Hydrocarb Energy (HECCQ) 10-K 2012 FY Annual report

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, 2012

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 x

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 x

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, 2012 (the last day of the registrant’s most recently completed second fiscal quarter) was approximately $10,800,000.

The registrant had 13,279,703 shares of common stock outstanding as of November 12, 2012.

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	16
ITEM 2.	PROPERTIES	16
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	19
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	27
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	65
ITEM 9A.	CONTROLS AND PROCEDURES	65
ITEM 9B.	OTHER INFORMATION	66
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	66
ITEM 11.	EXECUTIVE COMPENSATION	70
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	73
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	74
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	76
ITEM 15.	EXHIBITS	77

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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 Corporation, (iii) SPE Navigation I, LLC, a Nevada limited liability corporation, 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, 2012, we maintain developed acreage both onshore and offshore in Texas and Illinois.  As of July 31, 2012, we were producing oil and gas from our working interest in four wells onshore in Texas and in four offshore fields in Galveston Bay, Texas.  As of July 31, 2012, we also owned overriding royalty interests in producing properties in Louisiana and working interests in one field in Illinois under development.  During September 2012, we acquired, through the acquisition of Namibia Exploration Inc., a 39% non-operated interest in a concession located onshore in Namibia, Africa.  During August 2012, we also sold our overriding royalty interests in Louisiana.

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 significant oil and gas interests are as follows:

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 three of 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 fields are not yet producing at pre-storm levels. Our operational goals include infrastructure improvements and modifications to increase production as well as a full development strategy which will include drilling, reworking wells, and recompletions. The entire bay is covered with 3D seismic data, which can be purchased relatively cheaply and on an as-needed basis. We intend to utilize this seismic data, as needed, to complement our exploration and development plans.

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. In October 2011, the Welder #5 well was recompleted into a productive zone up the hole and is currently in production. The Welder #3 well has additional proved non-producing zones behind pipe. We intend to develop the proved developed non-producing (PDNP) zones as current producing horizons deplete.

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Janssen Lease, Texas

We currently own a 3% working interest on any producing zones and a 5% non-promoted option to participate in any offset drilling within the leased area encompassing approximately 138 acres of an oil and gas lease (the “Janssen Lease”). The operator successfully re-completed in the Roeder Sand and the Janssen A-1 well is currently producing primarily natural gas.

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.

Chapman Ranch II Prospect, Texas

In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas.  We paid $50,000 in acquisition and land costs for our interest in this prospect. According to the terms of the agreement, we will 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 will 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.  During October 2012, we participated in a recompletion operation which resulted in the completion of the well into an upper zone. Results of that completion are still pending. A pumping unit and related equipment are being installed and production updates will be made once the information is available.

Curlee Prospect, Texas

During August 2012, we leased approximately 190 acres of land in Bee County, Texas.  The operator of the project will be Carter E&P, a company owned by our Chief Operating Officer.  The planned operation is the drilling of a new well on the leased area. We have a 50% working interest in the project. As of the date of this report, the first test well has been drilled and confirmed the existence and location of the trapping fault, as well as the structural uplift forming the target reservoir. A second well will be planned to exploit these potential oil reserves.

Illinois

Through the date of this annual report, we have entered into numerous oil and gas leases in Jefferson and other counties in Illinois. Currently these leases total approximately 237 gross acres. In January 2011, we farmed out our interest in the Markham City prospect in Illinois to Core Minerals Management II, LLC (“Core”).  Under the farmout agreement, we retained a 10% working interest and assigned the balance of our working interest in the Markham City prospect to Core. Core will be the operator of the property. Core will perform exploration activities on the prospect including drilling new wells. Our working interest is carried until Core meets the “Earnings Threshold” of $1,350,000. Once Core has recouped their initial investment, we will gain an additional 15% working interest, bringing our total working interest in the project to 25%.  We are currently producing from three oil wells in this project area.

We are presently in the pilot phase of our waterflood operations for the Markham City project. During the pilot phase, Core Minerals is injecting water into the target formation and collecting data to determine the viability of a full-field development strategy. The pilot phase is expected to take 9-18 months before a decision can be made to expand the waterflood.

Louisiana

We received revenues from our 6% overriding royalty interests in 3 leases located in the South Delhi and Big Creek oil fields in Northeastern Louisiana through August 31, 2012. These interests carry no operational or financial responsibilities for expenses or liabilities except for ad valorum taxes.  Effective September 1, 2012, we sold the overriding royalty interests in these properties. As of the date of this report, we hold no interests in the State of Louisiana.

Acquisition of 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.

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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 a 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.

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).

For more information on this concession, see Recent Activities below.

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, 2012, as estimated by third party reservoir engineers.

Summary of Oil and Gas Reserves as of July 31, 2012 Based on Average Fiscal-Year Prices

Reserves Category	Oil (Mbls)	Natural Gas (MMcf)	Equivalent (MMcfe)
PROVED
Developed	630.15	6,011.09	9,791.99
Undeveloped	758.10	8,726.87	13,275.47
TOTAL PROVED	1,388.25	14,737.96	23,067.46

Estimates of proved reserves at July 31, 2012 and 2011 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.

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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 Operations Manager is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Operations Manager 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. The Operations Manager 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, including the material additions to the 2011 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.

Changes in Proved Undeveloped Reserves

As of July 31, 2012, we reported 13,275.47 MMcfe of proved undeveloped reserves, which represents an increase of 851.84  MMcfe from July 31, 2011.  The following table shows of the changes in total proved undeveloped reserves for 2012:

Beginning of year	12,423.63
Revisions of previous estimates	(2,585.06	)
Purchase of reserves in place	4,141.19
Sale of reserves in place	(704.29	)
End of year	13,275.47

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.  The well has been drilled and we are in the process of testing and evaluating the well.

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, 2012, 2011and 2010. 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.

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	For the Year Ended July 31, 2012		For the Year Ended July 31, 2011		For the Year Ended July 31, 2010
Production Data
Oil (MBbls)		61.0		28.2		6.4
Natural gas (MMcf)		223.0		59.5		15.7
Total (MMcfe)		589.0		228.6		54.4
Average Prices:
Oil (per Bbl)	$	106.29	$	110.65	$	72.89
Natural gas (per Mcf)	$	3.05	$	4.95	$	3.95
Total (per Mcfe)	$	12.16	$	14.93	$	9.78
Average Costs (per Mcfe):
Lease operating expenses (per Mcfe)(1)	$	6.81	$	7.43	$	10.49

(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.

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 (i)  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.

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, 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

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	Number of Wells Drilled During Year Ended July 31, 2010
	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		.25		0		0		0		0		0		0
Total		0		.25		0		0		0		0		0		0

Present Activities

As of November 12, 2012, we are in the process of completing a development well in Galveston Bay, Texas, which spudded in January 2012.  We own a 25% interest in the well and we are the operator of the well.  We are in the process of testing and evaluating the well.  We also are in the process of recompleting a well drilled onshore in Nueces County, Texas beginning in June 2012.  The well was originally completed to a non-economic zone.  During October 2012, we participated in a recompletion operation the results of which are still pending.  We own a 25% non-operated interest in this well. In October 2012, we spudded a well on the Curlee prospect that resulted in a dry hole.  We own a net 50% interest in this property.  33-1/3% of our interest is cost-bearing and 16-2/3% of the interest is carried to the casing point. The Curlee Prospect is currently being evaluated for a possible second drill well.

Delivery Commitments

None.

Productive Wells

The following table sets forth information regarding the total gross and net productive wells as of November 12, 2012, expressed separately for oil and gas. All of our productive oil and gas wells were located in Texas and Illinois. 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
Illinois		3		0.30		0		0.00
Texas		23		21.81		14		10.19
Total		26		22.11		14		10.19

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, 2012.

	Gross (1)		Net
Developed Acreage
Illinois		120		12
Texas		20,940		18,887
Undeveloped Acreage
Illinois		153		84
Texas		1,996		787
Total		23,209		19,770

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

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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.

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.

10

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.

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.

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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.

Employees

We currently have eighteen 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 Corporation, (iii) SPE Navigation I, LLC, a Nevada limited liability corporation, 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. 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 history upon which to base any assumption as to the likelihood that our business will prove successful, and it is possible we may never achieve profitable operations.

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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 to date and we have never been profitable. 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, our success in setting up and expanding distribution channels 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, 2012, we had cash and cash equivalents of $1,102,987 and a working capital deficit of $1,865,472. 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 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.

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.

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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.

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.

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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.

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.

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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.

ITEM 3.  LEGAL PROCEEDINGS

As of July 31, 2012, 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, the 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 case listed below 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.

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.

ITEM 4.  MINE SAFETY DISCLOSURE

Not applicable.

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PART I

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 the periods indicated. 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, 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
July 31, 2011	$	3.73	$	1.56
April 30, 2011	$	4.88	$	2.25
January 31, 2011	$	5.25	$	3.25
October 31, 2010	$	6.25	$	4.00

Holders

As of November 12, 2012, we had 92 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, 2012:

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.      2009 Stock Incentive Plan		188,000	$	2.50		200,629
	2.      2010 Stock Incentive Plan		56,000	$	2.50		144,000
	3.      2011 Stock Incentive Plan		800,000	$	2.50		186,964
	4.      Compensation Warrants		2,544,520	$	2.50		N/A

2009 Restated Stock Incentive Plan

On May 21, 2009, our Board of Directors authorized and approved the adoption of the 2009 Restated Stock Incentive Plan (the “2009 Plan”), which absorbs and replaces the 2007 Stock Incentive Plan, under which an aggregate of 400,000 of our shares (on a post-share consolidation basis) may be issued.

The purpose of the 2009 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.

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The 2009 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of two or more members of the Board of Directors, which shall determine, among other things, (i) the persons to be granted awards under the 2009 Plan; (ii) the number of shares or amount of other awards to be granted; and (iii) the terms and conditions of the awards granted. The Company may issue restricted shares, options, stock appreciation rights, deferred stock rights, dividend equivalent rights, among others, under the 2009 Plan. An aggregate of 400,000 of our shares may be issued pursuant to the grant of awards under the 2009 Plan.

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 2009 Plan. If the administrator under the 2009 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 2009 Plan is not complete and is qualified in its entirety by reference to the 2009 Plan, a copy of which has been filed with the SEC.

During the year ended July 31, 2012, we did not grant any options to purchase shares of our common stock under the 2009 Plan.

2010 Stock Incentive Plan

During August 2010, the Board of Directors authorized and approved the adoption of the 2010 Stock Incentive Plan (the “2010 Plan”). An aggregate of 200,000 shares (on a post-share consolidation basis) may be issued under the plan.

The purpose of the 2010 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.

The 2010 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of two or more members of the Board of Directors, which shall determine, among other things, (i) the persons to be granted awards under the 2010 Plan; (ii) the number of shares or amount of other awards to be granted; and (iii) the terms and conditions of the awards granted. The Company may issue restricted shares, options, stock appreciation rights, deferred stock rights, dividend equivalent rights, among others, under the 2010 Plan. An aggregate of 200,000 of our shares may be issued pursuant to the grant of awards under the 2010 Plan.

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 2010 Plan. If the administrator under the 2010 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 2010 Plan is not complete and is qualified in its entirety by reference to the 2010 Plan, a copy of which was filed as an exhibit to our annual report on Form 10-K for the year ended July 31, 2011.

During the year ended July 31, 2012, we did not grant any options to purchase shares of our common stock under the 2010 Plan.

2011 Stock Incentive Plan

During April 2011, the Board of Directors authorized and approved the adoption of the 2011 Stock Incentive Plan (the “2011 Plan”). An aggregate of 1,000,000 shares (on a post-share consolidation basis) may be issued under the plan.

The purpose of the 2011 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.

The 2011 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of two or more members of the Board of Directors, which shall determine, among other things, (i) the persons to be granted awards under the 2011 Plan; (ii) the number of shares or amount of other awards to be granted; and (iii) the terms and conditions of the awards granted. The Company may issue restricted shares, options, stock appreciation rights, deferred stock rights, dividend equivalent rights, among others, under the 2011 Plan. An aggregate of 1,000,000 of our shares may be issued pursuant to the grant of awards under the 2011 Plan.

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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 2011 Plan. If the administrator under the 2011 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 2011 Plan is not complete and is qualified in its entirety by reference to the 2011 Plan, a copy of which was filed as an exhibit to our annual report on Form 10-K for the year ended July 31, 2011.

During the year ended July 31, 2012, we did not grant any options to purchase shares of our common stock under the 2011 Plan.  During the year ended July 31, 2012, we issued 13,036 shares of common stock under the 2011 Plan.

Recent Sales of Unregistered Securities

We have previously disclosed in our Current 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, 2012.

Subsequent to our fiscal year ended July 31, 2012, as disclosed in our Current Report on Form 8-K as filed with the SEC on September 12, 2012, we issued 2,490,000 common shares to four persons in connection with our acquisition of Namibia Exploration, Inc.  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.

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, 2012 and 2011 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 4 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’s)	2009			2010			2011			2012
Revenue		0.49			0.53			3.41			7.17
Cash Flow From Operations		(1.13	)		(2.63	)		(2.27	)		0.63
Total Assets		1.47			2.53			16.94			25.78
Net Loss		(2.78	)		(3.49	)		(10.29	)		(4.58	)
Total Stockholders’ Equity		0.54			0.28			6.63			12.30

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Recent Accomplishments:

· We have successfully broadened our base of productive assets, including: reestablishing production from Red Fish Reef Field in Galveston Bay, Texas, drilling the Chapman Ranch well, drilling of the Palacios well, farming-out and establishing production of our Markham City waterflood project in Illinois, and development of the new Curlee project;

· We have enhanced our own in-house prospect generation capabilities resulting in several drillable and salable prospects, the first of which is the Curlee project,  already underway;

· With the recent appointment of our two new independent directors, we have now achieved a majority independent Board that is full of highly skilled and respected professionals;

· We have expanded our scope of exploration to Africa with the acquisition of Namibia Exploration Inc. and its 39% working interest in the 5.3 million-acre concession in Namibia’s Owambo Basin.

Near Term Focus and Plans:

· Continue drilling our own acreage. Although we may participate from time to time in other drilling opportunities, we believe that our best investment is in our own projects and developing our existing reserves;

· Enhance the value of our concession in Namibia, Africa, which is the size of the State of Massachusetts. The information gathered so far points to a very prospective region and we expect the value of this concession to grow exponentially with each successive phase of data acquisition, including aerial gravity magnetic surveys, 2D seismic, and 3D seismic;

· We believe that in this current market there are numerous opportunities for strategic acquisitions. We will focus on only those possible acquisition opportunities that enhance our cash flow, reserve base, and shareholder value both short and long term.

Plan of Operations

In South Texas, we plan to continue producing oil and gas from existing leases and we plan to initiate drilling on the Curlee prospect, which is described above. It is also expected that we will drill another of our own generated prospects in South Texas utilizing the third-for-a-quarter promoted method. This will provide us with a 25% carried working interest to the casing point, allowing us to avoid participating in the drilling costs.

In Illinois, we will continue the pilot waterflood program in the Markham City Field which is currently producing a modest amount of oil until such time that Core Minerals, the operator, believes there is sufficient data to make a recommendation about whether to expand the waterflood. We expect this decision before mid-2013.

In Galveston Bay, Texas we plan to continue enhancing the production from our four productive fields. Our plans include drilling, reworking, and recompletions, as well as infrastructure improvements to exploit the known reserves as well as explore for additional reserves. Through the date of this report, we have accomplished the following:

· In April 2012, we negotiated a production handling agreement for our production from the Redfish Reef field, which had been shut in since April 2011;

· We have brought most of our shut-in wells in the Red Fish Reef field back online;

· We are installing equipment in the field to reduce backpressure and thus enhance recovery;

· We replaced flow lines and worked over two wells in our Trinity Bay Field;

· We have recompleted a well in our North Point Bolivar field in order to access behind pipe reserves.  The well requires additional work to bring the hydrocarbons online, which we plan to conduct in November 2012;

· We drilled our first development well in Galveston Bay, the State Tract 9-12A #4, during the year ended July 31, 2012, but we experienced some cost and schedule over-runs both in the drilling and in completion of the well. Drilling and completion results for the ST 9-12A #4 well have so far indicated that the well is not capable of commercial production.  We are conducting further analysis and will also review new 3D seismic data to corroborate and update the geological mapping. A final determination on the future utility of the well is not likely to be made until 2013.

Our immediate near term focus for the Galveston Bay fields is to bring enhance our gas lift capability and increase production at our North Point Bolivar field.  Beyond this project, we plan to increase production through infrastructure enhancements and various reworks and recompletions identified during our field analysis. There still exist a large number of shut-in wells that are capable of producing. As capital permits, we will engage in these projects and bring on additional wells.

In Namibia, Africa, in conjunction with the operator, Hydrocarb Energy Corp., we will continue gathering data, including further source rock surveys, reservoir studies, seep studies, geologic mapping, and other analysis. Following this, we plan to conduct aerial gravity and magnetic surveys in 2013 across our entire concession which is approximately the size of the State of Massachusetts. This should, once interpreted, allow us to design our plan for 2D seismic acquisition. 3D seismic will 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.

Recent Activities

In August 2012, we acquired Namibia Exploration, Inc., a Nevada corporation. The primary asset of Namibia Exploration is a 39% working interest (43% cost share until the first discovery is made) in a 5.3 million-acre concession in northern Namibia in Africa. The operator and majority interest holder of this concession is Hydrocarb Energy Corp. The purchase of Namibia Exploration Inc. from the previous owners was facilitated through a share exchange agreement involving the issuance of restricted shares of our stock that is based upon future market capitalization milestones. The rationale for such a structure is two-fold:

1. We wanted to ensure that we were not paying for a project that would ultimately be a drain on our resources; therefore, by linking the consideration to Duma’s market capitalization we can ensure that the company is healthy and doing well overall before additional consideration is paid for Namibia Exploration Inc.;

2. Due to the potentially capital-intensive nature of exploration in Africa, we wanted to ensure that we did not weight the consideration on the front-end of the transaction; therefore, the milestones are heavily weighted toward the back-end at increasingly higher market capitalization levels.

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We believe that this structure is highly advantageous for the company. The costs associated with this transaction also include a consulting agreement with Hydrocarb which contemplates participation in future projects that Hydrocarb is actively pursuing around the world. We are looking forward to considering future projects in Africa and elsewhere around the world.

Results of Operations

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

	Year Ended July 31,						Increase/			2012%
	2012			2011			(Decrease)			change
Revenues	$	7,165,233		$	3,412,791		$	3,752,442		$	110	%
Operating expenses
Lease operating expense		4,013,083			1,698,191			2,314, 892			136	%
Depreciation, depletion, and amortization		1,021,981			304,851			717,130			235	%
Accretion		943,508			213,866			729,642			341	%
Impairment		-			140,029			(140,029	)		(100)	%
Consulting fees – related party		189,372			2,965,559			(2,776,187	)		(94)	%
Acquisition-related costs		-			2,617,099			(2,617,099	)		(100)	%
Acquisition-related costs – related party		4,367,750			-			4,367,750			100	%
Share return and settlement		-			1,800,000			(1,800,000	)		(100)	%
General and administrative expense		3,852,722			2,549,365			1,303,357			51	%
Total operating expenses		14,388,416			12,288,960			2,099,456			17	%
Loss from operations		(7,223,183	)		(8,876,169	)		1,652,986			(19	)
Interest expense, net		(157,964	)		(151,549	)		6,415			4	%
Gain on sale of available-for-sale securities		463,117			-			463,117			100	%
Loss on settlement of debt		-			(50,737	)		50,737			(100)	%
Gain (loss) on derivative warrant liability		1,217,835			(1,206,788	)		2,424,623			(201)	%
Net loss before income tax		(5,700,195	)		(10,285,243	)		4,585,048			(45	)
Income tax benefit		1,120,471			-			1,120,471			(100)	%
Net loss	$	(4,579,724	)	$	(10,285,243	)	$	5,705,519			(55)	%

We recorded a net loss of $4,579,724, or $0. 45 per basic and diluted common share, during the fiscal year ended July 31, 2012, as compared to a net loss of $10,285,243, or $2.34 per basic and diluted common share, during the fiscal year ended July 31, 2011.

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

· Revenues, lease operating expense, depreciation, depletion, and amortization expense, and accretion expense increased substantially because of the inclusion of the results of our new subsidiaries, GBE and SPE.  We purchased GBE on February 15, 2011.  Our consolidated financial statements include GBE’s results from February 15, 2011 through July 31, 2012; that is, five and one half months in 2011 as opposed to twelve months in 2012.  Through GBE, we produced from approximately 26 active oil and gas wells in four fields. We purchased SPE on September 23, 2011.  Our consolidated financial statements include SPE’s results from September 23, 2011 through July 31, 2012.  SPE owned 25% of the working interest in the properties that we acquired with GBE, thus this acquisition also increased our operations. The transactions resulted in a substantial increase in our operations.

· We recorded an impairment charge during the year ended July 31, 2011 because the net book value of our oil and gas properties exceeded the ceiling by $140,029 on January 31, 2011.

· 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 11 – Capital Stock for more information about these warrants.

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· Acquisition related costs in 2011 were attributable to stock granted to consultants as finders’ fees for their role in effecting the acquisition of GBE as well as due diligence costs.  The costs were not repeated in the current year.

· Acquisition related costs – related party: 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.  This was a one-time charge.

· Share return and settlement in 2011 related to a settlement with an officer and a director, Amiel David and Alan Gaines, in which they received cash and warrants and returned the stock previously granted to them in conjunction with the acquisition of GBE.  This was a one-time charge.

· After our purchase of GBE, we secured office space in Houston, Texas and hired additional accounting staff, an operations manager and regulatory manager for GBE.   These costs are included for only five and one-half months in 2011 as opposed to twelve months in 2012.  Additionally, as of June 2011, executive compensation increased by approximately $130,000 on an annualized basis.  Accordingly, general and administrative expenses increased, primarily due to increases in compensation, rent, and other general office costs. Audit and professional fees increased in part due to our larger scope of operations and in part due to some non-recurring expenditures such as acquisition audits and litigation costs.  The non-recurring portion of the increase was approximately $200,000.

· We acquired equity securities with our acquisition of SPE.  We sold securities with a cost basis of $3,546,431 for proceeds of $4,009,548, resulting in a gain on the sale of the securities.

· During 2011, we settled certain of our accounts payable by the issuance of common stock that, at the date of issuance, had a fair value in excess of the amount of debt being settled.  We therefore recognized a net loss on the settlements of $50,737.

· We re-measure our derivative warrants at fair value at every reporting date.  The fair value of the derivative warrants, as determined using a lattice model, reduced substantially as of July 31, 2012 as compared with July 31, 2011, resulting in a gain due to a reduction in our derivative warrant liability; whereas the change in fair value of the warrants in the comparative prior period resulted in a loss.

· We recognized an income tax benefit during the year ended July 31, 2012 due to an adjustment of the valuation allowance for our deferred tax assets and due to the current utilization of tax assets because of a tax gain generated by the gain on sale of securities.  We determined that current deferred tax assets exist that are sufficient to offset deferred tax liability on unrecognized tax gain on available for sale securities that had been acquired with the purchase of SPE.  In addition, we incurred intangible drilling costs and dry hole costs that resulted in tax losses that also offset the recognized gain on securities sold, and thus we recognized a tax benefit.  This is not a recurring item.

We do not expect the increase in acquisition costs, related party consulting expenses and settlement expense to be recurring expenses.  The increases in revenue, lease operating expense, depreciation, depletion, and amortization expense, accretion expense, general and administrative expense, and interest expense are associated with our larger scope of operations due to our acquisition of the properties in Galveston Bay and will be an ongoing element in our financial results.

The following table sets forth our cash and working capital as of July 31, 2012 and July 31, 2011:

	July 31, 2012			July 31, 2011
Cash reserves	$	1,102,987		$	1,082,099
Working capital (deficit)	$	(1,865,472	)	$	(3,773,504	)

Subject to the availability of additional financing, in order to maximize production from our Galveston Bay properties, we plan approximately $1.0 million to $3.5 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. The upper range of these capital expenditures contemplates the drilling of a new well in the bay. The determination of when this well is drilled will be made pursuant to financial performance and operational considerations.

At July 31, 2012, we had $1,102,987 of cash on hand and a working capital deficit of $1,865,472 ($1,325,388 of which is attributable to a warrant derivative liability which would ordinarily be settled in stock). As such, our working capital alone on July 31, 2012 was not sufficient to enable us to pay our lease operating costs, to pay our general and administrative expenses, and to pursue our plan of operations over the next 12 months. However, our cash flow from operations is good, and we believe it will support the payment of outstanding obligations as well as our planned capital expenditures. Our plan of operations over the next twelve months will always be subject to available capital which will be determined, in part, 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 recent projects and upcoming projects we could actually exceed our planned operations and have more 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.

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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 has suffered through a period of uncertainty during which the capital markets have been depressed from levels established in recent years, and that there is no certainty that these levels will stabilize or reverse. 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.  During our fiscal year ended July 31, 2011, oil price levels increased to a high of $114 per barrel, but they have decreased to approximately $86 per barrel as of late October 2012. 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.

Net Cash Provided by (Used in) Operating Activities

During the year ended July 31, 2012, net cash provided by operating activities was $626,076 compared to net cash used in operating activities of $2,266,201 during the year ended July 31, 2011. This change is attributable to increased net cash flows from our new subsidiaries, GBE and SPE.  Prior to our acquisition of GBE and SPE, operating activities have primarily used cash as a result of the operating and organizational activities such as consulting and professional fees, direct operating costs, management fees and travel and promotion. With our acquisition of GBE and SPE, we expect to derive a much greater percentage of our cash flows from operations from revenues and direct operating costs. Because the GBE properties will increase our contribution margin from our core activities, the acquisition should continue to enhance our cash flows from operations.

Net Cash Provided by (Used in) Investing Activities

During the year ended July 31, 2012, investing activities provided cash of $858,287 compared to a use of cash of $7,451,193 during the year ended July 31, 2011. Investing activities during fiscal 2012 consists primarily of proceeds from the sale of available for sale securities, offset by the purchase of oil and gas properties. The use of cash in 2011 relates primarily to our purchase of GBE.  Because of our planned investments in oil and gas properties, including our fields in Galveston Bay, our working interest in the concession in Namibia, and drilling of an onshore prospect that is currently underway, we expect to use cash in investing activities during fiscal 2013.

Net Cash (Used in) Provided by Financing Activities

As we have had limited revenues since inception through July 2011, we had financed our operations primarily through private placements of our common stock. Financing activities during the year ended July 31, 2012 used cash of $1,463,475 compared to cash provided of $10,551,642 during the year ended July 31, 2011.  This was primarily attributable to repayments of notes payable during 2012, whereas in 2011 we raised funds from an equity private placement.

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 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.

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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 year ended July 31, 2011, we recorded a $140,029 impairment charge because the net book value of our oil and gas properties exceeded the ceiling.

Beginning December 31, 2009, full cost companies use the un-weighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date. Prior to December 31, 2009, companies used the price in effect at the end of each accounting period and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the end of the accounting quarter.

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 gas 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 gas 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 as of the date of 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.

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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.

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

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

Beginning balance – July 31, 2011	$	2,543,223
Reduced for warrants exercised		-
Unrealized gain on changes in fair value of derivative liability		(1,217,835	)
Change in fair value of derivative liability		(1,217,835	)
At July 31, 2012	$	1,325,388

The $1,217,835 change 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 following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the year ended July 31, 2011:

Beginning balance – July 31, 2010	$	1,502,700
Reduced for warrants exercised		(166,265	)
Unrealized loss on changes in fair value of derivative liability		1,206,788
Change in fair value of derivative liability		1,040,523
At July 31, 2011	$	2,543,223

The $1,040,523 change in fair value was recorded as a reduction of the derivative liability and as a $1,206,788 unrealized loss on the change in fair value of the liability in our statement of operations and a $166,265 adjustment to paid-in capital related to the exercise during the period of warrants classified as derivative liabilities.

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.

25

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, 2012 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.

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.

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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	28
Consolidated Balance Sheets as of July 31, 2012  and 2011	29
Consolidated Statements of Operations and Comprehensive Loss for the years ended July 31, 2012 and 2011	30
Consolidated Statements of Stockholders’ Equity for the years ended July 31, 2012 and 2011	31
Consolidated Statements of Cash Flows for the years ended July 31, 2012 and  2011	32
Notes to Consolidated Financial Statements	33

27

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, 2012 and 2011 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, 2012 and 2011, 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 13, 2012

28

DUMA ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

	July 31,
	2012			2011
Assets
Current assets
Cash and cash equivalents	$	1,102,987		$	1,082,099
Oil and gas revenues receivable		457,567			875,918
Accounts receivable – related party		117,618			69,880
Available for sale securities		313,446			—
Other current assets		256,677			292,973
Other receivables, net		517,441			225,057
Total current assets		2,765,736			2,545,927
Oil and gas property, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $1,557,675 and $567,189, respectively, and accumulated impairment of $373,335 and $373,335, respectively		15,622,826			7,395,198
Unevaluated property		265,639			—
Restricted cash		6,890,000			6,716,850
Other assets		190,259			255,942
Property and equipment, net of accumulated depreciation of $36,572 and $11,158, respectively		45,969			22,857
Total assets	$	25,780,429		$	16,936,774
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued expenses	$	2,298,838		$	1,676,816
Line of credit		300,000			1,360,573
Current portion of notes payable		102,025			255,596
Asset retirement obligations – short term		549,796			468,500
Derivative warrant liability		1,325,388			2,543,223
Advances		55,161			-
Due to related parties		-			14,723
Total current liabilities		4,631,208			6,319,431
Notes payable		11,678			-
Asset retirement obligations – long term		8,833,137			3,987,428
Total liabilities		13,476,023			10,306,859
Commitments and contingencies
Stockholders’ equity:
Common stock, $.001 par; 500,000,000 authorized shares; 10,791,003 and 6,790,816 shares issued and outstanding in 2012 and 2011, respectively		10,791			6,791
Additional paid-in capital		38,963,817			27,970,520
Accumulated other comprehensive income		(743,082	)		-
Accumulated deficit		(25,927,120	)		(21,347,396	)
Total stockholders’ equity		12,304,406			6,629,915
Total liabilities and stockholders’ equity	$	25,780,429		$	16,936,774

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

29

DUMA ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

	Years Ended July 31,
	2012			2011
Revenues	$	7,165,233		$	3,412,791
Operating expenses
Lease operating expense		4,013,083			1,698,191
Depreciation, depletion, and amortization		1,021,981			304,851
Accretion		943,508			213,866
Impairment		—			140,029
Consulting fees – related party		189,372			2,965,559
Acquisition-related costs		—			2,617,099
Acquisition-related costs – related party		4,367,750			—
Share return and settlement		—			1,800,000
General and administrative expense		3,852,722			2,549,365
Total operating expenses		14,388,416			12,288,960
Loss from operations		(7,223,183	)		(8,876,169	)
Interest expense, net		(157,964	)		(151,549	)
Loss on settlement of debt		—			(50,737	)
Gain on sale of available for sale securities		463,117
Gain (loss) on derivative warrant liability		1,217,835			(1,206,788	)
Net loss before income taxes		(5,700,195	)		(10,285,243	)
Income tax benefit		1,120,471			—
Net loss	$	(4,579,724	)	$	(10,285,243	)
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	$	(5,322,806	)	$	(10,285,243	)
Basic and diluted loss per common share	$	(0.45	)	$	(2.34	)
Weighted average shares outstanding (basic and diluted)		10,218,355			4,397,657

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

30

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, 2010		2,097,285		$	2,097		$	11,339,930		$	—			(11,062,153	)		279,874
Common stock issued for:
Stock issued for cash, net of share issuance costs, and for warrants exercised for cash		3,790,400			3,790			9,395,194			—			—			9,398,984
Debt		71,814			72			231,215			—			—			231,287
Debt – related party		64,732			65			161,764			—			—			161,829
Services		656,585			657			2,654,309			—			—			2,654,966
Deemed dividend		710,000			710			2,839,290			—			—			2,840,000
Deemed dividend		—			—			(2,840,000	)		—			—			(2,840,000	)
Share return and settlement		(600,000	)		(600	)		756,850			—			—			756,250
Share-based compensation:
Amortization of fair value of stock options		—			—			466,409			—			—			466,409
Warrants granted to related party		—			—			2,965,559			—			—			2,965,559
Net loss		—			—			—			—			(10,285,243	)		(10,285,243	)
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

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

31

DUMA ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended July 31,
	2012			2011
Cash Flows From Operating Activities
Net loss	$	(4,579,724	)	$	(10,285,243	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		1,021,981			304,851
Impairment		—			140,029
Accretion		943,508			213,866
Write-off of reclamation deposit		—			19,317
Change in allowance for doubtful accounts		(26,563	)		—
Change in deferred tax allowance		(130,200	)		—
Amortization of loan origination fees and prepaid interest		143,388			30,684
Gain on sale of available for sale securities		(463,117	)		—
Warrants granted to related party		189,372			2,965,559
Common stock granted for services and for investor relations		620,155			108,624
Acquisition-related costs paid in common stock		—			2,546,342
Acquisition-related costs – related party		4,367,750			—
Share based compensation- amortization of the fair value of  stock options		687,770			466,409
Equity award vested in conjunction with settlement, net of cash payment of $1,043,750		—			756,250
(Gain) loss on derivative warrant liability		(1,217,835	)		1,206,788
Loss on settlement of accounts payable		—			50,737
Changes in operating assets and liabilities:
Accounts receivable		197,885			(543,012	)
Advances		55,161			—
Accounts payable and accrued expenses		(948,070	)		(210,238	)
Settlement of asset retirement obligations		(178,539	)		(135,318	)
Accounts receivable – related party		(47,738	)		(40,905	)
Other assets		(9,108	)		139,059
Net cash provided by (used in) operating activities		626,076			(2,266,201	)
Cash Flows From Investing Activities
Purchases of oil and gas properties		(2,221,242	)		(360,143	)
Purchases of property, equipment and domain name		(66,847	)		(16,050	)
Change in restricted cash		(160,213	)		—
Purchase of available for sale securities		(702,959	)		—
Proceeds from sale of available for sale securities		4,009,548			—
Proceeds from sale of oil and gas properties		—			1,425,000
Purchase of Galveston Bay Energy, LLC, including restricted cash of $6,675,487		—			(8,500,000	)
Net cash provided by (used in) investment activities		858,287			(7,451,193	)
Cash Flows From Financing Activities
Proceeds from exercise of warrants and from sales of common stock for cash, net of share issuance costs		—			9,232,719
Proceeds from notes payable		300,000			1,548,300
Payments on notes payable		(1,748,752	)		(229,377	)
Payments on notes payable to related parties		(14,723	)		—
Net cash (used in) provided by financing activities		(1,463,475	)		10,551,642
Net increase in cash		20,888			834,248
Cash at beginning of period		1,082,099			247,851
Cash at end of period	$	1,102,987		$	1,082,099

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

32

DUMA ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

	Years Ended July 31,
	2012		2011
Supplemental Disclosures:
Interest paid in cash	$	38,129	$	162,511
Income taxes paid in cash	$	4,847		—
Non-cash investing and financing
Accounts payable for oil and gas assets	$	244,793	$	54,256
Asset retirement obligation purchased		97,374		5,843,330
Asset retirement obligation – change in estimate		1,827,889		—
Asset retirement obligation incurred		1,389		—
Asset retirement obligation sold		32,772		1,523,573
Payment for sale of working interest paid to the seller (See Note 2 – Acquisitions - Galveston Bay Energy, LLC)		—		1,400,000
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		—
Note receivable for sale of oil and gas property		—		50,000
Unrealized loss on available for sale securities		743,082		—
Note payable for purchase of vehicle		18,027		—
Note payable for insurance		227,912		159,973
Loan origination fees		—		60,573
Non-cash capitalized interest		—		51,671
Stock and derivative warrants for accounts and notes payable		—		231,287
Stock and derivative warrants for accounts and note payable to related parties		—		161,829
Reclassification due to exercise of warrants classified as a derivative		—	166,265

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

33

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 were incorporated as Carlin Gold Corporation on April 12, 2005 in Nevada, U.S.A. On July 11, 2005, we changed our name to Nevada Gold Corp., on October 18, 2005 we changed our name to Gulf States Energy Inc. and on September 5, 2006, we changed our name to Strategic American Oil Corporation. On April 4, 2012, we changed our name to Duma Energy Corp. 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, and 100% of SPE Navigation I, LLC (“SPE”) a Nevada limited liability company.  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, and GBE. 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.

34

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 are operated by a company owned by one of our officers, who is 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, 2012 and 2011, we have reserved $1,302 and $73,220, respectively, for potentially uncollectable other receivables.

Available for sale securities

We invest in marketable equity securities which are classified as available for sale. 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, and loan origination costs associated with our line of credit. (See Note 7 – Line of Credit)

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, 2012, 67% of our revenue was attributable to one purchaser.  At July 31, 2012, this same purchaser accounted for 79% of our accounts receivable.  A second purchaser accounted for an additional 14% of our accounts receivable at July 31, 2012. For the year ended July 31, 2011, 77.4% of our revenue was attributable to one purchaser.  At July 31, 2011, this same purchaser accounted for 79% of our accounts receivable.  A second purchaser accounted for an additional 12.3% of our accounts receivable at July 31, 2011.

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.

35

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.

Beginning December 31, 2009, full cost companies use the un-weighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date. Prior to December 31, 2009, companies used the price in effect at the end of each accounting period and had the option, under certain circumstances, to elect to use subsequent commodity prices if they increased after the end of the accounting quarter.

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 year ended July 31, 2011, we recorded a $140,029 impairment charge because the net book value of our oil and gas properties exceeded the ceiling as of January 31, 2011. During the year ended July 31, 2012, the ceiling exceeded the 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 gas 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 gas 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. As of July 31, 2012 and 2011, restricted cash totaled $6,890,000 and $6,716,850, respectively.

Other assets

Other assets at July 31, 2012 and 2011 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases.  We acquired prepaid land use fees as part of our acquisition of Galveston Bay Energy, LLC (see Note 2 – Acquisitions – Galveston Bay Energy, LLC) and we pay for rentals as they come due on an ongoing basis.  In addition, during the year ended July 31, 2012, we purchased, for $30,267, a domain name, 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.  Additionally, other assets includes a note receivable for the sale of oil and gas properties that was deemed uncollectible during the quarter ended April 30, 2012, and was written off to bad debt expense for the entire amount that was then outstanding, $45,355.

36

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, 2012 and 2011, 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, 2012 and 2011, advances totaled $55,161 and $0, 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.

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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 as of the date of 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 9 – 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 (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.

Our derivative warrant liability is our only financial asset or liability that is 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 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.

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 loss per share using the weighted average number of shares of common stock outstanding during each period. Diluted loss per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2012 and 2011, 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 14 - Commitments and Contingencies for more information on legal proceedings.

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Evironmental

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, 2011	$	—
Change in fair value of available-for-sale securities		(743,082	)
Accumulated other comprehensive loss at July 31, 2012	$	(743,082	)

There is no tax effect of the unrealized loss in other comprehensive income given our full valuation allowance against deferred tax assets.

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

Acquisition of Galveston Bay Energy, LLC (“GBE”)

On February 15, 2011 we closed on the acquisition of a private Texas oil and gas company named Galveston Bay Energy, LLC (“GBE”) which owns working interests in and operates producing oil and natural gas properties and its related facilities in four fields located in Galveston Bay, Texas.  GBE holds both proved producing, proved shut-in, proved non-producing, and proved undeveloped reserves.  We acquired 100% of the membership interest in GBE and thus GBE is our wholly owned subsidiary.  Our consolidated financial statements include the results of GBE from the date of acquisition, February 15, 2011.

Immediately following our acquisition of GBE, 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 paid for its working interest by wiring the funds directly to the seller of the property.  Our agreement with SPE provided that SPE could acquire an additional 10% working interest in the properties for $1,150,000 paid within 90 days of the acquisition.  Effective May 1, 2011, SPE acquired an additional 10% of our aggregate working interest in the Galveston Bay fields for an additional $1,150,000 pursuant to our agreement.

The seller was paid $10,397,376 cash in February and March 2011, which included the purchase price of $9,900,000 and the settlement of certain then - outstanding liabilities of GBE.  SPE paid $1,400,000 of the purchase price directly to the seller and we paid $8,500,000 to the seller. The acquisition was funded primarily by proceeds from our 2011 private placement (see Note 11 – Capital Stock). The following table summarizes the preliminary allocation of the purchase price to the assets acquired and liabilities assumed recognized at the acquisition date:

Recognized Amount of Identifiable Assets Acquired and Liabilities Assumed
Restricted Cash	$	6,675,487
Accounts receivable and other current assets		590,312
Prepaid land use fees		159,218
Property and equipment		4,594
Oil and Gas Property, accounted for using the full cost basis of accounting:
Evaluated property		9,953,334
Accounts payable and accrued expenses		(1,639,615	)
Asset retirement obligations		(5,843,330	)
Total Identifiable Net Assets	$	9,900,000

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During the year ended July 31, 2012, we determined that we could estimate a range of potential loss associated with an environmental liability at one of the properties we acquired when we acquired GBE (See Note 14 – Commitments and Contingencies). We adjusted the purchase price allocation for the purchase by increasing accounts payable acquired and oil and gas properties acquired by the amount that we recognized, $112,500 ($37,500 of the cost was recognized with the acquisition of SPE, thus a total of $150,000 is accrued for this contingency). The adjustment did not change the identifiable net assets acquired.

Acquisition-related costs

We incurred $2,617,099 of acquisition-related costs, such as due diligence and finders’ fees.  Acquisition-related costs include cash payments of $70,757. Additionally, we granted 636,585 shares of common stock to three individuals, as detailed in Note 11 – Capital Stock, as finders’ fees for their roles in the acquisition of GBE. The shares were valued, based on the closing stock price on the date of grant, at $2,546,342, which was recorded as a current period expense.

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.

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 include the results of the 100% acquired working interest.

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 SPE’s carrying value on the date of the acquisition and 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.  The transaction is intended to be structured, for tax purposes, as a tax-free merger, and as such, Duma would assume a carry-over basis in SPE’s assets. Consequently, a deferred tax liability was established.

The following table summarizes the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the acquisition date:

Recognized Amount of Identifiable Assets Acquired and Liabilities Assumed
Available for sale securities (1)	$	3,900,000
Oil and Gas Property, accounted for using the full cost basis of accounting
Evaluated property (2)		4,855,656
Accounts payable and accrued expenses		(37,500	)
Deferred tax liability (1)		(1,317,750	)
Asset retirement obligations (2)		(2,268,156	)
Total Identifiable Net Assets	$	5,132,250

(1) The Hyperdynamics common stock is valued, using the closing market price on the acquisition date, at $3.90 per share. SPE management believes its tax basis in Hyperdynamics common stock is $0.135 per share. Deferred taxes, therefore, are computed on the difference between the tax basis and the book basis per share at the corporate tax rate of 35%. If the carry-over basis is not available to Duma, there would be no book tax difference and no deferred taxes associated with the acquisition. If that occurs, the identifiable net assets would be $6,450,000 and there would be $0 deferred tax liability acquired.

(2) Oil and gas properties include the asset retirement obligations measured as of the effective date of the transaction, accrual for an environmental liability, and $2,550,000, which was the cash price that SPE paid to obtain its 25% working interest in the oil and gas properties and represents the fair value of the properties.

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Supplemental pro forma information (unaudited)

The unaudited pro forma results presented below for the years ended July 31, 2012 and 2011 have been prepared to give effect to the purchases described above as if they had been consummated on August 1, 2010.  The unaudited pro forma results do not purport to represent what our results of operations actually would have been if these acquisitions had been completed on such date or to project our results of operations for any future date or period.

	July 31,
	2012			2011
Revenues	$	7,313,232		$	6,794,781
Loss from operations		(7,419,747	)		(9,921,427	)
Net loss		(4,776,288	)		(11,330,501	)
Loss per share, basic and diluted		(0.47	)		(1.38	)

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.

The cost, unrealized gains (loss), and fair value of available for sale securities at July 31, 2012 were as follows:

Cost	$	1,056,528
Unrealized loss		(743,082	)
Fair Value	$	313,446

We have no securities that have been in an unrealized loss position for longer than 12 months.

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 purchased securities at a market price of $702,959. We reclassified $6,383 unrealized loss from other comprehensive loss into earnings during the year ended July 31, 2012.  Available for sale securities are re-measured at fair value at every reporting date.  (See Note 9 – Fair Value)

Note 4 – Oil and Gas Properties

Oil and natural gas properties as of July 31, 2012 and 2011 consisted of the following:

	July 31,
	2012			2011
Evaluated Properties
Costs subject to depletion	$	17,180,501		$	7,962,387
Accumulated Depletion		(1,557,675	)		(567,189	)
Total evaluated properties		15,622,826			7,395,198
Unevaluated properties		265,639			—
Net oil and gas properties	$	15,888,465		$	7,395,198

Evaluated properties

We incurred geological and geophysical costs of $162,460 during the year ended July 31, 2012.

In February 2011, we acquired a company that operates producing oil and natural gas properties and its related facilities in four fields located in Galveston Bay, Texas.  The transaction is more fully described in Note 2 – Acquisitions - Galveston Bay Energy, LLC.  During the current year, we adjusted the purchase price by $112,500 to reflect recognition of an estimate of the cost of soil remediation required to be completed at one of GBE’s facilities.  The remediation liability existed as of the date of acquisition.

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Immediately following our acquisition of GBE, we sold 25% of our own aggregate working interest in the Galveston Bay fields for $2,550,000 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 as described in Note 2 – Acquisitions - Galveston Bay Energy, LLC. In conjunction with its working interest purchase, SPE also assumed 25% of the asset retirement obligations associated with the properties. In accordance with the Full Cost accounting rules, this transaction was accounted for as a reduction of our oil and gas properties and no gain or loss was recognized.

During the year ended July 31, 2012, we conducted detailed field evaluations and, as a result, revised our estimate of asset retirement obligations associated with the Galveston Bay properties upward by $1,827,889.

In September 2011, we purchased SPE and thus re-acquired the 25% working interest in the Galveston Bay properties for $2,550,000, which represents SPE’s historical cost basis of the working interest and assumption of the then current asset retirement obligation of $2,268,156 and SPE’s share of the environmental liability, $37,500, as discussed in Note 2 – Acquisitions – SPE Navigation I, LLC.

GBE has interests in multiple leases with the State of Texas General Land Office in Galveston Bay.  With the acquisition of GBE, our primary operations are offshore in Galveston Bay.

In January 2012, we sold 50% of our working interest in a development well in Galveston Bay to several parties who assumed their share of costs and expenses.  There were $0 cash proceeds from this transaction.  After the sale, we owned a 25% interest in the well.   As of July 31, 2012 we have incurred approximately $1,667,986 in development costs for the drilling of this well. Drilling and completion results for the ST 9-12A #4 well have so far indicated that the well is not capable of commercial production.  We are conducting further analysis and will also review new 3D seismic data to corroborate and update the geological mapping. A final determination on the future utility of the well is not likely to be made until 2013.

On July 31, 2012, we purchased a pipeline that transports gas from one of our fields to shore.  The purchase price was $1 and assumption of the abandonment liability, which we estimated to be $97,374.  The assumed liability was recorded as an asset retirement obligation with an offsetting debit to oil and gas properties.

Onshore property

We own interests in properties in Louisiana, Texas, and Illinois.  As of July 31, 2012, our interests in these properties were as follows:

Illinois

As of July 31, 2010, we owned 100% working interest in multiple leases in or near Markham City, Illinois. In January 2011, we farmed out our Markham City North, Illinois prospect to Core Minerals Management II, LLC (“Core”).   Under the farmout agreement, we retained a 10% working interest and assigned the balance of our working interest in the Markham City prospect to Core.  Core became the operator of the property.  Our working interest is carried until Core meets the “Earnings Threshold” of $1,350,000.  Core will perform exploration activities on the prospect. Additionally, in June 2011, Core acquired two existing wells from another operator and has assigned a 10% working interest in both wells to Penasco.  One of the acquired wells will be used as a water injection well and the other will be used as a production monitor well.  The wells and lease that the wells are on are subject to the farmout agreement.  Finally, in July 2011, Penasco assigned a 90% working interest in multiple leases to Core and the leases that were assigned are subject to the farmout agreement.

In September 2011, Core commenced drilling of three wells, which were completed during the year ended July 31, 2012. As of July 31, 2012, the operator had expended approximately $1,156,182 towards the Earnings Threshold.  In accordance with our farmout agreement, we will be required to contribute our 10% working interest share toward the capital development of the area after the Earnings Threshold has been met.  We are currently responsible for our 10% working interest pertaining to routine operational expenses for completed wells.  If Core does not expend the entire Earnings Threshold by January 24, 2013, Core will reassign to us working interest equal to the proportion of the Earnings Threshold which up to that time it has not spent.  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%. In February 2012, the operator commenced a pilot waterflood project to re-pressurize the reservoir and enhance recovery of oil from the area. We are currently producing oil from in the project area as water is injected into the reservoir and results are being monitored.

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 is operated by a company owned by one of our officers.

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We own a 3% working interest in approximately 138 acres of an oil and gas lease (the “Janssen Lease”) located in Karnes County, Texas.

In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas.  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%.  We incurred land acquisition costs of $3,354 and drilling costs of $59,279 on this well.

In January 2012, we sold our working interest in an onshore salt water disposal well.  The buyer assumed the asset retirement obligation for the well and related facilities, $32,772.  We received $0 cash proceeds in conjunction with the sale. The assumed asset retirement obligation was the only consideration we received for this transaction.  In accordance with full cost rules, we recognized no gain or loss on the sale.

In February 2012, we purchased a non-operated working interest in mineral leases covering 200 acres onshore in Hardeman County, Texas.  The operator had commenced drilling in the area on January 28, 2012.  Our working interest in the lease area is 13.3% to the casing point of the first well drilled and 10.0% after the casing point of the initial well and for subsequent operations in the lease area.  Our net revenue interest in the prospect is 7.50%. The well encountered no natural fracturing in the native limestone of the target geological formation which greatly limited the productivity of oil in the well. All parties chose to abandon and plug the well. We incurred $72,793 of costs associated with the drilling of the well and $16,000 of land acquisition costs for this prospect.

Louisiana

We own a 6.25% overriding royalty interest in properties located in Franklin and Richland parishes in Louisiana (the “Holt” and “Strahan” properties). As of July 31, 2010, we held 97% working interest in the Holt property and 100% working interest in the Strahan property.  In November 2010, we sold our working interest in the Holt and Strahan properties for $100,000 and a retained overriding royalty interest of 6.25%. The buyer assumed the asset retirement obligation, which was $38,775, associated with the property. We executed a note receivable for the purchase price of $100,000.  The buyer will pay 5% of its production revenue, net of severance tax, until the balance is repaid.  We estimate the realizable value of the note as $50,000, based on the operating environment in the lease area and the time frame for projected collection.  The proceeds and the assumption of the asset retirement obligation were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.

As of July 31, 2011 and July 31, 2012, the balance on the note was $45,355. During the quarter ended April 30, 2012, we evaluated the collectability of the note receivable and determined that it should be reserved; accordingly we experienced a charge to bad debt expense of approximately $45,355.  Subsequent to the balance sheet date, we conveyed the overriding royalty interests to the operator and released the operator from any further liability of the note in exchange for $50,000 cash.

Unevaluated Properties

In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas.  We paid $58,805 in acquisition and land costs for our interest in this prospect. According to the terms of the agreement, we paid 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 will pay 25% of the costs before and after the casing point. We have paid $206,834 for the drilling and completion costs.  The well was drilled in June 2012; however, the first completion zone was non-economic.  During October 2012, we participated in a recompletion operation which resulted in the completion of the well into an upper zone.  Results of that completion are still pending. A pumping unit and related equipment are being installed.

During August 2012, we leased approximately 190 acres of land in Bee County, Texas called the Curlee Prospect.  The operator of the project will be Carter E&P, a company owned by our Chief Operating Officer.  The planned operation is the drilling of a new well on the leased area.  We have a 50% working interest in the project, 25% of which is carried to the casing point by the other participants in the 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, we will be responsible for 50% of the costs of the well.  As of November 3, 2012, the Curlee No. 1 well had been drilled and was plugged and abandoned.  Results from the Curlee No. 1 well are currently being evaluated for a possible second new drill well.

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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.  During the quarter ended January 31, 2011, the net book value of oil and gas properties exceeded the ceiling amount by $140,029 and, accordingly, an impairment charge was recorded.  As of 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.

Note 6 – Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2012 and 2011:

	2012			2011
Liability for asset retirement obligation, beginning of period	$	4,455,928		$	57,623
Asset retirement obligations assumed – see Notes 2 and 4		2,365,530			5,843,330
Asset retirement obligations sold – see Note 4		(32,772	)		(1,523,573	)
Asset retirement obligations incurred on properties drilled		1,389			—
Accretion		943,508			213,866
Revisions in estimated cash flows		1,827,889			—
Costs incurred		(178,539	)		(135,318	)
Liability for asset retirement obligation, end of period	$	9,382,933		$	4,455,928
Current portion of asset retirement obligation	$	549,796		$	468,500
Noncurrent portion of asset retirement obligation		8,833,137			3,987,428
Total liability for asset retirement obligation	$	9,382,933		$	4,455,928

Note 7 – Line of Credit

On March 17, 2011, GBE secured a one year revolving line of credit of up to $5,000,000 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 has also executed a parental guarantee of payment. As of July 31, 2011, the amount outstanding under the line of credit was $1,360,573.

During the year ended July 31, 2012, we repaid $1,360,573, the amount then outstanding on the line of credit. We were subsequently advanced $300,000. As of July 31, 2012, the amount outstanding under the line of credit was $300,000.

In May 2012, we modified the line of credit to remove the floor on the minimum interest rate and to extend the maturity date for the credit facility to August 15, 2012. The current interest rate is 4.25%.  In August 2012, the maturity date was extended to October 31, 2012.  The line of credit expired on October 31, 2012.  We have requested an extension of the line of credit through December 31, 2012.

We incurred $64,151 of loan origination fees which are being amortized straight line over one year, the original term of the loan.  We had amortized $24,027 and $40,124 during the years ended July 31, 2011 and 2012, respectively.  We had amortized a total of $64,151 as of the year ended July 31, 2012.

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Note 8 – Notes Payable

2010 Promissory Notes

We issued promissory notes for funds received from two private lenders of $20,000 and $25,000 during January 2011. The principal on the notes are due after one year and bear interest at 15% per annum payable on a quarterly basis.  During 2011 the notes and the accrued interest thereon were extinguished with the issuance of 18,654 shares of common stock valued, using the closing stock price on the date of the extinguishment, at $46,636.  Because the amount extinguished was less than the principal and accrued interest, we experienced a gain on this extinguishment of $1,013.

During the year ended July 31, 2011, we issued promissory notes for funds received from three directors, two of whom were also officers of Duma, for aggregate proceeds of $203,300.  In February 2011, we paid $13,577 of principal on the notes payable using common stock. During the year ended July 31, 2012, the remaining principal due to the then-current directors, $14,723, was paid in full. The notes are more fully described in Note 12 – Related Party Transactions.

On February 15, 2011, one of the lenders resigned as a director and officer of the company.  Accordingly, his outstanding $175,000 note payable was no longer classified as a related party debt. This note was repaid in full in November 2011.

Insurance Note Payable

In addition, we financed our commercial insurance program using a note payable in installments that include principal and interest of $20,384 per month for nine months.  The monthly payments include interest at an annual percentage rate of 4.95%.  At July 31, 2011, there was $80,596 remaining outstanding on this note.  In September 2011, we purchased additional financed insurance coverage which resulted in the addition of $18,667 to the note.  The installments payable on the note increased to $26,704, effective for the three remaining payments on the note. This note was paid in full during the year ended July 31, 2012.

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 are 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.

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. As of the year ended July 31, 2012, future maturities on the note were as follows:

Fiscal year ending:
2013	$	5,773
2014		6,186
2015		5,492
Total	$	17,451

Note 9 – Fair Value

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

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, 2011.

	Carrying Value at		Fair Value Measurement at July 31, 2011
	July 31, 2011		Level 1		Level 2		Level 3
Liabilities:
Derivative warrant liability	$	2,543,223		-	$	-	$	2,543,223

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

Beginning balance – July 31, 2011	$	2,543,223
Reduced for warrants exercised		-
Unrealized gain on changes in fair value of derivative liability		(1,217,835	)
Change in fair value of derivative liability		(1,217,835	)
At July 31, 2012	$	1,325,388

The change 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 following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the year ended July 31, 2011:

Beginning balance – July 31, 2010	$	1,502,700
Reduced for warrants exercised		(166,265	)
Unrealized loss on changes in fair value of derivative liability		1,206,788
Change in fair value of derivative liability		1,040,523
At July 31, 2011	$	2,543,223

The change in fair value was recorded as a reduction of the derivative liability and as an unrealized loss on the change in fair value of the liability in our statement of operations and an adjustment to paid-in capital for the exercise during the period of warrants classified as derivative liabilities.

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 are not afforded equity treatment because these warrants have a down-round ratchet provision on the exercise price. As a result, the warrants are not considered indexed to our own stock, and as such, the fair value of the embedded derivative liability is reflected on the balance sheet and all future changes in the fair value of these warrants will be 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 expire. 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 do 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.

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The following table provides the basis for the volatility curve used in the model:

Date of valuation	1 year			2 year			3 year			4 year			5 year
October 15, 2009 (Issuance of warrants to purchase 519,100 shares of common stock)		121	%		255	%		304	%		320	%		331	%
November 13, 2009 (issuance of warrants to purchase 241,200 shares of common stock)		219	%		272	%		284	%		300	%		350	%
April 12, 2010 (exercise of warrants to purchase 111,035 shares of common stock)		219	%		272	%		284	%		300	%		350	%
July 31, 2010 (year end remeasurement)		132	%		271	%		300	%		312	%		329	%
October 13, 2010 (exercise of warrants to purchase 34,800 shares of common stock)		132	%		271	%		300	%		312	%		329	%
July 31, 2011 (year end remeasurement)		134	%		192	%		301	%		329	%		341	%
July 31, 2012 (year end remeasurement)		134 - 135	%		N/A			N/A			N/A			N/A

The total fair value of the warrants issued during October 2009, amounting to $3,349,984, was recognized as a derivative liability on the date of issuance.  The fair value on the date of issuance includes the net cash proceeds from the sale of stock of $2,042,112, the value of accounts payable and debt settled of $310,000, and an unrealized loss as of the date of issuance of $997,872.

The exercise price of all the 241,200 warrants issued to investors, consultants, and for finders’ fees in November 2009 is subject to “reset” provisions in the event we subsequently issue common stock, stock warrants, stock options or convertible debt with a stock price, exercise price or conversion price lower than $8.75. If these provisions are triggered, the exercise price of all their warrants will be reduced.

The total fair value of the warrants issued during November 2009, amounting to $1,467,759, was recognized as a derivative liability on the date of issuance.  The fair value on the date of issuance includes net cash proceeds from the sale of stock of $1,016,750, the fair value of warrants granted to a consultant for business development services of $12,170, and an unrealized loss as of the date of issuance of $438,839.

In April 2010, the exercise price of the 760,300 derivative warrants issued during October and November 2009 was reduced from $8.75 to $5.75 per share.  These warrants are measured at fair value, with changes in fair value recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on derivative warrant liability.  Thus, the impact of the repricing is included in earnings as a part of the recurring measurement of the warrants’ fair value.

111,035 of the warrants classified as derivatives and issued during October 2009 were exercised during April 2010 for $638,450. This reduced the derivative liability by $702,229 and increased the additional paid-in capital by the same amount.

34,800 of the warrants classified as derivatives and issued during November 2009 were exercised during the year ended July 31, 2011 for $200,100. This reduced the derivative liability by $166,265 and increased the additional paid-in capital by the same amount.

The warrant agreement provides that the anti-dilution provisions expire three years after the issuance of the warrants.  Accordingly, the provision for 1,253,760 warrants expired on October 15, 2012 and November 13, 2012, respectively.  As of each those dates, the fair value of the warrant will be determined for a final mark to market adjustment and the outstanding warrant derivative liability will be reclassified to equity, as the warrants will no longer be derivatives.

Note 10 – Share Return and Settlement

As discussed in Note 2 – Acquisitions – Galveston Bay Energy, LLC, we granted 1,200,000 shares of common stock to Alan D. Gaines and Amiel David in part as compensation for bringing us the opportunity to make the GBE acquisition and in part as new director and officer compensation. 50% of shares vested that date and are valued at $2,400,000 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs.  However, Mr. Gaines and Mr. David returned the stock they received and forfeited the unvested stock when they separated from Duma in April 2011.

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The return of the 600,000 shares of Duma’s common stock held by Mr. Gaines and Mr. David in April 2011 was subject to a settlement agreement whereby they would receive:

Cash	$	1,043,750
Warrants to purchase 400,000 shares of common stock at an exercise price of $2.50 and a three year term		991,240
Fair value of cash and warrants received	$	2,034,990

Cash settlement involving unvested equity awards effectively vests the award; accordingly, we recognized additional compensation cost for the unvested shares of common stock on the date of the settlement agreement.  The stock was valued using the closing stock price on the settlement date.  The warrants were valued using the Black-Sholes option pricing model.  See Note 11 – Capital Stock – Warrants for the significant assumptions used to compute the fair market values of the warrants.

In summary, the transactions involving Mr. David and Mr. Gaines are recognized on the income statement as follows:

Transaction	Amount		Income statement recognition
Grant of 600,000 vested shares of common stock on February 15, 2011	$	2,400,000	Included in Acquisition-related costs
Expense associated with the settlement of 600,000 shares of previously unvested common stock on April 1, 2011		1,800,000	Share return and settlement
Total expense recognized	$	4,200,000

The fair value of the cash and warrants received in the settlement did not exceed the value of compensation associated with February 2011 stock award that was previously recognized as detailed above.  Thus, the cash and warrants did not result in additional expense. The cash settlement was debited directly to additional paid-in capital and the return of stock was credited to paid-in capital and debited to common stock.

Note 11 – Capital Stock

Share Capital

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, 2012 was 500,000,000 authorized common shares with a par value of $0.001 per share.

Common Stock Issuances

Stock issued for cash, net of share issuance costs, and for warrants exercised for cash:

During October 2010, an aggregate of 34,800 share purchase warrants were exercised for net proceeds of $200,100.  The warrants were derivative warrants; accordingly, the warrant derivative liability associated with these warrants as of the date of exercise, $166,265 was reclassified to paid-in capital.

During February 2011, we completed a private placement in which we sold 3,695,600 shares of common stock for $2.50 per share to raise gross proceeds of $9,239,000 (the “2011 private placement”). We paid $142,800 in cash offering costs as finders’ fees and $63,581 in associated legal costs, resulting in net cash proceeds of $9,032,619. In conjunction with this placement, we granted equity-based compensation for finders’ fees as follows:

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Award	Exercise Price		Term (years)		Fair value		Valuation method
60,000 shares of common stock		N/A		N/A	$	240,000	closing stock price on the date of grant
Warrants to purchase:
52,000 shares of common stock	$	2.50		3		177,506	Black-Sholes option pricing model
5,120 shares of common stock	$	2.50		3		15,108	Black-Sholes option pricing model
Total equity-based finders’ fees					$	432,614

All costs associated with this transaction, including the shares and warrants granted as finders’ fees, were recorded as a reduction in the private placement proceeds, and reflected as an adjustment to equity.

The 2011 private placement triggered the anti-dilution provisions of units we had previously sold in October and November 2009.  The investors involved in the previous capital raise received 710,000 shares of common stock in accordance with these provisions.  

Stock issued for services and for investor relations:

During the year ended July 31, 2011, we issued 20,000 shares of common stock to consultants for services valued at $82,008.  The shares were valued using the closing market price on the date of grant.

We granted 636,585 shares of common stock to three individuals, as detailed below, as finders’ fees for their roles in the acquisition of GBE (See Note 2 – Acquisitions – Galveston Bay Energy, LLC).  The shares were valued, based on the closing stock price on the date of grant, at $2,546,342. 600,000 of the shares granted were later returned to us as described in Note 10 – Share Return and Settlement.

● On February 15, 2011, we granted 36,585 shares of common stock to a consultant for his role in bringing us the opportunity to make the acquisition.  The shares were valued at $146,341 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs.

● On February 15, 2011, we granted 600,000 shares of common stock to Alan D. Gaines in part as compensation for bringing us the opportunity to make the acquisition described above and in part as new director and officer compensation. 50% of shares vested that date and are valued at $1,200,000 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs.  The remaining shares were scheduled to vest as follows: 150,000 on February 15, 2012 and 150,000 on February 15, 2013.  However, Mr. Gaines returned the stock he received and forfeited the unvested stock when he separated from Duma in April 2011.

● On February 15, 2011, we granted 600,000 shares of common stock to Amiel David in part as compensation for bringing us the opportunity to make the acquisition described above and in part as new director and officer compensation. 50% of shares vested on that date and are valued at $1,200,000 based on the closing stock price on the grant date and recorded in expense as acquisition-related costs. The remaining shares were scheduled to vest as follows: 150,000 on February 15, 2012 and 150,000 on February 15, 2013.  However, Mr. David returned the stock he received and forfeited the unvested stock when he separated from Duma in April 2011.

We settled accounts payable and notes payable due to related parties, as discussed below.  Because the fair value of the stock issued exceeded the outstanding debt, we recognized $26,616 as compensation.

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.

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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.

For debt:

During February 2011, we settled accounts payable to consultants totaling $129,375 with the issuance of 51,750 shares of common stock.  The fair value of the stock, as determined using the closing stock price on the date of grant, was $181,127; the excess fair value over the outstanding debt, which was recognized as a loss on settlement of accounts payable, was $51,750.

During April 2011, we settled accounts payable to a consultant and notes payable (See Note 8 – Notes Payable) totaling $51,174 with the issuance of 20,064 shares of common stock.  The fair value of the stock, as determined using the closing stock price on the date of grant, was $50,162; the outstanding debt exceeded fair value by $1,013 and was recognized as a gain on settlement of accounts payable.

For debt – related party:

During February 2011, we settled accounts payable to officers and directors and $13,577 of principal on notes payable to officers totaling $66,539 with the issuance of 26,616 shares of common stock.  The fair value of the stock, as determined using the closing stock price on the date of grant, was $93,155; the excess fair value over the outstanding debt, which was recognized as additional compensation costs, was $26,616.

During April 2011, we settled accounts payable to officers and directors totaling $95,290 with the issuance of 38,116 shares of common stock.  The fair value of the stock, as determined using the closing stock price on the date of grant, was $95,290.

For the Acquisition of SPE:

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. (See Note 2 – Acquisitions – SPE Navigation I, LLC).

Deemed dividend:

Our 2011 capital raise triggered the anti-dilution provisions of the units previously sold in October and November 2009.  The investors involved in the previous capital raise received 710,000 shares of common stock in accordance with these provisions.  The value of the shares that were issued, based upon the closing stock price on the date of issuance, was $2,840,000 and was treated as a deemed dividend.

Share return and settlement

In April 2011, two individuals returned 600,000 shares that had been issued in conjunction with the acquisition of GBE as part of a settlement that is described in Note 10 – Share Return and Settlement.  The settlement resulted in additional expense of $756,250.

Stock Compensation Plans

Duma may grant up to 1,600,000 shares of common stock under several historical stock-based compensation plans (the “Plans”). During April 2011, the Board of Directors authorized and approved the adoption of the 2011 Stock Incentive Plan (the “2011 Plan”). An aggregate of 1,000,000 shares of our common stock may be issued under the 2011 Plan. During August 2010, the Board of Directors authorized and approved the adoption of the 2010 Stock Incentive Plan (the “2010 Plan”). An aggregate of 200,000 shares of our common stock may be issued under the 2010 Plan. An aggregate of 400,000 of our shares may be issued under the 2009 Re-Stated Stock Incentive Plan (the “2009 Plan”).  The Plans are 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.

For the years ended July 31, 2012 and 2011, compensation expense associated with option grants was $687,770 and $466,409, respectively.  In addition, we granted stock valued at $27,703 and $2,654,551, respectively, as described above.

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.  We will continue to use a peer group until we have sufficient trading history to determine our own historical volatility.

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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.

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:

	2012	2011
Risk-free interest rate	0.12% - 1.66%	0.18%-2.79%
Dividend yield	0%	0%
Volatility factor	135%-148%	138%-153%
Expected life (years)	1-6.5 years	1-6.5 years

Options granted to non-employees

The following table provides information about options granted to non-employees under our stock incentive plans during the years ended July 31, 2011 and 2012:

	2012		2011
Number of options granted (1)		-		596,000
Compensation expense recognized	$	424,569	$	313,284
Weighted average exercise price of options  granted	$	N/A	$	2.50

(1)      Excluding those options deemed re-issued in the repricing discussed below

No options were granted to non-employees during the year ended July 31, 2012.

Based on the fair value of the options as of July 31, 2012, there was $348,690 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 date the performance is complete.

A summary of the grants made during the year ended July 31, 2011 and which are being earned, and accordingly revalued, during the year ended July 31, 2012 follows:

· In April 2011, options to purchase 500,000 shares of common stock with an exercise price of $2.50 per share and a term of ten years were granted to an officer and director of the company.  The options vest 20% each six months over the 30 months following the award.

· In April 2011, options to purchase 40,000 shares of common stock with an exercise price of $2.50 per share and a term of ten years were granted to a director who also provides consulting services to us.  The options vest 20% each six months over the 30 months following the award.

· In August 2010, options to purchase 56,000 shares of common stock with an exercise price of $5.00 per share and a term of three years were granted to one of our officers.  The options vest 25% each six months over the 18 months following the award with the first 25% or 14,000 shares vesting immediately.  During April 2011, the option exercise price was reduced to $2.50 per share.

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· In November 2009, options to purchase 4,000 shares of common stock with an exercise price of $5.00 per share and a term of three years were granted to a consultant as a signing bonus.  The fair value of the options was $31,445.  The options vest 25% each six months over the 24 months following the award.  The expected term of the options, computed using the simplified method, was two years. During April 2011, the option exercise price was reduced to $2.50 per share.

· In November 2009, options to purchase 100,000 shares of common stock with an exercise price of $5.00 per share and a term of three years were granted to our new CEO.  The initial fair value of the options was $770,020.  Options to purchase 25,000 shares (25% of the award) vested immediately; the remaining options vested 25% each six months over the following 18 months.  The expected term of the options that vested immediately, computed using the simplified method, was two years.  The expected term of the options with graded vesting, computed using the simplified method, was 2.125 years. During April 2011, the option exercise price was reduced to $2.50 per share.

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, 2011 and 2012:

	2012		2011
Number of options granted		-		260,000
Compensation expense recognized	$	263,201	$	64,366
Weighted average exercise price of options  granted	$	N/A	$	2.50

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, 2012, we had $314,721 in unamortized compensation expense associated with options granted to employees.

During the year ended July 31, 2012, we granted no options to employees.

Option Repricing

During April 2011, the Board of Directors approved the repricing of all of the then outstanding options to $2.50 per share.  On the date of the repricing, options to purchase 301,200 shares were outstanding.  The modification was accounted for as a cancellation of the original grant and a new award.  The fair value of the modification was computed by comparing the fair value of the options immediately prior to the award with their original terms to the fair value of the repriced options.  At the time of the repricing, options to purchase 246,200 shares were vested.  The expense associated with the modification of these options, $88,759, was recognized in expense on the date of the repricing.  The remaining options to purchase 55,000 shares were granted to non-employees and an estimate of the fair value of the modified grant will be recognized at each reporting date with an adjustment to the estimate as of the vesting date to reflect the current fair value.

The following table details the significant assumptions used to compute the effects of the repricing:

	Risk-free interest rate			Dividend yield			Volatility factor			Expected life (years)
94,000 options with an exercise price of $8.75 per share and remaining expected term of 3 years		2.14	%		0.00	%		150.23	%		3
47,204 options with an exercise price of $8.75 per share and remaining expected term of 4 years		2.14	%		0.00	%		139.20	%		4
77,000 options with an exercise price of $5.00 per share and remaining expected term of 1 year		2.14	%		0.00	%		150.23	%		1

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Summary information regarding stock options issued and outstanding as of July 31, 2012 is as follows:

	Options			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2010		348,200		$	7.50	$	20,000		5.40
Granted		1,157,200			2.50
Exercised		-			-
Expired		(404,200	)		7.25
Outstanding at year ended July 31, 2011		1,101,200			2.50	$	1,101,200		8.14
Granted		-			-
Exercised		-			-
Expired		(57,200	)		2.50
Outstanding at year ended July 31,2012		1,044,000		$	2.50	$	-		7.22

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

Options outstanding and exercisable as of July 31, 2011:
Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		800,000	9.73 years		-
	2.50		47,200	7.81 years		47,200
	2.50		94,000	5.93 years		94,000
	2.50		56,000	2.05 years		28,000
	2.50		104,000	1.33 years		103,000
			1,101,200			272,200

Warrants

We issued or modified the following warrants during the year ended July 31, 2011:

With equity:

We issued a total of 457,120 warrants for services: warrants to purchase 57,120 shares of common stock at an exercise price of $2.50 per share for finders’ fees in connection with our 2011 private placement as discussed above and warrants to purchase 400,000 shares of common stock at an exercise price of $2.50 per share as a part of the share return and settlement discussed in Note 10.  The warrants were valued using the Black-Sholes option pricing model.�� The following table details the significant assumptions used to compute the fair market values of the warrants granted:

	Finders’ Fees	Share return and settlement
Risk-free interest rate	1.22%-1.41%	.61%
Dividend yield	0%	0%
Volatility factor	150.78-151.24%	150.43
Expected life (years)	3 years	3 years

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Additionally, the 2011 private placement triggered the anti-dilution provisions of previously issued warrants.  The exercise price of the warrants issued with these units decreased to $2.50 per share and the warrant holders received warrants to purchase an additional 639,295 shares of common stock.  The additional warrants received in this transaction contain the same price reset provision as the original warrants and accordingly are derivative warrants as more fully described in Note 9 – Fair Value - Derivative Warrant Liability.

Warrants granted to related party

On February 15, 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. We amended this agreement effective on March 9, 2011.  Geoserve will provide investor relations services.  The agreement has a three year term. The consulting agreement as amended provides that we will compensate Geoserve with warrants to purchase 800,000 shares of common stock at an exercise price of $2.50 per share with a five year term (expiring February 15, 2016) as prepayment for the first year of service.  We may terminate the agreement after the first year with thirty days’ notice. On February 15, 2011, the first tranche of warrants to purchase 800,000 shares of common stock vested. We estimated the fair value of the warrants using the Black-Scholes option pricing model with an expected life of five years, a risk free interest rate of 2.35%, a dividend yield of 0%, and an expected volatility of 134.26%.  We recognized $2,885,807, the fair value of the vested warrants, as consulting expense – related party in year ended July 31, 2011.

If our common stock attains a five day average closing price of $7.50 per share, an additional 600,000 warrants with an exercise price of $2.50 and an expiration date of February 15, 2016 shall be issued (“Warrant B”). If our common stock attains a five day average closing price of $15.00 per share, an additional 600,000 warrants with an exercise price of $2.50 and an expiration date of February 15, 2016 shall be issued (“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, 2011 and 2012:

	2012		2011
Fair Value of Warrant B	$	177,150	$	355,072
Fair Value of Warrant C	$	139,491	$	188,691
Compensation expense recognized	$	189,372	$	79,752

Summary information regarding common stock warrants issued and outstanding as of July 31, 2012, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2010		943,958		$	10.50		-		3.02
Granted		3,096,415			2.50		-		-
Exercised		(34,800	)		2.50		-		-
Expired		(247,118	)		23.00		-		-
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

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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

Warrants outstanding and exercisable as of July 31, 2011:

Exercise Price		Outstanding Number of Shares		Remaining Life	Exercisable Number of Shares
$	2.50		2,000,000	4.55 years		800,000
	2.50		1,253,757	3.21 years		1,253,757
	2.50		400,000	2.67 years		400,000
	2.50		5,120	2.58 years		5,120
	2.50		52,000	2.55 years		52,000
	10.00		37,578	1.15 years		37,578
	6.25		8,000	1.09 years		8,000
	25.00		2,000	1 year or less		2,000
			3,758,455			2,558,455

Note 12 – Related Party Transactions

A company controlled by one of our officers operates our Barge Canal properties. 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, 2012		Year Ended July 31, 2011
Revenue generated from Barge Canal properties	$	569,476	$	458,959
Lease operating costs incurred from Barge Canal properties	$	181,113	$	176,096
Overhead costs incurred	$	25,087	$	21,456
Outstanding accounts receivable at period end	$	74,972	$	69,880
Outstanding accounts payable at year end	$	-	$	-

Subsequent to the balance sheet date, we entered into a joint operating agreement under which this company will operate a leased area we obtained in Bee County, Texas (the Curlee prospect).

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 discussed in Note 4 – Oil and Gas Properties.  As of July 31, 2012, these parties owed $42,646 in billed and unbilled joint interest billings.

From time to time, officers, directors, and family members of officers and directors have loaned us funds.  The following table provides a summary of related party debt outstanding as of:

	July 31, 2012		July 31, 2011
Note payable to a director, interest rate 6% per annum, due on demand after February 2011	$	-	$	6,423
Note payable to an officer and director, interest rate 6% per annum, due on demand after February 2011		-		8,300
Notes payable to related parties	$	-	$	14,723

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Additionally, one of our directors loaned us $185,000 during November and December 2010.  This director resigned in February 2011 and his outstanding debt at the time of his resignation, $175,000, was classified as a non-related party note payable.  The note was repaid during the year ended July 31, 2012.

In February 2011, we settled $13,577 of the outstanding notes payable to two of the then related parties with the issuance of 135,769 shares of common stock using a conversion rate of $0.10 per share. The stock was valued using the closing stock price on the transaction date at $19,006; the excess fair value of $5,429 was recorded as compensation expense.

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 11 – Capital Stock.  The contract permits us to terminate the agreement after the first year with thirty days notice.  We recognized expense of $2,929,550 and 189,372 from this contract during the years ended July 31, 2011 and 2012, respectively.

We also sold 25% of the working interest we acquired when we acquired Galveston Bay Energy, LLC for a different company, SPE Navigation I, LLC, controlled by Mr. Watts (See Note 2 – Acquisitions and Note 4 – Oil and Gas Property).  As of July 31, 2011, SPE owed us $213,866 in joint interest receivables and we owed $497,108 of revenue payable to SPE. During the year ended July 31, 2012, we remitted $282,052 to SPE in conjunction with these balances. During the year ended July 31, 2012, we purchased SPE for 3,799,998 shares of Duma common stock, as described in Note 2 - Acquisitions.

Note 13 - Income Taxes

Our net loss before income taxes totaled $(5,700,195) and $(10,285,243) for the years ended July 31, 2012 and 2011, respectively.

We recognized an 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 exist 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,
	2012			2011
US statutory federal rate		35.00	%		35.00	%
State income tax rate		.58	%		.58	%
Equity-based compensation		(36.43	)%		(24.45	)%
Gain (loss) on derivative warrants		7.60	%		(5.25	)%
Gain on sale of securities		(21.15	)%		—	%
Other		4.02	%		(.23	)%
Acquired deferred tax liability		23.12	%		—	%
Net operating loss		6.92	%		(5.65	)%
		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.

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Components of deferred tax assets as of July 31, 2012 and 2011 are as follows:

	July 31,
	2012			2011
Stock based compensation	$	292,509		$	1,189,058
Property, including depreciable property		(2,070,809	)		(987,913	)
Asset retirement obligation		3,312,358			1,559,575
Net operating loss carry-forward		2,530,532			1,258,483
Other		318,032			220,103
		4,382,622			3,239,306
Valuation allowance for deferred tax assets		(4,382,622	)		(3,239,306	)
	$	—		$	—

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, 2012 will significantly increase or decrease within 12 months.

Generally, our income tax years 2009 through 2012 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, 2012, we had approximately $7,113,232 of U.S. federal and state net operating loss carry-forward (“NOLs”) available to offset future taxable income, which begins expiring in 2026, 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 will be an estimated $239,600.

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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Note 14 - 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.

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.  As of July 31, 2011, we had determined that it was probable that remediation would be required and we were evaluating the extent of the contamination, the activities that will be required to perform the remediation, and whether the former owner would be required to assume the remediation.  As of July 31, 2011, we concluded that the cost of the remediation was not estimable and, accordingly, it was not reflected in our financial results.

During the year ended July 31, 2012, we continued evaluation of the site and concluded that we could reasonably estimate a range of potential cost. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $500,000.  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.  $150,000 has been recognized and is included in the balance sheet caption Accounts payable and accrued expenses.  Because the liability was acquired with the acquisitions, we have adjusted the cost of acquired oil and gas properties to reflect the estimate of loss.

Commitments

We have the following contract obligations:

In June 2011, we entered into a consulting agreement with a company controlled by our former CFO. Under the terms of the agreement, the former CFO will provide business services for a term of one year and will receive $8,000 per month.  The contract provided for an automatic renewal at the end of the first year.  The contract also permits us to terminate it with three months’ notice.  The contract renewed in June 2012 and we later provided notice of termination; accordingly, this contract terminates on December 31, 2012.

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 July 2011, we signed a new lease for office space in Corpus Christi, Texas. Our scheduled rent is $3,199 per month and the lease term is 3 years.

Rent expense during the years ended July 31, 2012 and 2011 was $117,392 and $67,737, 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,

	2013		2014		2015		Total
Operating leases	$	119,265	$	100,848	$	-	$	220,113
Line of credit		312,375		-		-		312,375
Notes payable		105,116		6,804		5,670		117,590
Total	$	536,756	$	107,652	$	5,670	$	650,078

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. 

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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 $240,000 issued by Green Bank.  We pay a 1.5% per annum fee in conjunction with these letters of credit. These letters of credit are collateralized by a certificate of deposit held with the bank for the same amount. During June 2011, we had prepaid the first year’s interest on the letter of credit and amortized the interest cost through June 2012.  We currently prepay and amortize the fees due quarterly. As of the year ended July 31, 2012, we had prepaid $25,163 towards the quarterly fee. Subsequent to the year ended July 31, 2012, we prepaid an additional amount of $27,962. The prepaid interest will be amortized on a straight line basis.

Note 15 – 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, 2012, we have reserved approximately $1,302 for potentially uncollectable other receivables.

Other current assets

Other current assets consisted of the following:

	At July 31,
	2012		2011
Line of credit origination fees	$	-	$	42,019
Prepaid letter of credit fees		16,567		92,773
Prepaid insurance		178,471		132,482
Prepaid rent		10,164		-
Cash call paid to operator		23,234		-
Prepaid land use fees		19,852		25,699
Accrued interest income		8,389		-
Total other current assets	$	256,677	$	292,973

Property and Equipment

Property and equipment consisted of the following:

		at July 31,
	Approximate Life	2012			2011
Furniture and fixtures	5 years	$	7,604		$	10,804
Marine vessels	5 years		17,614			17,614
Vehicles	5 years		18,027			-
Computer equipment and software	2 years		39,296			5,597
Total property and equipment			82,541			34,015
Less accumulated depreciation			(36,572	)		(11,158	)
Net book value		$	45,969		$	22,857
Depreciation expense		$	31,495		$	3,534

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Accounts payable and accrued expenses

Accounts payable and accrued expenses consisted of the following:

	At July 31,
	2012		2011
Trade payables	$	1,950,768	$	943,320
Accrued payroll		40,000		84,256
Revenue payable		6,690		567,367
Local taxes and royalty payable		108,948		81,873
Federal income taxes payable		192,432		-
Total accounts payable and accrued expenses	$	2,298,838	$	1,676,816

Note 16 – Subsequent Events

In August 2012, we sold our remaining interests in oil and gas property in Louisiana.  We also leased acreage in Bee County, Texas known as the Curlee prospect. A company owned by one of our officers will operate the property.  Our recent oil and gas activities are described in Note 4 – Oil and Gas Properties.

During September and October 2012, we sold available for sale securities with a cost basis of $607,201 for cash proceeds of $145,237.

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 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 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.  We have entered into a joint operating agreement with Hydrocarb Namibia effective August 29, 2012, that covers operations for the Concession.

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 former owners of NEI are companies owned and controlled by the CEO and his brother-in-law and the CEO’s father-in-law.

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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 any Fee under the Consulting Agreement which will commence 30 calendar days from the date that any Fee or portion of Fee is due, which may only be paid in cash. Duma has not yet paid the first installment as described in(a) above.

Because the concession involves unproved property, the transaction will be accounted for as an asset purchase.

Note 17 – 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, 2012 and 2011 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 $95.07 and $90.41 per barrel, respectively. The gas price as of July 31, 2012 and 2011 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 $3.02 and $4.19 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, in on-shore and off-shore Texas and on-shore Louisiana.

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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, 2010		97,150			163,240			746,140
Revisions of previous estimates		10,547			90,277			153,559
Purchase of reserves in place		1,562,974			16,489,482			25,867,326
Sale of reserves in place		(423,541	)		(4,122,370	)		(6,663,616	)
Production		(28,180	)		(59,539	)		(228,619	)
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

	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

	Proved Reserves as of July 31, 2011
	Oil (Barrels)		Gas (MCF)		Total (MCFE)
Proved developed producing		248,470		864,840		2,355,660
Proved developed non-producing		226,860		3,734,340		5,095,500
Proved undeveloped		743,620		7,961,910		12,423,630
Total Proved reserves		1,218,950		12,561,090		19,874,790

The reserves in this 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. All oil and gas properties are located in the United States of America.

	2012			2011
Unevaluated properties	$	265,639		$	-
Evaluated properties		17,553,836			8,335,722
Less impairment		(373,335	)		(373,335	)
		17,446,140			7,962,387
Less depreciation, depletion, and amortization		(1,557,675	)		(567,189	)
Net capitalized cost	$	15,888,465			7,395,198

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Costs Incurred in Oil and Gas Activities

All costs incurred associated with oil and gas activities were incurred in the United States of America. Costs incurred in property acquisition, exploration and development activities were as follows.

	2012			2011
Property acquisition
Unproved	$	74,805		$	118,803
Proved		6,988,447			9,867,137
Exploration		420,200			284,570
Development		2,033,073			36,394
Cost recovery		(32,772	)		(4,398,573	)
Total costs incurred	$	9,483,753		$	5,908,331

Costs Excluded

Our excluded costs relate to a project onshore in Texas, the Chapman Ranch prospect. As of July 31, 2012, the well had been drilled but not completed.  The well is currently in the process of completion and testing.  We anticipate including the excluded costs in the amortization base within the next fiscal year.

Costs Excluded by Year Incurred

	As of July 31, 2012
Property Acquisition	$	58,805
Exploration		206,834
Total	$	265,639

Changes in Costs Excluded by Country

	United States
Balance at July 31, 2010	$	734,533
Additional Cost Incurred		217,098
Cost Recovery		(200,000	)
Costs Transferred to DD&A Pool		(751,631	)
Balance at July 31, 2011		-
Additional Costs Incurred		265,639
Costs Transferred to DD&A Pool		-
Balance at July 31, 2012	$	265,639

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

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● 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.

The Standardized Measure is as follows:

	2012			2011
Future cash inflows	$	200,741,090		$	172,677,470
Future production costs		(60,998,060	)		(48,521,190	)
Future development costs		(48,640,439	)		(27,834,490	)
Future income tax expenses		(31,885,907	)		(33,712,626	)
Future net cash flows		59,216,684			62,609,164
10% annual discount for estimated timing of cash flows		(25,552,798	)		(26,492,946	)
Future net cash flows at end of year	$	33,663,886		$	36,116,218

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, 2012:

	2012			2011
Standardized measure of discounted future net cash flows at beginning of year	$	36,116,218		$	1,748,629
Net changes in prices and production costs		(3,316,394	)		9,808,683
Changes in estimated future development costs		(10,006,008	)		(93,997	)
Sales of oil and gas produced, net of production costs		(3,152,150	)		(1,757,237	)
Discoveries and extensions		54,414			—
Purchases of minerals in place		16,662,628			62,840,899
Sales of minerals in place		(2,042,655	)		(18,720,719	)
Revisions of previous quantity estimates		(6,669,453	)		553,357
Development costs incurred		1,085,180			—
Change in income taxes		1,320,486			(19,447,193	)
Accretion of discount		3,611,622			1,183,796
Standardized measure of discounted future net cash flows at year end	$	33,663,886		$	36,116,218

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

		2012			2011
Net revenues from production		$	7,165,233		$	3,412,791
Expenses
Oil and gas operating			4,013,083			1,698,191
Impairment			-			140,029
Accretion			943,508			213,866
Operating expenses			4,956,591			2,052,086
Depreciation, depletion and amortization			990,486			304,851
Total expenses	��		5,947,077			2,356,937
Income (loss) before income tax			1,218,156			1,055,854
Income tax expenses			(426,355	)		(369,549	)
Results of operations		$	791,801		$	686,305
Depreciation, depletion and amortization rate per net equivalent MCFE		$	1.68		$	1.33

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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, 2012, 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. Based on that evaluation, we concluded that, as at July 31, 2012, 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) inadequate entity level controls due to: (i) weak tone at the top to implement an effective control environment, and (ii) ineffective audit committee due to a lack of a majority of independent members (1 of 3) on the audit committee and a lack of a majority of outside directors on our board of directors as of July 31, 2012; (2) inadequate segregation of duties consistent with control objectives; (3) insufficient written policies and procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements; and (4) insufficient controls and procedures governing the formulation of certain estimates required to prepare financial statements in conformity with accounting principles generally accepted in the United States of America; specifically (i) a lack of understanding on the part of operational personnel of the relevance of facts and circumstances in the field that would require accounting recognition or disclosure, (ii) a lack of communication between accounting and operational personnel regarding such facts and circumstances, and (iii) limited staffing that has exacerbated the process of gathering information about such facts and circumstances and providing the appropriate accounting and disclosure.

Management believes that the material weaknesses set forth in items (2) and (3) above did not have a material adverse effect on our financial results for the year ended July 31, 2012. However, we believe that the material weaknesses in entity level controls set forth in item (1) results in ineffective oversight in the establishment and monitoring of required internal controls and procedures, which could result in a material misstatement in our financial statements in future periods.  Additionally, item (4) resulted in the misstatement of our asset retirement obligations in the preliminary financial statements for the year ended July 31, 2012.  The misstatement was corrected prior to the completion of the financial statements.

We are committed to improving our financial organization. As part of this commitment, as of the date of this report, we have i) appointed two outside directors to our board of directors who were appointed to our audit committee resulting in a fully functioning audit committee who will undertake the oversight in the establishment and monitoring of required internal controls and procedures such as reviewing and approving estimates and assumptions made by management and ii) prepared and implemented some of the written policies and checklists which will set forth procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirement.  We plan to continue improving our internal controls.  When resources become available to us we will i) expand our personnel to improve segregation of duties consistent with control objectives, ii) continue to prepare and implement sufficient written policies and checklists which will set forth procedures for accounting and financial reporting with respect to the requirements and application of accounting procedures generally accepted in the United States of America and SEC disclosure requirements, and iii) support training and continuing education for all of our professionals so that they can remain current on regulatory developments and accounting and disclosure requirements.

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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

There have been no changes in our internal control over financial reporting during our fourth quarter of our fiscal year ended July 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION

Not applicable.

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	35	President, Chief Executive Officer, Chairman and a director
Sarah Berel-Harrop	45	Secretary, Treasurer and Chief Financial Officer
Leonard Garcia	62	Director
Steven L. Carter	53	Vice President of Operations and a director
John E. Brewster, Jr.	61	Director
S. Chris Herndon	52	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, President, Chief Executive Officer, Chairman 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.  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 15 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 present, she has been Duma Energy Corp.’s Controller. 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.

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Leonard G. Garcia

Mr. Garcia has been a director since April 17, 2006 and has served as our Land Manager from February 2006 to the present date. In addition, Mr. Garcia served as our President and Chief Executive Officer from April 17, 2006 until August 5, 2007. From August 2004 to the present date, Mr. Garcia has also served as the Land Manager for Uranium Energy Corp., a uranium company that has been publicly traded on the NYSE MKT Equities Exchange since September 2007. Mr. Garcia is an Independent Petroleum Landman with over thirty years of experience in oil and gas title research, lease negotiations and acquisitions, contracts, exploration and production. Prior to August 2004, Mr. Garcia worked under contract for various companies, including Harkins & Co., Sun Oil Company, Oryx Energy Co., Texaco, Monsanto Exploration and Production Company, Trans Texas Energy, Kerr-McGee Oil & Gas Corp., and Mestena Oil & Gas. His corporate experience includes serving as Chief Executive Officer of Texas corporations with annual sales in excess of eighteen million dollars. Mr. Garcia attended the University of Texas-Austin, The University of Texas-Pan American and Texas A&M University-Kingsville. He currently resides in Austin, Texas.

Steven L. Carter, Vice President of Operations

Mr. Carter has served as our Vice President of Operations since December 20, 2006 and as a director since July 2010. Mr. Carter is a registered professional engineer with thirty years of management and engineering experience in oil and gas exploration, production operations, reservoir management and drilling. Mr. Carter served as Operations Manager and Operations Engineer for T-C Oil Company from 1990 to June 2003, where he managed significant production, supervised drilling, provided economic evaluations and designed project workovers, as well as performing numerous other engineering services. In July 2003, Mr. Carter started Carter E&P, LLC, an independent oil and gas company, where he has worked from 2003 to the present. Mr. Carter has a B.S. in Petroleum Engineering from the University of Texas at Austin.

John E. Brewster, Jr., Director

Mr. Brewster has been a director since October 11, 2012.  Mr. Brewster is a distinguished oil and gas professional with an extensive and diversified background covering more than 36 years. Currently, Mr. Brewster serves as an independent consultant and attorney to various clients within the energy sector. Beginning in 1975, Mr. Brewster served as legal counsel for the Oklahoma Securities Commission, a state agency with oversight for securities registration and enforcement in Oklahoma. From 1977 to 1980, Mr. Brewster served as Vice President and Exploration Coordinator for Santa Fe Minerals, Inc. and was on the Board of Directors of Santa Fe Coal Company. From 1980 to 1984, Mr. Brewster served on the Board of Directors and was Executive Vice President and Chief Operating Officer for Odyssey Energy, Inc. In 1984, Odyssey Energy was sold to Trafalgar House plc. From 1984 to 1987, Mr. Brewster served as Chief Executive Officer and a director of Trafalgar House Oil and Gas Inc. From 1987 to 1993, Mr. Brewster was General Partner of Moffett & Brewster, a private firm whose primary focus was the acquisition of mineral estates and royalty interests for industry partners and institutional clients. From 1993 to 1997, Mr. Brewster was a consultant to Voyager Energy Corp., which later merged with Howell Corporation, a NYSE-listed E&P company where Mr. Brewster served as Vice President of Corporation Development & Planning from 1997 to 2002. Howell was acquired by Anadarko Petroleum Corporation in 2002. Mr. Brewster also served on the Board of Directors of Western Gas Resources, Inc. (NYSE:WGR) from 2005 to 2006, prior to its sale to Anadarko Petroleum Corporation.

Mr. Brewster is a graduate of Southern Methodist University, where he earned his Juris Doctorate (JD), Master of Business Administration (MBA), and Bachelor of Business Administration (BBA) degrees. He is a member of the State Bar of Texas and numerous oil and gas industry associations.

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.

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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 Operations Manager, 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, comprised of Leonard Garcia, John Brewster and S. Chris Herndon.  The Audit Committee operates pursuant to a charter adopted by the board.

Mr. Garcia, Mr. Brewster and Mr. Herndon are “independent” directors 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

There are no family relationships among our directors and officers.

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;

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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.

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.

A copy of our Code of Conduct is incorporated by reference to our Form 10-K for the fiscal year ended July 31, 2009.

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, 2012, except as follows:

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Name	Number of forms  filed late	Number of  transactions  reported late
Jeremy Driver	4	21
Leonard Garcia	2	2
Steven Carter	1	2
CW Navigation Inc.	5	24
KW Navigation Inc.	5	21

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, 2012 and 2011:

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)	2012	188,462	Nil	Nil	Nil	Nil	Nil	Nil	188,462
	2011	104,364	Nil	Nil	31,239	Nil	Nil	Nil	135,603
Sarah Berel-Harrop(2) Secretary, Treasurer & CFO	2012	94,220	Nil	27,703	Nil	Nil	Nil	Nil	121,923
	2011	92,744	Nil	27,150	296,440	Nil	Nil	Nil	416,334
Steven L. Carter(3) Executive Vice President	2012	185,067	Nil	Nil	Nil	Nil	Nil	Nil	185,067
	2011	129,167	Nil	Nil	1,442,119	Nil	Nil	Nil	1,571,286
Johnathan Lindsay(4) Former Secretary, Treasurer & CFO	2012	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
	2011	52,694	Nil	60,000	7,951	Nil	Nil	Nil	120,645
Amiel David(5) Former President	2012	N/A	N/A	N/A	N/A	N/A	N/A	N/A	N/A
	2011	543,750	Nil	1,556,250	Nil	Nil	Nil	Nil	2,100,000
Craig Alexander(6) Operations Manager	2012	188,846	N/A	N/A	N/A	N/A	N/A	N/A	188,846
	2011	53,654	Nil	Nil	296,440	Nil	Nil	Nil	350,094

(1) During the year ended July 31, 2011, the Company repriced outstanding options to purchase 100,000 shares of common stock from an exercise price of $8.75 per share to $2.50 per share (on a post-stock consolidation basis).  We reflected $31,239, the difference between the fair value of the outstanding award and the fair value of the repriced award as of the date of modification as compensation during the year ended July 31, 2011.

(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 grants related to amounts accrued and included as compensation for the year ended July 31, 2011.  Option awards as disclosed in 2011 include the aggregate grant date fair value of options to purchase 120,000 shares of common stock, with a ten year term, and exercisable at $2.50 per share (on a post-stock consolidation basis).  1/5 of the options vest each six months, beginning six months after the date of grant.  As of July 31, 2012, 48,000 of the options had vested and we recognized $118,576 as expenses. As of July 31, 2012, based on the fair value of the options there was $145,256 of unrecognized compensation cost related to non-vested share based compensation arrangements granted.

(3) During the year ended July 31, 2011, Steven Carter was awarded options to purchase 556,000 shares of common stock, with a ten year term, and exercisable at $2.50 per share (on a post-stock consolidation basis).  Option awards as disclosed in 2011, included the aggregate fair value of options of $1,408,779 and valued using Black Scholes option pricing model. 14,000 options vested immediately on the date of grant and 1/3 of the options vest each six months, beginning six months after the date of grant. As of July 31, 2012, 256,000 of the options had vested and we recognized $399,307 as expenses. As of July 31, 2012, based on the fair value of the options there was $322,863 of unrecognized compensation cost related to non-vested share based compensation arrangements granted.

(4) Johnathan Lindsay resigned as our Secretary, Treasurer and CFO on May 25, 2011. Johnathan Lindsay received varying amounts per month for the fiscal year ending July 31, 2011 for the provision of management consulting services provided by Mr. Lindsay to us on a monthly basis and from time to time. During the year ended July 31, 2011, Mr. Lindsay received 20,000 shares of common stock as consideration for the services provided. The stock was valued at the market closing price on the date of grant. Additionally, during the year ended July 31, 2011, Strategic repriced outstanding options to purchase 36,000 shares of common stock from an exercise price of $8.75 per share to $2.50 per share (on a post-consolidation basis). We reflected $7,951, the difference between the fair value of the outstanding award and the fair value of the repriced award as of the date of modification as compensation during the year ended July 31, 2011. The fair values were determined using the Black-Sholes option pricing method.

(5) Amiel David served as President from February 15, 2011 until April 1, 2011. See Note 10 – Share Return and Settlement in our Consolidated Financial Statements for details of his compensation during the year.

(6) During the year ended July 31, 2011, Craig Alexander was awarded options to purchase 120,000 shares of common stock, with a ten year term, and exercisable at $2.50 per share (on a post-stock consolidation basis).  The aggregate fair value of options was valued using Black Scholes option pricing model. 1/5 of the options vest each six months, beginning six months after the date of grant.  As of July 31, 2012, 48,000 of the options had vested and we recognized $118,576 as expenses. As of July 31, 2012, based on the fair value of the options there was $145,256 of unrecognized compensation cost related to non-vested share based compensation arrangements granted.

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See Note 11 – Capital Stock in our Consolidated Financial Statements for a discussion of the assumptions used in our option valuations.

Outstanding Equity Awards

The following table sets forth information as at July 31, 2012 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)	Equit  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 ($)
Jeremy G. Driver	100,000	N/A	N/A	2.50	12/01/2012	N/A	N/A	N/A	N/A
Sarah Berel-Harrop	48,000	N/A	72,000	2.50	04/21/2021	N/A	N/A	N/A	N/A
Steven L. Carter	24,000 56,000 200,000	N/A N/A N/A	N/A N/A 300,000	2.50 2.50 2.50	07/05/2017 08/16/2013 04/21/2021	N/A	N/A	N/A	N/A
Johnathan Lindsay	12,000 12,000	N/A N/A	N/A N/A	2.50 2.50	07/05/2017 05/21/2019	N/A	N/A	N/A	N/A
Craig Alexander	48,000	N/A	72,000	2.50	04/21/2021	N/A	N/A	N/A	N/A
Amiel David(1)	200,000	N/A	N/A	2.50	04/01/2014	N/A	N/A	N/A	N/A

(1) Warrants issued with settlement as described in Note 10 – Share Return and Settlement in our Consolidated Financial Statements.

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Director Compensation

We do not have a standard director compensation arrangement.  Compensation is negotiated with each director on a case by case basis.  Mr. Carter and Mr. Driver receive compensation for management services provided to the Company and they do not receive separate compensation for their services as directors.  The following table provides information regarding compensation during the year ended July 31, 2012 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 ($)	Non- Equity Incentive Plan Compen- sation ($)	Non- qualified Deferred Compen- sation Earnings ($)	All Other Compen- sation ($)	Total ($)
Leonard Garcia	2012	11,657	Nil	Nil	N/A	N/A	N/A	11,657

(1)  Leonard Garcia received varying amounts per month for the fiscal year ended July 31, 2012 for the provision of land work management consulting services provided by Mr. Garcia to us on a monthly basis and from time to time. Mr. Garcia was not granted any options during the year ended July 31, 2012.  As of July 31, 2012, Mr. Garcia had vested options outstanding to purchase an aggregate of 52,000 shares of common stock at $2.50 per share, as follows:  (i) vested stock options to purchase 36,000 shares expiring on May 21, 2012 and (ii) vested stock options to purchase 16,000 shares expiring on April 21, 2021.  In addition, as of July 31, 2012, Mr. Garcia had vesting options outstanding to purchase 24,000 shares of common stock at $2.50 per share, vesting according to the following schedule:  8,000 on October 21, 2012; 8,000 on April 21, 2013.

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.  The Carter Professional Services Agreement continues to be in effect by mutual agreement of the parties.  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 originally agreed to pay to Mr. Carter a monthly fee of $10,000; (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 June 2011, the Company determined to increase Mr. Carter’s monthly fee under this agreement to $14,583.33 per month.

Jeremy G. Driver Agreement

Effective December 1, 2009, we entered into an executive services agreement with Mr. Driver, 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, we have agreed:

● to pay Mr. Driver a monthly fee of $8,333.33 (subsequently amended as set forth below);

● 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.

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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 June 2011, the Company determined to increase Mr. Driver’s monthly fee under this agreement to $14,583.33 per month.

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 10, 2012 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	5,571,832 (3)	41.6% (9)
Common Stock	Steven L. Carter 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	403,428 (4)	3.0%
Common Stock	Leonard Garcia 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	113,829 (5)	Less than 1%
Common Stock	Sarah Berel-Harrop 800 Gessner, Suite 200 Houston, Texas, U.S.A., 77024	93,796 (6)	Less than 1%
Common Stock	John E. Brewster, Jr. 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	10,300	Less than 1%
Common Stock	Directors and officers together (6 persons)	6,193,185 (7)	44.6% (9)
	Major Stockholders:
Common Stock	Christopher Watts 14019 SW Frwy #301-600 Sugar Land, Texas, U.S.A.  77478	5,470,832 (8)	41.2% (9)

(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 13,279,703 shares of our common stock issued and outstanding as of November 10, 2012.

(3) This figure includes (i) 2,736,416 shares of common stock held by KD Navigation Inc., which is solely owned by Mr. Driver’s wife, (ii) 2,735,416 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 8 below), and (iii) vested stock options held by Mr. Driver to purchase 100,000 shares of our common stock.

(4) This figure includes (i) 23,428 shares of common stock and (ii) vested stock options to purchase 380,000 shares of our common stock.

(5) This figure includes (i) 49,843 shares of common stock, (ii) vested stock options to purchase 60,000 shares of our common stock and (iii) stock purchase warrants to purchase 3,986 shares of our common stock.

(6) This figure includes (i) 21,796 shares of common stock and (ii) vested stock options to purchase 72,000 shares of our common stock.

(7) This figure includes (i) 5,577,199 shares of common stock, (ii) vested stock options to purchase 612,000 shares of our common stock and (iii) stock purchase warrants to purchase 3,986 shares of our common stock.

(8) Represents (i) 2,735,416 shares held by CW Navigation Inc., which is solely owned by Mr. Watts, and (ii) 2,735,416 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).

(9) The 2,735,416 shares held by KW Navigation Inc. (representing 20.6% of the Company’s issued and outstanding stock as of November 10, 2012) is included in the beneficial ownership figures in the table for each of Jeremy Glenn Driver and Christopher Watts (see footnotes 3 and 8 above).

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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.

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.

Geoserve Marketing LLC

On February 15, 2011, we entered into a Consulting Agreement with Geoserve Marketing, LLC, a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer.  Effective March 17, 2011, this agreement was amended.  The Consulting Agreement, as amended, provides that Geoserve is to provide consulting services to the Company as an independent contractor for a term of three years. The Agreement provides that the Company will compensate Geoserve with warrants according to the following schedule: (i) upon signing, Geoserve shall be issued five-year term warrants to purchase 800,000 restricted shares of common stock at an exercise price of $2.50 per share (previously granted and vested as of the execution of the original agreement on February 15, 2011). If the Company’s stock price reaches a five-day average closing price of $7.50 per share, the Company shall grant Geoserve an additional 600,000 share purchase warrants at an exercise price of $2.50 per share and a five-year term. If the Company’s stock price reaches a five-day average closing price of $15.00 per share, the Company shall grant Geoserve a further 600,000 share purchase warrants at an exercise price of $2.50 per share and a five-year term. The Company may terminate the agreement after the first year with thirty days notice.  All information in this paragraph is presented on a post-share consolidation basis.

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.

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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.

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).

Barge Canal Properties

A company controlled by one of our officers, Steven Carter, operates our Barge Canal properties.  Revenues generated from these properties were $569,476 and $458,959 for the years ended July 31, 2012 and 2011, respectively.  In addition, lease operating costs incurred from these properties were $181,113 and $176,096 for the years ended July 31, 2012 and 2011, respectively.

As of July 31, 2012 and 2011, respectively, we had outstanding accounts receivable associated with these properties of $74,972 and $69,880 and no accounts payable.

Independent Directors

Leonard Garcia, John E. Brewster, Jr. and S. Chris Herndon are independent directors of our Company as provided in the listing standards of the NYSE MKT Equities Exchange.

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Director Loan

In November and December 2010, one of our former directors, Randall Reneau, loaned us $185,000. The interest rate on the notes was 6% and the principal was due as follows: $10,000 on demand and $175,000 in December 2011. We issued stock in payment of the $10,000 note payable in February 2011. We repaid the remaining note payable balance in November 2011.

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 $330,151 each.

ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES

Our current independent auditor, Malone & Bailey, P.C., served as our independent registered public accounting firm and audited our financial statements for the fiscal year ended July 31, 2012 and 2011.  Aggregate fees for professional services rendered to us by our auditor are set forth below:  

	Year Ended July 31, 2012		Year Ended July 31, 2011
Audit Fees	$	114,500	$	163,250
Audit-Related Fees		-		-
Other		10,000		-
Tax Fees		14,000		8,775
Total	$	138,500	$	172,025

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.

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.  During the year ended July 31, 2012, we incurred $10,000 in fees for the audit of the financial statements of our subsidiary, Galveston Bay Energy, LLC.

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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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)	Consulting Services and Options Agreement between the Company and Jim Thomas, dated April 2006, and Amended and Restated Consulting Services and Option Agreement between the Company and Jim Thomas, dated November 2007
10.11 (1)	Consulting Services and Options Agreement between the Company and Kyle Combest, dated August 2006
10.12 (1)	Professional Services Retainer Contract between the Company and Steven Carter, dated December 2006
10.13 (2)	Form of Securities Purchase Agreement regarding October 15, 2009 Private Placement
10.14 (2)	Form of Registration Rights Agreement regarding October 15, 2009 Private Placement
10.15 (3)	Form of Securities Purchase Agreement regarding November 13, 2009 Private Placement
10.16 (3)	Form of Registration Rights Agreement regarding November 13, 2009 Private Placement
10.17 (5)	Executive Services Consulting Agreement between the Company and Jeremy Glenn Driver dated for reference effective on December 1, 2009
10.18 (6)	Assignment of Oil and Gas Lease between Penasco Petroleum, Inc. and Chinn Exploration Company, dated September 13, 2010
10.19(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
10.20(7)	Geoserve Marketing, LLC Agreement, dated February 15, 2011
10.21(7)	SPE Navigation 1, LLC Agreement to acquire work interest., dated February 15, 2011
10.22(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
10.23 (9)	2010 Stock Incentive Plan
10.24 (9)	2011 Stock Incentive Plan
10.25(9)	Farm-Out Agreement with Core Minerals, January 2011, as amended March 9, 2011
10.26(12)	Share Exchange Agreement dated August 7, 2012
10.27(12)	Consulting Services Agreement between Duma Energy Corp. and Hydrocarb Corporation, dated August 7, 2012
10.28(13)	Joint Operating Agreement between Hydrocarb Namibia Energy Corporation and Namibia Exploration, Inc. as fully executed on September 6, 2012
10.29 (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.
14.1 (4)	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 8, 2012

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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 ex exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on December 14, 2011.

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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
	President, Chief Executive Officer, Chairman and a director
	(Principal Executive Officer)
	Date: November  13, 2012
By:	/s/Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
	Date: November  13, 2012

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
	President, Chief Executive Officer, Chairman and a director
	(Principal Executive Officer)
	Date: November  13, 2012
By:	/s/Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
	Date: November  13, 2012
By:	/s/ Leonard Garcia
	Leonard Garcia
	A director
	Date: November  13, 2012
By:	/s/ Steven L. Carter
	Steven L. Carter
	Vice President of Operations and a director
	Date: November  13, 2012
By:	/s/ John E. Brewster
	John E. Brewster
	A director
	Date: November  13, 2012
By:	/s/ S. Chris Herndon
	S. Chris Herndon
	A director
	Date: November  13, 2012