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DUMA > SEC Filings for DUMA > Form 10-K on 13-Nov-2012All Recent SEC Filings

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Form 10-K for DUMA ENERGY CORP


13-Nov-2012

Annual Report


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

The following discussion of our financial condition, changes in financial condition, plan of operations and results of operations should be read in conjunction with (i) our audited consolidated financial statements as at July 31, 2012 and 2011 and (ii) the section entitled "Business", included in this annual report. The discussion contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under "Risk Factors" and elsewhere in this annual report.

Executive Summary

To put into context the accomplishments of the last fiscal year, the following
table shows the comparison for the last 4 years in certain key areas. Our focus,
managerially, is on building revenue and cash flow. Our acquisition strategy
will be driven by these same two criteria. We believe that shareholder returns
and value will be most enhanced, at least in the short term, by focusing on
increasing both revenue and cash flow.

(in 1,000's)                  2009        2010         2011        2012
Revenue                         0.49        0.53         3.41        7.17
Cash Flow From Operations      (1.13 )     (2.63 )      (2.27 )      0.63
Total Assets                    1.47        2.53        16.94       25.78
Net Loss                       (2.78 )     (3.49 )     (10.29 )     (4.58 )
Total Stockholders' Equity      0.54        0.28         6.63       12.30


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

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

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

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

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

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

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

Plan of Operations

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

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

In Galveston Bay, Texas we plan to continue enhancing the production from our four productive fields. Our plans include drilling, reworking, and recompletions, as well as infrastructure improvements to exploit the known reserves as well as explore for additional reserves. Through the date of this report, we have accomplished the following:
In April 2012, we negotiated a production handling agreement for our production from the Redfish Reef field, which had been shut in since April 2011;

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

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

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

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

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

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

In Namibia, Africa, in conjunction with the operator, Hydrocarb Energy Corp., we will continue gathering data, including further source rock surveys, reservoir studies, seep studies, geologic mapping, and other analysis. Following this, we plan to conduct aerial gravity and magnetic surveys in 2013 across our entire concession which is approximately the size of the State of Massachusetts. This should, once interpreted, allow us to design our plan for 2D seismic acquisition. 3D seismic will be utilized for those identified structures which appear most prospective. Drilling of the first well is several years away. In the meanwhile, our goals are to increase the value and decrease the risk profile of our concession acreage in Namibia.

Recent Activities

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

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

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


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

Results of Operations

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

                                                     Year Ended July 31,            Increase/         2012%
                                                    2012             2011           (Decrease)       change

Revenues                                        $  7,165,233     $   3,412,791     $  3,752,442     $     110 %

Operating expenses
Lease operating expense                            4,013,083         1,698,191       2,314, 892           136 %
Depreciation, depletion, and amortization          1,021,981           304,851          717,130           235 %
Accretion                                            943,508           213,866          729,642           341 %
Impairment                                                 -           140,029         (140,029 )       (100) %
Consulting fees - related party                      189,372         2,965,559       (2,776,187 )        (94) %
Acquisition-related costs                                  -         2,617,099       (2,617,099 )       (100) %
Acquisition-related costs - related party          4,367,750                 -        4,367,750           100 %
Share return and settlement                                -         1,800,000       (1,800,000 )       (100) %
General and administrative expense                 3,852,722         2,549,365        1,303,357            51 %
Total operating expenses                          14,388,416        12,288,960        2,099,456            17 %
Loss from operations                              (7,223,183 )      (8,876,169 )      1,652,986           (19 )

Interest expense, net                               (157,964 )        (151,549 )          6,415             4 %
Gain on sale of available-for-sale securities        463,117                 -          463,117           100 %
Loss on settlement of debt                                 -           (50,737 )         50,737         (100) %
Gain (loss) on derivative warrant liability        1,217,835        (1,206,788 )      2,424,623         (201) %

Net loss before income tax                        (5,700,195 )     (10,285,243 )      4,585,048           (45 )
Income tax benefit                                 1,120,471                 -        1,120,471         (100) %

Net loss                                        $ (4,579,724 )   $ (10,285,243 )   $  5,705,519          (55) %

We recorded a net loss of $4,579,724, or $0. 45 per basic and diluted common share, during the fiscal year ended July 31, 2012, as compared to a net loss of $10,285,243, or $2.34 per basic and diluted common share, during the fiscal year ended July 31, 2011.
The changes in results were predominantly due to the factors below:

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

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

Consulting fees - related party pertain to warrants granted as compensation to a company for investor relations and public relations services. This company is a related party, as it is controlled by the father-in-law of our CEO, Jeremy Driver. The warrant grant occurred in April 2011 and consisted of immediately vesting warrants and warrants that vest in accordance with a market condition. The warrants that vested immediately were valued using the Black-Sholes option pricing method and the expense was recognized on the vesting date. The warrants with a market condition are valued using a lattice model and the expense is amortized over the service period. See Note 11 - Capital Stock for more information about these warrants.


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

Acquisition related costs - related party: We incurred an expense of $4,367,750 due to the excess of the fair value of the purchase price of SPE over the carrying value in the net assets acquired in the SPE acquisition. This was a one-time charge.

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

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

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

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

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

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

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

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

                             July 31, 2012       July 31, 2011

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

Subject to the availability of additional financing, in order to maximize production from our Galveston Bay properties, we plan approximately $1.0 million to $3.5 million in capital expenditures in the next 12 months on the properties to include upgrading production facilities, new flowlines, recompletion of existing shut-in wells, and other projects aimed specifically at increasing production. The upper range of these capital expenditures contemplates the drilling of a new well in the bay. The determination of when this well is drilled will be made pursuant to financial performance and operational considerations.

At July 31, 2012, we had $1,102,987 of cash on hand and a working capital deficit of $1,865,472 ($1,325,388 of which is attributable to a warrant derivative liability which would ordinarily be settled in stock). As such, our working capital alone on July 31, 2012 was not sufficient to enable us to pay our lease operating costs, to pay our general and administrative expenses, and to pursue our plan of operations over the next 12 months. However, our cash flow from operations is good, and we believe it will support the payment of outstanding obligations as well as our planned capital expenditures. Our plan of operations over the next twelve months will always be subject to available capital which will be determined, in part, by the success of projects that are currently in progress or will begin soon. It is even possible that given a high degree success in recent projects and upcoming projects we could actually exceed our planned operations and have more funds available for capital expenditures for the next 12 months. As management, we will determine the best use of our capital given the circumstances at the time.


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Various conditions outside of our control may detract from our ability to raise the capital needed to execute our plan of operations, including the price of oil as well as the overall market conditions in the international and domestic economies. We recognize that the United States economy has suffered through a period of uncertainty during which the capital markets have been depressed from levels established in recent years, and that there is no certainty that these levels will stabilize or reverse. We also recognize that the price of oil decreased from approximately $140 per barrel in 2008 to under $40 per barrel in February of 2009. During our fiscal year ended July 31, 2011, oil price levels increased to a high of $114 per barrel, but they have decreased to approximately $86 per barrel as of late October 2012. If the price of oil drops to levels seen in previous years, we recognize that it will adversely affect our cash flow from operations and our ability to raise additional capital. Any of these factors could have a material adverse impact upon our ability to raise capital or obtain financing and, as a result, upon our short-term or long-term liquidity.

Net Cash Provided by (Used in) Operating Activities

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

Net Cash Provided by (Used in) Investing Activities

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

Net Cash (Used in) Provided by Financing Activities

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

Critical Accounting Policies

The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America and the rules of the Securities and Exchange Commission ("SEC"). The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.

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

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

Oil and Natural Gas Properties

We account for our oil and natural gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Under this method, subject to a limitation based on estimated value, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including internal costs directly associated with acquisition, exploration, and development activities, the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized within a cost center. Costs of production and general and administrative corporate costs unrelated to acquisition, exploration, and development activities are expensed as incurred.


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Costs associated with unevaluated properties are capitalized as oil and natural gas properties but are excluded from the amortization base during the evaluation period. When we determine whether the property has proved recoverable reserves or not, or if there is an impairment, the costs are transferred into the amortization base and thereby become subject to amortization.

We assess all items classified as unevaluated property on at least an annual basis for inclusion in the amortization base. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate that there would be impairment, or if proved reserves are assigned to a property, the cumulative costs incurred to date for such property are transferred to the amortizable base and are then subject to amortization.

Capitalized costs included in the amortization base are depleted using the unit of production method based on proved reserves. Depletion is calculated using the capitalized costs included in the amortization base, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

The net book value of all capitalized oil and natural gas properties within a cost center, less related deferred income taxes, is subject to a full cost ceiling limitation which is calculated quarterly. Under the ceiling limitation, costs may not exceed an aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10 percent using current prices, plus the lower of cost or market value of unproved properties included in the amortization base, plus the cost of unevaluated properties, less any associated tax effects. Any excess of the net book value, less related deferred tax benefits, over the ceiling is written off as expense. Impairment expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. During the year ended July 31, 2011, we recorded a $140,029 impairment charge because the net book value of our oil and gas properties exceeded the ceiling.

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

Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.

Asset Retirement Obligation

We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is . . .

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