Overview

As used in this Quarterly Report: (i) the terms "we", "us", "our", "Duma", "Penasco", "Galveston Bay", "SPE", "NEI" and the "Company" mean Duma Energy Corp and its wholly owned subsidiaries, Penasco Petroleum Inc., Galveston Bay, LLC, SPE Navigation I, LLC, and Namibia Exploration, Inc. unless the context otherwise requires; (ii) "SEC" refers to the Securities and Exchange Commission;
(iii) "Securities Act" refers to the Securities Act of 1933, as amended; (iv) "Exchange Act" refers to the Securities Exchange Act of 1934, as amended; and
(v) all dollar amounts refer to United States dollars unless otherwise indicated.

The following discussion of our plan of operations, results of operations and financial condition as at and for the three months ended October 31, 2012 should be read in conjunction with our unaudited consolidated interim financial statements and related notes for the three months ended October 31, 2012 included in this Quarterly Report, as well as our Annual Report on Form 10-K for the year ended July 31, 2012.

Operation Plans and Focus

In South Texas, we plan to continue producing oil and gas from existing leases and we are evaluating plans to drill a second well on the Curlee prospect. The first well drilled on this prospect resulted in the well location being on the opposite side of the fault, but did provide further valuable data on the location, structure, and aerial extent of the formation. We are now evaluating this new data along with 3D seismic. 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 exploratory 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 are primarily focused on reworking and recompleting a number of shut-in wells, as well as infrastructure improvements to exploit the known reserves. There still remain a large number of projects that we were unable to begin work on due to the drilling activity in calendar 2012. These projects are estimated to have a much higher return on invested dollar compared with drilling. As we are already generating positive cash flow from the operations in Galveston Bay, additional oil and gas produced will have a much greater positive impact on our financial success. The economies of scale that we hope to achieve in all of our fields in the bay should reduce our lifting costs on a per barrel or per mcf basis, further enhancing the value of the asset and our cash flow.

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. When this acquisition was under review by management and the board of directors, several factors were evaluated. One of the sources of information that provided a great deal of insight into the resource potential of the Namibian concession, and specifically the Owambo Basin, was a public disclosure in 2004 by Circle Oil Plc. In its annual public filing on the London Exchange in 2004, the company disclosed information about their Namibia license, which at the time included a portion of our current concession. As part of this disclosure, Circle Oil included a portion of a third-party resource estimate. Although we were not able to specifically calculate what portion of their reported estimate was attributable to our concession acreage, the report did lend further veracity and credibility to the field studies and analysis already performed by Hydrocarb. We believed and still believe that Namibia possesses all of the necessary ingredients to become a major petroleum play in Africa. Studies so far have continually confirmed and expanded this belief.

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 many-fold:

1. This structure required no cash for the acquisition of the concession. Any cash used would be for operations and further development;

2. 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.;

3. 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:

Production data:

                                                     Three months ended October 31,
                                        2012                                                2011
                    Oil (Bbls)       Gas (Mcf)       Total (Mcfe)       Oil (Bbls)       Gas (Mcf)       Total (Mcfe)
Production               18,288          47,113            156,844           13,179          47,013            126,085
Average sales
price              $     103.67     $      2.81     $        12.93     $     103.05     $      4.36     $        12.40
Average lease
operating
expense                                             $         7.06                                      $         6.39



Statements of operations:

                                                 Three months ended
                                                    October 31,
                                                                                Increase/           %
                                               2012              2011          (Decrease)        Change

Revenues                                   $   2,028,505     $  1,562,879     $     465,626            30 %

Operating expenses
Lease operating expense                        1,107,678          805,372           302,306            38 %
Depreciation, depletion, and
amortization                                     273,294          178,010            95,284            54 %
Accretion                                        232,188          137,882            94,306            68 %
Consulting fees - related party                   80,493           47,757            32,736            69 %
Acquisition cost - related party              37,234,752        4,367,750        32,867,002           752 %
Other general and administrative expense         833,097        1,408,053          (574,956 )        (41) %
Total operating expenses                      39,761,502        6,944,824        32,816,678           473 %

Loss from operations                         (37,732,997 )     (5,381,945 )     (32,351,052 )         601 %

Interest expense, net                            (41,382 )        (67,494 )          26,112          (39) %
Gain (loss) on sale of available for
sale securities                                 (461,964 )        433,168          (895,132 )       (207) %
Impairment of available for sale
securities                                      (275,327 )              -          (275,327 )       (100) %
Gain on derivative warrant liability             641,594          859,028          (217,434 )        (25) %
Income tax provision                                   -          (41,948 )          41,948         (100) %

Net Loss                                   $ (37,870,076 )   $ (4,199,191 )   $ (33,670,885 )         802 %

We recorded net loss of $37,870,076, or ($3.23) per basic and diluted common share, during the quarter ended October 31, 2012, as compared to a net loss of $4,199,191, or ($0.49) per basic and diluted common share, during the quarter ended October 31, 2011.

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

? Revenues increased due to increased oil production volume in fiscal 2013.

? Lease operating expense increased primarily due to the fact that an offshore field, Redfish Reef, that had been shut in during the quarter ended October 31, 2011 was online during the quarter ended October 31, 2012.

? Depreciation, depletion, and amortization increased because of an increase in the amortization rate, which was attributable primarily to an increase in the full cost pool as of the end of fiscal 2012. Accretion increased because of an increase in the estimated asset retirement obligation that occurred in fourth quarter 2012, which affected accretion going forward.

? Consulting fees - related party pertains to amortization of expense associated with warrants granted as compensation to a company for investor relations and public relations services. The award has a market condition whose cost is recognized over a multiple year service period. The expense in each period is derived from the market value of the award, which is amortized over the service period.

? During the three months ended October 31, 2012, we incurred $37,234,752 of expense in conjunction with our acquisition of NEI. The transaction, which is a related party transaction, is discussed in detail in Note 2 of our Consolidated Financial Statements. This charge is the most significant difference in the results of operations from the comparable period in fiscal 2012. 2,490,000 shares of common stock were issued to the sellers of NEI and up to 22,410,000 additional shares of Duma common stock may be issued based on the achievement of certain market conditions over the next ten years. The estimated fair value of our commitment to issue the 22,410,000 shares was charged to expense as of the date of the transaction as required by relevant accounting standards. The estimated fair value of the contingently issuable shares was $31,612,000, the bulk of the charge. During the three months ended October 31, 2011, we recognized a charge of $4,367,750 from the issuance of stock whose value exceeded the net asset value acquired with SPE Navigation 1, LLC, which was a separate related party transaction involving similar parties.

? Our decrease in general and administrative expenses is primarily attributable to a one-time stock grant that occurred during the quarter ended October 31, 2011. Legal and professional expenses in 2012 also decreased.

? GBE maintains a letter of credit to satisfy a Texas Railroad Commission requirement and has a line of credit with a commercial bank. During the three months ended October 30, 2012 we had a lower balance outstanding on the line of credit than during the comparable prior quarter, which resulted in a decrease in interest expense.

? We incurred a loss on the sale of securities in 2012 due to the sale of securities that had declined in value since the time of acquisition. We sold our investments in the same security in 2011 at a gain. Management assessed the remaining securities that we owned as of October 31, 2012 for impairment and determined that an other than temporary impairment existed.

? We re-measure our derivative warrants at fair value at every reporting date. Change in the fair value of the derivative warrants, as determined using a lattice model, for the three months ending October 31, 2012 was less compared to the change in fair value for the three months ended October 31, 2011 and hence the decrease in the gain recognized.

We continue to evaluate areas where we can reduce costs in both lease operating expense and general and administrative expense.

Liquidity and Capital Resources

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

                                       October 31, 2012       July 31, 2012

          Cash and cash equivalents   $        1,941,549     $     1,102,987
          Working capital (deficit)   $       (3,353,222 )   $    (1,865,472 )

At October 31, 2012, we had $1,941,549 of cash on hand and a working capital deficit of $3,353,222 ($508,254 is attributable to a warrant derivative liability which would ordinarily be settled in stock and $1,600,000 is attributable to amounts which can be settled, at Duma's option, in stock). The current working capital deficit reflects the impact of our recent drilling and capital investment activities. As such, our working capital alone on October 31, 2012 was not sufficient to enable us 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 of 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 Used in Operating Activities

During the three months ended October 31, 2012, operating activities provided $1,172,316 in comparison to cash used of $83,710 during the three months ended October 31, 2011. The increase in the cash provided by operating activities is primarily attributable to increase in income generated from properties acquired net of operating expenses. In addition, use of trade credit and cash calls received from partners increased cash flow from operations.

Net Cash (Used in) Provided by Investing Activities

During the three months ended October 31, 2012, investing activities used cash of $236,096 compared to cash provided of $3,820,583 during the three months ended October 31, 2011. In 2011, the cash provided is mainly attributable to proceeds from the sale of available for sale securities that had been acquired with the acquisition of SPE. In 2012, the use of cash is attributable to investment in oil and gas assets.

Net Cash Used in Financing Activities

Financing activities during the three months ended October 31, 2012 used cash of $97,658 in comparison to $81,192 used during the three month ended October 31, 2011. The change between periods is comparable.

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 units 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.

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 Obligations

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 accordingly update our assessment. 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 carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable - related party, accounts payable and accrued expenses, and notes payable approximate their fair market value based on the short-term maturity of these instruments.

Stock-Based Compensation

ASC 718, "Compensation-Stock Compensation" requires recognition in the financial statements of the cost of employee services received in exchange for an award of equity instruments over the period the employee is required to perform the services in exchange for the award (presumptively the vesting period). We measure the cost of employee services received in exchange for an award based on the grant-date fair value of the award.

We account for non-employee share-based awards based upon ASC 505-50, "Equity-Based Payments to Non-Employees." ASC 505-50 requires the costs of goods and services received in exchange for an award of equity instruments to be recognized using the fair value of the goods and services or the fair value of the equity award, whichever is more reliably measurable. The fair value of the equity award is determined on the measurement date, which is the earlier of the date that a performance commitment is reached or the date that performance is complete. Generally, our awards do not entail performance commitments. When an award vests over time such that performance occurs over multiple reporting periods, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete.

. . .