Attached files

file filename
EX-99.1 - EXHIBIT 99.1 - HYDROCARB ENERGY CORPex99_1.htm
EX-31.1 - EXHIBIT 31.1 - HYDROCARB ENERGY CORPex31_1.htm
EX-32.1 - EXHIBIT 32.1 - HYDROCARB ENERGY CORPex32_1.htm
EX-31.2 - EXHIBIT 31.2 - HYDROCARB ENERGY CORPex31_2.htm


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.

 
2

 

TABLE OF CONTENTS

ITEM 1.
4
     
ITEM 1A.
12
     
ITEM 1B.
16
     
ITEM 2.
16
     
ITEM 3.
16
     
ITEM 4.
16
     
ITEM 5.
17
     
ITEM 6.
19
     
ITEM 7.
19
     
ITEM 7A.
26
     
ITEM 8.
27
     
ITEM 9.
65
     
ITEM 9A.
65
     
ITEM 9B.
66
     
ITEM 10.
66
     
ITEM 11.
70
     
ITEM 12.
73
     
ITEM 13.
74
     
ITEM 14.
76
     
ITEM 15.
77
 

PART I
 
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.


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.
 

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.


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.

 
   
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  
 
 
 
 
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.

 
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.


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.


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.

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.


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.
 
 
 
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.


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.


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.
 
UNRESOLVED STAFF COMMENTS
 
None.
 
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.
 
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.
 
MINE SAFETY DISCLOSURE
 
Not applicable.
 
 
 
PART I
 
 
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.


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.


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.
 
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.

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  


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.
 
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.

 
 
·
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.

 
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.


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.


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.


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.

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.


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


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
 

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


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


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