, the Company’s independent certified public accountants, or any executive compensation consultant or other professional retained by the Company to assist in the administration of the Plan.

Limitation on Liability

4.5To the extent permitted by applicable law in effect from time to time, no member of the Administrator shall be liable for any action or omission of any other member of the Administrator nor for any act or omission on the member’s own part, excepting only the member’s own wilful misconduct or gross negligence, arising out of or related to this Plan.  The Company shall pay expenses incurred by, and satisfy a judgment or fine rendered or levied against, a present or former member of the Administrator in any action against such person (whether or not the Company is joined as a party defendant) to impose liability or a penalty on such person for an act alleged to have been committed by such person while a member of the Administrator arising with respect to this Plan or administration thereof or out of membership on the Administrator or by the Company, or all or any combination of the preceding, provided, the member was acting in good faith, within what such member reasonably believed to have been within the scope of his or her employment or authority and for a purpose which he or she reasonably believed to be in the best interests of the Company or its stockholders.  Payments authorized hereunder include amounts paid and expenses incurred in settling any such action or threatened action.  The provisions of this Section 4.5 shall apply to the estate, executor, administrator, heirs, legatees or devisees of a member of the Administrator, and the term “person” as used on this Section 4.5 shall include the estate, executor, administrator, heirs, legatees, or devisees of such person.

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5. ELIGIBILITY

Except as otherwise provided, all types of Awards may be granted to Eligible Participants. An Eligible Participant who has been granted an Award may be, if he or she continues to be eligible, granted additional Awards.

6. AWARDS

Type of Awards

6.1The Administrator is authorized to award any type of arrangement to an Eligible Participant that is not inconsistent with the provisions of the Plan and that by its terms involves or might involve the issuance of:

(a)Shares, including unrestricted Shares;

(b)Options;

(c) SARs or similar rights with a fixed or variable price related to the Fair Market Value of the Shares and with an exercise or conversion privilege related to the passage of time, the occurrence of one or more events, or the satisfaction of performance criteria or other conditions;

(d) any other security with the value derived from the value of the Shares, such as Restricted Stock and Restricted Stock Units;

(e)Deferred Stock Units;

(f)Dividend Equivalent Rights, as defined in Section 13; or

(g)any combination of the foregoing.

Designation of Award

6.2Each type of Award shall be designated in the Award Agreement.  In the case of an Option, the Option shall be designated as either an Incentive Stock Option or a Non-Qualified Stock Option.  But see Section 7.3(a) regarding exceeding the Incentive Stock Option threshold.

7. GRANT OF OPTIONS; TERMS AND CONDITIONS OF GRANT

Grant of Options

7.1 (a)           One or more Options may be granted to any Eligible Participant.  Subject to the express provisions of this Plan, the Administrator shall determine from the Eligible Participants those individuals to whom Options under this Plan may be granted.  The Shares underlying a grant of an Option may be in the form of Restricted Stock or unrestricted Stock.

(b) Further, subject to the express provisions of this Plan, the Administrator shall specify the Grant Date, the number of Shares covered by the Option, the exercise price and the terms and conditions for exercise of the Options.  As soon as practicable after the Grant Date, the Company shall provide the Grantee with a written Award Agreement in the form approved by the Administrator, which sets out the Grant Date, the number of Shares covered by the Option, the exercise price and the terms and conditions for exercise of the Option.

(c) The Administrator may, in its absolute discretion, grant Options under this Plan at any time and from time to time before the expiration of this Plan.

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General Terms and Conditions

7.2Except as otherwise provided herein, the Options shall be subject to the following terms and conditions and such other terms and conditions not inconsistent with this Plan as the Administrator may impose:

(a) Exercise of Option.  The Administrator may determine in its discretion whether any Option shall be subject to vesting and the terms and conditions of any such vesting.  The Award Agreement shall contain any such vesting schedule;

(b) Option Term.  Each Option and all rights or obligations thereunder shall expire on such date as shall be determined by the Administrator, but not later than ten years after the Grant Date (five years in the case of an Incentive Stock Option when the Optionee beneficially owns more than 10% of the total combined voting power of all classes of stock of the Company or any Parent or Subsidiary (a “Ten Percent Stockholder”), as determined with reference to Rule 13d-3 of the Exchange Act), and shall be subject to earlier termination as hereinafter provided;

(c) Exercise Price.  The Exercise Price of any Option shall be determined by the Administrator when the Option is granted, at such Exercise Price as may be determined by the Administrator in the Administrator’s sole and absolute discretion; provided, however, that the Exercise Price may not be less than 100% of the Fair Market Value of the Shares on the Grant Date with respect to any Incentive Stock Options which are granted and, provided further, that the Exercise Price of any Incentive Stock Option granted to a Ten Percent Stockholder shall not be less than 110% of the Fair Market Value of the Shares on the Grant Date.  Payment for the Shares purchased shall be made in accordance with Section 16 of this Plan.  The Administrator is authorized to issue Options, whether Incentive Stock Options or Non-qualified Stock Options, at an option price lower than or in excess of the Fair Market Value on the Grant Date, to determine the terms and conditions of any Award granted under the Plan, including, but not limited to, the exercise price, grant price or purchase price, any restrictions or limitations on the Award, any schedule for lapse of forfeiture restrictions or restrictions on the exercisability of the Award, and acceleration or waivers thereof, based in each case on such considerations as the Committee in its sole discretion determines that is not inconsistent with any rule or regulation under any tax or securities laws or includes an alternative right that does not disqualify an Incentive Stock Option under applicable regulations;

(d) Method of Exercise.  Options may be exercised only by delivery to the Company of a stock option exercise agreement (the “Exercise Agreement”) in a form approved by the Administrator (which need not be the same for each Grantee), stating the number of Shares being purchased, the restrictions imposed on the Shares purchased under such Exercise Agreement, if any, and such representations and agreements regarding the Grantee’s investment intent and access to information and other matters, if any, as may be required or desirable by the Company to comply with applicable securities laws, together with payment in full of the exercise price for the number of Shares being purchased;

(e)Exercise After Certain Events.

(i)Termination of Continuous Services.

(A)Options.

(I) Termination of Continuous Services.  If for any reason other than Disability or death, a Grantee terminates Continuous Services with the Company or a Subsidiary, vested Options held at the date of such termination may be exercised, in whole or in part, either (i) at any time within three months after the date of such termination, or (ii) during any greater or lesser period as specified in the Award Agreement or (iii) during any greater or lesser period as may be determined by the Administrator, in its sole and absolute discretion, prior the date of such termination (but in no event after the earlier of (A) the expiration date of the Option as set forth in the Award Agreement and (B) ten years from the Grant Date (five years for a Ten Percent Stockholder if the Option is an Incentive Stock Option)).

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(II) Continuation of Services as Consultant/Advisor.  If a Grantee granted an Incentive Stock Option terminates employment but continues as a Consultant (no termination of Continuous Services), the Grantee need not exercise an Incentive Stock Option within either of the termination periods provided for immediately hereinabove but shall be entitled to exercise, in whole or in part, either (i) at any time within three months after the then date of termination of Continuous Services to the Company or a Subsidiary, or (ii) during any greater or lesser period as specified in the Award Agreement or (iii) during any greater or lesser period as may be determined by the Administrator, in its sole and absolute discretion, prior the date of such then termination of Continuous Services to the Company or the Subsidiary (one year in the event of Disability or death) (but in no event after the earlier of (A) the expiration date of the Option as set forth in the Award Agreement and (B) ten years from the Grant Date (five years for a Ten Percent Stockholder if the Option is an Incentive Stock Option)).  However, if the Grantee does not exercise within three months of termination of employment, pursuant to Section 422 of the Code the Option shall not qualify as an Incentive Stock Option.

(B) Disability and Death.  If a Grantee becomes Disabled while rendering Continuous Services to the Company or a Subsidiary, or dies while employed by the Company or Subsidiary or within three months thereafter, vested Options then held may be exercised by the Grantee, the Grantee’s personal representative, or by the person to whom the Option is transferred by the laws of descent and distribution, in whole or in part, at any time within one year after the termination because of the Disability or death or any lesser period specified in the Award Agreement (but in no event after the earlier of (i) the expiration date of the Option as set forth in the Award Agreement, and (ii) ten years from the Grant Date (five years for a Ten Percent Stockholder if the Option is an Incentive Stock Option).

Limitations on Grant of Incentive Stock Options

7.3 (a)           Threshold.  The aggregate Fair Market Value (determined as of the Grant Date) of the Shares for which Incentive Stock Options may first become exercisable by any Grantee during any calendar year under this Plan, together with that of Shares subject to Incentive Stock Options first exercisable by such Grantee under any other plan of the Company or any Parent or Subsidiary, shall not exceed $100,000.  For purposes of this Section 7.3(a), all Options in excess of the $100,000 threshold shall be treated as Non-Qualified Stock Options notwithstanding the designation as Incentive Stock Options.  For this purpose, Options shall be taken into account in the order in which they were granted, and the Fair Market Value of the Shares shall be determined as of the date the Option with respect to such Shares is granted.

(b) Compliance with Section 422 of the Code.  There shall be imposed in the Award Agreement relating to Incentive Stock Options such terms and conditions as are required in order that the Option be an “incentive stock option” as that term is defined in Section 422 of the Code.

(c) Requirement of Employment.  No Incentive Stock Option may be granted to any person who is not an Employee of the Company or a Parent or Subsidiary of the Company.

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8. RESTRICTED STOCK AWARDS

Grant of Restricted Stock Awards

8.1Subject to the terms and provisions of this Plan, the Administrator is authorized to make awards of Restricted Stock to any Eligible Participant in such amounts and subject to such terms and conditions as may be selected by the Administrator.  The restrictions may lapse separately or in combination at such times, under such circumstances, in such instalments, time-based or upon the satisfaction of performance goals or otherwise, as the Administrator determines at the time of the grant of the Award or thereafter. (See Performance Goals, Section 14.4).  All awards of Restricted Stock shall be evidenced by Award Agreements.

Consideration

8.2Restricted Stock may be issued in connection with:

(a)Services.  Services rendered to the Company or an Affiliate (i.e. bonus); and/or

(b) Purchase Price.  A purchase price, as specified in the Award Agreement related to such Restricted Stock, equal to not be less than 100% of the Fair Market Value of the Shares underlying the Restricted Stock on the date of issuance.

Voting and Dividends

8.3Unless the Administrator in its sole and absolute discretion otherwise provides in an Award Agreement, holders of Restricted Stock shall have the right to vote such Restricted Stock and the right to receive any dividends declared or paid with respect to such Restricted Stock.  The Administrator may provide that any dividends paid on Restricted Stock must be reinvested in shares of Stock, which may or may not be subject to the same vesting conditions and restrictions applicable to such Restricted Stock.  All distributions, if any, received by a Grantee with respect to Restricted Stock as a result of any stock split, stock dividend, combination of shares, or other similar transaction shall be subject to the restrictions applicable to the original Award.

Forfeiture

8.4In the case of an event of forfeiture pursuant to the Award Agreement, including failure to satisfy the restriction period or a performance objective during the applicable restriction period, any Restricted Stock that has not vested prior to the event of forfeiture shall automatically expire, and all of the rights, title and interest of the Grantee thereunder shall be forfeited in their entirety including but not limited to any right to vote and receive dividends with respect to the Restricted Stock.  Notwithstanding the foregoing, the Administrator may provide in any Award Agreement that restrictions or forfeiture conditions relating to Restricted Stock shall be waived in whole or in part in the event of terminations resulting from specified causes, and the Administrator may in other cases waive in whole or in part restrictions or forfeiture conditions relating to Restricted Stock, provided such waiver is in accordance with the Applicable Laws.

Certificates for Restricted Stock

8.5Restricted Stock granted under this Plan may be evidenced in such manner as the Administrator shall determine, including by way of certificates.  The Administrator may provide in an Award Agreement that either (i) the Secretary of the Company shall hold such certificates for the Grantee’s benefit until such time as the Restricted Stock is forfeited to the Company or the restrictions lapse, (see Escrow; Pledge of Shares, Section 23) or (ii) such certificates shall be delivered to the Grantee, provided, however, that such certificates shall bear a legend or legends that comply with the applicable securities laws and regulations and make appropriate reference to the restrictions imposed under this Plan and the Award Agreement.

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9. UNRESTRICTED STOCK AWARDS

The Administrator may, in its sole discretion, grant (or sell at not less than 100% of the Fair Market Value or such other higher purchase price determined by the Administrator in the Award Agreement) an Award of unrestricted Shares to any Grantee pursuant to which such Grantee may receive Shares free of any restrictions under this Plan.

10. RESTRICTED STOCK UNITS

Grant of Restricted Stock Units

10.1Subject to the terms and provisions of this Plan, the Administrator is authorized to make awards of Restricted Stock Units to any Eligible Participant in such amounts and subject to such terms and conditions as may be selected by the Administrator.  These restrictions may lapse separately or in combination at such times, under such circumstances, in such instalments, time-based or upon the satisfaction of performance goals or otherwise, as the Administrator determines at the time of the grant of the Award or thereafter. (See Performance Goals, Section 14.4).  All awards of Restricted Stock Units shall be evidenced by Award Agreements.

Number of Restricted Stock Units

10.2The Award Agreement shall specify the number of Share equivalent units granted and such other provisions as the Administrator determines.

Consideration

10.3Restricted Stock Units may be issued in connection with:

(a)Services.  Services rendered to the Company or an Affiliate (i.e. bonus); and/or

(b) Purchase Price.  A purchase price as specified in the Award Agreement related to such Restricted Stock Units, equal to not be less than 100% of the Fair Market Value of the Shares underlying the Restricted Stock Units on the date of issuance.

No Voting Rights

10.4The holders of Restricted Stock Units shall have no rights as stockholders of the Company.

Dividend Equivalency

10.5The Administrator, in its sole and absolute discretion, may provide in an Award Agreement evidencing a grant of Restricted Stock Units that the holder shall be entitled to receive, upon the Company’s payment of a cash dividend on its outstanding Shares, a cash payment for each Restricted Stock Unit.  (See Section 13, Dividend Equivalent Right).  Such Award Agreement may also provide that such cash payment shall be deemed reinvested in additional Restricted Stock Units at a price per unit equal to the Fair Market Value of a Share on the date that such dividend is paid.

Creditor’s Rights

10.6A holder of Restricted Stock Units shall have no rights other than those of a general creditor of the Company.  Restricted Stock Units represent an unfunded and unsecured obligation of the Company, subject to the terms and conditions of the applicable Award Agreement.

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Settlement of Restricted Stock Units

10.7Each Restricted Stock Unit shall be paid and settled by the issuance of Restricted Stock or unrestricted Shares in accordance with the Award Agreement and if such settlement is subject to Section 409A of the Code only upon any one or more of the following as provided for in the Award Agreement:

(a)a specific date or date determinable by a fixed schedule;

(b) upon the Eligible Participant’s termination of Continuous Services to the extent the same constitutes a separation from services for purposes of Section 409A of the Code except that if an Eligible Participant is a “key employee” as defined in Section 409A of the Code for such purposes, then payment or settlement shall occur 6 months following such separation of service;

(c)as a result of the Eligible Participant’s death or Disability; or

(d) in connection with or as a result of a Change of Control in compliance with Section 409A of the Code.

Forfeiture

10.8Upon failure to satisfy any requirement for settlement as set forth in the Award Agreement, including failure to satisfy any restriction period or performance objective, any Restricted Stock Units held by the Grantee shall automatically expire, and all of the rights, title and interest of the Grantee thereunder shall be forfeited in their entirety including but not limited to any right to receive dividends with respect to the Restricted Stock Units.

11. DIRECTOR SHARES AND DIRECTOR DEFERRED STOCK UNITS

The grant of Awards of Shares to Directors and the election by Directors to defer the receipt of the Awards of Shares (the “Deferred Stock Units”) shall be governed by the provisions of Subpart A which is attached hereto.  The provisions of Subpart A are attached hereto as part of this Plan and are incorporated herein by reference.

12. STOCK APPRECIATION RIGHTS

Awards of SARs

12.1An SAR is an award to receive a number of Shares (which may consist of Restricted Stock), or cash, or Shares and cash, as determined by the Administrator in accordance with Section 12.4 below, for services rendered to the Company.  A SAR may be awarded pursuant to an Award Agreement that shall be in such form (which need not be the same for each Grantee) as the Administrator shall from time to time approve, and shall comply with and be subject to the terms and conditions of this Plan.  A SAR may vary from Grantee to Grantee and between groups of Grantees, and may be based upon performance objectives (See Performance Goals in Section 14.4).

Term

12.2The term of a SAR shall be set forth in the Award Agreement as determined by the Administrator.

Exercise

12.3A Grantee desiring to exercise a SAR shall give written notice of such exercise to the Company, which notice shall state the proportion of Shares and cash that the Grantee desires to receive pursuant to the SAR exercised, subject to the discretion of the Administrator.  Upon receipt of the notice from the Grantee, subject to the Administrator’s election to pay cash as provided in Section 12.4 below, the Company shall deliver to the person entitled thereto (i) a certificate or certificates for Shares and/or (ii) a cash payment, in accordance with Section 12.4 below.  The date the Company receives written notice of such exercise hereunder is referred to in this Section 12 as the “exercise date”.

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Number of Shares or Amount of Cash

12.4Subject to the discretion of the Administrator to substitute cash for Shares, or some portion of the Shares for cash, the amount of Shares that may be issued pursuant to the exercise of a SAR shall be determined by dividing: (i) the total number of Shares as to which the SAR is exercised, multiplied by the amount by which the Fair Market Value of the Shares on the exercise date exceeds the Fair Market Value of a Share on the date of grant of the SAR; by (ii) the Fair Market Value of a Share on the exercise date; provided, however, that fractional Shares shall not be issued and in lieu thereof, a cash adjustment shall be paid.  In lieu of issuing Shares upon the exercise of a SAR, the Administrator in its sole discretion may elect to pay the cash equivalent of the Fair Market Value of the Shares on the exercise date for any or all of the Shares that would otherwise be issuable upon exercise of the SAR.

Effect of Exercise

12.5A partial exercise of a SAR shall not affect the right to exercise the remaining SAR from time to time in accordance with this Plan and the applicable Award Agreement with respect to the remaining shares subject to the SAR.

Forfeiture

12.6In the case of an event of forfeiture pursuant to the Award Agreement, including failure to satisfy any restriction period or a performance objective, any SAR that has not vested prior to the date of termination shall automatically expire, and all of the rights, title and interest of the Grantee thereunder shall be forfeited in their entirety.

13. DIVIDEND EQUIVALENT RIGHT

A dividend equivalent right is an Award entitling the recipient to receive credits based on cash distributions that would have been paid on the Shares specified in the dividend equivalent right (or other Award to which it relates) if such Shares had been issued to and held by the recipient (a “Dividend Equivalent Right”).  A Dividend Equivalent Right may be granted hereunder to any Grantee as a component of another Award or as a freestanding Award.  The terms and conditions of Dividend Equivalent Right shall be specified in the grant.  Dividend equivalents credited to the holder of a Dividend Equivalent Right may be paid currently or may be deemed to be reinvested in additional Shares, which may thereafter accrue additional equivalents.  Any such reinvestment shall be at Fair Market Value on the date of reinvestment. Dividend Equivalent Rights may be settled in cash or Shares or a combination thereof, in a single instalment or instalments, all determined in the sole discretion of the Administrator.  A Dividend Equivalent Right granted as a component of another Award may provide that such Dividend Equivalent Right shall be settled upon exercise, settlement, or payment of, or lapse of restrictions on, such other Award, and that such Dividend Equivalent Right shall expire or be forfeited or annulled under the same conditions as such other Award.  A Dividend Equivalent Right granted as a component of another Award may also contain terms and conditions different from such other Award.

14. TERMS AND CONDITIONS OF AWARDS

In General

14.1Subject to the terms of the Plan and Applicable Laws, the Administrator shall determine the provisions, terms, and conditions of each Award including, but not limited to, the Award vesting schedule, repurchase provisions, rights of first refusal, forfeiture provisions, form of payment (cash, Shares, or other consideration) upon settlement of the Award, payment contingencies, and satisfaction of any performance criteria.

Term of Award

14.2The term of each Award shall be the term stated in the Award Agreement.

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Transferability

14.3  (a)Limits on Transfer.  No right or interest of a Grantee in any unexercised or restricted Award may be pledged, encumbered or hypothecated to or in favor of any party other than to the Company or a Related Entity or Affiliate.  No Award shall be sold, assigned, transferred or disposed of by a Grantee other than by the laws of descent and distribution or, in the case of an Incentive Stock Option, pursuant to a domestic relations order that would satisfy Section 414(p)(1)(A) of the Code if such Section applied to an Award under the Plan; provided, however, that the Administrator may (but need not) permit other transfers where the Administrator concludes that such transferability (i) does not result in accelerated taxation or other adverse tax consequences, (ii) does not cause any Option intended to be an Incentive Stock Option to fail to be described in Section 422(b) of the Code, and (iii) is otherwise appropriate and desirable, taking into account any factors deemed relevant, including, without limitation, state or federal tax or securities laws applicable to transferable Awards.

(b) Beneficiaries.  Notwithstanding Section 14.3(a), a Grantee may, in the manner determined by the Administrator, designate a beneficiary to exercise the rights of the Grantee and to receive any distribution with respect to any Award upon the Grantee’s death.  A beneficiary, legal guardian, legal representative or other person claiming any rights under the Plan is subject to all terms and conditions of the Plan and any Award Agreement applicable to the Grantee, except to the extent the Plan and such Award Agreement otherwise provide, and to any additional restrictions deemed necessary or appropriate by the Administrator.  If no beneficiary has been designated or survives the Grantee, payment shall be made to the Grantee’s estate. Subject to the foregoing, a beneficiary designation may be changed or revoked by a Grantee at any time, provided the change or revocation is filed with the Administrator.

Performance Goals

14.4In order to preserve the deductibility of an Award under Section 162(m) of the Code, the Administrator may determine that any Award granted pursuant to this Plan to a Grantee that is or is expected to become a Covered Employee shall be determined solely on the basis of (a) the achievement by the Company or Subsidiary of a specified target return, or target growth in return, on equity or assets, (b) the Company’s stock price, (c) the Company’s total shareholder return (stock price appreciation plus reinvested dividends) relative to a defined comparison group or target over a specific performance period, (d) the achievement by the Company or a Parent or Subsidiary, or a business unit of any such entity, of a specified target, or target growth in, net income, earnings per share, earnings before income and taxes, and earnings before income, taxes, depreciation and amortization, or (e) any combination of the goals set forth in (a) through (d) above.  If an Award is made on such basis, the Administrator shall establish goals prior to the beginning of the period for which such performance goal relates (or such later date as may be permitted under Section 162(m) of the Code or the regulations thereunder but not later than 90 days after commencement of the period of services to which the performance goal relates), and the Administrator has the right for any reason to reduce (but not increase) the Award, notwithstanding the achievement of a specified goal.  Any payment of an Award granted with performance goals shall be conditioned on the written certification of the Administrator in each case that the performance goals and any other material conditions were satisfied.

In addition, to the extent that Section 409A is applicable, (i) performance-based compensation shall also be contingent on the satisfaction of pre-established organizational or individual performance criteria relating to a performance period of at least 12 consecutive months in which the Eligible Participant performs services and (ii) performance goals shall be established not later than 90 calendar days after the beginning of any performance period to which the performance goal relates, provided that the outcome is substantially uncertain at the time the criteria are established.

Acceleration

14.5The Administrator may, in its sole discretion (but subject to the limitations of and compliance with Section 409A of the Code and Section 14.7 in connection therewith), at any time (including, without limitation, prior to, coincident with or subsequent to a Change of Control) determine that (a) all or a portion of a Grantee’s Awards shall become fully or partially exercisable, and/or (b) all or a part of the restrictions on all or a portion of the outstanding Awards shall lapse, in each case, as of such date as the Administrator may, in its sole discretion, declare.  The Administrator may discriminate among Grantees and among Awards granted to a Grantee in exercising its discretion pursuant to this Section 14.5.

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Compliance with Section 162(m) of the Code

14.6Notwithstanding any provision of this Plan to the contrary, if the Administrator determines that compliance with Section 162(m) of the Code is required or desired, all Awards granted under this Plan to Named Executive Officers shall comply with the requirements of Section 162(m) of the Code.  In addition, in the event that changes are made to Section 162(m) of the Code to permit greater flexibility with respect to any Award or Awards under this Plan, the Administrator may make any adjustments it deems appropriate.

Compliance with Section 409A of the Code

14.7Notwithstanding any provision of this Plan to the contrary, if any provision of this Plan or an Award Agreement contravenes any regulations or Treasury guidance promulgated under Section 409A of the Code or could cause an Award to be subject to the interest and penalties under Section 409A of the Code, such provision of this Plan or any Award Agreement shall be modified to maintain, to the maximum extent practicable, the original intent of the applicable provision without violating the provisions of Section 409A of the Code.  In addition, in the event that changes are made to Section 409A of the Code to permit greater flexibility with respect to any Award under this Plan, the Administrator may make any adjustments it deems appropriate.

Section 280G of the Code

14.8Notwithstanding any other provision of this Plan to the contrary, unless expressly provided otherwise in the Award Agreement, if the right to receive or benefit from an Award under this Plan, either alone or together with payments that a Grantee has a right to receive from the Company, would constitute a “parachute payment” (as defined in Section 280G of the Code), all such payments shall be reduced to the largest amount that shall result in no portion being subject to the excise tax imposed by Section 4999 of the Code.

Exercise of Award Following Termination of Continuous Service

14.9An Award may not be exercised after the termination date of such Award set forth in the Award Agreement and may be exercised following the termination of a Grantee’s Continuous Service only to the extent provided in the Award Agreement.  Where the Award Agreement permits a Grantee to exercise an Award following the termination of the Grantee’s Continuous Service for a specified period, the Award shall terminate to the extent not exercised on the last day of the specified period or the last day of the original term of the Award, whichever occurs first.

Cancellation of Awards

14.10In the event a Grantee’s Continuous Services has been terminated for “Cause”, he or she shall immediately forfeit all rights to any and all Awards outstanding.  The determination that termination was for Cause shall be final and conclusive.  In making its determination, the Board shall give the Grantee an opportunity to appear and be heard at a hearing before the full Board and present evidence on the Grantee’s behalf.  Should any provision to this Section 14.10. be held to be invalid or illegal, such illegality shall not invalidate the whole of this Section 14, but, rather, this Plan shall be construed as if it did not contain the illegal part or narrowed to permit its enforcement, and the rights and obligations of the parties shall be construed and enforced accordingly.

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15. ADDITIONAL TERMS IF THE COMPANY BECOMES LISTED ON A STOCK EXCHANGE

15.1In the event the Shares become listed on a stock exchange, and to the extent required by the rules of such stock exchange, then the following terms and conditions shall apply to an Award in addition to those contained herein, as applicable:

(a) the exercise price of an Award must not be lower than 100% of the Fair Market Value (without discount) of the Shares on the stock exchange at the time the Award is granted;

(b) the number of securities issuable to Insiders, at any time, under all of the Company’s security based compensation arrangements (whether entered into prior to or subsequent to such listing), cannot exceed 20% of the Company’s total issued and outstanding Common Stock, unless the Company obtains Disinterested Shareholder Approval; and

(c) the number of securities issued to Insiders, within any one year period, under all of the Company’s security based compensation arrangements (whether entered into prior to or subsequent to such listing), cannot exceed 20% of the issued and outstanding Common Stock, unless the Company obtains Disinterested Shareholder Approval.

16. PAYMENT FOR SHARE PURCHASES

Payment

16.1Payment for Shares purchased pursuant to this Plan may be made:

(a) Cash.  By cash, cashier’s check or wire transfer or, at the discretion of the Administrator expressly for the Grantee and where permitted by law as follows:

(b) Surrender of Shares.  By surrender of shares of Common Stock of the Company that have been owned by the Grantee for more than six months, or lesser period if the surrender of shares is otherwise exempt from Section 16 of the Exchange Act, (and, if such shares were purchased from the Company by use of a promissory note, such note has been fully paid with respect to such shares);

(c) Deemed Net-Stock Exercise.  By forfeiture of Shares equal to the value of the exercise price pursuant to a “deemed net-stock exercise” by requiring the Grantee to accept that number of Shares determined in accordance with the following formula, rounded down to the nearest whole integer:

where:

a  = net Shares to be issued to Grantee;

b  = number of Awards being exercised;

c  = Fair Market Value of a Share; and

d  = Exercise price of the Awards;

(d) Cashless Exercise.  By a “cashless exercise”, in which event the Company shall issue to the Grantee the number of Shares of Common Stock determined as follows:

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where:

a  = the net Shares to be issued to Grantee;

b  = the number of Awards being exercised;

c  = the average of the “Closing Sale Prices” of the Shares of Common Stock (as reported by Bloomberg Financial Markets) for at least the two trading days ending on the date immediately preceding the Exercise Date; and

d  = the Exercise price of the Award.

For purposes of such an Award, “Closing Sale Price” means, for any security as of any date, the last trade price for such security on the principal securities exchange or trading market for such security, as reported by Bloomberg Financial Markets, or, if such exchange or trading market begins to operate on an extended hours basis and does not designate the last trade price, then the last trade price of such security prior to 4:00 p.m., New York City time, as reported by Bloomberg Financial Markets, or if the foregoing do not apply, the last trade price of such security in the over-the-counter market on the electronic bulletin board for such security as reported by Bloomberg Financial Markets, or, if no last trade price is reported for such security by Bloomberg Financial Markets, the average of the bid prices, or the ask prices, respectively, of any market makers for such security as reported in the “pink sheets” by Pink Sheets LLC.  If the Closing Sale Price cannot be calculated for a security on a particular date on any of the foregoing bases, the Closing Sale Price of such security on such date shall be the fair market value as mutually determined by the Company and the Grantee.  If the Company and the Grantee are unable to agree upon the fair market value of such security, then the Company shall, within two business days submit via facsimile (a) the disputed determination of the Closing Sale Price to an independent, reputable investment bank selected by the Company and approved by the Grantee or (b) the disputed arithmetic calculation of the Shares of Common Stock to the Company's independent, outside accountant.  The Company shall cause at its expense the investment bank or the accountant, as the case may be, to perform the determinations or calculations and notify the Company and the Grantee of the results no later than ten business days from the time it receives the disputed determinations or calculations.  Such investment bank’s or accountant's determination or calculation, as the case may be, shall be binding upon all parties absent demonstrable error.  All such determinations shall be appropriately adjusted for any stock dividend, stock split, stock combination or other similar transaction during the applicable calculation period.  For purposes of Rule 144 promulgated under the Securities Act, it is intended, understood and acknowledged that the Shares of Common Stock issued in a cashless exercise transaction shall be deemed to have been acquired by the Grantee, and the holding period for the shares shall be deemed to have commenced, on the date the Award was originally issued (provided that the United States Securities and Exchange Commission continues to take the position that such treatment is proper at the time of such exercise); or

(e) Broker-Assisted.  By delivering a properly executed exercise notice to the Company together with a copy of irrevocable instructions to a broker to deliver promptly to the Company the amount of sale or loan proceeds necessary to pay the exercise price and the amount of any required tax or other withholding obligations.

Combination of Methods

16.2By any combination of the foregoing methods of payment or any other consideration or method of payment as shall be permitted by applicable corporate law.

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17. WITHHOLDING TAXES

Withholding Generally

17.1Whenever Shares are to be issued in satisfaction of Awards granted under this Plan or Shares are forfeited pursuant to a deemed net-stock exercise, the Company may require the Grantee to remit to the Company an amount sufficient to satisfy the foreign, federal, state, provincial, or local income and employment tax withholding obligations, including, without limitation, on exercise of an Award.  When, under applicable tax laws, a Grantee incurs tax liability in connection with the exercise or vesting of any Award, the disposition by a Grantee or other person of an Award or an Option prior to satisfaction of the holding period requirements of Section 422 of the Code, or upon the exercise of a Non-Qualified Stock Option, the Company shall have the right to require such Grantee or such other person to pay by cash, or check payable to the Company, the amount of any such withholding with respect to such transactions.  Any such payment must be made promptly when the amount of such obligation becomes determinable.

Stock for Withholding

17.2To the extent permissible under applicable tax, securities and other laws, the Administrator may, in its sole discretion and upon such terms and conditions as it may deem appropriate, permit a Grantee to satisfy his or her obligation to pay any withholding tax, in whole or in part, with Shares up to an amount not greater than the Company’s minimum statutory withholding rate for federal and state tax purposes, including payroll taxes, that are applicable to such supplemental taxable income.  The Administrator may exercise its discretion, by (i) directing the Company to apply Shares to which the Grantee is entitled as a result of the exercise of an Award, or (ii) delivering to the Company Shares that have been owned by the Grantee for more than six months, unless the delivery of Shares is otherwise exempt from Section 16 of the Exchange Act.  A Grantee who has made an election pursuant to this Section 17.2 may satisfy his or her withholding obligation only with Shares that are not subject to any repurchase, forfeiture, unfulfilled vesting or other similar requirements.  The Shares so applied or delivered for the withholding obligation shall be valued at their Fair Market Value as of the date of measurement of the amount of income subject to withholding.

18. ADJUSTMENTS UPON CHANGES IN CAPITALIZATION

In General

18.1Subject to any required action by the shareholders of the Company, the number of Shares covered by each outstanding Award, and the number of Shares which have been authorized for issuance under the Plan but as to which no Awards have yet been granted or which have been returned to the Plan, the exercise or purchase price of each such outstanding Award, as well as any other terms that the Administrator determines require adjustment shall be proportionately adjusted for (i) any increase or decrease in the number of issued Shares resulting from a stock split, reverse stock split, stock dividend, combination or reclassification of the Shares, or (ii) any other increase or decrease in the number of issued Shares effected without receipt of consideration by the Company; provided, however that conversion of any convertible securities of the Company shall not be deemed to have been effected without receipt of consideration. The Administrator shall make the appropriate adjustments to (i) the maximum number and/or class of securities issuable under this Plan; and (ii) the number and/or class of securities and the exercise price per Share in effect under each outstanding Award in order to prevent the dilution or enlargement of benefits thereunder; provided, however, that the number of Shares subject to any Award shall always be a whole number and the Administrator shall make such adjustments as are necessary to insure Awards of whole Shares. Such adjustment shall be made by the Administrator and its determination shall be final, binding and conclusive.

Company’s Right to Effect Changes in Capitalization

18.2The existence of outstanding Awards shall not affect the Company’s right to effect adjustments, recapitalizations, reorganizations or other changes in its or any other corporation’s capital structure or business, any merger or consolidation, any issuance of bonds, debentures, preferred or prior preference stock ahead of or affecting the Shares, the dissolution or liquidation of the Company’s or any other corporation’s assets or business or any other corporate act whether similar to the events described above or otherwise.

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19. CORPORATE TRANSACTIONS/CHANGES IN CONTROL/RELATED ENTITY DISPOSITIONS

Company is Not the Survivor

19.1Subject to Section 19.3 and except as may otherwise be provided in an Award Agreement, the Administrator shall have the authority, in its absolute discretion, exercisable either in advance of any actual or anticipated Corporate Transaction, Change in Control or Related Entity Disposition in which the Company is not the surviving corporation, or at the time of an actual Corporate Transaction, Change in Control or Related Entity Disposition in which the Company is not the surviving corporation (a) to cancel each outstanding Award upon payment in cash to the Grantee of the amount by which any cash and the Fair Market Value of any other property which the Grantee would have received as consideration for the Shares covered by the Award if the Award had been exercised before such Corporate Transaction, Change in Control or Related Entity Disposition exceeds the exercise price of the Award, or (b) to negotiate to have such Award assumed by the surviving corporation.  The determination as to whether the Company is the surviving corporation is at the sole and absolute discretion of the Administrator.

In addition to the foregoing, in the event of a dissolution or liquidation of the Company, or a Corporate Transaction or Related Entity Disposition in which the Company is not the surviving corporation, the Administrator, in its absolute discretion, may accelerate the time within which each outstanding Award may be exercised.  Section 19.3 shall control with respect to any acceleration in vesting in the event of Change of Control.

The Administrator shall also have the authority:

(a) to release the Awards from restrictions on transfer and repurchase or forfeiture rights of such Awards on such terms and conditions as the Administrator may specify; and

(b) to condition any such Award’s vesting and exercisability or release from such limitations upon the subsequent termination of the Continuous Service of the Grantee within a specified period following the effective date of the Corporate Transaction, Change in Control or Related Entity Disposition.

Effective upon the consummation of a Corporate Transaction, Change in Control or Related Entity Disposition governed by this Section 19.1, all outstanding Awards under this Plan not exercised by the Grantee or assumed by the successor corporation shall terminate.

Company is the Survivor

19.2In the event of a Corporate Transaction, Change in Control or Related Entity Disposition in which the Company is the surviving corporation, the Administrator shall determine the appropriate adjustment of the number and kind of securities with respect to which outstanding Awards may be exercised, and the exercise price at which outstanding Awards may be exercised.  The Administrator shall determine, in its sole and absolute discretion, when the Company shall be deemed to survive for purposes of this Plan.  Subject to any contrary language in an Award Agreement evidencing an Award, any restrictions applicable to such Award shall apply as well to any replacement shares received by the Grantee as a result.

Change in Control

19.3If there is a Change of Control, all outstanding Awards shall fully vest immediately upon the Company’s public announcement of such a Change of Control.

20. PRIVILEGES OF STOCK OWNERSHIP

No Grantee shall have any of the rights of a stockholder with respect to any Shares until the Shares are issued to the Grantee.  After Shares are issued to the Grantee, the Grantee shall be a stockholder and have all the rights of a stockholder with respect to such Shares, including the right to vote and receive all dividends or other distributions made or paid with respect to such Shares; provided, that if such Shares are Restricted Stock, then any new, additional or different securities the Grantee may become entitled to receive with respect to such Shares by virtue of a stock dividend, stock split or any other change in the corporate or capital structure of the Company shall be subject to the same restrictions as the Restricted Stock.  The Company shall issue (or cause to be issued) such stock certificate promptly upon exercise of the Award.

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21. RESTRICTION ON SHARES

At the discretion of the Administrator, the Company may reserve to itself and/or its assignee(s) in the Award Agreement that the Grantee not dispose of the Shares for a specified period of time, or that the Shares are subject to a right of first refusal or a right to repurchase by the Company at the Shares’ Fair Market Value at the time of sale.  The terms and conditions of any such rights or other restrictions shall be set forth in the Award Agreement evidencing the Award.

22. CERTIFICATES

All certificates for Shares or other securities delivered under this Plan shall be subject to such stock transfer orders, legends and other restrictions as the Administrator may deem necessary or advisable, including restrictions under any applicable federal, state or foreign securities law, or any rules, regulations and other requirements of the SEC or any stock exchange or automated quotation system upon which the Shares may be listed or quoted.

23. ESCROW; PLEDGE OF SHARES

To enforce any restrictions on a Grantee’s Shares, the Administrator may require the Grantee to deposit all certificates representing Shares, together with stock powers or other instruments of transfer approved by the Administrator, appropriately endorsed in blank, with the Company or an agent designated by the Company to hold in escrow until such restrictions have lapsed or terminated, and the Administrator may cause a legend or legends referencing such restrictions to be placed on the certificates.

24. SECURITIES LAW AND OTHER REGULATORY COMPLIANCE

Compliance With Applicable Law

24.1An Award shall not be effective unless such Award is in compliance with all applicable federal and state securities laws, rules and regulations of any governmental body, and the requirements of any stock exchange or automated quotation system upon which the Shares may then be listed or quoted, as they are in effect on the Grant Date and also on the date of exercise or other issuance.  Notwithstanding any other provision in this Plan, the Company shall have no obligation to issue or deliver certificates for Shares under this Plan prior to (i) obtaining any approvals from governmental agencies that the Company determines are necessary or advisable; and/or (ii) completion of any registration or other qualification of such Shares under any state or federal laws or rulings of any governmental body that the Company determines to be necessary or advisable.  The Company shall be under no obligation to register the Shares with the Securities Exchange Commission or to effect compliance with the registration, qualification or listing requirements of any state securities laws, stock exchange or automated quotation system, and the Company shall have no liability for any inability or failure to do so.  Evidences of ownership of Shares acquired pursuant to an Award shall bear any legend required by, or useful for purposes of compliance with, applicable securities laws, this Plan or the Award Agreement.

During any time when the Company has a class of equity security registered under Section 12 of the Exchange Act, it is the intent of the Company that Awards pursuant to this Plan and the exercise of Awards granted hereunder shall qualify for the exemption provided by Rule 16b-3 under the Exchange Act.  To the extent that any provision of this Plan or action by the Board or the Administrator does not comply with the requirements of Rule 16b-3, it shall be deemed inoperative to the extent permitted by law and deemed advisable by the Board or the Administrator, and shall not affect the validity of this Plan.  In the event that Rule 16b-3 is revised or replaced, the Administrator may exercise its discretion to modify this Plan in any respect necessary to satisfy the requirements of, or to take advantage of any features of, the revised exemption or its replacement.

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Investment Representation

24.2As a condition to the exercise of an Award, the Company may require the person exercising such Award to represent and warrant at the time of any such exercise that the Shares are being purchased only for investment and without any present intention to sell or distribute such Shares if, in the opinion of counsel for the Company, such a representation is required by any Applicable Laws.

25. NO OBLIGATION TO EMPLOY

Nothing in this Plan or any Award granted under this Plan shall confer or be deemed to confer on any Grantee any right to continue in the employ of, or to continue any other relationship with, the Company or to limit in any way the right of the Company to terminate such Grantee’s employment or other relationship at any time, with or without Cause.

26. EFFECTIVE DATE AND TERM OF PLAN

This Plan shall become effective upon the earlier to occur of its adoption by the Board or its approval by the shareholders of the Company. It shall continue in effect for a term of ten years unless sooner terminated.

27. SHAREHOLDER APPROVAL

This Plan shall be subject to approval by the shareholders of the Company within 12 months from the date the Plan is adopted by the Company’s Board for any and all intended Incentive Stock Options granted hereunder.  Such shareholder approval shall be obtained in the degree and manner required under Applicable Laws.  The Administrator may grant Awards under this Plan prior to approval by the shareholders, however, until such approval is obtained, all Option Awards granted under this Plan shall be deemed Non-Qualified Stock Options.  In the event that shareholder approval is not obtained within the 12 month period provided above, all Incentive Stock Option Awards previously granted under this Plan shall be deemed Non-Qualified Stock Options.

28. AMENDMENT, SUSPENSION OR TERMINATION OF THIS PLAN OR AWARDS

The Board may amend, suspend or terminate this Plan at any time and for any reason.  To the extent necessary to comply with Applicable Laws, the Company shall obtain shareholder approval of any Plan amendment in such a manner and to such a degree as required.  Shareholder approval shall be required for the following types of amendments to this Plan: (i) any change to those persons who are entitled to become participants under the Plan which would have the potential of broadening or increasing Insider participation; or (ii) the addition of any form of financial assistance or amendment to a financial assistance provision which is more favourable to Grantees.

Further, the Board may, in its discretion, determine that any amendment should be effective only if approved by the shareholders even if such approval is not expressly required by this Plan or by law.  No Award may be granted during any suspension of this Plan or after termination of this Plan.

Any amendment, suspension or termination of this Plan shall not affect Awards already granted, and such Awards shall remain in full force and effect as if this Plan had not been amended, suspended or terminated, unless mutually agreed otherwise between the Grantee and the Administrator, which agreement must be in writing and signed by the Grantee and the Company.  At any time and from time to time, the Administrator may amend, modify, or terminate any outstanding Award or Award Agreement without approval of the Grantee; provided, however, that subject to the applicable Award Agreement, no such amendment, modification or termination shall, without the Grantee’s consent, reduce or diminish the value of such Award determined as if the Award had been exercised, vested, cashed in or otherwise settled on the date of such amendment or termination.

Notwithstanding any provision herein to the contrary, the Administrator shall have broad authority to amend this Plan or any outstanding Award under this Plan without approval of the Grantee to the extent necessary or desirable: (i) to comply with, or take into account changes in, applicable tax laws, securities laws, accounting rules and other applicable laws, rules and regulations; or (ii) to ensure that an Award is not subject to interest and penalties under Section 409A of the Code or the excise tax imposed by Section 4999 of the Code.

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Further, notwithstanding any provision herein to the contrary, and subject to Applicable Law, the Administrator may, in its absolute discretion, amend or modify this Plan: (i) to make amendments which are of a “housekeeping” or clerical nature; (ii) to change the vesting provisions of an Award granted hereunder, as applicable; (iii) to change the termination provision of an Award granted hereunder, as applicable, which does not entail an extension beyond the original expiry date of such Award; and (iv) the addition of a cashless exercise feature, payable in cash or securities, which provides for a full deduction of the number of underlying securities from the Maximum Number.

29. RESERVATION OF SHARES

The Company, during the term of this Plan, shall at all times reserve and keep available such number of Shares as shall be sufficient to satisfy the requirements of this Plan.

The Shares to be issued hereunder upon exercise of an Award may be either authorized but unissued; supplied to the Plan through acquisitions of Shares on the open market; Shares forfeited back to the Plan; Shares surrendered in payment of the exercise price of an Award; or Shares withheld for payment of applicable employment taxes and/or withholding obligations resulting from the exercise of an Award.

The inability of the Company to obtain authority from any regulatory body having jurisdiction, which authority is deemed by the Company’s counsel to be necessary to the lawful issuance and sale of any Shares hereunder, shall relieve the Company of any liability in respect of the failure to issue or sell such Shares as to which such requisite authority shall not have been obtained.

30. EXCHANGE AND BUYOUT OF AWARDS

The Administrator may, at any time or from time to time, authorize the Company, with the consent of the respective Grantees, to issue new Awards in exchange for the surrender and cancellation of any or all outstanding Awards.  The Administrator may at any time buy from a Grantee an Award previously granted with payment in cash, Shares (including Restricted Stock) or other consideration, based on such terms and conditions as the Administrator and the Grantee may agree.

31. APPLICABLE TRADING POLICY

The Administrator and each Eligible Participant will ensure that all actions taken and decisions made by the Administrator or an Eligible Participant, as the case may be, pursuant to this Plan comply with any Applicable Laws and policies of the Company relating to insider trading or “blackout” periods.

32. GOVERNING LAW

The Plan shall be governed by the laws of the State of Nevada; provided, however, that any Award Agreement may provide by its terms that it shall be governed by the laws of any other jurisdiction as may be deemed appropriate by the parties thereto.

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33.                          MISCELLANEOUS

Except as specifically provided in a retirement or other benefit plan of the Company or a Related Entity, Awards shall not be deemed compensation for purposes of computing benefits or contributions under any retirement plan of the Company or a Related Entity, and shall not affect any benefits under any other benefit plan of any kind or any benefit plan subsequently instituted under which the availability or amount of benefits is related to level of compensation. The Plan is not a “Retirement Plan” or “Welfare Plan” under the Employee Retirement Income Security Act of 1974, as amended.

__________

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SUBPART A

STOCK AND DEFERRED STOCK UNITS FOR ELIGIBLE DIRECTORS

A.Stock Award.  The Administrator shall pay Eligible Remuneration to each Director pursuant to an Award Agreement.

B.Election.  Further, the Administrator may, in its sole discretion, permit each Eligible Director to receive all or any portion of his Eligible Remuneration during the Remuneration Period in the form of Deferred Stock Units under this Plan (an “Election”).  All deferrals pursuant to such an Election shall be evidenced by an Award Agreement.

For purposes of this Subpart A, the following definitions shall apply:

“Annual Retainer” for a particular Director means the retainer (including any additional amounts payable for serving as lead Director or on any committee of the Board), payable to that Director for serving as a Director for the relevant Remuneration Period, as determined by the Board;

“Attendance Fee” means amounts payable annually to a Director as a Board meeting attendance fee or a committee meeting attendance fee, or any portion thereof;

“Canadian Director” means a Director who is a resident of Canada for the purposes of the Canadian Tax Act, and whose income from employment by the Company or Related Entity is subject to Canadian income tax, notwithstanding any provision of the Canada-United States Income Tax Convention (1980), as amended;

“Canadian Tax Act” and “Canadian Tax Regulations” means respectively the Income Tax Act (Canada), as amended and the Income Tax Regulation promulgated thereunder, as amended;

“Deferred Stock Unit” means a right granted by the Company to an Eligible Director to receive, on a deferred payment basis, Shares under this Plan;

“Eligible Director” is any Director of this Company or Related Entity that the Administrator determines is eligible to elect to receive Deferred Stock Units under this Plan;

“Eligible Remuneration” means all amounts payable to an Eligible Director in Shares, including all or part of amounts payable in satisfaction of the Annual Retainer, Attendance Fees or any other fees relating to service on the Board which are payable to an Eligible Director or in satisfaction of rights or property surrendered by an Eligible Director to the Company; it being understood that the amount of Eligible Remuneration payable to any Eligible Director may be calculated by the Administrator in a different manner than Eligible Remuneration payable to another Eligible Director in its sole and absolute discretion;

“Prescribed Plan or Arrangement” means a prescribed plan or arrangement as defined in s.6801(d) of the Canadian Tax Regulation;

“Remuneration Period” means, as applicable, (a) the period commencing on the Effective Date of this Plan and ending on the last day of the calendar year in which the Effective Date occurs; and (b) thereafter each subsequent calendar year, or where the context requires, any portion of such period; and

“Salary Deferral Arrangement” means a salary deferral arrangement as defined in the Canadian Tax Act.

1.Election.  An Eligible Director who desires to defer receipt of all or a portion of his or her Eligible Remuneration in any calendar year shall make such election in writing to the Company specifying:

(a)the dollar amount or percentage of Eligible Remuneration to be deferred; and

(b)the deferral period.

Otherwise, such election must be made before the first day of the calendar year in which the Eligible Remuneration shall be payable, however a newly appointed Eligible Director shall be eligible to defer payment of future Eligible Remuneration by providing written election to the Company within 30 calendar days of his or her appointment to the Board of Directors.  The elections made pursuant to this Section shall be irrevocable with respect to Eligible Remuneration to which such elections pertain and shall also apply to subsequent Eligible Remuneration payable in future calendar years unless such Eligible Director notifies the Company in writing, before the first day of the applicable calendar year, that he or she desires to change such election.

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If the Eligible Director does not timely deliver an election in respect of a particular Remuneration Period, the Eligible Director will receive the Eligible Remuneration as provided for in the Award Agreement.

2.Determination Of Deferred Stock Units.  The Company will maintain a separate account for each Eligible Director to which it will quarterly credit Deferred Stock Units at the end of March, June, September and December, or as otherwise determined by the Administrator, the Deferred Stock Units granted to the Eligible Director for the relevant Remuneration Period.  The number of Deferred Stock Units (including fractional Deferred Stock Units, computed to three digits) to be credited to an account for an Eligible Director will be determined on the date approved by the Administrator by dividing the appropriate amount of Eligible Remuneration to be deferred into Deferred Stock Units by the Fair Market Value on that date.

3.No Voting Rights.  The holders of Deferred Stock Units shall have no rights as stockholders of the Company.

4.Dividend Equivalency.  The Company will, on any date on which a cash or stock dividend is paid on its outstanding Shares, credit to each Eligible Director’s account that number of additional Deferred Stock Units (including fractional Deferred Stock Units, computed to three digits) calculated by (i) multiplying the amount of the dividend per Share by the number of Deferred Stock Units in the account as of the record date for payment of the dividend, and (ii) dividing the amount obtained in (i) by the Fair Market Value on the date on which the dividend is paid.  (See Section 13 of the Plan, Dividend Equivalent Right).

5.Eligible Director’s Account.  A written confirmation of the balance in each Eligible Directors’ Account will be sent by the Company to the Eligible Director upon request of the Eligible Director.

6.Creditor’s Rights.  A holder of Deferred Stock Units shall have no rights other than those of a general creditor of the Company.  Deferred Stock Units represent an unfunded and unsecured obligation of the Company, subject to the terms and condition of the applicable Award Agreement.

7.Settlement of Deferred Stock Units.  Subject to Section 8, each Deferred Stock Unit shall be paid and settled by the issuance of Restricted or unrestricted Shares in accordance with the Award Agreement and if such settlement is subject to Section 409A of the Code only upon any one or more of the following as provided for in the Award Agreement:

(a) a specific date or date determinable by a fixed schedule;

(b) upon the Eligible Director’s termination of Continuous Services to the extent the same constitutes a separation from services for the purposes of Section 409A of the Code except that if an Eligible Director is a “key employee” as defined in Section 409A of the Code for such purposes, then payment or settlement shall occur 6 months following such separation of service;

(c) as a result of the Eligible Director’s death or Disability; or

(d) in connection with or as a result of a Change in Control in compliance with 409A of the Code.

The Company will issue one Share for each whole Deferred Stock Unit credited to the Eligible Director’s account (net of any applicable withholding tax as provided for in this Plan).  Such payment shall be made by the Company as soon as reasonably possible following the settlement date.  Fractional Shares shall not be issued, and where the Eligible Director would be entitled to receive a fractional Shares in respect of any fractional Deferred Stock Unit, the Company shall pay to such Eligible Director, in lieu of such fractional Shares, cash equal to the Fair Market Value of such fractional Shares calculated as of the day before such payment is made, net of any applicable withholding tax.

8.Canadian Directors.  If a Deferred Stock Unit is granted to an Eligible Director who is a Canadian Director would otherwise constitute a Salary Deferred Arrangement, the Award Agreement pertaining to that Deferred Stock Unit shall contain such other or additional terms as will cause the Deferred Stock Unit to be a Prescribed Plan or Arrangement.

9.Issuance of Stock Certificates.  A stock certificate or certificates shall be registered and issued in the name of the holder of Deferred Stock Units and delivered to such holder as soon as practicable after such Deferred Stock Units have become payable or satisfied in accordance with the terms of the Plan

10.Non-Exclusivity.  Nothing in this Subpart A shall prohibit the Administrator from making discretionary Awards to Eligible Directors pursuant to the other provisions of this Plan or outside this Plan, not otherwise inconsistent with these provisions.

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11.Defined Terms.  Capitalized terms used in this Subpart A and not defined herein have the meaning give in the Plan.

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EX-10.32

EXHIBIT 10.32

EMPLOYMENTAGREEMENT

THIS AGREEMENT (this “Agreement”) is made effective as of the first day of October, 2013, between Duma Energy Corp., a Nevada corporation doing business at 800 Gessner, Suite 200, Houston, Texas  77024 (the “Company”), and William Craig Alexander, a Texas resident (the “Employee”), together referred to hereinafter as the “Parties.”

In consideration of the mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.Employment  The Company shall employ Employee, and Employee hereby accepts employment with the Company, upon the terms and conditions set forth in this Agreement for the period beginning on the effective date and ending on the Termination Date, as defined in Section 4 hereof (the “Employment Period”).

2.Position and Duties

(a)During the Employment Period, Employee shall serve as the Company’s (and its subsidiaries, where appropriate) Vice President and shall be responsible for such duties as are normally performed by persons serving in such a position in companies similarly situated with Company, as well as any other duties as may be reasonably prescribed by the Board of Directors of the Company (the “Board”) and Chief Executive Officer.  Employee will report to the President.

(b)While this Agreement remains in force and effect, Employee will act in the best interests of the Company and devote full-time to the Company’s business and affairs, performing his work in a competent and efficient manner and at all times in compliance with the business policies of the Company.

3.Base Salary and Benefits

(a)Employee's initial base salary for the term of this Agreement shall be $185,000.00 per year (the “Base Salary”).  The Base Salary shall be payable in approximately equal installments in accordance with the Company’s general payroll practices (but at least monthly) and shall be subject to required withholding.

(b)The Company shall reimburse Employee for all reasonable expenses incurred by him in the course of performing his duties under this Agreement which are consistent with the Company’s policies in effect from time to time for its employees with respect to travel, entertainment and other business expenses, subject to the Company’s requirements for its employees with respect to reporting and documentation of such expenses.

(c)Employee shall be entitled to three (3) weeks of vacation per year, including up to two (2) weeks of sick leave, during which times his compensation shall be paid in full.   Any un-used vacation time shall be forfeited and not carried over to future periods.

(d)Employee shall be eligible to participate, to the extent Employee meets all eligibility requirements of general application, in each of the employee benefit plans maintained by Employer from time to time in which employees of Employer generally are eligible to participate, including by way of illustration, any 401K Plan, group medical, dental, life and AD&D plans.  Employee shall also be entitled to participate in the award of any stock options, warrants, or other forms of non-cash compensation that may be offered to qualified employees by the Board in its discretion.

4.Term and Termination

(a)This Agreement shall be effective on the date first above written and continue for one (1) year, ending on the first anniversary date of execution unless extended as provided below.  This Agreement may be terminated at any time by: (i) by Employee’s resignation with or without Good Reason (as defined below), (ii) by Employee’s death or Disability (as defined below), or (iii) by the Company with or without Cause (as defined below).  The effective term of this Agreement shall be automatically extended for consecutive one (1) year periods unless written notice not to extend is given by either party to the other party not less than sixty (60) days prior to the date any extension period is to commence. The date on which Employee’s employment with the Company ends is referred to herein as the “Termination Date”, with sixty (60) day advance written notice required.

(b)(i)If Employee’s employment with the Company is terminated by the Company for Cause, or by Employee without Good Reason, Employee shall not be entitled to a severance payment and will not receive his Base Salary beyond the Termination Date.

(ii)If Employee’s employment with the Company is terminated by the Company for any reason other than for Cause (“without Cause”), or if Employee terminates his employment for Good Reason, Employee shall be entitled to receive as a severance payment, his then current Base Salary for a period of six (6) months following the Termination Date.

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(iii)If Employee’s employment with the Company is terminated by Employee’s death or Disability, Employee or his heirs or designee(s) shall be entitled to continue to receive his Base Salary for a period of three (3) months following the Termination Date.

(c)All of Employee’s rights to benefits provided by the Company or any affiliate of or successor to the Company shall cease upon the Termination Date, except to the extent required by law.

(d)For purposes of this Agreement, the following terms shall have the meanings set forth below:

“Cause” shall mean (i) the conviction of Employee for a felony, a crime involving moral turpitude, or a plea of guilty or no lo contendre by Employee to a charge of any such crime, (ii) Employee’s theft or embezzlement, or attempted theft or embezzlement, of money or property of the Company, (iii) Employee’s perpetration or attempted perpetration of fraud, or Employee’s participation in a fraud or an attempted fraud on the Company, or Employee’s unauthorized appropriation or attempted appropriation of any tangible or intangible material asset or property of the Company, (iv) Employee’s dishonesty with respect to any matter concerning the Company, or (v) Employee’s substantial and repeated failure to perform his duties hereunder in accordance with the reasonable directions of the Board.

“Disability” shall mean any illness, disability or incapacity of such a character as to render Employee unable to perform Employee’s primary duties hereunder for a period of ninety (90) consecutivedays, as determined in the discretion of the Board.

“Good Reason” shall mean (i) material breach by the Company of its obligations under this Agreement, including the failure of the Company to pay Employee the Base Salary or any other payment or benefit due Employee hereunder; (ii) any action of the Company that results in a material diminishment in Employee’s functions or responsibilities, or any attempt by the Company to cause Employee to relocate outside the city of Houston as a requirement of his continued employment; (iii) any reduction in Employee’s Base Salary; or (iv) any material reduction of benefits unless the same reduction is applicable generally to all employees of the Company.

(e)A termination of this Agreement pursuant to its terms on the Expiration Date or any subsequent anniversary date, shall not in and of itself constitute a termination of Employee’s employment with the Company. At such time, unless the Company or the Employee terminates Employee’s employment with the Company, Employee shall become an employee at-will of the Company.

5.Confidential Information  Employee acknowledges that the information and data obtained by him while employed by the Company concerning the business or affairs of the Company reasonably considered to be of a confidential nature (“Confidential Information”) are the property of the Company.  The Company agrees, in consideration for Employee’s agreement to the various terms of this Agreement, to provide Employee with Confidential Information belonging to the Company.  Employee agrees that he shall not disclose to any unauthorized person or use for his own purposes any Confidential Information without the prior written consent of the Company’s board of directors, unless and to the extent that the aforementioned matters become generally known to and available for use by the public other than as a result of Employee’s acts or omissions, or is otherwise known to Employee from independent sources outside of Employee’s employment with the Company. Employee shall deliver to the Company at the termination of the Employment Period, or at any other time the Company may reasonably request, all memoranda, notes, plans, records, reports, computer tapes, printouts and software and other documents and data (and copies thereof) relating to the Confidential Information or the business of the Company which he may then possess or have under his control. Nothing herein shall prohibit Employee’s disclosure of Confidential Information as directed by judicial, administrative or other governmental law, rule, regulation or order provided that Employee shall, to the extent possible, give immediate notice to the Company of any disclosure of Confidential Information so required in order for the Company to seek a protective order if it so desires.

6.Restrictive Covenants

(a)In further consideration of the compensation to be paid to Employee hereunder and the obligations of the Company under this Agreement, Employee acknowledges that in the course of his employment with the Company he shall become familiar with the Company’s trade secrets and with other Confidential Information concerning the Company and that his services have a special, unique and extraordinary value to the Company.  Therefore, Employee agrees that for one (1) year after his termination by the Company for Cause, or his own termination of employment without Good Reason (the “Restricted Period”), he shall not as an employee, consultant, advisor, agent, shareholder, independent contractor, investor, partner, member, owner or otherwise act or engage in activity that directly competes with or has or could reasonably be expected to have a material adverse economic effect on any of the activities or business of the Company.  Nothing herein shall prohibit Employee from being a passive owner of not more than 20% of the outstanding stock of any class of a corporation which is publicly traded, so long as Employee has no active participation in the business of such corporation.  The Restricted Period shall not apply to Employee if he is terminated without Cause, or if he terminates his employment with the Company for Good Reason.

(b)During the Restricted Period, Employee shall not directly or indirectly through another entity (i) induce or attempt to induce any employee of the Company to leave the employ of the Company, or in any way interfere with the relationship between the Company and any employee thereof, (ii) hire any person who was an employee of the Company at any time during the Employment Period, or (iii) induce or attempt to induce any customer, supplier, licensee, licensor, franchisee or other business relation of the Company to cease doing business with the Company, or in any way interfere with the relationship between any such customer, supplier, licensee or business relation and the Company.  Notwithstanding anything herein to the contrary, nothing shall prevent the Employee from hiring an employee of the Company as a result of a general solicitation, including the internet, and not directly or indirectly through the Employee, and nothing shall prevent the Employee from doing business with or otherwise enjoying professional relationships with customers, suppliers, licensees or business relations of the Company if that business is not solicited directly or indirectly by Employee.

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(c)If, at the time of enforcement of this Section 6, a court shall hold that the duration, scope or area restrictions stated herein are unreasonable under circumstances then existing, the parties agree that the maximum duration, scope or area reasonable under such circumstances shall be substituted for the stated duration, scope or area and that the court shall be allowed to revise the restrictions contained herein to cover the maximum period, scope and area permitted by law.  Employee agrees that the restrictions contained in this Section 6 are reasonable.

(d)In the event of the breach or a threatened breach by Employee of any of the provisions of this Section 6, the Company, in addition and supplementary to other rights and remedies existing in its favor, may apply to any court of law or equity of competent jurisdiction for specific performance and\or injunctive or other relief in order to enforce or prevent any violations of the provisions hereof (without posting a bond or other security). In addition, in the event of an alleged breach or violation by Employee of this Section 6, the Restricted Period shall be tolled until such breach or violation has been duly cured.

7.Property RightsIn keeping with Employee’s fiduciary duties to the Company, Employee hereby covenants and agrees that during Employee’s Employment Period, and for a period of six (6) months following Employee’s Termination Date if terminated by the Company for Cause or by the Employee without Good Reason, Employee shall promptly disclose in writing to Company any and all information, ideas, concepts, improvements, discoveries, inventions, and other intellectual properties, whether patentable or not, and whether or not reduced to practice, which are conceived, developed, made or acquired by Employee, either individually or jointly with others, and which relate to the business, products or services of Company or any of its affiliated entities. In consideration for Employee’s employment hereunder, Employee hereby specifically sells, assigns and transfers to Company all of Employee’s worldwide right, title and interest in and to all such information, ideas, concepts, improvements, discoveries, inventions and other intellectual properties which relate to the business, products or services of Company or any of its affiliated entities. If during the Employment Period, Employee creates any original work of authorship or other property fixed in any tangible medium of expression which (a) is the subject matter of copyright (including computer programs) and (b) relates to Company’s present or planned business, products, or services, whether such property is created solely by Employee or jointly with others, such property shall be deemed a work for hire, with the copyright automatically vesting in Company. To the extent that any such writing or other property is determined not to be a work for hire for whatever reason, Employee hereby consents and agrees to the unconditional waiver of “moral rights” in such writing or other property, and to assign to Company all of Employee’s right, title and interest, including copyright, in such writing or other property.  Notwithstanding anything herein to the contrary, if Employee is terminated by the Company without Cause, or terminates his employment for Good Reason, his obligations to disclose the information set forth above, and to sell, assign and transfer such information to the Company, are no longer in effect after the Termination Date.

Employee hereby agrees (a) to exercise reasonable effort to assist Company or its nominee in the protection of any and all property subject to this Section, (b) not to disclose any such property to third parties who are not employed by the Company without the written consent of Company or its nominee, except as required by Employee’s  employment hereunder, and (c) at the request of Company, to execute such assignments, certificates or other interests as Company or its nominee may from time to time deem desirable to evidence, establish, maintain, perfect, protect or enforce its rights, title or interests in or to any such property.

8.Representations  Employee and the Company each represents and warrants to the other that (i) the execution, delivery and performance of this Agreement by such party does not and shall not conflict with, breach, violate or cause a default under any contract, agreement, instrument, order, judgment or decree to which such party is subject or by which it is bound, (ii) such party is not a party to or bound by any employment agreement, non-compete agreement or confidentiality agreement with any other person or entity that would be breached or violated by such party’s execution and delivery or performance of this Agreement and (iii) upon the execution and delivery of this Agreement by such party, this Agreement shall be the valid and binding obligation of such party, enforceable against such party in accordance with its terms. Such party hereby acknowledges and represents that it has consulted with independent legal counsel regarding his rights and obligations under this Agreement and that he fully understands the terms and conditions contained herein.

9.Survival  Sections 5 and 6 and Sections 9 through 16 shall survive and continue in full force in accordance with their terms notwithstanding any termination of the Employment Period.

10.Notices  Any notice provided for in this Agreement shall be in writing and shall be either personally delivered, or mailed by first class mail, return receipt requested, to the recipient at the address below indicated:

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 Notices to Employee:

 William Craig Alexander

 5314 Sunbright Court

 Houston, TX 77041

 Notices to the Company:

 Duma Energy Corp.

 Attn: Chairman of the Board

 800 Gessner, Suite 200

 Houston, TX  77024

 or such other address or to the attention of such other person as the recipient party shall have specified by prior written notice to the sending party. Any notice under this Agreement shall be deemed to have been given when so delivered or three (3) days after so mailed.

11.Severability  Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is held to be invalid, illegal or unenforceable in any respect under any applicable law or rule in any jurisdiction, such invalidity, illegality or unenforceability shall not affect any other provision or any other jurisdiction, but this Agreement shall be reformed, construed and enforced in such jurisdiction as if such invalid, illegal or unenforceable provision had never been contained herein.

12.Complete Agreement  This Agreement embodies with respect to the subject matter hereof the complete agreement and understanding among the parties and supersedes and preempts with respect to the subject matter hereof any prior understandings, agreements or representations by or among the parties, written or oral, which may have related to the subject matter hereof in any way.

13.No Strict Construction  The language used in this Agreement shall be deemed to be the language chosen by the parties hereto to express their mutual intent, and no rule of strict construction shall be applied against any party, it being understood that Section 6(c) contemplates that a court of competent jurisdiction shall be entitled to conform the express language of Section 6(a) if necessary in order to comply with Texas law.

14.Counterparts  This Agreement may be executed in separate counterparts, each of which is deemed to be an original and all of which taken together constitute one and the same agreement.

15.Successors and Assigns  This Agreement is intended to bind and inure to the benefit of and be enforceable by Employee, the Company and their respective heirs, successors and assigns, except that Employee may not assign his rights or delegate his obligations hereunder without the prior written consent of the Company.

16.Choice of Law  All issues and questions concerning the construction, validity, enforcement and interpretation of this Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas, without giving effect to any choice of law or conflict of law rules or provisions (whether of the State of Texas or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of Texas.

17.ArbitrationIn the event of a dispute, the parties agree that such dispute shall be submitted to binding arbitration in Texas, U.S.A., pursuant to the rules of arbitration of the American Arbitration Association (the “Rules”). Except as set forth in this Section, the arbitration shall proceed pursuant to the Rules in effect on the date such arbitration is commenced.  In the event of arbitration, the parties shall attempt to reach agreement on the selection of a single impartial arbitrator.  If the parties are unable to agree on a single impartial arbitrator, each party shall select one impartial arbitrator and those arbitrators shall select a single impartial arbitrator who shall thereafter conduct the arbitration as the sole arbitrator.  The arbitrator so selected shall be competent in the legal and technical aspects of the subject matter of this Agreement. The arbitrator shall not limit, expand or modify the terms of this Agreement nor award damages in excess of compensatory damages.  Any party to the arbitration may seek conservatory or interim measures in accordance with the Rules.  The prevailing party in the arbitration shall be awarded all attorney fees and costs incurred in the arbitration.  The final award shall specify the factual and legal bases for the award, if any.  Any final award or decision issued as a result of such arbitration shall be final, binding and conclusive between the parties, and shall be enforceable by any court having jurisdiction over the party against whom enforcement is sought.  Each party to this Agreement hereby consents to non-exclusive jurisdiction and venue of the State of Texas, for any court proceedings to enforce any such final award or decision.  Except where clearly prevented by the subject matter of the dispute, each party to this Agreement shall continue performing its respective obligations under this Agreement while the dispute is being resolved.

18.Amendment and Waiver  The provisions of this Agreement may be amended or waived only with the prior written consent of the Company and Employee, and no course of conduct or failure or delay in enforcing the provisions of this Agreement shall affect the validity, binding effect or enforceability of this Agreement.

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IN WITNESS WHEREOF, the parties hereto have executed this Employment Agreement as of the date first written above.

EMPLOYEE:
/s/ William Craig Alexander
William Craig Alexander
COMPANY:
Duma Energy Corp.,
a Nevada corporation
By:	/s/ Jeremy G. Driver
	Jeremy G. Driver
	Chief Executive Officer

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EX-14.1

EXHIBIT 14.1

CODE OF BUSINESS CONDUCT FOR DIRECTORS, OFFICERS AND EMPLOYEES

The Board of Directors of the Company (the “Board of Directors”) adopted the following Code of Business Conduct (the “Code”) for all directors, officers and employees of the Company.  The “Company” includes Duma Energy Corp. and all of its subsidiaries.

While there cannot be a specific rule for every situation you may encounter in your workday, we have adopted this Code to provide certain principles for the business conduct of the Company’s directors, officers and employees. In addition to this Code, you are expected to be familiar with and comply with the Company’s other policies and procedures, as well as adhere to the highest ethical standards in all your business dealings.

A violation of the law or this Code is a serious matter.  A director, officer or employee that violates a law, government regulation or this Code will face appropriate disciplinary action, which may include demotion or immediate termination of employment for cause.

The provisions of this Code may be amended or waived only by the Company’s Board of Directors.

1.Criteria for Ethical Decision Making

Before embarking on any course of action, you need to ask yourself these questions:

· Is the life, health or safety of anyone, or the environment endangered by the action?;

· Is it legal?;

· Does it feel fair and honest?;

· Does it benefit anyone's self-interests at the expense of the corporation (a director, for example)?;

· Are any conflicts of interest apparent or even possible?;

· Does it favor one shareholder over another?;

· Is it an arm's-length transaction, or are any related-parties involved but not disclosed?;

· Does it compromise trust or integrity?; and

· Could I justify it to the public?

You are required to promptly discuss any questions or concerns you may have about this Code or the correctness of any past, present or anticipated conduct with an officer, and/or an independent director.

2.Ethical Business Practices

Each director, officer and employee is to be accountable to adhere to and advocate high standards of honest and ethical conduct as outlined in this Code.

3.Fair Dealings

Deal fairly and honestly with the Company’s collaborators, suppliers, competitors, other employees and anyone else with whom you have contact in the course of performing your job.  You should not take unfair advantage of anyone through manipulation, concealment, misappropriate or abuse of confidential information, falsification, misrepresentation of material facts or any other unfair dealing practice.

The Company requires that all contracts, agreements and other documents correctly set forth the terms of the underlying business arrangement and that any such documents are reviewed and approved through established Company policy and procedures.

4.Corporate Opportunities and Duty of Loyalty

You have a duty of loyalty to the Company, which includes a duty to advance the Company’s legitimate interests when the opportunity to do so arises.  Accordingly, you may not use your position or the Company’s name, property, information or good will for personal gain or for the gain of others.  You are further prohibited from taking advantage of a personal opportunity that is discovered through the use of corporate property, information or your position with the Company. It is further understood that all work product, opportunities, rights, information, data, and other such tangible and intangible assets of the Company are the sole property of the Company and are to be considered proprietary and confidential.

5.Conflicts of Interest

A conflict of interest arises when your private interests interfere, or appear to interfere, in any way, with the interests of the Company as a whole.  You are to take care to ensure that you identify and avoid any situation of actual or apparent conflict of interest.

Some conflicts are clear-cut; others are less obvious.  For that reason you must fully disclose to a member of the executive team all circumstances that could be construed or perceived as a conflict of interest.  Full disclosure enables us to resolve unclear situations and create an opportunity to dispose of or ethically handle conflicts of interest before any difficulty can arise.  To the extent a conflict of interest cannot be avoided in a reasonable fashion, then appropriate procedures must be put in place to minimize the involvement of any conflicted individuals in the relationship or interaction giving rise to the conflict.  Failure to make required disclosures or resolve conflicts of interest satisfactorily can result in discipline up to and including termination of employment.

Any employment agreement with the Company may appropriately prohibit an employee’s employment or engagement in any capacity in any other business without the prior permission of the Company.  This provision broadly addresses potential conflicts of interest.  Specific examples include, but are not limited to:

· Acting as an employee, director or officer of or a consultant to, a competitor or potential competitor of the Company, regardless of the nature of the employment or consulting relationship;

· Holding a substantial interest in a business which is a customer, competitor or supplier of the Company or which otherwise does business with the Company;

· The purchase of merchandise or services for the Company from, or placement of other business with, a company directly or beneficially owned or controlled by an employee, director or officer of the Company or his or her spouse, relative, in-law or co-habitant; and

· Serving as a proprietor, general partner, officer or director of any business (except charitable organizations or family businesses that in no way compete with the Company or do business with the Company) without first obtaining written consent of the Chief Executive Officer of the Company.  Non-employee directors of the Company are excluded from this prohibition.

6.Accepting or Giving Gifts

You must avoid activities or relationships that conflict with the Company’s interests or adversely affect the Company’s reputations.  The types of activities and relationships you must avoid include, but are not limited to:

· Accepting or soliciting a gift, favor, service, or any other item of value that is intended to, or might appear to, influence the employee’s decision-making or professional conduct; or

· Giving or offering to give any gift, gratuity, favor, entertainment, reward, “bribe” or “kickback” or any other thing of value that might influence or appear to influence the judgment or conduct of the recipient in the performance of his or her job. This includes transactions with government personnel, customers and supplier

You may give or receive unsolicited gifts or entertainment only in cases where the gifts or entertainment are of nominal value, are customary to the industry, will not violate any laws and will not influence or appear to influence the recipient’s judgment or conduct at his or her employer’s business.

7.Fraud, Theft or Dishonesty

You will not commit any acts of fraud, theft, dishonesty, embezzlement, misappropriation or falsification in connection with the performance of your duties for the Company.  The Company reports any suspicion of fraud or theft to the applicable law enforcement agency or agencies.  If instructed to participate in, commit, or ignore any act that would violate or might be construed to violate these ethical standards, you should notify an independent director immediately.

8.Compliance with Laws, Regulations and Rules

You will at all times obey and comply with all federal, provincial, state and local laws, regulations and ordinances of the countries in which we operate, including but not limited to:

· Health and safety laws concerning the workplace;

· Civil rights laws concerning harassment and job discrimination;

· Employment laws concerning payment of minimum wage, overtime requirements, child labor and general working conditions;

· Immigration related laws concerning the hiring of legally documented workers;

· Laws concerning racketeering and corrupt practices;

· Laws concerning the proper maintenance of books, records and internal controls;

· Laws, regulations and accepted industry practices concerning drug development and commercialization;

· Laws prohibiting illegal payments, gifts, bribes or kickbacks to governmental officials, political parties or others;

· Privacy laws;

· Environmental laws;

· Laws prohibiting misappropriation, unauthorized use, reproduction or distribution of any third party’s trade secrets, copyrighted information or confidential proprietary information;

· Antitrust and other laws prohibiting unfair competition or restraint of trade; and

· Any other applicable law or regulation ordinance.

You will not commit or condone an unethical or illegal act nor instruct another employee, consultant, contractor, supplier or representative of the Company to do so.  You will not authorize or permit any consultant, contractor, distributor or representative of the Company to have authority to enter into, incur, make, change, enlarge or modify any contract, liability or agreement, obligation, representations, guarantee, warranty or commitment on behalf of the Company or its affiliated companies unless expressly approved by duly authorized representatives of the Company in the performance of the services contemplated under their respective agreement.

You are expected to be sufficiently familiar with any laws that apply to our work, to recognize potential breaches and to know when to seek legal advice.  If in doubt, you should discuss the matter with a member of the executive team.

9.Insider Information and Tipping

Securities laws prohibit the buying and selling of any securities, including Company securities, as well as securities of partners, contractors, suppliers and all other corporations, by anyone who possesses material, non-public information relating to the issuer of the securities.  Material non-public information is information which, if disclosed, would reasonably be expected to have a significant impact on the market value of such securities or which would be likely to influence an investor’s decision to purchase or sell a security.

From time to time the Company implements stock trading blackout periods during which time directors, officers and employees are restricted from buying or selling shares.  Background information on blackouts will be made available to employees on the Company’s Intranet site and/or otherwise through the Company’s email system.

Also prohibited is “tipping” – the disclosure of material, non-public information to anyone other than in the necessary course of business.  “Tipping” is a violation of the law and may result in civil or criminal liability of the person who passes material non-public information to another person who buys or sells securities while in possession of the information.

The Company does not condone, nor assist others in conducting activities which contravene the securities laws. Employees and contractors who are involved in or perpetrate any violation of the securities laws shall be subject to disciplinary action including, in the discretion of the Company, dismissal or termination.

10.Accounting and Recordkeeping

Many people associated with the Company, not just accountants and controllers, participate in the financial control and reporting processes of the Company.  If you have ANY responsibility for any aspect of the Company’s financial activities (including, but not limited to, processing of cash receipts or processing or approval of payments; creation, processing or approval of invoices and credit memos; payroll and benefits decisions; approval of expense reports and any and all other transactions; or the estimation of reserves or other claims or the amount of any accrual of deferral; or the recording of any of the foregoing in the Company’s ledgers) and/or the preparation of the Company’s financial statements or other reports, you must ensure your involvement complies with complete and accurate procedures as per established Company practice.

You shall not subvert the Company’s established systems of internal management and accounting controls, maintain funds or assets for any illegal or improper purposes or make false or misleading statements in any Company documents, reports or records.  No undisclosed or unrecorded accounts may be established using the Company’s funds or other assets. All accounting records and the financial reports produced from those records must be kept and presented in accordance with applicable law, must fully, fairly, accurately and timely reflect in understandable reasonable detail the Company’s assets, liabilities, revenue and expenses, and must be in accordance with generally accepted accounting principles, which are filed by the Company in periodic reports as required by the securities laws.

Transactions must be supported by accurate and reasonably detailed documentation and recorded in the proper account.  Best efforts are to be made to record transactions in the proper accounting time period.  To the extent that estimates are necessary, they must be based on your good faith judgment and be supported by appropriate documentation.  No payment or the related accounting entry may be approved or made with the intention or understanding that any part of the payment will be used for any purpose other than that described by the document supporting the entry or payment.

If you receive inquiries from the Company’s independent accountants, you must respond promptly, fully and accurately.

11.Use of Company Property

You are entrusted with the care, management and cost-effective use of the Company’s property and you will not make use of these resources for your own personal benefit or purposes or for the personal benefit of anyone else.

You will ensure that all Company property assigned to you is maintained in good condition and you should be able to account for such equipment. Any dispositions of Company property should be for the benefit of the Company and not for personal benefit.

Access to the Company’s computer systems is restricted where computer systems are defined as any combination of hardware, programs, applications, peripheral devices, personnel and/or associated documentation.

Passwords are to be kept confidential and use of the computer systems is limited to authorized business purposes with the exception of nominal personal use of email and voicemail which does not interfere or conflict with business use.

12.Proprietary and Confidential Information, Intellectual Property and Inventions

We want our employees to be well informed about our business, our plans for the future and the successes and challenges we have along the way.  In return for this openness the Company places trust in its employees to maintain, absent a court order or other legal requirement, the confidentiality of our proprietary information and those aspects of our business that we have not yet shared with shareholders and the general public.

You are to take all reasonable measures to protect the confidentiality of non-public information about the Company obtained or created in connection with your activities and to prevent the unauthorized disclosure of such information unless required by applicable law or regulation of legal or regulatory process.  You must use proprietary information only for the Company’s legitimate business purposes, and not for your personal benefit or the personal benefit of anyone else.

To provide the Company with reasonable protection against disclosure of trade secrets and confidential information, employees may be required to sign employment agreements or documents prior to their start with the Company that may include, but is not limited to clauses addressing confidential information, invention assignment and a prior invention declaration.  These clauses state in part that the Company retains exclusive ownership of all inventions and discoveries arising out of employment and any information pertaining to the business or research activities of the Company.

Proprietary and confidential information is any information about the Company that has not been disclosed to the public and includes, without limitation:

· The Company’s ideas, discoveries, inventions, formulae, algorithms, techniques, processes, know how, trade secrets, research, laboratory notes, data, analysis, assays, designs, methods, flow charts, drawings, specifications, plans, prototypes, apparatus, devices, specimens, manufacturing and production processes;

· Regulatory filings and correspondences;

· Software;

· Information concerning actual or projected sales, earnings or operating results or business transactions;

· Customer and supplier lists, relationship with consultants, contracts, business plans and marketing strategies; and

· Personnel information.

It is each employee’s responsibility to know what is confidential or proprietary and ensure that they use it only in the performance of duties with the Company.  If unsure, consider the information to be confidential until you obtain clarification.

13.Reporting and Compliance Procedures

Every employee, officer and director has the responsibility to ask questions, seek guidance, report suspected violation and express concern regarding compliance with this Code, including but not limited to questionable accounting, internal accounting control or auditing matters.

Any employee, officer or director who knows or believes that any other employee or representative of the Company has engaged or is engaging in Company-related conduct that violates applicable law or this Code has the responsibility to report such information.

You should first talk to the CEO and/or an independent director.

If you are not comfortable reporting to the above, it is not feasible, such reporting has resulted in unsatisfactory results, or you suspect the above individual(s) may be involved in such violations, you are to report such suspected violations to an independent member of the Board of Directors’ Audit Committee (the “Audit Committee”) as set out below.

Failure to comply with the standards outlined in this Code will result in disciplinary action including, but not limited to, reprimands, warnings, probation or suspension without pay, demotions, reductions in salary, discharge and restitution.  Certain violations of this Code may require the Company to refer the matter to the appropriate governmental or regulatory authorities for investigation or persecution.  Moreover, any supervisor who directs or approves of any conduct in violation of this Code, or who has knowledge of such conduct and does not immediately report it, also will be subject to disciplinary action, up to and including discharge.

14.Whistle-blower Protection

Any employee, officer, stockholder or third party who has a concern about the Company’s business conduct or any possible violations of law, or of this Code, or about its accounting, internal accounting controls or financial or auditing matters may communicate that concern directly to the Chairman of the Board of Directors or Chairman of the Audit Committee of the Board of Directors.

Such communication may be confidential.  You may also contact these persons to report any issues, complaints or concerns about potential breaches in ethics, compliance requirements or company policy.

Contact information:

  Jeremy G. DriverChairman of the Board800 Gessner, Suite 200Houston, Texas 77024Tel:(281) 408-4880Email:jdriver@duma.com   S. Chris HerndonBoard member and Chair of the Audit Committee800 Gessner, Suite 200Houston, Texas 77024Tel:(281) 352-3785Email:scherndon@cyruspartners.net

All such concerns will be forwarded to one or more appropriate individuals, inside or outside of the Company, for their review.  The status of all outstanding concerns addressed to the Chairman of the Board of Directors or the Chairman of the Audit Committee will be reported to the Audit Committee periodically.  The non-employee directors of the Audit Committee may direct specialized support, including the retention of outside advisors or counsel with payment by the Company, for any concern addressed to them.

No adverse action or retribution of any kind (i.e., discharge, demote, suspend, threaten or harass or in any other manner discriminate against an employee in the terms and conditions of employment) will be taken by the Company against any employee because he or she reports in good faith a suspected violation of this Code or other irregularity by any person other than the reporting employee.

15.Waivers and Amendments

While some of the policies contained in this Code must be strictly adhered to and no exception can be allowed, in other cases exceptions may be possible.  Any executive officer or director who seeks an exception to any of these policies should contact the Chairman of the Board of Directors.  Any waiver of this Code for executive officers and directors or any change to this Code that applies to executive officers or directors may be made only by the Board of Directors of the Company and will be disclosed as required by law or stock exchange policies, rules and/or regulations.

Any other employee or officer who believes that an exception to any of these policies is appropriate in his or her case should first contact his or her immediate supervisor.  If the supervisor agrees that an exception is appropriate, the approval of the Chief Executive Officer must be obtained.  The Chief Executive Office shall be responsible for maintaining a complete record of all requests for exceptions to any of these policies and the disposition of such requests.

16.Administration and Distribution

The Company’s Board of Directors and Audit Committee have established the standards of business conduct contained in this Code and oversee compliance with this Code.

This Code shall be distributed to each new employee, officer and director of the Company upon commencement of his or her employment or other relationship with the Company. It will also be made available via the Company’s Intranet site and/or otherwise through the Company’s email system.

Strict adherence to this Code is vital. Managers are responsible for ensuring that employees are aware of and understand the provisions of the Code. For clarification or guidance on any point in the Code of Business Conduct, please consult an officer of the Company Any officer receiving information about a possible violation of the Code will immediately bring it to the attention of the CEO, who will notify the board of directors as appropriate.

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Jeremy Glenn Driver, certify that:

1. I have reviewed this annual report on Form 10-K of Duma Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the consolidated financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 12, 2013
By:	/s/ Jeremy Glenn Driver
	Jeremy Glenn Driver
	Chief Executive Officer and a director
	(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Sarah Berel-Harrop, certify that:

1. I have reviewed this annual report on Form 10-K of Duma Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the consolidated financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 12, 2013
By:	/s/ Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATIONS PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the Annual Report of Duma Energy Corp. on Form 10-K for the year ended July 31, 2013, as filed with the Securities and Exchange Commission (the “Report”), Jeremy Glenn Driver, Chief Executive Officer and Sarah Berel-Harrop, Chief Financial Officer of Duma Energy Corp., do hereby certify, pursuant to 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350), that to his or her knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 12, 2013
By:	/s/ Jeremy Glenn Driver
	Jeremy Glenn Driver
	Chief Executive Officer and a director
	(Principal Executive Officer)

By:	/s/ Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signatures that appear in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

October 21, 2013

Duma Energy Corp

800 Gessner Rd., Suite 200

Houston, TX 77024

Attention:   Mr. Jeremy G. Driver

                   President and CEO

Re: Oil, Condensate and Natural Gas Reserves

SEC Non-Escalated Analysis

       Duma Energy Corp

As of July 31, 2013

Gentlemen:

At the request of Duma Energy Corp (“Duma”), the firm of Ralph E. Davis Associates Inc. (“Davis”) has prepared an evaluation of the oil, natural gas and natural gas liquid reserves on leaseholds in which Dumahas certain interests.  The purpose of this report is to present a summary of the Proved Developed Producing, Proved Developed Behind Pipe, Shut-In, and Undeveloped reserves that in our opinion meet the criteria for proved reserve volumes in keeping with the directives of the Securities and Exchange Commission as detailed later in this report.

Davis has evaluated 100% of Duma’s proved developed producing, proved developed behind pipe, shut-in, and undeveloped properties, all of which are located in various counties and parishes of Texas and Illinois respectively. We have prepared these estimates of the reserves, future production and income attributable to the subject interests with an effective date of July 31, 2013.

The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part 210—Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility Holding Company Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rules of General Application § 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975. A summation of these definitions is included as a portion of this letter.

We have also estimated the future net revenue and discounted present value associated with these reserves as of July 31, 2013, utilizing a scenario of non-escalated product prices as well as non-escalated costs of operations, i.e., prices and costs were not escalated above current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.

Duma Oil Corp October 21, 2013	October 21, 2013
SEC Non-Escalated Analysis Page of	Page 2 of 12
Oil, Condensate and Natural Gas Reserves

The results of our study related to our estimate of the Total Proved Reserves attributable to Duma and remaining to be produced as ofJuly 31, 2013are as follows:

Estimated Proved Reserves

Net to Duma Energy Corp

SEC Non-Escalated Analysis

As of July 31, 2013

	Estimated Net Reserves				Estimated Future Net Income *
Reserve Category	Oil		Gas		Undiscounted		Discounted@10%
	MBbls		MMCF		US $1000.		US $1000.
PROVED RESERVES
Producing		256.28		1,554.43	$	12,856.88	$	10,124.74
Shut-In		86.19		1,003.09	$	4,819.33	$	3,802.45
Behind Pipe		143.11		3,997.86	$	10,856.55	$	6,830.44
Undeveloped		174.12		6,175.01	$	9,192.51	$	3,758.84
TOTAL PROVED		659.70		12,730.39	$	37,725.26	$	24,516.50

*(Expenses are applied on a field wide basis.  Therefore, the net undiscounted and discounted income (10%) has been adjusted.  The values have been adjusted by application of each category’s share of the expense as a percent of its share of the unadjusted income.)  Note:  Errors in addition are due to rounding

Liquid volumes are expressed in thousands of barrels (MBbls) of stock tank oil.  Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.

A summary presentation by reserve category at the scheduled price scenario is included behind the economic summary analysis tab.  An additional presentation by reserve category by producing area is also included in the presentation to the report.

DISCUSSION

The scope of this study was to review basic information compiled by and prepare estimates of the proved reserves attributable to the interests of Duma.  Reserve estimates were prepared by Davis using acceptable evaluation principles for each source and were based in large part on the basic information supplied by Duma.

The quantities presented herein are estimated reserves of oil and natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty.  Proved undeveloped locations are scheduled to be drilled such that the investment cost will be fully recovered prior to recovery of estimated reserve volumes.

Duma Oil Corp October 21, 2013	October 21, 2013
SEC Non-Escalated Analysis Page of	Page 3 of 12
Oil, Condensate and Natural Gas Reserves

This evaluation has been prepared in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” as proclaimed by the Society of Petroleum Engineers”, the SPE Standards.

The majority of the evaluated properties are operated by Duma.  All proved developed producing properties were reviewed for this evaluation.  All data was made available.  Data provided includes seismic, well logs, sub-surface maps, analogous well data and timing of future development, drilling and investments.

Certain properties have been drilled, completed and previously produced.  Many of these contain additional reserves in intervals not yet completed within an existing wellbore and have been classified as proved behind pipe.  All of these properties are considered to have recoverable reserves and are scheduled to be placed on production at a future time.

Certain properties which have been drilled are currently shut-in.  They are considered to have recoverable reserves and are scheduled to be placed on production at a future time.  These properties will require remedial action before they can be restored to production.

Reserves classified as undeveloped are scheduled for future drilling beginning in 2015.  The undrilled locations have been reviewed on an individual well location basis.  The estimates of these recoverable reserves are based on volumetric estimates.

DATA SOURCE

Basic well and field data used in the preparation of this report were furnished by Duma or were obtained from commercial sources or from Davis’ own database of information. Records as they pertain to factual matters such as acreage controlled the number and depths of wells, reservoir pressure and/or production history, the existence of contractual obligations to others and similar matters were accepted as presented.

Additionally, the analyses of these properties utilized not only the basic data on the subject wells but also data on analogous properties as provided.  Well logs, ownership interest, revenues received from the sale of products and operating costs were furnished by Duma. No physical inspection of the properties was made nor any well tests conducted.

Operating cost data were provided by Duma and were utilized to estimate the direct cost of operation for each property or producing unit.  Certain historical costs of operation are charged against a producing unit or group of wells in addition to those individual well costs that may be scheduled for an area.

OWNERSHIP

Ownership interests in the subject properties have been furnished by Duma and accepted by Davis as accurate without independent verification.

Duma Oil Corp October 21, 2013	October 21, 2013
SEC Non-Escalated Analysis Page of	Page 4 of 12
Oil, Condensate and Natural Gas Reserves

RESERVE ESTIMATES

The estimate of reserves included in this report is based primarily upon production history or analogy with wells in the area producing from the same or similar formations.

In addition to individual well production history, geological and well test information, when available, were utilized in the evaluation.  Individual well production histories were analyzed and forecast until an anticipated economic limit.

Reserves for the behind pipe categories were estimated using volumetric methods which consolidated well log, sidewall core and subsurface mapping. Reserves for Fishers Reef, N. Point Bolivar, Red Fish Reed and Trinity Bay Fields were prepared on a field wide basis.  They are estimated to the limit of profitable operation for each field.

The accuracy of reserve estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data. It should be noted that all reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geological and engineering data available at the time of the estimate and the interpretation of these data. The reserves have been determined using methods and procedures widely accepted within the industry and are believed to be appropriate for the purposes of this report. In our opinion, we used all methods and procedures necessary under the circumstances to prepare this report.

PRODUCING RATES

For the purpose of this report, estimated reserves are scheduled for recovery primarily on the basis of actual producing rates or appropriate well test information. They were prepared giving consideration to engineering and geological data such as reservoir pressure, anticipated producing mechanisms, the number and types of completions, as well as past performance of analogous reservoirs.

These and other future rates may be subject to regulation by various agencies, changes in market demand or other factors; consequently, reserves recovered and the actual rates of recovery may vary from the estimates included herein.  Scheduled dates of future well completions may vary from that provided by Duma due to changes in market demand or the availability of materials and/or capital; however, the timing of the wells and their estimated rates of production are reasonable and consistent with established performance to date.

PRICING PROVISIONS

Prices received for products sold, adjustments due to the BTU content of the gas, shrinkage for transportation, measuring or the removal of liquids, the liquid yield from gas processed, etc., were provided by Duma and were accepted as presented.

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Oil, Condensate and Natural Gas Reserves

The unit price used throughout this report for crude oil, condensate and natural gas is based upon the appropriate price in effect the first trading of each month during fiscal year from August 2012 through July 2013 and averaged for the year.

Crude Oil, Condensate and/or Natural Gas Liquids – The unit price used throughout this report for crude oil and condensate is based upon the average of prices for the fiscal year as indicated above. An average crude oil price of $92.52 per barrel represents the effective average crude oil price utilized in the evaluation. This scheduled price for 2013 was held flat throughout the remaining producing life of the properties.  Prices for the liquid reserves scheduled for initial production at some future date were estimated using this same price.  Oil prices were adjusted for price differentials.

Natural Gas – The unit price used throughout this report for natural gas is based upon the average of prices for the fiscal year as indicated above.   An average gas price of $3.51 per MMBTU represents the effective average natural gas price utilized in the evaluation.   The scheduled price for 2013 was held flat throughout the remaining producing life of the properties.  Prices for natural gas reserves scheduled for initial production at some future date were estimated using this same price.  Gas prices were adjusted for BTU content and price differentials.

FUTURE NET INCOME

Future net income is based upon gross income from future production, less direct operating expenses and applicable provincial taxes.  Estimated future capital for development was also deducted from gross income at the time it will be expended.  No allowance was made for depletion, depreciation, income taxes or administrative expense.

Direct lease operating expense includes direct cost of operations of each lease or an estimated value for future operations based upon analogous properties.  Lease operating expenses and/or capital costs for drilling and/or major workover expense were held flat throughout the producing life of the properties.  Abandonment costs were deducted at the end of the economic life of the fields.

Future net income has been discounted for present worth at values ranging from 0 to 100 percent using continuous discounting.  In this report the future net income is discounted at a primary rate of ten (10.0) percent.

GENERAL

Duma has provided access to all of its accounts, records, geological and engineering data, reports and other information as required for this audit. The ownership interests, product classifications relating to prices and other factual data were accepted as furnished without verification.

No consideration was given in this report to potential environmental liabilities which may exist, nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

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Neither Ralph E. Davis Associates, Inc. nor any of its employees have any interest in Duma or the properties reported herein.  The employment and compensation to make this study are not contingent on our estimate of reserves. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE standards.

This report has been prepared for public disclosure by Duma in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please feel free to contact us if we can be of further service.

We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.

Very truly yours,

RALPH E. DAVIS ASSOCIATES, INC.

/s/ Nathan Kucharski

Nathan Kucharski

Reservoir Engineer

/s/ Allen C. Barron, P. E.

Allen C. Barron, P. E.

President

Ralph E. Davis Associates, Inc.

Texas Registered Engineering Firm F-1529

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SECURITIES AND EXCHANGE COMMISSION

DEFINITIONS OF RESERVES

The following information is taken from the United States Securities and Exchange Commission:

PART 210—FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACT OF 1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT COMPANY ACT OF 1940, AND ENERGY POLICY AND CONSERVATION ACT OF 1975

Rules of General Application

§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.

Reserves

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

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Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

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(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Oil and Gas Reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

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Oil, Condensate and Natural Gas Reserves

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Additional Definitions:

Deterministic Estimate

The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Probabilistic Estimate

The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Reasonable Certainty

If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

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CERTIFICATE OF QUALIFICATION

I, Allen C. Barron, of 1717 St. James Place, Suite 460, Houston, Texas 77056 hereby certify:

1. I am an employee of Ralph E. Davis Associates, Inc., that has prepared an audit and certification of the oil, natural gas and natural gas liquid reserves on specific leaseholds in which Duma Energy Corporation has certain interests. The effective date of this evaluation is August 1, 2013.

2. I am Licensed Professional Engineer by the State of Texas, P.E. License number 48284.

3. I attended the University of Houston in Houston, Texas and graduated with a Bachelor of Science Degree in Chemical Engineering with a Petroleum Engineering option in 1968. I have in excess of forty years experience in the Petroleum Industry of which over thirty years experience are in the conduct of evaluation and engineering studies relating to both domestic U.S. oil and gas fields and international energy assets.

4. I have prepared reserve evaluation studies and reserve audits for public and private companies for the purpose of reserve certification filings in foreign countries, domestic regulatory filings, financial disclosures and corporate strategic planning. I personally supervised and participated in the evaluation of the Duma Energy Corporation properties that are the subject of this report.

5. I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Duma Energy Corporation or any affiliated organizations.

6. A personal field inspection of the properties was not made, however, such an inspection was not considered necessary in view of the information available from public information, records and the files of the operator of the properties.

SIGNED: October 21, 2013

/s/ Allen C. Barron

Allen C. Barron, P.E.

President

Ralph E. Davis Associates, Inc.

1717 St. James Place, Suite 460 Houston, Texas 77056 Office 713-622-8955 Fax 713-626-3664 www.ralphedavis.com

Worldwide Energy Consultants Since 1924

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Standardized Measure) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Supplemental Oil And Gas Infomation Unaudited [Abstract]
Future cash inflows	$ 113,603,450	$ 200,741,090
Future production costs	(55,897,070)	(60,998,060)
Future development costs	(41,794,284)	(48,640,439)
Future income tax expenses	(5,569,234)	(31,885,907)
Future net cash flows	10,342,862	59,216,684
10% annual discount for estimated timing of cash flows	(3,990,069)	(25,552,798)
Future net cash flows at end of year	$ 6,352,793	$ 33,663,886

XML

Supplemental Oil and Gas Information (Unaudited) (Schedule of Results of Operations for Producing Activities) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Supplemental Oil And Gas Infomation Unaudited [Abstract]
Net revenues from production	$ 7,070,540	$ 7,165,233
Expenses
Lease operating expense	4,560,201	4,013,083
Accretion	1,056,508	943,508
Operating expenses	5,544,111	4,956,591
Depreciation, depletion, and amortization	1,059,803	990,486
Total expenses	6,603,914	5,947,077
Income before income tax	466,626	1,218,156
Income tax expenses	(163,319)	(426,355)
Results of operations	$ 303,307	$ 791,801
Depreciation, depletion and amortization rate per net equivalent MCFE	1.95	1.68

XML

Related Party Transactions

12 Months Ended

Jul. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

Note 10 - Related Party Transactions

During the years ended July 31, 2013 and 2012, a company controlled by one of our former officers, Carter E & P ("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 Duma 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		2012
Revenue generated from Barge Canal properties	$	643,203	$	569,476
Lease operating costs incurred from Barge Canal properties	$	224,047	$	181,113
Overhead costs incurred	$	28,038	$	25,087
Outstanding accounts receivable at period end	$	91,967	$	74,972
Outstanding accounts payable at year end	$	-	$	-

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 4 - Oil and Gas Properties)

The father of the Chief Financial Officer and a company controlled by the father-in-law of the Chief Executive Officer each purchased a 5% working interest in the ST 9-12A #4 well.  As of July 31, 2012, these parties owed $42,646 in billed and unbilled joint interest billings. As of July 31, 2013, the company controlled by the father-in-law of the Chief Executive Officer owed us $84,806. We also had an advance outstanding from the father of the Chief Financial Officer, which was reflected in the caption "Due to related parties", of $15,046.

In November 2011, we paid $6,423 principal on a note payable due to a director.  We also paid the associated accrued interest of $416.

In October 2011, we paid $8,300 of principal on a note payable due to an officer and director of Duma. We also paid the accrued interest associated with the note of $413.

During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our Chief Executive Officer and a Director, as detailed in Note 9 - Capital Stock.  We recognized expense of $196,384 and 189,372 from this contract during the years ended July 31, 2013 and 2012, respectively.

During the quarter ended October 2012, we purchased NEI for up to 24,900,000 shares of Duma common stock, as described in Note 2 - Acquisitions - Namibia Exploration, Inc.

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Capital Stock (Options Outstanding and Exercisable) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2011
Options Outstanding and Exercisable [Line Items]
Outstanding Number of Shares	1,536,000	1,044,000	1,101,200
Term of options granted	7 years 11 months 23 days	7 years 2 months 19 days	8 years 1 month 21 days
Exercisable Number of Shares	776,800	564,000
Options One [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price	$ 2.20	$ 2.50
Outstanding Number of Shares	600,000	800,000
Term of options granted	9 years 6 months 15 days	8 years 8 months 19 days
Exercisable Number of Shares		320,000
Options Two [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price	$ 2.50	$ 2.50
Outstanding Number of Shares	796,000	24,000
Term of options granted	7 years 8 months 23 days	6 years 9 months 22 days
Exercisable Number of Shares	636,800	24,000
Options Three [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price	$ 2.50	$ 2.50
Outstanding Number of Shares	60,000	60,000
Term of options granted	3 years 11 months 5 days	4 years 11 months 5 days
Exercisable Number of Shares	60,000	60,000
Options Four [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price	$ 2.50	$ 2.50
Outstanding Number of Shares	24,000	56,000
Term of options granted	5 years 9 months 22 days	1 year 15 days
Exercisable Number of Shares	24,000	56,000
Options Five [Member]
Options Outstanding and Exercisable [Line Items]
Exercise price	$ 2.50	$ 2.50
Outstanding Number of Shares	56,000	104,000
Term of options granted	1 year	1 year
Exercisable Number of Shares	56,000	104,000

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CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) [Abstract]
Revenues	$ 7,070,540	$ 7,165,233
Operating expenses
Lease operating expense	4,560,201	4,013,083
Depreciation, depletion, and amortization	1,085,980	1,021,981
Accretion	1,056,508	943,508
Consulting fees - related party	196,384	189,372
Acquisition-related costs - related party	37,234,752	4,367,750
General and administrative expense	3,298,376	3,852,722
Total operating expenses	47,432,201	14,388,416
Loss from operations	(40,361,661)	(7,223,183)
Interest expense, net	(499,360)	(157,964)
Net gain (loss) on sale of available for sale securities	(793,247)	463,117
Gain on derivative warrant liability	1,056,224	1,217,835
Net loss before income taxes	(40,598,044)	(5,700,195)
Income tax benefit	122,949	1,120,471
Net loss	(40,475,095)	(4,579,724)
Other comprehensive income, net of tax:
Change in market value of available for sale securities, including unrealized loss and reclassification adjustments to net income, net of income tax of $0 and $0		(743,082)
Comprehensive Loss	$ (40,475,095)	$ (5,322,806)
Basic and diluted loss per common share	$ (3.11)	$ (0.45)
Weighted average shares outstanding (basic and diluted)	13,028,592	10,218,355

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Available for Sale Securities

12 Months Ended

Jul. 31, 2013

Available for Sale Securities [Abstract]

Available for Sale Securities

Note 3 - Available for Sale Securities

Beginning in the quarter ended October 31, 2011, we owned marketable equity securities, which are classified as available for sale.

We acquired securities with a market value of $3,900,000 in conjunction with our acquisition of SPE. (See Note 2 - Acquisitions - SPE Navigation I, LLC). During the year ended July 31, 2012, we received cash proceeds of $4,009,548 from sales of securities with a cost basis of $3,546,431; thus, we had a realized gain on sale of available for sale securities of $463,117.  During the year ended July 31, 2012, we also 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, 2013, we do not hold any available for sale securities.

XML

Description of Business and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Jul. 31, 2013

Description of Business and Summary of Significant Accounting Policies [Abstract]

Schedule of the Components of Accumulated Other Comprehensive Income (Loss)

The components of accumulated other comprehensive loss:

	Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss at July 31, 2012	$	(743,082	)
Reclassification into earnings		743,082
Accumulated other comprehensive loss at July 31, 2013	$	-

XML

Additional Financial Statement Information (Schedule of Property and Equipment) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Property, Plant and Equipment [Line Items]
Total property and equipment	$ 82,541	$ 82,541
Less accumulated depreciation	(62,749)	(36,572)
Net book value	19,792	45,969
Depreciation expense	26,177	31,495
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	7,604	7,604
Marine vessels [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	17,614	17,614
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	5 years
Total property and equipment	18,027	18,027
Computer equipment and software [Member]
Property, Plant and Equipment [Line Items]
Approximate Life	2 years
Total property and equipment	$ 39,296	$ 39,296

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Capital Stock (Summary of Warrants Issued and Outstanding) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2011
Warrants
Outstanding, beginning balance	3,756,455	3,758,455
Granted
Exercised
Expired	(45,578)	(2,000)
Outstanding, ending balance	3,710,877	3,756,455	3,758,455
Weighted Average Share Price
Outstanding, beginning balance	2.58	2.50
Granted
Exercised
Expired	$ 9.34	$ 25.00
Outstanding, ending balance	2.50	2.58	2.50
Aggregate intrinsic value			$ 3,710,880
Weighted average remaining contractual life	1 year 10 months 13 days	2 years 9 months 29 days	3 years 9 months 29 days

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Income Taxes

12 Months Ended

Jul. 31, 2013

Income Taxes [Abstract]

Income Taxes

Note 11 -  Income Taxes

Our net loss before income taxes totaled $(40,598,044) and $(5,700,195) for the years ended July 31, 2013 and 2012, respectively.

We recognized an income tax benefit during the year ended July 31, 2013 because the estimated tax liability for 2012 exceeded the actual tax liability.

We recognized a large income tax benefit during the year ended July 31, 2012 primarily due to intangible drilling costs and dry hole costs that resulted in tax losses and the utilization of net operating losses that offset the recognized tax gain on securities sold during the year.  The securities were acquired with SPE (See Note 2 - Acquisitions) and had built-in capital gains on the purchase date, which resulted in the recognition of a deferred tax liability on the date of purchase.  In accordance with purchase accounting, the utilization of the tax losses, which were possible because the gains existed, was recognized as a tax benefit and the purchase price accounting remained unchanged. A portion of the stock acquired in the purchase of SPE was not sold during the year.  We determined that current deferred tax assets existed that are sufficient to offset deferred tax liability on unrecognized tax gain on these available for sale securities  and accordingly we adjusted the valuation allowance for our deferred tax assets, which resulted in a further tax benefit.  

The reconciliation of our income tax provision at the statutory rate to the reported income tax expense is as follows:

	July 31,
	2013			2012
US statutory federal rate		35.00	%		35.00	%
State income tax rate		.58	%		.58	%
Equity-based compensation		(33.62	)%		(36.43	)%
Gain on derivative warrants		.93	%		7.60	%
Gain on sale of securities		(.33	)%		(21.15	)%
Other		(.50	)%		4.02	%
Acquired deferred tax liability		-	%		23.12	%
Net operating loss		(1.75	)%		6.92	%
		.31	%		19.66	%

Our deferred income taxes reflect the net tax effects of operating loss and 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 that 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, 2013 and 2012 are as follows:

	July 31,
	2013			2012
Stock based compensation	$	713,867		$	292,509
Property, including depreciable property		(2,980,005	)		(2,070,809	)
Asset retirement obligation		3,942,918			3,312,358
Net operating loss carry-forward		3,846,783			2,530,532
Other		42,368			318,032
		5,565,931			4,382,622
Valuation allowance for deferred tax assets		(5,565,931	)		(4,382,622	)
	$	-		$	-

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, 2013 will significantly increase or decrease within 12 months.

Generally, our income tax years 2010 through 2013 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, 2013, we had approximately $10,813,165 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.

Our ability to use our NOLs would be limited if it was determined that we underwent an "ownership change" under Section 382 ("Section 382") of the Internal Revenue Code. Based upon the information available to us, along with our evaluation of various scenarios, we believe that our 2011 private placement caused us to experience an "ownership change".

In order to determine whether an "ownership change" occurred, we had to compare the percentage of shares owned by each 5.0% shareholder immediately after the close of the testing date to the lowest percentage of shares owned by such 5.0% shareholder at any time during the testing period (which is generally a three year rolling period). The amount of the increase in the percentage of Company shares owned by each 5.0% shareholder whose share ownership percentage has increased is added together with increases in share ownership of other 5.0% shareholders, and an "ownership change" occurs if the aggregate increase in ownership by all such 5.0% shareholders exceeds 50%.  The issuance of our common shares as part of the 2011 private placement caused such threshold to be exceeded.

As a result of experiencing an "ownership change", we will only be allowed to use a limited amount of NOLs to offset our taxable income subsequent to the "ownership change." The annual limit pursuant to Section 382 (the "382 Limitation") is obtained by multiplying (i) the aggregate value of our outstanding equity immediately prior to the "ownership change" (reduced by certain capital contributions made during the immediately preceding two years and certain other items) by (ii) the federal long-term tax-exempt interest rate in effect for the month of the "ownership change."  As our ownership change occurred in February 2011, the federal long-term tax-exempt interest rate applicable to our limitation is 4.47%.  Therefore, based on the factors in place at the time of our ownership change, we believe our annual limitation would be an estimated $239,600. On September 6, 2012, we acquired Namibia Exploration, Inc.  We believe the transaction may have resulted in a second "ownership change", which would further limit the availability of NOLs incurred prior to the transaction.

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" will significantly defer the utilization of the loss carryforwards, accelerate payment of federal income tax and may cause some of the NOLs to expire unused.

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Fair Value (Schedule of the Change in Fair Value of the Derivative Warrant Liability) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Fair Value [Abstract]
Beginning balance	$ 1,325,388	$ 2,543,223
Expiration of derivative warrant feature	(269,164)
Unrealized gain on changes in fair value of derivative liability	(1,056,224)	(1,217,835)
Ending balance		$ 1,325,388

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Capital Stock (Warrants Outstanding and Exercisable) (Details)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2011
Warrants Outstanding And Exercisable [Line Items]
Exercise Price	2.50	2.58	2.50
Outstanding Number of Shares	3,710,877	3,756,455
Remaining Life	1 year 10 months 13 days	2 years 9 months 29 days	3 years 9 months 29 days
Exercisable Number of Shares	2,510,877	2,556,455
Warrants One [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise Price	2.50	2.50
Outstanding Number of Shares	2,000,000	2,000,000
Remaining Life	3 years	3 years 6 months 18 days
Exercisable Number of Shares	800,000	800,000
Warrants Two [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise Price	2.50	2.50
Outstanding Number of Shares	1,253,757	1,253,757
Remaining Life	2 years	2 years 2 months 16 days
Exercisable Number of Shares	1,253,757	1,253,757
Warrants Three [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise Price	2.50	2.50
Outstanding Number of Shares	457,120	400,000
Remaining Life	1 year	1 year 8 months 1 day
Exercisable Number of Shares	457,120	400,000
Warrants Four [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise Price		2.50
Outstanding Number of Shares		5,120
Remaining Life		1 year 6 months 26 days
Exercisable Number of Shares		5,120
Warrants Five [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise Price		2.50
Outstanding Number of Shares		52,000
Remaining Life		1 year 6 months 18 days
Exercisable Number of Shares		52,000
Warrants Six [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise Price		6.25
Outstanding Number of Shares		8,000
Remaining Life		1 year
Exercisable Number of Shares		8,000
Warrants Seven [Member]
Warrants Outstanding And Exercisable [Line Items]
Exercise Price		10.00
Outstanding Number of Shares		37,578
Remaining Life		1 year
Exercisable Number of Shares		37,578

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Acquisitions (Narrative) (Details) (USD $)	12 Months Ended		0 Months Ended		1 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Sep. 23, 2011 SPE Navigation I, LLC [Member]	Sep. 06, 2012 Namibia Exploration, Inc. [Member] acre	Sep. 30, 2012 Namibia Exploration, Inc. [Member]	Jul. 31, 2013 Namibia Exploration, Inc. [Member] acre	Sep. 06, 2012 Namibia Exploration, Inc. [Member] Hydrocarb Namibia [Member]	Sep. 06, 2012 Namibia Exploration, Inc. [Member] NPC Namibia [Member]
Business Acquisition [Line Items]
Percentage of equity interests acquired			100.00%
Percentage of interest sold			25.00%
Number of shares owned			1,000,000
Acquisition related costs, cash paid					$ 713,655
Stock issued during period for acquisition, shares			3,799,998	2,490,000
Stock issued during period for acquisition	35,396,800	9,500,000		3,784,800
Acquisition-related costs - related party	37,234,752	4,367,750		37,234,752
Amount of farm-in fee paid by original owners for payment of concession				2,400,000
Cost basis in working interest in oil and gas property				562,048	562,048
Liabilities assumed in business acquisition				1,837,952
Ownership percentage				39.00%		39.00%	51.00%	10.00%
Cost responsibility percentage				43.33%		43.33%	56.67%
Number of acres included in oil and gas property				5,300,000		530,000
Contingent shares to be issued upon achievement of milestone one				2,490,000
Total contingent shares that could be issued if all milestones are achieved				24,900,000
Contingent shares to be issued upon achievement of milestone two				7,470,000
Contingent shares to be issued upon achievement of milestone three				12,450,000
The minimum ten day volume-weighted average market capitalization to achieve milestone one				82,000,000
The minimum ten day volume-weighted average market capitalization to achieve milestone two				196,000,000
The minimum ten day volume-weighted average market capitalization to achieve milestone three				434,000,000
Total consulting fee per consulting services agreement				2,400,000
Value of the consulting fee to be paid in either cash or stock				800,000
Value of consulting fee to be paid through issuance of promissory note				1,600,000
Interest rate on promissory note to be issued as payment of consulting fee				5.00%
Total principal amount due on the first anniversary of effective date				800,000
Total principal amount due on the second anniversary of effective date				800,000
Late fee percentage owed on any balance under the consulting services agreement that is outstanding greater than thirty days				10.00%
Fair value of contingent equity grant				31,612,000
Fair value of assets acquired		5,132,250
Accounts payable and accrued expenses	$ 3,779,401	$ 2,298,838		$ 320,000

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Asset Retirement Obligation (Tables)

12 Months Ended

Jul. 31, 2013

Asset Retirement Obligation [Abstract]

Schedule of Reconciliation of Asset Retirement Obligations

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2013 and 2012:

	2013			2012
Liability for asset retirement obligation, beginning of period	$	9,382,933		$	4,455,928
Asset retirement obligations assumed		-			2,365,530
Asset retirement obligations sold		(438	)		(32,772	)
Asset retirement obligations incurred on properties drilled		26,500			1,389
Accretion		1,056,508			943,508
Revisions in estimated cash flows		786,120			1,827,889
Costs incurred		(318,225	)		(178,539	)
Liability for asset retirement obligation, end of period	$	10,933,398		$	9,382,933
Current portion of asset retirement obligation	$	724,374		$	549,796
Noncurrent portion of asset retirement obligation		10,209,024			8,833,137
Total liability for asset retirement obligation	$	10,933,398		$	9,382,933

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Oil and Gas Properties (Tables)

12 Months Ended

Jul. 31, 2013

Oil and Gas Properties [Abstract]

Schedule of Oil and Natural Gas Properties

Oil and natural gas properties as of July 31, 2013 and July 31, 2012 consisted of the following:

	July 31, 2013			July 31, 2012
Evaluated Properties
Costs subject to depletion, net of accumulated impairment of $373,355 and $373,355, respectively	$	19,484,507		$	17,180,501
Accumulated depletion		(2,617,478	)		(1,557,675	)
Total evaluated properties		16,867,029			15,622,826
Unevaluated properties		713,655			265,639
Net oil and gas properties	$	17,580,684		$	15,888,465

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Fair Value (Narrative) (Details)	1 Months Ended
	Oct. 31, 2009	Nov. 13, 2012	Oct. 15, 2012
Fair Value [Abstract]
Discount to market price	65.00%
Number of warrants expired		206,400	408,065

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Additional Financial Statement Information (Tables)

12 Months Ended

Jul. 31, 2013

Additional Financial Statement Information [Abstract]

Schedule of Other Current Assets

Other current assets consisted of the following:

	At July 31,
	2013		2012
Prepaid letter of credit fees	$	93,362		16,567
Prepaid insurance		180,433		178,471
Other prepaid expenses		2,000		10,164
Cash call paid to operator		24,225		23,234
Prepaid land use fees		28,728		19,852
Accrued interest income		4,388		8,389
Total other current assets	$	333,136	$	256,677

Schedule of Property and Equipment

Property and equipment consisted of the following:

		At July 31,
	Approximate Life	2013			2012
Furniture and fixtures	5 years	$	7,604		$	7,604
Marine vessels	5 years		17,614			17,614
Vehicles	5 years		18,027			18,027
Computer equipment and software	2 years		39,296			39,296
Total property and equipment			82,541			82,541
Less accumulated depreciation			(62,749	)		(36,572	)
Net book value		$	19,792		$	45,969
Depreciation expense		$	26,177		$	31,495

Schedule of Accounts Payables and Accrued Expenses

Accounts payable and accrued expenses consisted of the following:

	At July 31,
	2013		2012
Trade payables	$	3,068,671	$	1,950,768
Accrued payroll		151,577		40,000
Accrued interest and fees		398,966		-
Revenue payable		4,717		6,690
Local taxes and royalty payable		128,470		108,948
Federal and state income taxes payable		27,000		192,432
Total accounts payable and accrued expenses	$	3,779,401	$	2,298,838

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Available for Sale Securities (Details) (USD $)	1 Months Ended			12 Months Ended
	Dec. 31, 2012	Oct. 31, 2012	Sep. 30, 2012	Jul. 31, 2013	Jul. 31, 2012
Schedule of Available-for-sale Securities [Line Items]
Proceeds from sale of available for sale securities	$ 142,637		$ 145,637	$ 287,874	$ 4,009,548
Cost basis of available for sale securities sold	198,593	174,000	607,201		3,546,431
(Gain) loss on sale of available for sale securities	55,956		461,964	793,247	(463,117)
Impairment of available for sale securities		275,327		275,327
Unrealized loss reclassified from other comprehensive loss into earnings	(743,082)				6,383
Market value of available-for-sale securities				24,593	702,959
SPE Navigation I, LLC [Member]
Schedule of Available-for-sale Securities [Line Items]
Market value of available-for-sale securities					$ 3,900,000

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Capital Stock (Stock Issued for Services and Investor Relations) (Details) (USD $)	0 Months Ended	1 Months Ended	3 Months Ended	12 Months Ended			0 Months Ended	12 Months Ended			1 Months Ended
	Apr. 04, 2012	Dec. 31, 2011	Apr. 30, 2012	Jul. 31, 2013	Jul. 31, 2012	May 16, 2012	Sep. 06, 2012 Namibia Exploration, Inc. [Member]	Jul. 31, 2013 Common Stock [Member]	Jul. 31, 2012 Common Stock [Member]	Jul. 31, 2011 Common Stock [Member]	Aug. 31, 2011 Investors Group [Member]
Stock Issued During Period [Line Items]
Issuance of common stock for services		$ 27,703			$ 620,155				$ 200
Issuance of common stock for services, shares		13,036							200,189		189,585
Investor relations expense											592,452
Shares cancelled			2,431
Acquisition				35,396,800	9,500,000		3,784,800	2,490	3,800
Acquisition, shares							2,490,000	2,490,000	3,799,998
Fair value of contingent equity grant							$ 31,612,000
Common stock, shares authorized				500,000,000	500,000,000	20,000,000
Common stock, par value per share				$ 0.001	$ 0.001	$ 0.001
Stock split conversion ratio	25
Common stock, shares issued				13,281,003	10,791,003	269,742,986
Common stock, shares outstanding				13,281,003	10,791,003	269,742,986		13,281,003	10,791,003	6,790,816

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Related Party Transactions (Tables)

12 Months Ended

Jul. 31, 2013

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		2012
Revenue generated from Barge Canal properties	$	643,203	$	569,476
Lease operating costs incurred from Barge Canal properties	$	224,047	$	181,113
Overhead costs incurred	$	28,038	$	25,087
Outstanding accounts receivable at period end	$	91,967	$	74,972
Outstanding accounts payable at year end	$	-	$	-

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Commitments and Contingencies (Letter of Credit) (Details) (USD $)	12 Months Ended				1 Months Ended
	Jul. 31, 2013	Jun. 30, 2013	Apr. 30, 2013 Letter of Credit One [Member]	Apr. 30, 2013 Letter of Credit Two [Member]	Apr. 30, 2013 Accounts payable and accrued expenses [Member]
Commitments And Contingencies [Line Items]
Environmental remediation expense					$ 150,000
Monthly compression and handling fees	1,000
Debt instrument, face amount		$ 300,000	$ 6,610,000	$ 180,000
Debt instrument, fee percentage			1.50%	1.50%

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Capitalized Costs) (Details) (USD $)	Jul. 31, 2013	Jul. 31, 2012
Supplemental Oil And Gas Infomation Unaudited [Abstract]
Unevaluated properties	$ 713,655	$ 265,639
Evaluated properties	19,857,842	17,553,836
Less impairment	(373,355)	(373,355)
Gross capitalized costs	20,198,162	17,446,140
Less depreciation, depletion and amortization	(2,617,478)	(1,557,675)
Net oil and gas properties	$ 17,580,684	$ 15,888,465

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Commitments and Contingencies (Schedule of Future Payments of Operating Leases and Debt) (Details) (USD $)	Jul. 31, 2013
Commitments And Contingencies [Line Items]
Operating leases, 2014	$ 71,047
Operating leases, 2015
Operating leases, 2016
Operating leases, Total	71,047
2014	1,059,644
2015	942,992
Total	2,002,636
Total, 2014	1,206,089
Total, 2015	967,295
Total, 2016
Total Long-term debt and Operating leases	2,173,384
Notes Payable [Member]
Commitments And Contingencies [Line Items]
2014	1,135,042
2015	967,295
2016
Total	$ 2,102,337

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Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Asset Retirement Obligation [Abstract]
Liability for asset retirement obligation, beginning of period	$ 9,382,933	$ 4,455,928
Asset retirement obligations assumed		2,365,530
Asset retirement obligations sold	(438)	(32,772)
Asset retirement obligation incurred on properties drilled	26,500	1,389
Accretion	1,056,508	943,508
Revisions in estimated cash flows	786,120	1,827,889
Costs incurred	(318,225)	(178,539)
Liability for asset retirement obligation, end of period	10,933,398	9,382,933
Current portion of asset retirement obligation	724,374	549,796
Noncurrent portion of asset retirement obligation	10,209,024	8,833,137
Total liability for asset retirement obligation	$ 10,933,398	$ 9,382,933

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Subsequent Events (Details) (USD $)	1 Months Ended	12 Months Ended		1 Months Ended
	Dec. 31, 2011	Jul. 31, 2013	Jul. 31, 2012	Oct. 31, 2013 Subsequent Event [Member]	Aug. 31, 2013 Subsequent Event [Member]	Oct. 31, 2013 Subsequent Event [Member] Namibia Exploration, Inc. [Member]
Subsequent Event [Line Items]
Expected life		6 years 6 months		6 years 6 months	6 years 6 months
Risk free interest rate				2.09%	2.01%
Dividend yield		0.00%	0.00%	0.00%	0.00%
Volitility factor				117.31%	144.01%
Vested				480,000	120,000
Number of options granted		600,000			600,000
Fair value of options vested				$ 851,096	$ 16,184
Services, shares	13,036					1,859,879
Services	27,703		620,155			2,400,000
Joint interest billings payable						635,937
Interest and late fees						$ 553,640

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Acquisitions (Tables)

12 Months Ended

Jul. 31, 2013

Business Acquisition [Line Items]

Summary of Pro Forma Information

Revenues	$	7,313,232
Loss from operations		(7,419,747	)
Net loss		(4,776,288	)
Loss per share, basic and diluted		(0.47	)

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CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Loss [Member]	Accumulated Deficit [Member]
Balance at Jul. 31, 2011	$ 6,629,915	$ 6,791	$ 27,970,520		$ (21,347,396)
Balance, shares at Jul. 31, 2011		6,790,816
Common stock issued for:
Services	620,155	200	619,955
Services, shares		200,189
Acquisition	9,500,000	3,800	9,496,200
Acquisition, shares		3,799,998
Share-based compensation:
Amortization of fair value of stock options	687,770		687,770
Warrants granted to related party	189,372		189,372
Expiration of derivative warrant liability
Unrealized loss on available for sale securities	(743,082)			(743,082)
Net loss	(4,579,724)				(4,579,724)
Balance at Jul. 31, 2012	12,304,406	10,791	38,963,817	(743,082)	(25,927,120)
Balance, shares at Jul. 31, 2012	10,791,003	10,791,003
Common stock issued for:
Acquisition	35,396,800	2,490	35,394,310
Acquisition, shares		2,490,000
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
Net loss	(40,475,095)				(40,475,095)
Balance at Jul. 31, 2013	$ 9,367,867	$ 13,281	$ 75,756,801		$ (66,402,215)
Balance, shares at Jul. 31, 2013	13,281,003	13,281,003

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Description of Business and Summary of Significant Accounting Policies

12 Months Ended

Jul. 31, 2013

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

Duma Energy Corp. ("we", "us", "Duma", the "Company") was formed for the purpose of oil and gas exploration, development, and production. We own 100% of Penasco Petroleum Inc. ("Penasco"), a Nevada corporation incorporated on November 23, 2005 and 100% of Galveston Bay, LLC, ("GBE"), a Texas limited liability company, 100% of SPE Navigation I, LLC ("SPE") a Nevada limited liability company and 100% of Namibia Exploration, Inc. ("NEI") a Nevada corporation.  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").

Reclassifications

Certain prior year amounts have been reclassified to conform with the current presentation.

Principles of consolidation

The accompanying consolidated financial statements include the accounts of Duma and our wholly owned subsidiaries, Penasco, SPE, GBE and NEI. 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 which 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 the Chief Financial Officer and the Chief Executive Officer.

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, 2013 and 2012, we have reserved $58,585 and $1,302, 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, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable. For the year ended July 31, 2012, 67% of our revenue was attributable to one purchaser.  At July 31, 2012, this same purchaser accounted for 79% 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, 2013 and July 31, 2012, 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, 2013 and 2012, restricted cash totaled $6,920,739 and $6,890,000, respectively.

Other assets

Other assets at July 31, 2013 and 2012 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, 2013 and 2012, 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, 2013 and 2012, advances totaled $180,804 and $55,161, 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 valorum 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, 2013 and o ur derivative warrant liability was our only financial asset or liability that was accounted for at fair value, using a Level 3 valuation technique, on a recurring basis as of July 31, 2012. 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 April 4, 2012, we effected a 1-for-25 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, 2013 and 2012, 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 12 - 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. The components of accumulated other comprehensive loss:

	Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss at July 31, 2012	$	(743,082	)
Reclassification into earnings		743,082
Accumulated other comprehensive loss at July 31, 2013	$	-

Recent accounting pronouncements

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.

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Oil and Gas Properties

12 Months Ended

Jul. 31, 2013

Oil and Gas Properties [Abstract]

Oil and Gas Properties

Note 4 - Oil and Gas Properties

Oil and natural gas properties as of July 31, 2013 and July 31, 2012 consisted of the following:

	July 31, 2013			July 31, 2012
Evaluated Properties
Costs subject to depletion, net of accumulated impairment of $373,355 and $373,355, respectively	$	19,484,507		$	17,180,501
Accumulated depletion		(2,617,478	)		(1,557,675	)
Total evaluated properties		16,867,029			15,622,826
Unevaluated properties		713,655			265,639
Net oil and gas properties	$	17,580,684		$	15,888,465

Evaluated properties

We incurred geological and geophysical costs of $157,818 during the year ended July 31, 2013.

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, 2013 include:

● costs associated with a development well, the State Tract 9-12A#4 well in Galveston Bay totaling $447,511;

● costs for a recompletion in Galveston Bay totaling $361,372; and

● increase in asset retirement obligations of $803,788 primarily due to changes in timing and in estimated costs for the gathering systems located in Galveston Bay.

Onshore property

As of July 31, 2013, we owned interests in properties in Texas and Illinois as follows:

Illinois

We owned 10% working interest in multiple leases in or near Markham City, Illinois that are operated by Core Minerals Management II, LLC ("Core") in accordance with a farmout agreement, which we entered into during January 2011. After payout of the property, $1,350,000 or 29,000 barrels, whichever comes first, provided that we hold less than 25% working interest in the property at payout, our working interest will be adjusted to 25%. During fiscal 2012, the operator drilled wells in the contract area and commenced a pilot waterflood project to re-pressurize the reservoir and enhance recovery of oil from the area. The wells in the project area produce oil.

Texas

We own 100% working interest and a 72.5% net revenue interest in approximately 81 acres of an oil and gas lease (the "Welder Lease") located in Calhoun County, Texas.  There are two productive wells on the property, which was operated by a company owned by one of our former officers until September 1, 2013.  Effective September 1, 2013, we took over operations of the lease.

In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas (the "Palacios Lease").  Under the agreement, the operator commenced drilling a well, the Palacios #1, during November 2011.  Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area.  Our net revenue interest in the prospect is 4.125%.  The well produces primarily gas.

In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas (the "Chapman Prospect"). According to the terms of the agreement, we would pay 31.25% of costs to casing point of the initial well and of the plug and abandonment costs if the initial well is a dry hole and 25% of costs after casing point. For subsequent wells, we would pay 25% of the costs before and after the casing point. The well was drilled in June 2012; however, the first completion zone was non-economic. $265,639 in costs, including acquisition costs of $58,805 and drilling costs of $206,834, were reflected as unevaluated property as of July 31, 2012. During October 2012, we participated in a recompletion operation which resulted in the completion of the well into an upper zone, however commercial production was not established. Another rework operation was attempted in June 2013, which was unsuccessful.  Because of the lack of success, management determined that there would be no reserves ascribed and the prospect is classified as evaluated as of the July 31, 2013.

During August 2012, we leased approximately 190 acres of land in Bee County, Texas (the "Curlee Prospect").  The operator of the project was Carter E&P, a company owned by our former Vice President of Operations.  We had a 50% working interest in the project, 25% of which was carried to the casing point by the other participants in the initial well.  Because we took a 25% additional interest, the portion of the working interest that we pay, prior to the casing point, is 33.3%.  After the casing point and for all costs in future wells, we will be responsible for 50% of the costs. We paid $45,931 in acquisition and land costs for this prospect. We received a bonus of $51,589 from the other parties in the well, which was reflected as a reduction of capitalized costs in accordance with full cost accounting. During the quarter ended October 31, 2012, we drilled a well on the property, the Curlee No. 1 well, which was plugged and abandoned.

In December 2012, we acquired a 366.85 acre tract of property, the Dix Prospect, in San Patricio County, Texas. We paid $76,938 in acquisition and land costs. In February 2013, we sold 75% working interest in the prospect to partners on a third for a quarter basis, under which the 75% interest holders will carry 25% of the working interest to the casing point of the initial well drilled on the prospect. We also sold 2% of the carried working interest to Carter E&P, a company owned by our former Vice President of Operations. Thus we retained a 23% working interest which is carried to the casing point of the initial well. We received proceeds of $109,328 from the other parties in the prospect, which was reflected as a reduction of capitalized costs in accordance with full cost accounting. The initial well was drilled in May 2013, but it was determined that the well could not produce economically. Accordingly, it was not completed.

During April 2013, we purchased a 12.5% working interest in a 260.12 acre tract of property, the Melody Prospect, in Bee County, Texas.  The operator of the project is Carter E&P, a company owned by our former Vice President of Operations.  We incurred acquisition costs of $7,355 on the prospect. The well was drilled in June 2013 and it was a dry hole.

We incurred $210,588 of exploratory drilling costs during the year ended July 31, 2013 on the Chapman, Curlee, Dix, and Melody prospects.

Effective September 1, 2013, we conveyed our interest in the Dix, Melody, Curlee, Palacios and Illinois 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.

Sales of properties

As of July 31, 2012, we owned a 6.25% overriding royalty interest in properties located in Franklin and Richland parishes in Louisiana (the "Holt" and "Strahan" properties).  We also had a note receivable from the sale of our working interests in these properties, which had been fully reserved.  In September 2012, we conveyed the overriding royalty interests to the operator and released the operator from any further liability from the note receivable in exchange for $50,000 cash.  We allocated the cash proceeds between the note receivable 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.

During 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.

We received proceeds of $160,917 in conjunction with sales of interest in the Dix and Curlee prospects, as described above.

Unevaluated Properties

Namibia, Africa.

In September 2012, we acquired a 39% (43.33% cost responsibility) working interest in a concession in Namibia, Africa, as discussed in Note 2 - Acquisitions - Namibia Exploration, Inc.  This property is a 5.3 million-acre concession in northern Namibia in Africa.

We have incurred total costs of $713,655, including NEI's cost basis at the time we acquired 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, conduct and environmental study. The minimum expenditure is $300,000.

As of July 31, 2013, approximately $900,000 has been expended towards the initial exploration period.

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Incurred) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Property acquisition
Unproved	$ 808,307	$ 74,805
Proved	3,000	6,988,447
Exploration	404,265	420,200
Development	1,732,451	2,033,073
Cost recovery	(196,001)	(32,772)
Total costs incurred	2,752,022	9,483,753
Namibia [Member]
Property acquisition
Unproved	677,795
Proved
Exploration	35,860
Development
Cost recovery
Total costs incurred	713,655
Unites States [Member]
Property acquisition
Unproved	130,512
Proved	3,000
Exploration	368,405
Development	1,732,451
Cost recovery	(196,001)
Total costs incurred	$ 2,038,367

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Acquisitions

12 Months Ended

Jul. 31, 2013

Acquisitions [Abstract]

Acquisitions

Note 2 - Acquisitions

SPE Navigation I, LLC

On September 23, 2011, Duma acquired SPE, which owned 25% of the working interest in the oil and gas properties originally owned by Galveston Bay Energy, LLC and 1,000,000 shares of Hyperdynamics Corporation, a public company traded on the New York Stock Exchange (NYSE:HDY). The total purchase price consisted of 3,799,998 shares of Duma's common stock. We acquired 100% of the membership interest in SPE and thus SPE is our wholly owned subsidiary.

The transaction was a related party transaction because SPE was owned by companies controlled by our CEO, his brother-in-law, and his sister-in-law, and SPE was managed by our CEO's father-in-law. The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition. The assets and liabilities were recorded at fair value on the date of the acquisition, $5,132,250.  The excess purchase price over the net assets acquired was $4,367,750, which was recorded as an acquisition-related expense because this was a related party transaction.  

As of the acquisition date, the working interests previously owned by SPE were conveyed to GBE. Thus, all oil and gas revenues after the SPE acquisition were attributed to GBE.  Our consolidated statements for 2013 include the results of SPE, and accordingly the 100% acquired working interest, for the entire year.  Our consolidated statements for 2012 include the results of SPE after September 23, 2011.

Supplemental pro forma information (unaudited)

The unaudited pro forma results presented below for the year ended July 31, 2012 have been prepared to give effect to the purchase of SPE as if it had been consummated on August 1, 2011.  The unaudited pro forma results do not purport to represent what our results of operations actually would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.

Revenues	$	7,313,232
Loss from operations		(7,419,747	)
Net loss		(4,776,288	)
Loss per share, basic and diluted		(0.47	)

Namibia Exploration, Inc.

On August 7, 2012, we entered into a Share Exchange Agreement (the "Agreement"), which was closed on September 6, 2012, under which we purchased Namibia Exploration, Inc. ("NEI"), a corporation organized under the laws of the state of Nevada for the issuance of up to 24,900,000 shares of our common stock as described below.  Prior to the acquisition, NEI was directly and indirectly owned and controlled by the CEO, his brother-in-law, and his father-in-law. As a result, the acquisition was accounted for as an asset purchase from an entity under common control and the asset was recorded at NEI's historical cost.  NEI originally acquired the concession from a subsidiary of Hydrocarb Corporation ("Hydrocarb") in exchange for a farm-in fee, as discussed below, totaling $2,400,000, payable over two years. Hydrocarb is partly owned by the uncle of the 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 Hydrocarb given that the concession was unproved, management concluded that Hydrocarb'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 provides for preferential offerings of other international oil and gas opportunities similar to the concession in Namibia.

NEI was formed in February 2012 and its sole asset was this oil and gas concession in Namibia, Africa. NEI had no operations other than ownership of this oil and gas concession; and accordingly, the transaction was accounted for as an asset purchase.  Duma has assumed payment of the fee, as described below.  Due to the fact that the former owners of NEI had no significant historical cost basis in NEI and the fact that the acquisition is accounted for as a related party transaction, the consideration that Duma paid beyond NEI's cost basis ($562,048) is considered compensatory and thus an expense of the acquisition.  The consideration included stock granted at the closing of the transaction as well as series of stock grants that are 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.  $37,234,752 is reflected in our statement of operations as Acquisition-related costs - related party in conjunction with this transaction.

As a result of the completion of the acquisition, NEI became a wholly-owned subsidiary of Duma. NEI holds the rights to 39% working interest (43.33% cost responsibility) in an onshore petroleum concession (the "Concession"), located in the Republic of Namibia, 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.

The assignment of the 39% working interest to NEI from Hydrocarb Namibia, the operator of the concession, is subject to the prior approval of the government of the Republic of Namibia, which was obtained during August 2012. Duma now holds working interest in the Concession in partnership with the National Petroleum Corporation of Namibia Ltd. ("NPC Namibia") and Hydrocarb Namibia Energy Corporation ("Hydrocarb Namibia"), a company chartered in the Republic of Namibia and which is a majority owned subsidiary of Hydrocarb Corporation ("Hydrocarb"), a company organized under the laws of the State of Nevada. Hydrocarb Namibia, as operator of the Concession, now holds at 51% working interest (56.67% cost responsibility) in the Concession and NPC Namibia now holds a 10% carried working interest in the Concession.  We have entered into a joint operating agreement with Hydrocarb Namibia effective August 29, 2012, that covers operations for the Concession.

Consideration for the acquisition of NEI

Pursuant to the terms of the Agreement, Duma issued 2,490,000 shares of common stock in September 2012 at the closing.  Additional shares are required to be issued as consideration for the Acquisition, in accordance with the following milestones which must be reached within 10 years after the closing of the acquisition:

(a) a further 2,490,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $82,000,000;

(b) a further 7,470,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $196,000,000; and

(c) a further and final 12,450,000 of the Shares will be issued when and if Duma's 10-day volume-weighted average market capitalization reaches $434,000,000.

Duma will maintain 100% ownership of NEI after Closing even if one or more of the market capitalization milestones have not been attained within 10 years from the Closing.  The accounting for this stock award is discussed in the section "Valuation" below.

Hydrocarb agreement

In conjunction with the execution of the Agreement, and as a condition of Closing, Duma has entered into a Consulting Services Agreement with Hydrocarb (the "Consulting Agreement"), whereby Hydrocarb will provide various consulting services with respect to Duma's business ventures in Namibia and whereby Hydrocarb has acknowledged and agreed that the obligations of NEI under its existing Farmin Opportunity Report with Hydrocarb (the "FOR") will be satisfied in exchange for Duma paying a consulting fee (the "Fee") to Hydrocarb of $2,400,000 as follows:

(a) payment on the later of the effective date of the Consulting Agreement or 15 days from the receipt of the working interest assignment under the FOR to be processed by Hydrocarb to be signed by Namibia's Minister of Mines and Energy, by Duma to Hydrocarb of $800,000 in cash or stock (at a deemed conversion price which equates to the then previous 60-day volume-weighted average trading price of Duma's common stock) or a combination of cash and stock.  Duma has the sole and absolute discretion to select the manner of payment.

(b) for the remaining $1,600,000 by way of the issuance of a promissory note in favor of Hydrocarb in the principal amount of $1,600,000 (the "Promissory Note"), with interest accruing on the principal amount at the rate of 5% per annum, calculated semi-annually and payable in arrears, and of which $800,000 of the principal amount plus accrued interest is due on or before the first anniversary of the effective date and the remaining $800,000 of the principal amount plus accrued interest is due on or before the second anniversary of the effective date. Duma has the sole and absolute discretion to select whether payment of the note will be in stock (at a deemed conversion price which equates to the then previous 60-day volume-weighted average trading price of Duma's common stock), cash, or a combination of cash and stock.

Duma is required to pay a late fee of 10% per quarter for any outstanding balance of the Fee under the Consulting Agreement which will commence 30 calendar days from the date that the Fee or portion of the Fee is due, which may only be paid in cash. Duma has not yet paid the first installment as described in (a) above.  Thus, the fee, which totals $320,000 as of July 31, 2013, has been accrued and it is characterized as interest expense. The fee is included in the balance sheet caption "Accounts payable and accrued expenses".

Valuation

NEI's cost basis in the concession is $562,048.  Since Duma acquired the liability due to Hydrocarb, Duma acquired a net liability of $1,837,952.  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 consists of the 2,490,000 shares that were awarded at closing, which were valued using the closing market price of the stock on the date of grant, and the contingent stock grant.  The fair value of equity compensation that vests upon the attainment of a market condition (in this case, market capitalization) must be estimated and recorded on the date of the grant.  The fair value of the 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 Duma and NEI, using multiple probability-weighted scenarios, and projections of Duma's capital structure.

As of July 31, 2013, we had recognized $37,234,752 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 $31,612,000 associated with the contingent consideration.

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Oil and Gas Properties (Schedule of Oil and Gas Properties) (Details) (USD $)	Jul. 31, 2013	Jul. 31, 2012
Oil and Gas Properties [Abstract]
Costs subject to depletion, net of accumulated impairment of $373,355 and $373,355, respectively	$ 19,484,507	$ 17,180,501
Accumulated Depletion	(2,617,478)	(1,557,675)
Total evaluated properties	16,867,029	15,622,826
Unevaluated properties	713,655	265,639
Net oil and gas properties	17,580,684	15,888,465
Accumulated impairment, oil and gas properties	$ (373,355)	$ (373,355)

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Notes Payable (Tables)

12 Months Ended

Jul. 31, 2013

Notes Payable [Abstract]

Schedule of Future Maturities on Notes Payable

As of July 31, 2013, future maturities on our notes payable were as follows:

Fiscal year ending:
2014	$	1,059,644
2015		942,992
Total	$	2,002,636

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Income Taxes (Tables)

12 Months Ended

Jul. 31, 2013

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:

	July 31,
	2013			2012
US statutory federal rate		35.00	%		35.00	%
State income tax rate		.58	%		.58	%
Equity-based compensation		(33.62	)%		(36.43	)%
Gain on derivative warrants		.93	%		7.60	%
Gain on sale of securities		(.33	)%		(21.15	)%
Other		(.50	)%		4.02	%
Acquired deferred tax liability		-	%		23.12	%
Net operating loss		(1.75	)%		6.92	%
		.31	%		19.66	%

Summary of Deferred Tax Assets

Components of deferred tax assets as of July 31, 2013 and 2012 are as follows:

	July 31,
	2013			2012
Stock based compensation	$	713,867		$	292,509
Property, including depreciable property		(2,980,005	)		(2,070,809	)
Asset retirement obligation		3,942,918			3,312,358
Net operating loss carry-forward		3,846,783			2,530,532
Other		42,368			318,032
		5,565,931			4,382,622
Valuation allowance for deferred tax assets		(5,565,931	)		(4,382,622	)
	$	-		$	-

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Net Proved Reserves) (Details)	12 Months Ended
	Jul. 31, 2013 gal	Jul. 31, 2012 gal
Reserve Quantities [Line Items]
Beginning Balance	23,067,460	19,874,790
Revisions of previous estimates	(5,834,587)	(1,936,599)
New discoveries and extensions		15,800
Purchase of reserves in place		6,406,780
Sale of reserves in place	(8)	(704,290)
Production	(544,275)	(589,021)
Ending Balance	16,688,590	23,067,460
Proved developed producing	3,092,160	3,636,850
Proved developed non-producing	6,376,700	6,155,140
Proved undeveloped	7,219,730	13,275,470
Total Proved reserves	16,688,590	23,067,460
Oil [Member]
Reserve Quantities [Line Items]
Beginning Balance	1,388,250	1,218,950
Revisions of previous estimates	(667,307)	(88,689)
New discoveries and extensions		660
Purchase of reserves in place		383,070
Sale of reserves in place	(1)	(64,730)
Production	(61,242)	(61,011)
Ending Balance	659,700	1,388,250
Proved developed producing	256,290	308,640
Proved developed non-producing	229,290	321,510
Proved undeveloped	174,120	758,100
Total Proved reserves	659,700	1,388,250
Gas [Member]
Reserve Quantities [Line Items]
Beginning Balance	14,737,960	12,561,090
Revisions of previous estimates	(1,830,745)	(1,404,465)
New discoveries and extensions		11,840
Purchase of reserves in place		4,180,360
Sale of reserves in place	(2)	(315,910)
Production	(176,823)	(222,955)
Ending Balance	12,730,390	14,737,960
Proved developed producing	1,554,420	1,785,010
Proved developed non-producing	500,960	4,266,080
Proved undeveloped	6,175,010	8,726,870
Total Proved reserves	12,730,390	14,737,960

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Description of Business and Summary of Significant Accounting Policies (Schedule of Accumulated Other Comprehensive Loss) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013
Description of Business and Summary of Significant Accounting Policies [Abstract]
Accumulated other comprehesive loss at July, 31, 2012	$ (743,082)
Change in fair value of available-for-sale securities	743,082
Accumulated other comprehesive loss at July, 31, 2013

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Supplemental Oil and Gas Information (Unaudited) (Narrative) (Details)	Jul. 31, 2013	Jul. 31, 2012
Supplemental Oil And Gas Infomation Unaudited [Abstract]
Average oil and gas price per barrel	92.52	95.07
Average gas price per MMbtu	3.51	3.02

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Capital Stock (Warrants Granted to Related Party) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2011
Warrants Granted To Related Party [Line Items]
Total shares of common stock issuable under warrants	3,710,877	3,756,455	3,758,455
Exercise Price	2.50	2.58	2.50
Compensation expense recognized	$ 933,126	$ 687,770
Warrant B [Member]
Warrants Granted To Related Party [Line Items]
Exercise Price	2.50
Term of warrants	2 years 29 days
Average closing stock price that will trigger issuance of additional warrants	$ 7.50
Fair value of warrants	266,017	177,150
Number of warrants issued	600,000
Warrant C [Member]
Warrants Granted To Related Party [Line Items]
Exercise Price	2.50
Term of warrants	2 years 5 months 27 days
Average closing stock price that will trigger issuance of additional warrants	$ 15.00
Fair value of warrants	202,127	139,491
Number of warrants issued	600,000
Geoserve Marketing, LLC [Member]
Warrants Granted To Related Party [Line Items]
Exercise Price			2.50
Compensation expense recognized	$ 196,384	$ 189,372

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Capital Stock (Stock Compensation Plans) (Details)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate, minimum	1.11%	0.12%
Risk-free interest rate, maximum	2.00%	1.66%
Dividend yield	0.00%	0.00%
Volatility factor, minimum	140.30%	135.00%
Volatility factor, maximum	144.00%	148.00%
Expected life	6 years 6 months
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life		1 year
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life		6 years 6 months
2013 Stock Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance	2,650,000
Expected life	4 years 6 months

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Notes Payable (Line of Credit) (Details) (USD $)	1 Months Ended
	Mar. 17, 2011	Jul. 31, 2013	Jul. 31, 2012
Line of Credit Facility [Line Items]
Line of credit, amount outstanding	$ 300,000	$ 0	$ 300,000
Line of credit, interest rate spread over prime rate	1.00%
Debt instrument, minimum interest rate	5.00%
Line of credit, interest rate	6.00%
Revolving credit facility, expiration date	Jun. 22, 2015

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jul. 31, 2013	Jul. 31, 2012	May 16, 2012
CONSOLIDATED BALANCE SHEETS [Abstract]
Accumulated depletion on evaluated oil and gas property accounted for using the full cost method of accounting	$ 2,617,478	$ 1,557,675
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	$ 62,749	$ 36,572
Common stock, par value per share	$ 0.001	$ 0.001	$ 0.001
Common stock, shares authorized	500,000,000	500,000,000	20,000,000
Common stock, shares issued	13,281,003	10,791,003	269,742,986
Common stock, shares outstanding	13,281,003	10,791,003	269,742,986

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Notes Payable

12 Months Ended

Jul. 31, 2013

Notes Payable [Abstract]

Notes Payable

Note 7 - Notes Payable

Installment Notes Payable

In February 2012, we entered into a premium financing arrangement to pay principal of $209,244 in conjunction with our commercial insurance program renewal. We were obligated to make nine payments of $24,578 per month, which include principal and interest, beginning in March 2012. As of July 31, 2012, $96,252 remained unpaid on the note.  As of July 31, 2013, the note payable balance was $0.

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 $17,451 and $11,678 as of July 31, 2012 and July 31, 2013, respectively.

In September 2012, we entered into a note payable of $1,600,000 with Hydrocarb Corporation, as described in Note 2 - Acquisitions - Namibia Exploration, Inc. The note carries interest of 5%; which is calculated semi-annually and payable with principal payments. Principal of $800,000 is due on August 7, 2013 and $800,000 is due on August 7, 2014.  In October 2013, we paid off the note and accrued interest and fees associated with the note.

In March 2013, we financed our commercial insurance program using a note payable for $260,905. Under the note, we are obligated to make nine payments of $29,591 per month, which include principal and interest, beginning in March 2013. As of July 31, 2013, $115,958 remained outstanding on this note.

In June 2013, the outstanding balance on our line of credit, $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 principal reduction plus interest for the month. The note carries interest at prime + 1%, currently 6%. As of July 31, 2013, $275,000 remained outstanding on this note.  As of November 12, 2013, the date of this report, $250,000 remained outstanding on the note.

As of July 31, 2013, future maturities on our notes payable were as follows:

Fiscal year ending:
2014	$	1,059,644
2015		942,992
Total	$	2,002,636

Line of Credit

On March 17, 2011, GBE secured a one year revolving line of credit of up to with a commercial bank. The note specified interest at a rate of prime + 1% with a minimum interest rate of 5%. The initial interest rate was 6%. Interest is payable monthly. We must use proceeds from the line of credit solely to enhance our Galveston Bay properties.  The note is collateralized by our Galveston Bay properties and substantially all GBE's assets. Duma also executed a parental guarantee of payment. As of July 31, 2012 the amount outstanding under the line of credit was $300,000.  The note was extended several times during fiscal 2013 and finally replaced by a term loan note in June 2013.

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CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) [Abstract]
Tax benefit on change in market value of available for sale securities, including reclassification adjustments to net income	$ 0	$ 0

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Related Party Transactions (Details) (USD $)	12 Months Ended				1 Months Ended		12 Months Ended			1 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2013 Father Of Chief Financial Officer [Member]	Jul. 31, 2012 Father Of Chief Financial Officer [Member]	Nov. 30, 2011 Director [Member]	Oct. 31, 2011 Officer And Director [Member]	Jul. 31, 2013 Father-In-Law of Chief Executive Officer [Member]	Jul. 31, 2012 Father-In-Law of Chief Executive Officer [Member]	Sep. 06, 2012 Galveston Bay Energy, LLC [Member]	Feb. 28, 2013 Carter E&P [Member]
Related Party Transaction [Line Items]
Revenue generated from Barge Canal properties	$ 643,203	$ 569,476
Lease operating costs incurred from Barge Canal properties	224,047	181,113
Overhead costs incurred	28,038	25,087
Outstanding accounts receivable at period end	91,967	74,972
Outstanding accounts payable at year end
Outstanding billed and unbilled joint interest billings owed by related party			84,806	42,646
Due to related parties	15,046
Expense recognized from consulting contract with related party							196,384	189,372
Total contingent shares that could be issued if all milestones are achieved									24,900,000
Percentage of working interest sold										2.00%
Land acquisition costs	45,147									1,541
Repayments of related party debt					6,423	8,300
Repayments of accrued interest on related party debt					$ 416	$ 413

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CONSOLIDATED BALANCE SHEETS (USD $)	Jul. 31, 2013	Jul. 31, 2012
Current assets
Cash and cash equivalents	$ 317,881	$ 1,102,987
Oil and gas revenues receivable	725,691	457,567
Accounts receivable - related party	176,773	117,618
Available for sale securities		313,446
Other current assets	333,136	256,677
Other receivables, net	23,730	517,441
Total current assets	1,577,211	2,765,736
Oil and Gas Property, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $2,617,478 and $1,557,675, respectively; and accumulated impairment of $373,335 and $373,335, respectively	16,867,029	15,622,826
Unevaluated property	713,655	265,639
Restricted cash	6,920,739	6,890,000
Other assets	180,726	190,259
Property and equipment, net of accumulated depreciation of $62,749 and $36,572, respectively	19,792	45,969
Total assets	26,279,152	25,780,429
Current liabilities
Accounts payable and accrued expenses	3,779,401	2,298,838
Line of credit		300,000
Current portion of notes payable	1,059,644	102,025
Asset retirement obligations - short term	724,374	549,796
Derivative warrant liability		1,325,388
Advances	180,804	55,161
Due to related parties	15,046
Total current liabilities	5,759,269	4,631,208
Notes payable	942,992	11,678
Asset retirement obligations - long term	10,209,024	8,833,137
Total liabilities	16,911,285	13,476,023
Commitments and contingencies
Stockholders' equity:
Common stock, $.001 par; 500,000,000 authorized shares; 13,281,003 and 10,791,003 shares issued and outstanding in 2013 and 2012, respectively	13,281	10,791
Additional paid in capital	75,756,801	38,963,817
Accumulated other comprehensive loss		(743,082)
Accumulated deficit	(66,402,215)	(25,927,120)
Total stockholders' equity	9,367,867	12,304,406
Total liabilities and stockholders' equity	$ 26,279,152	$ 25,780,429

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Capital Stock (Options Granted to Non-employees and Employees) (Details) (USD $)	12 Months Ended		1 Months Ended	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Feb. 28, 2013 Director [Member]	Jul. 31, 2013 Employee [Member]	Jul. 31, 2012 Employee [Member]	Jul. 31, 2011 Employee [Member]	Jul. 31, 2013 Non-employee [Member]	Jul. 31, 2012 Non-employee [Member]
Share Based Arrangements With Employees And Nonemployees [Line Items]
Share Based Arrangements Aggregate Number Of Options Granted			600,000			260,000
Number of options granted	600,000						600,000
Compensation expense recognized	$ 933,126	$ 687,770		$ 253,952	$ 263,201		$ 679,174	$ 424,569
Weighted average exercise price of options granted	$ 2.20		$ 2.20			$ 2.50	$ 2.20
Unrecognized compensation cost related to stock options				56,917			1,011,847
Vesting period			10 years			10 years
Fair value of options granted			$ 1,196,589
Expected term	6 years 6 months

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Excluded by Country) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Ending Balance	$ 713,655	$ 265,639
Namibia [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Beginning Balance
Additional Cost Incurred	713,655
Cost Recovery
Costs Transferred to DD&A Pool
Ending Balance	713,655
Unites States [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Beginning Balance	265,639
Additional Cost Incurred	278,090	265,639
Cost Recovery	(132,662)
Costs Transferred to DD&A Pool	(411,067)
Ending Balance		$ 265,639

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Fair Value (Tables)

12 Months Ended

Jul. 31, 2013

Fair Value [Abstract]

Schedule of Assets and Liabilities Measured on a Recurring Basis

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2012.

	Carrying Value at		Fair Value Measurement at July 31, 2012
	July 31, 2012		Level 1		Level 2		Level 3
Assets:
Available for sale securities	$	313,446	$	313,446	$	-	$	-
Liabilities:
Derivative warrant liability	$	1,325,388	$	-	$	-	$	1,325,388

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 during the years ended July 31, 2013 and 2012:

	2013			2012
Beginning of the period	$	1,325,388		$	2,543,223
Expiration of derivative warrant feature		(269,164	)		-
Unrealized gain on changes in fair value of derivative liability		(1,056,224	)		(1,217,835	)
End of the period	$	-		$	1,325,388

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Description of Business and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Jul. 31, 2013

Description of Business and Summary of Significant Accounting Policies [Abstract]

Description of business and basis of presentation

Description of business and basis of presentation

Duma Energy Corp. ("we", "us", "Duma", the "Company") was formed for the purpose of oil and gas exploration, development, and production. We own 100% of Penasco Petroleum Inc. ("Penasco"), a Nevada corporation incorporated on November 23, 2005 and 100% of Galveston Bay, LLC, ("GBE"), a Texas limited liability company, 100% of SPE Navigation I, LLC ("SPE") a Nevada limited liability company and 100% of Namibia Exploration, Inc. ("NEI") a Nevada corporation.  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").

Reclassifications

Reclassifications

Certain prior year amounts have been reclassified to conform with the current presentation.

Principles of consolidation

Principles of consolidation

The accompanying consolidated financial statements include the accounts of Duma and our wholly owned subsidiaries, Penasco, SPE, GBE and NEI. 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 which 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 the Chief Financial Officer and the Chief Executive Officer.

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, 2013 and 2012, we have reserved $58,585 and $1,302, 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, 2013, 85% of our revenue was attributable to one purchaser.  At July 31, 2013, this same purchaser accounted for 76% of our accounts receivable. For the year ended July 31, 2012, 67% of our revenue was attributable to one purchaser.  At July 31, 2012, this same purchaser accounted for 79% 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, 2013 and July 31, 2012, 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, 2013 and 2012, restricted cash totaled $6,920,739 and $6,890,000, respectively.

Other assets

Other assets

Other assets at July 31, 2013 and 2012 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, 2013 and 2012, 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, 2013 and 2012, advances totaled $180,804 and $55,161, 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 valorum 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, 2013 and o ur derivative warrant liability was our only financial asset or liability that was accounted for at fair value, using a Level 3 valuation technique, on a recurring basis as of July 31, 2012. 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 April 4, 2012, we effected a 1-for-25 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, 2013 and 2012, 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 12 - 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. The components of accumulated other comprehensive loss:

	Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss at July 31, 2012	$	(743,082	)
Reclassification into earnings		743,082
Accumulated other comprehensive loss at July 31, 2013	$	-

Recent accounting pronouncements

Recent accounting pronouncements

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.

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Notes Payable (Details) (USD $)	1 Months Ended				1 Months Ended			1 Months Ended		1 Months Ended				1 Months Ended
	Jun. 30, 2013	Nov. 12, 2013	Jul. 31, 2013	Jul. 31, 2012	Feb. 29, 2012 Commercial Insurance Program Renewal [Member]	Jul. 31, 2013 Commercial Insurance Program Renewal [Member]	Jul. 31, 2012 Commercial Insurance Program Renewal [Member]	Mar. 31, 2013 Note Payable For Commercial Insurance Program [Member]	Jul. 31, 2013 Note Payable For Commercial Insurance Program [Member]	May 31, 2012 Notes Payable For Vehicle Purchase [Member]	Jul. 31, 2013 Notes Payable For Vehicle Purchase [Member]	Jul. 31, 2012 Notes Payable For Vehicle Purchase [Member]	Sep. 30, 2012 Note Payable - Hydrocarb Corporation [Member]	Sep. 30, 2012 Note Payable - Hydrocarb Corporation - Payment One [Member]	Sep. 30, 2012 Note Payable - Hydrocarb Corporation - Payment Two [Member]
Debt Instrument [Line Items]
Debt instrument, face amount	$ 300,000				$ 209,244			$ 260,905		$ 18,375			$ 1,600,000
Debt instrument, interest rate										6.93%			5.00%
Installment payments start date					Mar. 01, 2012			Mar. 01, 2013		Jun. 01, 2012				Aug. 07, 2013	Aug. 07, 2014
Current portion of notes payable			1,059,644	102,025		0	96,252		115,958		11,678	17,451		800,000	800,000
Principal balance		250,000	275,000
Periodic installments amount	12,500				24,578			29,591		567
Number of required periodic payments	24				9			9		36
Year ending:
2014			1,059,644
2015			942,992
Total			$ 2,002,636

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Changes in Standardized Measure) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Supplemental Oil And Gas Infomation Unaudited [Abstract]
Standardized measure of discounted future net cash flows at beginning of year	$ 33,663,886	$ 36,116,218
Net changes in prices and production costs	(37,550,412)	(3,316,394)
Changes in estimated future development costs	4,205,045	(10,006,008)
Sales of oil and gas produced, net of production costs	(2,582,937)	(3,152,150)
Discoveries and extensions		54,414
Purchases of minerals in place		16,662,628
Sales of minerals in place	(17)	(2,042,655)
Revisions of previous quantity estimates	(12,391,911)	(6,669,453)
Development costs incurred	1,124,107	1,085,180
Change in income taxes	14,705,973	1,320,486
Accretion of discount	5,179,059	3,611,622
Standardized measure of discounted future net cash flows at year end	$ 6,352,793	$ 33,663,886

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Capital Stock (Schedule of Nonvested Share Activity) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013
Number of shares
Nonvested at July 31, 2012	480,000
Granted	600,000
Vested	(319,200)
Forfeited	(1,600)
Nonvested at July 31, 2013	759,200
Weighted average grant date fair value
Nonvested at July 31, 2012	$ 2.47
Granted	$ 1.99
Vested	$ 2.47
Forfeited	$ 2.47
Nonvested at July 31, 2013	$ 2.09

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Commitments and Contingencies (Schedule of Prepaid Balances) (Details) (USD $)	Jul. 31, 2013	Jul. 31, 2012
Commitments and Contingencies [Abstract]
Prepaid letter of credit fees	$ 101,850	$ 25,163
Amortization	(8,488)	(8,596)
Net prepaid letter of credit fees	$ 93,362	$ 16,567

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Acquisitions (Schedule of Pro Forma Information) (Details) (USD $)	12 Months Ended
	Jul. 31, 2012
Business Acquisition [Line Items]
Revenues	$ 7,313,232
Loss from operations	(7,419,747)
Net loss	$ (4,776,288)
Loss per share, basic and diluted	$ (0.47)

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Supplemental Oil and Gas Information (Unaudited) (Tables)

12 Months Ended

Jul. 31, 2013

Supplemental Oil And Gas Infomation Unaudited [Abstract]

Schedule of Net Proved Reserves

Proved Reserves

	Oil (Barrels)			Gas (MCF)			Total ( MCFE)
Balance - July 31, 2011		1,218,950			12,561,090			19,874,790
Revisions of previous estimates		(88,689	)		(1,404,465	)		(1,936,599	)
New discoveries and extensions		660			11,840			15,800
Purchase of reserves in place		383,070			4,108,360			6,406,780
Sale of reserves in place		(64,730	)		(315,910	)		(704,290	)
Production		(61,011	)		(222,955	)		(589,021	)
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

	Proved Reserves as of July 31, 2013
	Oil (Barrels)		Gas (MCF)		Total ( 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 Reserves as of July 31, 2012
	Oil (Barrels)		Gas (MCF)		Total ( MCFE)
Proved developed producing		308,640		1,785,010		3,636,850
Proved developed non-producing		321,510		4,226,080		6,155,140
Proved undeveloped		758,100		8,726,870		13,275,470
Total proved reserves		1,388,250		14,737,960		23,067,460

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.

	2013			2012
Unevaluated properties	$	713,655		$	265,639
Evaluated properties		19,857,842			17,553,836
Less impairment		(373,335	)		(373,335	)
		20,198,162			17,446,140
Less depreciation, depletion, and amortization		(2,617,478	)		(1,557,675	)
Net capitalized cost	$	17,580,684		$	15,888,465

Schedule of Costs Incurred

Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2013 were as follows.

	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 incurred in property acquisition, exploration, and development activities for the year ended July 31, 2012 were all incurred in the USA.  The following table provides information about the costs incurred:

	July 31, 2012
Property acquisition
Unproved	$	74,805
Proved		6,988,447
Exploration		420,200
Development		2,033,073
Cost recovery		(32,772	)
Total costs incurred	$	9,483,753

Schedule of Costs Excluded by Year

Costs Excluded by Year Incurred

	As of July 31, 2013
Property Acquisition	$	677,795
Exploration		35,860
Total	$	713,655

Schedule of Costs Excluded by Country

Changes in Costs Excluded by Country

	Namibia		United States
Balance at July 31, 2011	$	-	$	-
Additional Cost Incurred		-		265,639
Costs Transferred to DD&A Pool		-		-
Balance at July 31, 2012				265,639
Additional Costs Incurred		713,655		278,090
Cost recovery		-		(132,662	)
Costs Transferred to DD&A Pool		-		(411,067	)
Balance at July 31, 2013	$	713,655	$	-

Schedule of Standardized Measure

The Standardized Measure is as follows:

	2013			2012
Future cash inflows	$	113,603,450		$	200,741,090
Future production costs		(55,897,070	)		(60,998,060	)
Future development costs		(41,794,284	)		(48,640,439	)
Future income tax expenses		(5,569,234	)		(31,885,907	)
Future net cash flows		10,342,862			59,216,684
10% annual discount for estimated timing of cash flows		(3,990,069	)		(25,552,798	)
Future net cash flows at end of year	$	6,352,793		$	33,663,886

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, 2013:

	2013			2012
Standardized measure of discounted future net cash flows at beginning of year	$	33,663,886		$	36,116,218
Net changes in prices and production costs		(37,623,010	)		(3,316,394	)
Changes in estimated future development costs		4,205,045			(10,006,008	)
Sales of oil and gas produced, net of production costs		(2,510,339	)		(3,152,150	)
Discoveries and extensions		-			54,414
Purchases of minerals in place		-			16,662,628
Sales of minerals in place		(17	)		(2,042,655	)
Revisions of previous quantity estimates		(12,391,911	)		(6,669,453	)
Development costs incurred		1,124,107			1,085,180
Change in income taxes		14,705,973			1,320,486
Accretion of discount		5,179,059			3,611,622
Standardized measure of discounted future net cash flows at year end	$	6,352,793		$	33,663,886

Schedule of Results of Operations for Producing Activities

	2013			2012
Net revenues from production	$	7,070,540		$	7,165,233
Expenses
Lease operating expense		4,560,201			4,013,083
Accretion		1,056,508			943,508
Operating expenses		5,616,709			4,956,591
Depreciation, depletion and amortization		1,059,803			990,486
Total expenses		6,676,512			5,947,077
Income before income tax		394,028			1,218,156
Income tax expense		(137,910	)		(426,355	)
Results of operations	$	256,118		$	791,801
Depreciation, depletion and amortization rate per net equivalent MCFE	$	1.95		$	1.68

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Description of Business and Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Revenue, Major Customer [Line Items]
Other receivables, allowance for doubtful accounts	$ 58,585	$ 1,302
Accumulated impairment	373,355	373,355
Restricted cash	6,920,739	6,890,000
Prepaid land use fees, term	10 years
Purchase of domain name	30,267
Advances	$ 180,804	$ 55,161
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	85.00%	67.00%
Purchaser One [Member] | Accounts receivable [Member]
Revenue, Major Customer [Line Items]
Risk percentage	76.00%	79.00%

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Asset Retirement Obligation

12 Months Ended

Jul. 31, 2013

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

Note 6 - Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2013 and 2012:

	2013			2012
Liability for asset retirement obligation, beginning of period	$	9,382,933		$	4,455,928
Asset retirement obligations assumed		-			2,365,530
Asset retirement obligations sold		(438	)		(32,772	)
Asset retirement obligations incurred on properties drilled		26,500			1,389
Accretion		1,056,508			943,508
Revisions in estimated cash flows		786,120			1,827,889
Costs incurred		(318,225	)		(178,539	)
Liability for asset retirement obligation, end of period	$	10,933,398		$	9,382,933
Current portion of asset retirement obligation	$	724,374		$	549,796
Noncurrent portion of asset retirement obligation		10,209,024			8,833,137
Total liability for asset retirement obligation	$	10,933,398		$	9,382,933

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Commitments and Contingencies (Narrative) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Commitments And Contingencies [Line Items]
Rent expense	$ 127,867	$ 117,392
Monthly compression and handling fees	1,000
Houston, Texas Office [Member]
Commitments And Contingencies [Line Items]
Monthly rental payments	6,406
Monthly rental payments, year two	6,673
Monthly rental payments, year three	6,940
Operating lease, term of lease	3 years
Operating lease, term of lease extension	3 years
Minimum [Member]
Commitments And Contingencies [Line Items]
Loss contengency, estimate	150,000
Maximum [Member]
Commitments And Contingencies [Line Items]
Loss contengency, estimate	$ 900,000

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Capital Stock (Tables)

12 Months Ended

Jul. 31, 2013

Capital Stock [Abstract]

Schedule of 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 July 31:

	2013	2012
Risk-free interest rate	1.11% - 2.00%	0.12% - 1.66%
Dividend yield	0%	0%
Volatility factor	140.30%-144%	135%-148%
Expected life (years)	6.5 years	1-6.5 years

Schedule of Information Relating to 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 July 31, 2013 and 2012:

	2013		2012
Number of options granted		600,000		-
Compensation expense recognized	$	679,174	$	424,569
Weighted average exercise price of options  granted	$	2.20	$	N/	A

Schedule of Information Relating to Stock Options Granted to Employees Under Stock Incentive Plans

The following table provides information about options granted to employees under our stock incentive plans during the years ended July 31, 2013 and 2012:

	2013		2012
Number of options granted		-		-
Compensation expense recognized	$	253,952	$	263,201
Weighted average exercise price of options  granted	$	N/A	$	N/A

Summary of Stock Option Activity Under Stock Option and Incentive Plans

Summary information regarding stock options issued and outstanding as of July 31, 2013 is as follows:

	Options			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at July 31, 2011		1,101,200		$	2.50	$	1,101,200		8.14
Granted		-			-
Exercised		-			-
Expired or forfeited		(57,200	)		2.50
Outstanding at July 31, 2012		1,044,000		$	2.50	$	-		7.22
Granted		600,000			2.20
Exercised		-			-
Expired or forfeited		(108,000	)		2.50
Outstanding at July 31,2013		1,536,000		$	2.38	$	-		7.98
Exercisable at July 31, 2013		776,800		$	2.50	$	-		6.82

Schedule of Stock Options Outstanding and Exercisable

Options outstanding and exercisable as of July 31, 2013:
Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.20		600,000	9.54 years		-
	2.50		796,000	7.73 years		636,800
	2.50		60,000	3.93 years		60,000
	2.50		24,000	5.81 years		24,000
	2.50		56,000	Less than 1 year		56,000
			1,536,000			776,800

Options outstanding and exercisable as of July 31, 2012:
Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		800,000	8.72 years		320,000
	2.50		24,000	6.81 years		24,000
	2.50		60,000	4.93 years		60,000
	2.50		56,000	1.04 years		56,000
	2.50		104,000	Less than 1 year		104,000
			1,044,000			564,000

Schedule of Nonvested Share Activity

Summary information regarding nonvested stock options as of July 31, 2013 is as follows:

	Number of shares			Weighted average grant date fair value
Nonvested at July 31, 2012		480,000		$	2.47
Granted		600,000		$	1.99
Vested		(319,200	)	$	2.47
Forfeited		(1,600	)	$	2.47
Nonvested at July 31, 2013		759,200		$	2.09

Schedule of Information for Warrants Granted to Related Parties

The following table reflects information regarding Warrant B and Warrant C as of July 31, 2013 and 2012:

	2013		2012
Fair Value of Warrant B as of the end of the derived service period in 2013 and as of July 31, 2012	$	266,017	$	177,150
Fair Value of Warrant C as of July 31, 2013 and 2012, respectively	$	202,127	$	139,491
Compensation expense recognized during the years ended July 31, 2013 and 2012, respectively	$	196,384	$	189,372

Summary of Warrant Activity

Summary information regarding common stock warrants issued and outstanding as of July 31, 2013, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2011		3,758,455		$	2.50	$	3,710,880		3.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(2,000	)		25.00		-		-
Outstanding at year ended July 31, 2012		3,756,455		$	2.58	$	-		2.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(45,578	)		9.34		-		-
Outstanding at year ended July 31,2013		3,710,877		$	2.50	$	-		1.87

Schedule of Warrants Outstanding and Exercisable

 Warrants outstanding and exercisable as of July 31, 2013:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		2,000,000	3 years or less		800,000
	2.50		1,253,757	2 years or less		1,253,757
	2.50		457,120	1 year or less		457,120
			3,710,877			2,510,877

Warrants outstanding and exercisable as of July 31, 2012:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		2,000,000	3.55 years		800,000
	2.50		1,253,757	2.21 years		1,253,757
	2.50		400,000	1.67 years		400,000
	2.50		5,120	1.57 years		5,120
	2.50		52,000	1.55 years		52,000
	6.25		8,000	1 year or less		8,000
	10.00		37,578	1 year or less		37,578
			3,756,455			2,556,455

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Oil and Gas Properties (Narrative) (Details) (USD $)	12 Months Ended		1 Months Ended	12 Months Ended			1 Months Ended		1 Months Ended						12 Months Ended		0 Months Ended	12 Months Ended		0 Months Ended	1 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Jan. 31, 2011 Core [Member]	Jul. 31, 2013 Core [Member]	Jul. 31, 2013 Welder Lease [Member] acre	Jul. 31, 2013 Palacios Lease [Member] acre	Jun. 30, 2012 Chapman Prospect [Member]	Apr. 30, 2012 Chapman Prospect [Member]	Aug. 31, 2012 Curlee Prospect [Member] acre	Dec. 31, 2012 Janssen lease [Member]	Dec. 31, 2012 Dix prospect [Member] acre	Apr. 30, 2013 Melody Prospect [Member] acre	Sep. 30, 2012 Holt And Strahan Properties [Member]	Jul. 31, 2012 Holt And Strahan Properties [Member]	Jul. 31, 2013 Chapman, Curlee, Dix and Melody Prospects [Member]	Jul. 31, 2013 Dix and Curlee Prospects [Member]	Sep. 06, 2012 Galveston Bay Energy, LLC [Member]	Jul. 31, 2013 Galveston Bay Energy, LLC [Member]	Apr. 30, 2013 Galveston Bay Energy, LLC [Member]	Sep. 06, 2012 Namibia Exploration, Inc. [Member] acre	Sep. 30, 2012 Namibia Exploration, Inc. [Member]	Jul. 31, 2013 Namibia Exploration, Inc. [Member] acre
Oil And Gas Properties [Line Items]
Acquisition related costs, cash paid												$ 7,355									$ 713,655
Land acquisition costs	45,147								45,931		76,938
Geological And Geophysical Costs	157,818
Drilling costs	89,783														210,588
Development	1,732,451	2,033,073					265,639
Development well costs	447,511																	447,511
Recompletion development costs	361,372																	361,372
Asset retirement obligation increase	803,788																	803,788
Ownership percentage				10.00%	100.00%			25.00%	50.00%			12.50%		6.25%			39.00%			39.00%		39.00%
Net revenue interest owned					72.50%	4.125%
Percentage of working interest retained			10.00%
Payout of property			1,350,000	1,350,000
Working interest adjustment				25.00%
Number of acres included in oil and gas property					81	460			190		366.85	260.12								5,300,000		530,000
Acquisition related costs	713,655	265,639						58,805									679,870
Drilling costs								206,834
Proceeds from sale of working interest									51,589	2,500	109,328		50,000			160,917
Portion of overriding royalty interest treated as reduction of capitalized costs													32,146
Percentage of costs to first casing point						6.70732%		31.25%	33.30%		25.00%
Percentage of costs subsequent to first casing point						5.50%		25.00%	50.00%
Additional percentage of interest acquired									25.00%
Percentage of working interest sold										3.00%	75.00%
Cost responsibility percentage								25.00%									43.33%			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					4,505,000
Minimum cost responsibilities during the first renewal exploration period																	17,350,000					17,350,000
Minimum cost responsibilities during the second renewal exploration period																	300,000					300,000
The cumulative amount expended toward costs for the initial exploration period																			800,000			900,000
Asset retirement obligation sold	$ 438	$ 32,772								$ 438

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Capital Stock

12 Months Ended

Jul. 31, 2013

Capital Stock [Abstract]

Capital Stock

Note 9 -  Capital Stock

On April 4, 2012, we effected a reverse stock split of our authorized, issued and outstanding shares of common stock on a one new share for twenty-five old share basis (1:25). The effect of the reverse stock split has been retroactively applied to all periods presented.

As a result of the reverse split, our authorized share capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock and correspondingly, our issued and outstanding share capital decreased from 269,742,986 shares of common stock to 10,791,003 shares of common stock.

Effective May 16, 2012, Duma increased the number of its authorized shares of common stock from 20,000,000 shares, par value $0.001 per share, to 500,000,000 shares, par value $0.001 per share.

Our capitalization at July 31, 2013 was 500,000,000 authorized common shares with a par value of $0.001 per share.

Common Stock Issuances

During August 2011, we granted 189,585 shares of common stock to certain investors who had participated in our October and November 2009 equity raises, and as a consequence owned derivative warrants. These investors had exercised some of their warrants prior to our equity raise in February 2011, which triggered the down-round ratchet provision in the warrants.  The warrant contracts specify that the ratchet adjustment is not made for warrants that were exercised prior to the repricing event.  As a consequence of their warrant exercises, they had forfeited their contractual right to receive ratchet warrant shares.  However, management granted stock to these investors as a goodwill gesture.  The stock grant was treated as an investor relations expense and valued at $592,452.  The shares were valued using the closing market price on the date of grant.

During December 2011 we granted 13,036 shares of common stock as compensation for services valued at $27,703. The shares were valued using the closing market price on the date of the grant.

During the quarter ended April 30, 2012, we canceled 2,431 shares that had previously been deemed issued to two consultants. No adjustment to compensation was made in conjunction with this settlement.

During September 2011, we issued 3,799,998 shares of common stock to the members of SPE Navigation I, LLC towards acquisition of SPE.  The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition.

During September 2012, we issued 2,490,000 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.)

Stock Compensation Plans

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. Duma may grant up to 2,650,000 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 or warrant award 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

The following table details the significant assumptions used to compute the fair market values of stock options granted or revalued during the years ended July 31:

	2013	2012
Risk-free interest rate	1.11% - 2.00%	0.12% - 1.66%
Dividend yield	0%	0%
Volatility factor	140.30%-144%	135%-148%
Expected life (years)	6.5 years	1-6.5 years

In February 2013, options to purchase an aggregate of 600,000 shares of common stock with an exercise price of $2.20 per share and a term of ten years were granted to our three independent directors. The options vest 20% each six months over the 30 months following the award. 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.

No options were granted to non-employees during the year ended July 31, 2012.  Expense during 2012 consists of the amortization of options granted prior to July 31, 2012.

The following table provides information about options granted to non-employees under our stock incentive plans during the years ended July 31, 2013 and 2012:

	2013		2012
Number of options granted		600,000		-
Compensation expense recognized	$	679,174	$	424,569
Weighted average exercise price of options  granted	$	2.20	$	N/	A

Based on the fair value of the options as of July 31, 2013, there was $1,011,847 of unrecognized compensation costs related to non-vested share based compensation arrangements 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.

Options granted to employees

The following table provides information about options granted to employees under our stock incentive plans during the years ended July 31, 2013 and 2012:

	2013		2012
Number of options granted		-		-
Compensation expense recognized	$	253,952	$	263,201
Weighted average exercise price of options  granted	$	N/A	$	N/A

During the year ended July 31, 2011, options to purchase 260,000 shares of common stock with an exercise price of $2.50 per share and a term of ten years were granted to five employees.  The options vest 20% each six months over the 30 months following the award. 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, 2013, we had $56,917 in unamortized compensation expense associated with options granted to employees.

No options were granted to employees during the years ended July 31, 2013 or 2012.

Summary information regarding stock options issued and outstanding as of July 31, 2013 is as follows:

	Options			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at July 31, 2011		1,101,200		$	2.50	$	1,101,200		8.14
Granted		-			-
Exercised		-			-
Expired or forfeited		(57,200	)		2.50
Outstanding at July 31, 2012		1,044,000		$	2.50	$	-		7.22
Granted		600,000			2.20
Exercised		-			-
Expired or forfeited		(108,000	)		2.50
Outstanding at July 31,2013		1,536,000		$	2.38	$	-		7.98
Exercisable at July 31, 2013		776,800		$	2.50	$	-		6.82

Options outstanding and exercisable as of July 31, 2013:
Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.20		600,000	9.54 years		-
	2.50		796,000	7.73 years		636,800
	2.50		60,000	3.93 years		60,000
	2.50		24,000	5.81 years		24,000
	2.50		56,000	Less than 1 year		56,000
			1,536,000			776,800

Options outstanding and exercisable as of July 31, 2012:
Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		800,000	8.72 years		320,000
	2.50		24,000	6.81 years		24,000
	2.50		60,000	4.93 years		60,000
	2.50		56,000	1.04 years		56,000
	2.50		104,000	Less than 1 year		104,000
			1,044,000			564,000

Summary information regarding nonvested stock options as of July 31, 2013 is as follows:

	Number of shares			Weighted average grant date fair value
Nonvested at July 31, 2012		480,000		$	2.47
Granted		600,000		$	1.99
Vested		(319,200	)	$	2.47
Forfeited		(1,600	)	$	2.47
Nonvested at July 31, 2013		759,200		$	2.09

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 Director and our Chief Executive Officer. Under the terms of the agreement, we granted warrants to purchase 1,200,000 shares of common stock that have a market condition.  If our common stock attains a five day average closing price of $7.50 per share, 600,000 warrants with an exercise price of $2.50 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 $15.00 per share, 600,000 warrants with an exercise price of $2.50 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 will be amortized over the derived service periods of 2.08 years and 2.49 years, respectively.  The following table reflects information regarding Warrant B and Warrant C as of July 31, 2013 and 2012:

	2013		2012
Fair Value of Warrant B as of the end of the derived service period in 2013 and as of July 31, 2012	$	266,017	$	177,150
Fair Value of Warrant C as of July 31, 2013 and 2012, respectively	$	202,127	$	139,491
Compensation expense recognized during the years ended July 31, 2013 and 2012, respectively	$	196,384	$	189,372

Summary information regarding common stock warrants issued and outstanding as of July 31, 2013, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2011		3,758,455		$	2.50	$	3,710,880		3.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(2,000	)		25.00		-		-
Outstanding at year ended July 31, 2012		3,756,455		$	2.58	$	-		2.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(45,578	)		9.34		-		-
Outstanding at year ended July 31,2013		3,710,877		$	2.50	$	-		1.87

 Warrants outstanding and exercisable as of July 31, 2013:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		2,000,000	3 years or less		800,000
	2.50		1,253,757	2 years or less		1,253,757
	2.50		457,120	1 year or less		457,120
			3,710,877			2,510,877

Warrants outstanding and exercisable as of July 31, 2012:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		2,000,000	3.55 years		800,000
	2.50		1,253,757	2.21 years		1,253,757
	2.50		400,000	1.67 years		400,000
	2.50		5,120	1.57 years		5,120
	2.50		52,000	1.55 years		52,000
	6.25		8,000	1 year or less		8,000
	10.00		37,578	1 year or less		37,578
			3,756,455			2,556,455

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Supplemental Oil and Gas Information (Unaudited) (Schedule of Costs Excluded by Year) (Details) (USD $)	Jul. 31, 2013	Jul. 31, 2012
Supplemental Oil And Gas Infomation Unaudited [Abstract]
Property Acquisition	$ 677,795
Exploration	35,860
Total	$ 713,655	$ 265,639

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Impairment

12 Months Ended

Jul. 31, 2013

Impairment [Abstract]

Impairment

Note 5 - 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, 2013 and July 31, 2012, the net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.

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.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Cash Flows From Operating Activities
Net loss	$ (40,475,095)	$ (4,579,724)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, and amortization	1,085,980	1,021,981
Accretion	1,056,508	943,508
Change in allowance for doubtful accounts	57,491	(26,563)
Change in deferred taxes		(130,200)
(Gain) loss on sale of available for sale securities	517,920	(463,117)
Impairment of available for sale securities	275,327
Warrants granted to related party	196,384	189,372
Common stock granted for services and for investor relations		620,155
Acquisition-related costs - related party	37,234,752	4,367,750
Share based compensation - amortization of the fair value of stock options	933,126	687,770
Gain on derivative warrant liability	(1,056,224)	(1,217,835)
Changes in operating assets and liabilities:
Accounts receivable	168,096	197,885
Advances	125,643	55,161
Accounts payable and accrued expenses	491,956	(948,070)
Settlement of asset retirement obligations	(318,225)	(178,539)
Accounts receivable - related party	(44,109)	(47,738)
Other assets	189,177	134,280
Net cash provided by operating activities	438,707	626,076
Cash Flows From Investing Activities
Purchases of oil and gas properties	(1,379,946)	(2,221,242)
Purchases of property, equipment and domain name		(66,847)
Change in restricted cash	(30,739)	(160,213)
Purchase of available for sale securities	(24,593)	(702,959)
Proceeds from sale of available for sale securities	287,874	4,009,548
Proceeds from sale of oil and gas properties	195,563
Net cash provided by (used in) investment activities	(951,841)	858,287
Cash Flows From Financing Activities
Proceeds from notes payable		300,000
Payments on notes payable	(271,972)	(1,748,752)
Payments on notes payable to related parties		(14,723)
Net cash used in financing activities	(271,972)	(1,463,475)
Net increase (decrease) in cash	(785,106)	20,888
Cash at beginning of period	1,102,987	1,082,099
Cash at end of period	317,881	1,102,987
Supplemental Disclosures:
Interest paid in cash	207,269	38,129
Income taxes paid in cash	42,483	4,847
Non-cash investing and financing
Accounts payable for oil and gas assets	188,607	244,793
Asset retirement obligation purchased		97,374
Asset retirement obligation - change in estimate	786,120	1,827,889
Asset retirement obligations incurred	26,500	1,389
Asset retirement obligation sold	438	32,772
Acquisition of SPE Navigation I, LLC for Duma common stock, including asset retirement obligation assumed of $2,268,156		5,132,250
Adjustment of purchase price of acquisition: environmental liability acquired		112,500
Acquisition of Namibia Exploration, Inc.	562,048
Unrealized loss on available for sale securities		743,082
Note payable for purchase of vehicle		18,027
Note payable for prepaid insurance	260,905	227,912
Expiration of derivative warrant liability	$ 269,164

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Capital Stock (Summary of Stock Options Issued and Outstanding) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012	Jul. 31, 2011
Options
Outstanding, beginning balance	1,044,000	1,101,200
Granted	600,000
Exercised
Expired	(108,000)	(57,200)
Outstanding, ending balance	1,536,000	1,044,000	1,101,200
Exercisable, ending balance	776,800	564,000
Weighted Average Share Price
Outstanding, beginning balance	$ 2.50	$ 2.50
Granted	$ 2.20
Exercised
Expired	$ 2.50	$ 2.50
Outstanding, ending balance	$ 2.38	$ 2.50	$ 2.50
Exercisable, ending balance	$ 2.50
Aggregate intrinsic value			$ 1,101,200
Weighted average remaining contractual life	7 years 11 months 23 days	7 years 2 months 19 days	8 years 1 month 21 days
Weighted average remaining contractual life exercisable	6 years 9 months 26 days

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Fair Value (Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) (Recurring [Member], USD $)	Jul. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities	$ 313,446
Derivative warrant liability	1,325,388
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities	313,446
Derivative warrant liability
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities
Derivative warrant liability
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available for sale securities
Derivative warrant liability	$ 1,325,388

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Commitments and Contingencies (Tables)

12 Months Ended

Jul. 31, 2013

Commitments and Contingencies [Abstract]

Schedule of Future Payment Obligations

The following table details our payment obligations related to our operating leases and to our debt that are due during the years ended July 31,

	2014		2015		2016		Total
Operating leases	$	71,047	$	-	$	-	$	71,047
Notes payable		1,135,042		967,295		-		2,102,337
Total	$	1,206,089	$	967,295	$	-	$	2,173,384

Schedule of Prepaid Balances

The following table reflects the prepaid balances as of July 31,

	2013			2012
Prepaid letter of credit fees	$	101,850		$	25,163
Amortization		(8,488	)		(8,596	)
Net prepaid letter of credit fees	$	93,362		$	16,567

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Additional Financial Statement Information (Schedule of Other Current Assets) (Details) (USD $)	Jul. 31, 2013	Jul. 31, 2012
Additional Financial Statement Information [Abstract]
Prepaid letter of credit fees	$ 93,362	$ 16,567
Prepaid insurance	180,433	178,471
Other prepaid expenses	2,000	10,164
Cash call paid to operator	24,225	23,234
Prepaid land use fees	28,728	19,852
Accrued interest income	4,388	8,389
Total other current assets	333,136	256,677
Other receivables, allowance for doubtful accounts	$ 58,585	$ 1,302

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Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Income Taxes [Abstract]
Net loss before income taxes	$ (40,598,044)	$ (5,700,195)
Net operating loss carry forwards	10,607,549
Beginning year of expiration of operating loss carry forwards	Jan. 01, 2027
Minimum ownership percentage in the company to be considered party to potential ownership change.	5.00%
Aggregate ownership percentage threshold that would trigger an ownership change event.	50.00%
Federal long-term tax-exempt interest rate	4.47%
Net operating loss carry-forwards, annual limitation	$ 239,600

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Commitments and Contingencies

12 Months Ended

Jul. 31, 2013

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 12 - 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.

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 6) that is estimated using the guidance in ASC 410-20.

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, 2013 and July 31, 2012, $150,000 has been recognized and is included in the balance sheet caption "Accounts payable and accrued expenses."

Commitments

We have the following contract obligations:

In March 2011, we executed a lease for office space in Houston, Texas.  The lease term is three years and we have an option to extend the lease for an additional three years.  Our scheduled rent is $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.

During September 2013, we terminated our lease for office space in Corpus Christi, Texas.

Rent expense during the years ended July 31, 2013 and 2012 was $127,867 and $117,392, respectively.

The following table details our payment obligations related to our operating leases and to our debt that are due during the years ended July 31,

	2014		2015		2016		Total
Operating leases	$	71,047	$	-	$	-	$	71,047
Notes payable		1,135,042		967,295		-		2,102,337
Total	$	1,206,089	$	967,295	$	-	$	2,173,384

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.

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 $180,000 issued by Green Bank. These letters of credit are collateralized by a certificate of deposit held with the bank for the same amount. In addition, we have a letter of credit in the amount of $40,000 issued by a commercial bank in favor of the landowner of the Welder lease as security that we will meet our obligations with regard to the salt water disposal well located on the lease. The letter of credit is 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, 2012, we paid the fees associated with the Greenbank letters quarterly. In June 2013, when we renewed the letters of credit, we prepaid the entire years' interest upfront. We amortized these fees on a straight-line basis. The following table reflects the prepaid balances as of July 31,

	2013			2012
Prepaid letter of credit fees	$	101,850		$	25,163
Amortization		(8,488	)		(8,596	)
Net prepaid letter of credit fees	$	93,362		$	16,567

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Fair Value

12 Months Ended

Jul. 31, 2013

Fair Value [Abstract]

Fair Value

Note 8 - Fair Value

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2013.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2012.

	Carrying Value at		Fair Value Measurement at July 31, 2012
	July 31, 2012		Level 1		Level 2		Level 3
Assets:
Available for sale securities	$	313,446	$	313,446	$	-	$	-
Liabilities:
Derivative warrant liability	$	1,325,388	$	-	$	-	$	1,325,388

Derivative Warrant Liability

Effective July 31, 2009, we adopted FASB ASC Topic No. 815-40 (formerly EITF 07-05) which defines determining whether an instrument (or embedded feature) is indexed to an entity's own stock. This literature specifies that a contract that would otherwise meet the definition of a derivative but is both (a) indexed to our own stock and (b) classified in stockholders' equity in the statement of financial position, would not be considered a derivative financial instrument and provides a new two-step model to be applied in determining whether a financial instrument or an embedded feature is indexed to an issuer's own stock and thus able to qualify for the scope exception.

Certain warrants we issued during the year ended July 31, 2010 were not afforded equity treatment because these warrants had a down-round 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 total fair values of the warrants issued during the year ended July 31, 2010, were determined using a lattice model and have been recognized as a derivative liability as described below.

The warrants were valued using a multi-nomial 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;

 · 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 following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the years ended July 31, 2013 and 2012:

	2013			2012
Beginning of the period	$	1,325,388		$	2,543,223
Expiration of derivative warrant feature		(269,164	)		-
Unrealized gain on changes in fair value of derivative liability		(1,056,224	)		(1,217,835	)
End of the period	$	-		$	1,325,388

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 anti-dilution provisions expire three years after the issuance of the warrants. Accordingly, the provision for warrants to purchase 408,065 and 206,400 shares of common stock expired on October 15, 2012 and November 13, 2012, respectively. As of each those dates, the fair value of the warrant was determined for a final mark to market adjustment and the outstanding warrant derivative liability was reclassified to additional paid-in capital, as the warrants were no longer derivatives.

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Additional Financial Statement Information (Schedule of Accounts Payable and Accrued Expenses) (Details) (USD $)	Jul. 31, 2013	Jul. 31, 2012
Additional Financial Statement Information [Abstract]
Trade payables	$ 3,068,671	$ 1,950,768
Accrued payroll	151,577	40,000
Accrued interest and fees	398,966
Revenue payable	4,717	6,690
Local taxes and royalty payable	128,470	108,948
Federal and state income taxes payable	27,000	192,432
Total accounts payable and accrued expenses	$ 3,779,401	$ 2,298,838

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Supplemental Oil and Gas Information (Unaudited)

12 Months Ended

Jul. 31, 2013

Supplemental Oil And Gas Infomation Unaudited [Abstract]

Supplemental Oil and Gas Information (Unaudited)

Note 15 - 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, crude oil and condensate 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. In the following table, natural gas liquids are included in natural gas reserves. The oil and natural gas liquids price as of July 31, 2013 and 2012 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 $92.52 and $95.07 per barrel, respectively. The gas price as of July 31, 2013 and 2012 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 $3.51and $3.02 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 (Barrels)			Gas (MCF)			Total ( MCFE)
Balance - July 31, 2011		1,218,950			12,561,090			19,874,790
Revisions of previous estimates		(88,689	)		(1,404,465	)		(1,936,599	)
New discoveries and extensions		660			11,840			15,800
Purchase of reserves in place		383,070			4,108,360			6,406,780
Sale of reserves in place		(64,730	)		(315,910	)		(704,290	)
Production		(61,011	)		(222,955	)		(589,021	)
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

	Proved Reserves as of July 31, 2013
	Oil (Barrels)		Gas (MCF)		Total ( 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 Reserves as of July 31, 2012
	Oil (Barrels)		Gas (MCF)		Total ( MCFE)
Proved developed producing		308,640		1,785,010		3,636,850
Proved developed non-producing		321,510		4,226,080		6,155,140
Proved undeveloped		758,100		8,726,870		13,275,470
Total proved reserves		1,388,250		14,737,960		23,067,460

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.

	2013			2012
Unevaluated properties	$	713,655		$	265,639
Evaluated properties		19,857,842			17,553,836
Less impairment		(373,335	)		(373,335	)
		20,198,162			17,446,140
Less depreciation, depletion, and amortization		(2,617,478	)		(1,557,675	)
Net capitalized cost	$	17,580,684		$	15,888,465

Costs Incurred in Oil and Gas Activities

Costs incurred in property acquisition, exploration and development activities for the year ended July 31, 2013 were as follows.

	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 incurred in property acquisition, exploration, and development activities for the year ended July 31, 2012 were all incurred in the USA.  The following table provides information about the costs incurred:

	July 31, 2012
Property acquisition
Unproved	$	74,805
Proved		6,988,447
Exploration		420,200
Development		2,033,073
Cost recovery		(32,772	)
Total costs incurred	$	9,483,753

Costs Excluded

Our excluded costs as of July 31, 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, 2013 were incurred during that year.

Costs Excluded by Year Incurred

	As of July 31, 2013
Property Acquisition	$	677,795
Exploration		35,860
Total	$	713,655

Costs excluded as of July 31, 2012 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		United States
Balance at July 31, 2011	$	-	$	-
Additional Cost Incurred		-		265,639
Costs Transferred to DD&A Pool		-		-
Balance at July 31, 2012				265,639
Additional Costs Incurred		713,655		278,090
Cost recovery		-		(132,662	)
Costs Transferred to DD&A Pool		-		(411,067	)
Balance at July 31, 2013	$	713,655	$	-

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:

	2013			2012
Future cash inflows	$	113,603,450		$	200,741,090
Future production costs		(55,897,070	)		(60,998,060	)
Future development costs		(41,794,284	)		(48,640,439	)
Future income tax expenses		(5,569,234	)		(31,885,907	)
Future net cash flows		10,342,862			59,216,684
10% annual discount for estimated timing of cash flows		(3,990,069	)		(25,552,798	)
Future net cash flows at end of year	$	6,352,793		$	33,663,886

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, 2013:

	2013			2012
Standardized measure of discounted future net cash flows at beginning of year	$	33,663,886		$	36,116,218
Net changes in prices and production costs		(37,623,010	)		(3,316,394	)
Changes in estimated future development costs		4,205,045			(10,006,008	)
Sales of oil and gas produced, net of production costs		(2,510,339	)		(3,152,150	)
Discoveries and extensions		-			54,414
Purchases of minerals in place		-			16,662,628
Sales of minerals in place		(17	)		(2,042,655	)
Revisions of previous quantity estimates		(12,391,911	)		(6,669,453	)
Development costs incurred		1,124,107			1,085,180
Change in income taxes		14,705,973			1,320,486
Accretion of discount		5,179,059			3,611,622
Standardized measure of discounted future net cash flows at year end	$	6,352,793		$	33,663,886

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

	2013			2012
Net revenues from production	$	7,070,540		$	7,165,233
Expenses
Lease operating expense		4,560,201			4,013,083
Accretion		1,056,508			943,508
Operating expenses		5,616,709			4,956,591
Depreciation, depletion and amortization		1,059,803			990,486
Total expenses		6,676,512			5,947,077
Income before income tax		394,028			1,218,156
Income tax expense		(137,910	)		(426,355	)
Results of operations	$	256,118		$	791,801
Depreciation, depletion and amortization rate per net equivalent MCFE	$	1.95		$	1.68

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Additional Financial Statement Information

12 Months Ended

Jul. 31, 2013

Additional Financial Statement Information [Abstract]

Additional Financial Statement Information

Note 13 - 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, 2013 and 2012, we have reserved $58,585 and $1,302, respectively, for potentially uncollectable other receivables.

Other current assets

Other current assets consisted of the following:

	At July 31,
	2013		2012
Prepaid letter of credit fees	$	93,362		16,567
Prepaid insurance		180,433		178,471
Other prepaid expenses		2,000		10,164
Cash call paid to operator		24,225		23,234
Prepaid land use fees		28,728		19,852
Accrued interest income		4,388		8,389
Total other current assets	$	333,136	$	256,677

Property and Equipment

Property and equipment consisted of the following:

		At July 31,
	Approximate Life	2013			2012
Furniture and fixtures	5 years	$	7,604		$	7,604
Marine vessels	5 years		17,614			17,614
Vehicles	5 years		18,027			18,027
Computer equipment and software	2 years		39,296			39,296
Total property and equipment			82,541			82,541
Less accumulated depreciation			(62,749	)		(36,572	)
Net book value		$	19,792		$	45,969
Depreciation expense		$	26,177		$	31,495

Accounts payable and accrued expenses

Accounts payable and accrued expenses consisted of the following:

	At July 31,
	2013		2012
Trade payables	$	3,068,671	$	1,950,768
Accrued payroll		151,577		40,000
Accrued interest and fees		398,966		-
Revenue payable		4,717		6,690
Local taxes and royalty payable		128,470		108,948
Federal and state income taxes payable		27,000		192,432
Total accounts payable and accrued expenses	$	3,779,401	$	2,298,838

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Document and Entity Information (USD $)	12 Months Ended
	Jul. 31, 2013	Nov. 12, 2013	Jan. 31, 2013
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Jul. 31, 2013
Entity Registrant Name	DUMA ENERGY CORP
Entity Central Index Key	0001425808
Current Fiscal Year End Date	--07-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2013
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		15,140,882
Entity Public Float			$ 15,400,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

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Subsequent Events

12 Months Ended

Jul. 31, 2013

Subsequent Events [Abstract]

Subsequent Events

Note 14 - Subsequent Events

In August 2013, 120,000 of the 600,000 options granted to our independent directors became vested and the fair market value of these options on the date of vesting was $16,184. The fair market 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 480,000 options so that they became fully and immediately vested. The fair value of the options on the date of vesting of $851,096 was recognized immediately as an expense. The fair market 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 October 2013, we issued 1,859,879 shares of common stock to Hydrocarb Corporation to settle the $2,400,000 consulting fee described in Note 2 - Acquisitions - Namibia Exploration, Inc., $553,640 of interest and late fees associated with the fee, and $635,937 of joint interest billings payable to Hydrocarb for its work on the Namibian concession.

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Income Taxes (Schedule of Deferred Tax Assets) (Details) (USD $)	Jul. 31, 2013	Jul. 31, 2012
Income Taxes [Abstract]
Stock based compensation	$ 713,867	$ 292,509
Property, including depreciable property	(2,980,005)	(2,070,809)
Asset retirement obligation	3,942,918	3,312,358
Net operating loss carry-forward	3,846,783	2,530,532
Other	42,368	318,032
Deferred tax assets, gross	5,565,931	4,382,622
Valuation allowance for deferred tax assets	(5,565,931)	(4,382,622)
Deferred tax assets, net

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Income Taxes (Reconciliation of Income Tax Provision at the Statutory Rate) (Details)	12 Months Ended
	Jul. 31, 2013	Jul. 31, 2012
Income Taxes [Abstract]
US statutory federal rate	35.00%	35.00%
State income tax rate	0.58%	0.58%
Equity-based compensation	(33.62%)	(36.43%)
Gain on derivative warrants	0.93%	7.60%
Gain on sale of securities	(0.33%)	(21.15%)
Other	(0.50%)	4.02%
Acquired deferred tax liability		23.12%
Net operating loss	(1.75%)	6.92%
Effective income tax rate	0.31%	19.66%