Hydrocarb Energy (HECCQ) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

x Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934: For the quarterly period ended April 30, 2013

or

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 or organization)	(IRS Employer Identification No.)

800 Gessner, Suite 200

Houston, Texas  77024

(Address of principal executive offices, including zip code)

(281) 408-4880

(registrant’s principal executive office telephone number)

Indicate by check mark whether the registrant (1) has 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 check mark 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 (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x    Noo

Indicate by check mark 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. (Check one):

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

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

As of June 14, 2013, 13,281,003 shares of common stock, $0.001 par value, were outstanding.

 Table of Contents

Part I. Financial Information

Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results Of Operations	19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26
Item 4.	Controls and Procedures	26
Part II. Other Information
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27
Item 3.	Defaults Upon Senior Securities	27
Item 4.	Mine Safety Disclosures	27
Item 5.	Other Information	27
Item 6.	Exhibits	27

2

Part I. Financial Information

Item 1. Financial Statements

1. Consolidated Balance Sheets (unaudited)

2. Consolidated Statements of Operations and Comprehensive Income (Loss) (unaudited)

3. Consolidated Statements of Cash Flows (unaudited)

4. Notes to Consolidated Financial Statements (unaudited)

3

 DUMA ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	April 30,2013			July 31, 2012
Assets
Current assets
Cash and cash equivalents	$	513,155		$	1,102,987
Oil and gas revenues receivable		407,162			457,567
Accounts receivable – related party		169,435			117,618
Available for sale securities		-			313,446
Other receivables, net		17,057			517,441
Other current assets		415,356			256,677
Total current assets		1,522,165			2,765,736
Oil and Gas Property, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $2,297,532 and $1,557,675, respectively; and accumulated impairment of $373,335 and $373,335, respectively		16,107,087			15,622,826
Unevaluated property		1,020,747			265,639
Restricted cash		6,927,215			6,890,000
Other assets		179,275			190,259
Property and equipment, net of accumulated depreciation of $56,242 and $36,572, respectively		26,299			45,969
Total assets	$	25,782,788		$	25,780,429
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued expenses	$	3,098,482		$	2,298,838
Line of credit		300,000			300,000
Current portion of notes payable		1,009,006			102,025
Asset retirement obligations – short term		882,364			549,796
Derivative warrant liability		-			1,325,388
Advances		181,415			55,161
Due to related parties		15,180			-
Total current liabilities		5,486,447			4,631,208
Notes payable		807,078			11,678
Asset retirement obligations – long term		9,180,343			8,833,137
Total liabilities		15,473,868			13,476,023
Commitments and contingencies
Stockholders’ equity:
Common stock, $.001 par; 500,000,000 shares authorized shares; 13,281,003 and 10,791,003 shares issued and outstanding		13,281			10,791
Additional paid in capital		75,460,700			38,963,817
Accumulated other comprehensive loss		-			(743,082	)
Accumulated deficit		(65,165,061	)		(25,927,120	)
Total stockholders’ equity		10,308,920			12,304,406
Total liabilities and stockholders’ equity	$	25,782,788		$	25,780,429

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

4

DUMA ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three months ended April 30,						Nine months ended April 30,
	2013			2012			2013			2012
Revenues	$	1,384,727		$	1,878,907		$	5,102,991		$	5,281,747
Operating expenses
Lease operating expense		1,025,745			948,176			3,279,345			2,815,750
Depreciation, depletion, and amortization		221,465			201,294			759,527			593,137
Accretion		225,498			149,760			682,614			433,554
Consulting fees – related party		15,912			96,759			178,959			189,372
Acquisition-related costs – related party		-			-			37,234,752			4,367,750
General and administrative expense		869,719			742,833			2,460,957			3,079,673
Total operating expenses		2,358,339			2,138,822			44,596,154			11,479,236
Loss from operations		(973,612	)		(259,915	)		(39,493,163	)		(6,197,489	)
Interest expense, net		(41,283	)		(19,782	)		(130,704	)		(122,458	)
Gain on derivative warrant liability		-			40,376			1,056,224			1,026,207
Net gain (loss) on sale of available for sale securities		-			28,359			(793,247	)		461,527
Net loss before income taxes		(1,014,895	)		(210,962	)		(39,360,890	)		(4,832,213	)
Income tax benefit		128,812			284,050			122,949			414,233
Net Income (Loss)	$	(886,083	)	$	73,088		$	(39,237,941	)	$	(4,417,980	)
Other comprehensive income, net of tax:
Change in market value of available for sale securities, including reclassification adjustments to net income, net of income tax benefit of $0, $0, $0 and $0 respectively		-			(666,415	)		-			(679,849	)
Comprehensive Loss	$	(886,083	)	$	(593,327	)	$	(39,237,941	)	$	(5,097,829	)
Basic income (loss) per common share	$	(0.07	)	$	0.01		$	(3.03	)	$	(0.44	)
Diluted income (loss) per common share	$	(0.07	)	$	0.01		$	(3.03	)	$	(0.44	)
Basic weighted average shares outstanding		13,281,003			10,791,003			12,943,530			10,027,370
Diluted weighted average shares outstanding		13,281,003			14,345,880			12,943,530			10,027,370

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

5

 DUMA ENERGY CORP.

 CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine months ended April 30,
	2013			2012
Cash Flows From Operating Activities
Net loss	$	(39,237,941	)	$	(4,417,980	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		759,527			593,137
Accretion		682,614			433,554
Change in deferred taxes		-			(417,750	)
Amortization of debt discount, loan origination fees and prepaid interest		77,362			101,659
(Gain) loss on sale of available for sale securities		517,920			(461,527	)
Impairment of available for sale of securities		275,327			-
Change in allowance for doubtful accounts		39,637			-
Warrants granted to related party		178,959			189,372
Common stock granted for services and for investor relations		-			620,156
Share based compensation – amortization of the fair value of  stock options		654,450			556,972
Acquisition-related costs – related party		37,234,752			4,367,750
Gain on warrant derivative liability		(1,056,224	)		(1,026,207	)
Changes in operating assets and liabilities:
Accounts receivable		493,297			(42,342	)
Accounts receivable – related party		(36,637	)		(22,573	)
Accounts payable and accrued expenses		(182,576	)		(842,112	)
Advances		126,254			56,193
Settlement of asset retirement obligation		(165,665	)		-
Other assets		108,123			(103,093	)
Net cash provided by (used in) operating activities		469,179			(414,791	)
Cash Flows From Investing Activities
Purchases of oil and gas properties		(1,234,900	)		(436,769	)
Purchases of property and equipment		-			(66,847	)
Proceeds from sale of oil and gas properties		108,347			-
Change in restricted cash		(37,215	)		54,946
Purchase of available for sale securities		(24,593	)		(702,958	)
Proceeds from sale of available for sale securities		287,874			4,002,336
Net cash provided by (used in) investment activities		(900,487	)		2,850,708
Cash Flows From Financing Activities
Payments on notes payable		(158,524	)		(1,675,639	)
Payments on notes payable to related parties		-			(14,723	)
Net cash used in financing activities		(158,524	)		(1,690,362	)
Net increase (decrease) in cash		(589,832	)		745,555
Cash at beginning of period		1,102,987			1,082,099
Cash at end of period	$	513,155		$	1,827,654

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

6

DUMA ENERGY CORP.

 CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(Unaudited)

	Nine months ended April 30,
	2013		2012
Supplemental Disclosures:
Interest paid in cash	$	97,879	$	35,951
Income taxes paid in cash		5,880		17
Non-cash investing and financing
Asset retirement obligation sold	$	438	$	32,772
Asset retirement obligations incurred		20,500		1,389
Asset retirement obligation – change in estimate		142,763		-
Acquisition of SPE Navigation I, LLC for Duma common stock, including asset retirement obligation assumed of $2,268,156		-		5,132,250
Accounts payable for oil and gas properties		182,220		1,567,868
Notes payable for prepaid insurance		260,905		227,912
Adjustment of purchase price of acquisition: environmental liability acquired		-		112,500
Acquisition of  Namibia Exploration, Inc.		562,048		-
Expiration of derivative warrant liability		269,164		-
Unrealized loss on available for sale securities, net of tax benefit		-		679,849

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

7

DUMA ENERGY CORP.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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

Description of business and basis of presentation

The unaudited consolidated financial statements of Duma Energy Corp. (“Duma”, the “Company”, “we”, “us”, “our”) have been prepared in accordance with accounting principles generally accepted in the United States and the rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited financial statements and notes thereto contained in our Annual Report filed with the SEC on Form 10-K for the year ended July 31, 2012. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the financial statements which would substantially duplicate the disclosures contained in the audited financial statements for the most recent fiscal year ended July 31, 2012, as reported in the Form 10-K, have been omitted.

Reclassifications

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

Principles of consolidation

The accompanying consolidated financial statements include the accounts of Duma and our wholly owned subsidiaries, Penasco Petroleum Corporation (“Penasco”), SPE Navigation I, LLC (“SPE”), Galveston Bay Energy, LLC (“GBE”), and Namibia Exploration, Inc. (“NEI”). All significant intercompany accounts and transactions have been eliminated in consolidation.

Earnings per share

We compute basic earnings per share using the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the three and nine months ended April 30, 2013 and the nine months ended April 30, 2012, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share. For the three months ended April 30, 2012, certain options and warrants, which were outstanding during the entire three months, were exercisable at a price less than the average market price per common share during the period. Accordingly, those options were included in diluted weighted average shares of common stock outstanding as if they had been exercised at the beginning of the period and thus in the denominator for earnings per share. Options with an exercise price greater than the average market price per common share for the three months ended April 30, 2012 and warrants with a market condition that had not been met during the period were excluded from diluted weighted average shares of common stock outstanding.

Recent accounting pronouncements

Recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on our financial position or results from operations.

Note 2 – Acquisitions

SPE Navigation I, LLC

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

As of the acquisition date, the working interests previously owned by SPE were conveyed to GBE. Thus, all oil and gas revenues after the SPE acquisition were attributed to GBE. Our consolidated statements include the results of the 100% acquired working interest.

8

Supplemental pro forma information

The unaudited pro forma results presented below for the nine months ended April 30, 2012 have been prepared to give effect to the purchase of SPE as if it had been consummated on August 1, 2011. The unaudited pro forma results do not purport to represent what our results of operations actually would have been if the acquisition had been completed on such date or to project our results of operations for any future date or period.

Revenues	$	5,429,746
Loss from operations		(6,388,425	)
Net income (loss)		(4,608,916	)
Earnings per share, basic and diluted		(0.46	)

Namibia Exploration, Inc.

On August 7, 2012, we entered into a Share Exchange Agreement (the “Agreement”), which was closed on September 6, 2012, under which we purchased Namibia Exploration, Inc. ("NEI"), a corporation organized under the laws of the state of Nevada for the issuance of up to 24,900,000 shares of our common stock as described below. Prior to the acquisition, NEI was directly and indirectly owned and controlled by the CEO, his brother-in-law and his father-in-law. As a result, the acquisition was accounted for as an asset purchase from an entity under common control and the asset was recorded at NEI’s historical cost. NEI originally acquired the concession from a subsidiary of Hydrocarb Corporation (“Hydrocarb”) in exchange for a farm-in fee, as discussed below, totaling $2,400,000, payable over two years. Hydrocarb is partly owned by the uncle of the Chief Executive Officer’s wife and brother-in-law. Because the $2,400,000 fee was a related party transaction, and accordingly presumed not to be arms-length, and because there was substantial uncertainty about the realizability of the fair value given that the concession was unproved, management concluded that Hydrocarb’s historical cost of $562,048 (which consists primarily of fees paid to the Namibian government for the concession) represented the fair value of the asset. The farm-in agreement also provides for preferential offerings of other international oil and gas opportunities similar to the concession in Namibia.

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

As a result of the completion of the acquisition, NEI became a wholly-owned subsidiary of Duma. NEI holds the rights to 39% working interest (43.33% cost responsibility) in an onshore petroleum concession (the “Concession"), located in the Republic of Namibia, measuring approximately 5.3 million acres and covered by Petroleum Exploration License No. 0038 as issued by the Republic of Namibia Ministry of Mines and Energy.

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

9

Consideration for the acquisition of NEI

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

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

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

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

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

Hydrocarb agreement

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

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

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

Duma is required to pay a late fee of 10% per quarter for any outstanding balance of the Fee under the Consulting Agreement which will commence 30 calendar days from the date that the Fee or portion of the Fee is due, which may only be paid in cash. Duma has not yet paid the first installment as described in (a) above.

Valuation

NEI’s cost basis in the concession is $562,048. Since Duma acquired the liability due to Hydrocarb, Duma acquired a net liability of $1,837,952. The assets and liabilities were recorded at NEI’s carrying value on the date of the acquisition and the excess purchase price over the net assets acquired was recorded as an acquisition-related expense because this was a related party transaction.  The purchase price consists of the 2,490,000 shares that were awarded at closing, which were valued using the closing market price of the stock on the date of grant, and the contingent stock grant. The fair value of equity compensation that vests upon the attainment of a market condition (in this case, market capitalization) must be estimated and recorded on the date of the grant. The fair value of the contingent stock grant was valued in accordance with ASC 820 – Fair Value Measurements. The determination of fair value used a market approach weighted at 75% and the income approach (discounted cash flows) weighted at 25%. The computations included consideration of projections of the future results of Duma and NEI, using multiple probability-weighted scenarios, and projections of Duma’s capital structure.

As of April 30, 2013, we had recognized $37,234,752 of expense associated with the acquisition of NEI, which consisted of the assumption of NEI’s net liability of $1,837,952, $3,784,800 associated with the 2,490,000 shares issued at the closing date of the acquisition and $31,612,000 associated with the contingent consideration.

10

Note 3 – Available for Sale Securities

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

During September 2012, we received cash proceeds of $145,237 from sales of securities with a cost basis of $607,201; thus, we had a realized loss on sale of available for sale securities of $461,964. In October 2012, we recognized an other than temporary impairment of $275,327 resulting in a new cost basis in the stock of $174,000.

During December 2012, we received cash proceeds of $142,637 from sales of securities with a cost basis of $198,593; thus, we had a realized loss on sale of available for sale securities of $55,956. We reclassified $743,082 unrealized loss from other comprehensive loss into earnings in conjunction with these sales and the impairment.

As of April 30, 2013, we do not hold any available for sale securities.

Note 4 – Oil and Gas Properties

Oil and natural gas properties as of April 30, 2013 and July 31, 2012 consisted of the following:

	April 30, 2013			July 31, 2012
Evaluated Properties
Costs subject to depletion	$	18,404,619		$	17,180,501
Accumulated Depletion		(2,297,532	)		(1,557,675	)
Total evaluated properties		16,107,087			15,622,826
Unevaluated properties		1,020,747			265,639
Net oil and gas properties	$	17,127,834		$	15,888,465

Evaluated properties

Significant additions to evaluated oil and gas properties include:

● Land acquisition costs of $45,147;

● Exploration costs, consisting of geological and geophysical costs of $118,650 and drilling costs of $89,783; and

● Development costs of $1,079,323, which is primarily comprised of costs for a development well, the State Tract 9-12A#4 well in Galveston Bay totaling $444,119; costs for a recompletion in Galveston Bay totaling $357,990; increase in asset retirement obligations of $163,263, primarily due to a change in timing for one of our non-operated wells in Galveston Bay; and purchase of oil and gas well equipment.

Purchases and Sales of oil and gas property

As of July 31, 2012, we owned a 6.25% overriding royalty interest in properties located in Franklin and Richland parishes in Louisiana (the “Holt” and “Strahan” properties). We also had a note receivable from the sale of our working interests in these properties, which had been fully reserved. In September 2012, we conveyed the overriding royalty interests to the operator and released the operator from any further liability from the note receivable in exchange for $50,000 cash. We allocated the cash proceeds between the note receivable and the overriding royalty interests based on the relative fair value of the balance on the note and the projected present value of the income streams from the royalty interests. The portion attributable to the overriding royalty interest, $32,146, was treated as a reduction of capitalized costs in accordance with rules governing full cost companies.

During August 2012, we leased approximately 190 acres of land in Bee County, Texas called the Curlee Prospect. The operator of the project is Carter E&P, a company owned by our Chief Operating Officer. We have a 50% working interest in the project, 25% of which was carried to the casing point by the other participants in the initial well. Because we took a 25% additional interest, the portion of the working interest that we pay, prior to the casing point, is 33.3%. After the casing point and for all costs in future wells, we will be responsible for 50% of the costs. We received a bonus of $23,701 from the other parties in the well, which was reflected as a reduction of capitalized costs. During the quarter ended October 31, 2012, we drilled a well on the property, the Curlee No. 1 well, which was plugged and abandoned. Results from the Curlee No. 1 well are currently being evaluated for a possible second new drill well.

11

During December 2012, we sold our 3% working interest in the producing Janssen lease located in Karnes County, Texas. We received $2,500 as cash proceeds in conjunction with the sale. The buyer assumed the asset retirement obligation for the well, which was $438. In accordance with full cost rules, we recognized no gain or loss on the sale.

In December 2012, we acquired a 366.85 acre tract of property, the Dix prospect, in San Patricio County, Texas. We paid $76,296 in acquisition and land costs for this prospect. As of January 31, 2013, the lease was reflected as unevaluated property. In February 2013, we sold 75% working interest in the prospect to partners on a third for a quarter basis under which the 75% interest holders will carry 25% of the working interest to the casing point of the initial well drilled on the prospect. We also sold 2% of the carried working interest to Carter E&P, a company owned by our Chief Operating Officer. Thus we retained a 23% working interest which is carried to the casing point of the initial well. We received a bonus of $50,000 from the other parties in the well, which was reflected as a reduction of capitalized costs in accordance with full cost accounting. The initial well was drilled in May 2013, but it was determined that it could not produce economically. Accordingly, the well was not completed.

Unevaluated Properties

USA

In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas. We paid $58,805 in acquisition and land costs for our interest in this prospect. According to the terms of the agreement, we 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. We have paid $270,150 for the drilling and completion costs. The well was drilled in June 2012; however, the first completion zone was non-economic. During October 2012, we participated in a recompletion operation which resulted in the completion of the well into an upper zone, however commercial production was not established.  The owners have agreed to attempt another rework operation, which was started June 7, 2013 and is currently in progress. Since the determination of whether the prospect will result in additions to oil and gas reserves has not been made, the prospect is carried as unevaluated.

During April 2013, we purchased a 12.5% working interest in a 260.12 acre tract of property, the Melody prospect, in Bee County, Texas. The operator of the project is Carter E&P, a company owned by our Chief Operating Officer. We paid Carter $60,219, which represents acquisition costs of $7,376 and $52,843 as a cash call for the estimated drilling costs for the initial well on the prospect, which is reflected as a prepaid expense. Additionally we have incurred internal geological and geophysical costs of $4,546 on the prospect. As of June 14, 2013, the well had not yet been spudded.

Namibia, Africa.

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

We have incurred total costs of $679,870, which includes NEI’s cost basis at the time we acquired the property, which was $562,048. The concession specifies the following minimum cost responsibilities on an 8/8ths basis:

1) Initial Exploration Period (expires September 2015): Perform a hydrocarbon potential study, gather and review existing technical data including reprocessing of seismic lines,  and acquire and process 750 kilometers of new 2D seismic data. The minimum expenditure is $4,505,000 on an 8/8ths basis.

2) First renewal exploration period (two years from end of the initial exploration period): Acquire 200 square kilometers of 3D seismic data, interpret and map the data, design a drilling program, drill one well, conduct an environmental study, and relinquish 25% of the Exploration license area. The minimum expenditure is $17,350,000 on an 8/8ths basis.

3) Second Renewal (Production License) Exploration Period (25 years): report on reserves and production, and conduct an environmental study. The minimum expenditure is $300,000 on an 8/8ths basis.

As of April 30, 2013, approximately $800,000 has been expended during the initial exploration period on an 8/8ths basis.

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Note 5 - Impairment

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

We evaluated our capitalized costs using the full cost ceiling test as prescribed by the Securities and Exchange Commission at the end of each reporting period. As of July 31, 2012 and April 30, 2013, the net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.

Changes in production rates, levels of reserves, future development costs, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Note 6 – Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of April 30, 2013 and July 31, 2012:

	April 30, 2013			July 31, 2012
Liability for asset retirement obligation, beginning of period	$	9,382,933		$	4,455,928
Asset retirement obligations assumed		-			2,365,530
Asset retirement obligations sold		(438	)		(32,772	)
Asset retirement obligations incurred on properties drilled		20,500			1,389
Accretion		682,614			943,508
Revisions in estimated cash flows		142,763			1,827,889
Costs incurred		(165,665	)		(178,539	)
Liability for asset retirement obligation, end of period	$	10,062,707		$	9,382,933
Current portion of asset retirement obligation	$	882,364		$	549,796
Noncurrent portion of asset retirement obligation		9,180,343			8,833,137
Total liability for asset retirement obligation	$	10,062,707		$	9,382,933

Note 7 – Line of Credit

On March 17, 2011, GBE secured a one year revolving line of credit of up to $5,000,000 with a commercial bank. The note specified interest at a rate of prime + 1% with a minimum interest rate of 5%. The initial interest rate was 6%. Interest is payable monthly. We must use proceeds from the line of credit solely to enhance our Galveston Bay properties.  The note is collateralized by our Galveston Bay properties and substantially all GBE’s assets. Duma has also executed a parental guarantee of payment. As of July 31, 2012 and April 30, 2013, the amount outstanding under the line of credit was $300,000.

In May 2012, we modified the line of credit to remove the floor on the minimum interest rate and to extend the maturity date for the credit facility to August 15, 2012. In November 2012, the maturity date was extended to December 31, 2012 and the borrowing base was reduced to $2,250,000. In February 2013, the maturity date was extended to March 31, 2013. The current interest rate is 4.25%. As of June 14, 2013, we are in the process of renewing the note.

Note 8 – Notes Payable

In February 2012, we entered into a premium financing arrangement to pay principal of $209,244 in conjunction with our commercial insurance program renewal. We were obligated to make nine payments of $24,578 per month, which include principal and interest, beginning in March 2012. As of July 31, 2012, $96,252 remained unpaid on the note.  As of April 30, 2013, the note payable balance was $0.

In May 2012, we entered into a note payable of $18,375 to purchase a vehicle. The note carries an interest rate of 6.93% and is payable beginning in June 2012, in 36 installments of $567 per month.  The principal balance owed on the note payable was $17,451 and $13,158 as of July 31, 2012 and April 30, 2013, respectively.

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

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In March 2013, we financed our commercial insurance program using a note payable for $260,905. Under the note, we are obligated to make nine payments of $29,591 per month, which include principal and interest, beginning in March 2013. As of April 30, 2013, $202,926 remained outstanding on this note.

As of April 30, 2013, future maturities on our notes payable were as follows:

Year ending:
April 30, 2014	$	1,009,006
April 30, 2015		806,515
April 30, 2016		563
Total	$	1,816,084

Note 9 – Fair Value

We had no financial assets and liabilities that were accounted for at fair value on a recurring basis as of April 30, 2013.

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

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

Derivative Warrant Liability

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

Certain warrants we issued during the year ended July 31, 2010 are not afforded equity treatment because these warrants have a down-round ratchet provision on the exercise price. As a result, the warrants are not considered indexed to our own stock, and as such, the fair value of the embedded derivative liability is reflected on the balance sheet and all future changes in the fair value of these warrants will be recognized currently in earnings in our consolidated statement of operations under the caption “Gain (loss) on warrant derivative liability” until such time as the warrants are exercised or expire. The total fair values of the warrants issued during the year ended July 31, 2010, were determined using a lattice model and have been recognized as a derivative liability as described below.

The warrants were valued using a multi-nomial lattice model with the following assumptions:

● The stock price on the valuation date would fluctuate with our projected volatility;

● Warrant holders would exercise at target price multiples of the market price trigger prices. The target price multiple reduces as the warrants approach maturity;

● Warrant holders would exercise the warrant at maturity if the stock price was above two times the reset exercise price;

● An annual reset event would occur at 65% discount to market price;

● The projected volatility was based on historical volatility. Because we do not have sufficient trading history to determine our own historical volatility, we used the volatility of a group of comparable companies combined with our own historical volatility from May 2009, when we began trading.

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The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the nine months ended April 30, 2013:

Beginning balance – July 31, 2012	$	1,325,388
Expiration of derivative warrant feature		(269,164	)
Unrealized gain on changes in fair value of derivative liability		(1,056,224	)
As of April 30, 2013	$	-

The unrealized gain on changes in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.

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

Note 10 – Capital Stock

Common Stock Issuances

For the Acquisition of NEI:

During September 2012, we issued 2,490,000 shares of common stock to the owners of Namibia Exploration, Inc. (“NEI”) for the acquisition of NEI. The shares were valued at $3,784,800, based on the quoted market price of our stock on the date of the acquisition. (See Note 2 – Acquisitions – Namibia Exploration, Inc.). Additionally, $31,612,000 was recognized in conjunction with our commitment to issue additional stock if certain market conditions are achieved.

Stock Options and Warrants

A new 2013 Stock Incentive Plan (2013 Plan) was approved by the Board during February 2013. The 2013 Plan replaced our prior stock incentive plans. Duma may grant up to 2,650,000 shares of common stock under the 2013 Plan. The Plan is administered by the Board of Directors, which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.

Options granted to non-employees

We account for options granted to non-employees under the provisions of ASC 505-50 and record the associated expense at fair value on the final measurement date. Because there is no disincentive for nonperformance for these awards, the final measurement date occurs when the services are complete, which is the vesting date. For the options granted to non-employees on a graded vesting schedule, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date. When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete.

In February 2013, options to purchase an aggregate of 600,000 shares of common stock with an exercise price of $2.20 per share and a term of ten years were granted to our three independent directors. The options vest 20% each six months over the 30 months following the award. The fair value of the total option award on the date of grant was $1,196,589. The fair market value of this award was estimated using the Black-Sholes option pricing model with an expected life of 6.5 years, a risk free interest rate of 1.35%, a dividend yield of 0%, and a volatility factor of 142.06%.

The following table provides information about options granted to non-employees under our stock incentive plans during the nine months ended April 30, 2013 and 2012:

	2013		2012
Number of options granted		600,000		-
Compensation expense recognized	$	463,739	$	358,000
Weighted average exercise price of options  granted	$	2.20	$	N/	A

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The following table details the significant assumptions used to compute the fair market values of stock options revalued during the nine months ended April 30:

	2013	2012
Risk-free interest rate	1.11% - 1.14%	0.12%-1.66%
Dividend yield	0%	0%
Volatility factor	142.32%-142.44%	135.20-147.92%
Expected life (years)	6.5 years	1-6.5 years

Options granted to employees

The following table provides information about options granted to employees under our stock incentive plans during the nine months ended April 30, 2013 and 2012:

	2013		2012
Number of options granted		-		-
Compensation expense recognized	$	190,711	$	198,972
Weighted average exercise price of options  granted	$	N/A	$	N/A

During the year ended July 31, 2011, options to purchase 260,000 shares of common stock with an exercise price of $2.50 per share and a term of ten years were granted to five employees. The options vest 20% each six months over the 30 months following the award. Because the grantees were employees, the awards are accounted for under the provisions of ASC 718. Accordingly, they were measured at fair value on the date of grant and the expense associated with the grant will be amortized over the 30 month vesting period on a straight line basis. As of April 30, 2013, we had $120,157 in unamortized compensation expense associated with options granted to employees.

No options were granted to employees during the nine months ended April 30, 2013 or 2012.

Summary information regarding stock options issued and outstanding as of April 30, 2013 is as follows:

	Options			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2012		1,044,000		$	2.50	$	-		7.22
Granted		600,000			2.20
Exercised		-			-
Expired		(108,000	)	$	2.50
Outstanding at April 30, 2013		1,536,000		$	2.38	$	-		8.23

Warrants

Warrants granted to related party

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

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If our common stock attains a five day average closing price of $7.50 per share, an additional 600,000 warrants with an exercise price of $2.50 and an expiration date of February 15, 2016 shall be issued (“Warrant B”). If our common stock attains a five day average closing price of $15.00 per share, an additional 600,000 warrants with an exercise price of $2.50 and an expiration date of February 15, 2016 shall be issued (“Warrant C”). The fair value of warrants that vest upon the attainment of a market condition must be estimated and amortized over the lower of the implicit or derived service period of the warrants. Previously recognized expense is not reversed in the event of a subsequent decline in the fair value of market condition equity based compensation. The fair value of the warrants and the derived service period were valued using a lattice model that values the liability of the warrants based on a probability weighted discounted cash flow model. This model is based on future projections of the various potential outcomes. Warrant B and Warrant C will be amortized over the derived service periods of 2.08 years and 2.49 years, respectively. The following table reflects information regarding Warrant B and Warrant C as of April 30, 2013 and 2012:

	2013		2012
Fair Value of Warrant B	$	266,017	$	274,077
Fair Value of Warrant C	$	205,554	$	226,209
Compensation expense recognized (nine months)	$	178,959	$	189,372

Summary information regarding common stock warrants issued and outstanding as of April 30, 2013, is as follows:

	Warrants			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2012		3,756,455		$	2.58	$	-		2.83
Granted		-			-		-		-
Exercised		-			-		-		-
Expired		(45,578	)	$	9.34		-		-
Outstanding at April 30, 2013		3,710,877		$	2.50	$	-		2.12

Note 11 – Related Party Transactions

A company controlled by one of our officers operates our Barge Canal properties, the Curlee Prospect in Bee County, Texas, and the Dix Prospect in San Patricio County, Texas. Revenues generated, lease operating costs, and contractual overhead charges, which are included in lease operating costs incurred from these properties or drilling costs, as appropriate, were as follows:

	Three months ended April 30,				Nine months ended April 30,
	2013		2012		2013		2012
Revenues	$	157,692	$	149,042	$	476,828	$	424,923
Lease operating costs	$	63,819	$	48,710	$	178,968	$	139,832
Overhead costs incurred	$	6,708		6,295	$	20,668	$	18,540

	April 30, 2013		July 31, 2012
Outstanding accounts receivable at period end	$	83,738	$	74,972
Outstanding accounts payable at period end	$	-	$	-

The father of the Chief Financial Officer and a company controlled by the father-in-law of the Chief Executive Officer each purchased a 5% working interest in our ST 9-12A #4 well. As of July 31, 2012, these parties owed $42,646 in billed and unbilled joint interest billings. As of April 30, 2013, the company controlled by the father-in-law of the Chief Executive Officer owed us $85,697. We also had an advance outstanding from the father of the Chief Financial Officer, which was reflected in the caption “Due to related parties”, of $15,180.

During 2011, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our Chief Executive Officer and a Director, as detailed in Note 10 – Capital Stock.  We recognized expense of $189,372 and $178,959 from this contract during the nine months ended April 30, 2012 and 2013, respectively.

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

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In February 2013, we sold a 2% working interest in a 366.85 acre tract of unevaluated property, the Dix prospect, in San Patricio County, Texas to Carter E&P, a company owned by one of our officers. Carter paid cash of $1,541, the proportional share of the land acquisition costs.

Note 12 - Commitments and Contingencies

Contingencies

We accrue for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded at their undiscounted value as assets when their receipt is deemed probable.

There is soil contamination at a tank facility owned by GBE. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $900,000. We cannot determine a most likely scenario, thus we have recognized the lower end of the range. We have submitted a remediation plan to the appropriate authorities and have not yet received a response. $150,000 has been recognized and is included in the balance sheet caption “Accounts payable and accrued expenses.”

Letters of Credit

Oil and gas operators in the State of Texas are required to obtain a letter of credit in favor of the Railroad Commission of Texas as security that they will meet their obligations to plug and abandon the wells they operate. We have two letters of credit in the amount of $6,610,000 and $240,000 issued by Green Bank. We pay a 1.5% per annum fee in conjunction with these letters of credit. These letters of credit are collateralized by a certificate of deposit held with the bank for the same amount. During June 2011, we had prepaid the first year’s interest on the letter of credit and amortized the interest cost through June 2012. We currently prepay and amortize the fees due quarterly. As of the year ended July 31, 2012, we had prepaid $25,163 towards the quarterly fee. As of April 30, 2013, the prepaid balance was $103,150. The prepaid interest will be amortized on a straight line basis. Accordingly, we had amortized interest in the amount of $8,596 and $85,958 as of July 31, 2012 and April 30, 2013, respectively, for net prepaid interest of $16,567 and $17,192 respectively.

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CAUTIONARY STATEMENT ON FORWARD-LOOKING INFORMATION

The Company is including the following cautionary statement for any forward-looking statements made by, or on behalf of, the Company. This quarterly report on Form 10-Q contains “forward looking statements” (as that term is defined in Section 27A(i)(1) of the Securities Act of 1933), including statements concerning plans, objectives, goals, strategies, expectations, future events or performance and underlying assumptions and other statements which are other than statements of historical facts. Such forward looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward looking statements. Some of the factors that could cause actual results to differ materially from those expressed in such forward looking statements are set forth in the section entitled “Risk Factors” and elsewhere throughout this Form 10-Q. Our expectations, beliefs and projections are expressed in good faith and are believed by us to have a reasonable basis, but there can be no assurance that our expectations, beliefs or projections will result or be achieved or accomplished. We have no obligation to update or revise forward looking statements to reflect the occurrence of future events or circumstances.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 nine months ended April 30, 2013 should be read in conjunction with our unaudited consolidated interim financial statements and related notes for the nine months ended April 30, 2013 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 making plans to lease additional acreage for new drill wells. Additional wells may be drilled this year depending on the outcome of the Melody Prospect and the negotiation and timing of additional acreage.

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. The next steps may include the drilling of an acceleration test well in the middle of the field.

In Galveston Bay, Texas we plan to continue enhancing the production from our three northern productive fields. Our southernmost field, Bolivar, is no longer in our core area of focus and lacks sufficient cash flow to remain a priority for us. We plan to divest this field and associated infrastructure in the near future. In our three northern 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. These projects are estimated to have a much higher return on invested dollar compared with drilling projects. As we are already generating positive cash flow from the operations in Galveston Bay, additional oil and gas produced will have an increasing positive effect on our margin and cash flow. The economies of scale that we hope to achieve in all three 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. The plan to accelerate this development and increase production will be financed in part by divesting 25% working interest to a partner/investor.

We have recently received new 3D seismic data from Samson Energy Company, LLC who acquired 3D seismic data over the eastern portion of the bay, as well as on land. We negotiated to receive the data over our fields, where available, including a half-mile buffer around. We are currently working to have the data analyzed and interpreted in order to best maximize our exploration efforts. The primary targets of this data are believed to be the deep structures including the Vicksburg and Yegua formations, which are prolific producers in southeast Texas with the trend moving toward Galveston Bay.

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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 later be utilized for those identified structures which appear most prospective. Drilling of the first well is several years away. In the meanwhile, our goals are to increase the value and decrease the risk profile of our concession acreage in Namibia. After 3D data has been acquired and interpreted, we plan to seek partners who could engage in the task of actually drilling the concession to make a discovery. The terms of such a farm-out are not yet determined.

Results of Operations

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

Production data:

	Three months ended April 30,
	2013									2012
	Oil (Bbls)			Gas (Mcf)			Total (Mcfe)			Oil (Bbls)			Gas (Mcf)			Total (Mcfe)
Production			11,390			45,230			113,570			15,966			36,161			131,957
Average sales price		$	108.86		$	3.20		$	12.19		$	112.29		$	2.38		$	14.24
Average lease operating expense								$	9.03								$	7.19

Statements of operations:

	Three months ended April 30,
	2013			2012			Increase/ (Decrease)			% Change
Revenues	$	1,384,727		$	1,878,907		$	(494,180	)		(26	)%
Operating expenses
Lease operating expense		1,025,745			948,176			77,569			8	%
Depreciation, depletion, and amortization		221,465			201,294			20,171			10	%
Accretion		225,498			149,760			75,738			51	%
Consulting fees – related party		15,912			96,759			(80,847	)		(84	)%
General and administrative expense		869,719			742,833			126,886			17	%
Total operating expenses		2,358,339			2,138,822			219,517			10	%
Loss from operations		(973,612	)		(259,915	)		(713,697	)		275	%
Interest expense, net		(41,283	)		(19,782	)		(21,501	)		109	%
Gain on derivative warrant liability		-			40,376			(40,376	)		(100	)%
Net gain on sale of available for sale securities		-			28,359			(28,359	)		(100	)%
Income tax benefit		128,812			284,050			(155,238	)		(55	)%
Net Income (Loss)	$	(886,083	)	$	73,088		$	(959,171	)		(1,312	)%

We recorded net loss of $886,083, or ($0.07) per basic and diluted common share, during the three months ended April 30, 2013, as compared to a net income of $73,088, or $0.01 per basic and diluted common share, during the three months ended April 30, 2012.

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

● Revenues decreased primarily due to decreased production as well as lower oil prices during the three months ended April 30, 2013. The lower production was primarily due to substantial downtime that occurred in one of our bay fields. The decreased revenue was the largest contributor to the change in the net income (loss).

● Lease operating expense increased primarily due to the fact that an offshore field, Redfish Reef, that had been shut in during the quarter ended April 30, 2012 was online during the quarter ended April 30, 2013.

● Depreciation, depletion, and amortization increased because of an increase in the amortization rate, which was attributable to an increase in the full cost pool as of the end of fiscal 2012 and to a reduction in estimated reserves because of unsuccessful drilling and recompletion results since 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. The reduction in expense is attributable to the reduction in the value of the award.

● Our increase in general and administrative expenses is primarily attributable to an increase in the expenses associated with the amortization of stock option grants. We granted options to our independent directors during the quarter ended April 30, 2013, and the cost for those options will be amortized over the vesting period, the next thirty months. The options represent new grants that did not occur during the comparable quarter in 2012.

● Interest expense increased because of an increase in notes payable, specifically the note payable acquired with Namibia Exploration, Inc. in August 2012.

● Our derivative warrant liability expired during the quarter ended January 31, 2013. Accordingly there was no gain or loss from the revaluation of the liability during the quarter ended April 30, 2013. Prior to the expiration of the derivative warrant feature, we revalued the warrants at fair value at every reporting date using a lattice model.

● We incurred a gain on the sale of securities during the three months ended April 30, 2012, whereas we did not sell securities during the comparable quarter of 2013.

● We recognized an income tax benefit during the three months ended April 30, 2012 due to an adjustment of the valuation allowance for our deferred tax assets. We determined that current deferred tax assets sufficient to offset deferred tax liabilities that had been acquired with the purchase of SPE Navigation 1, LLC existed. We also recognized an income tax benefit in the comparable quarter in 2013 because our estimate of income tax payable for the year ended July 31, 2012 was higher than the actual income tax payable.

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

Nine months ended April 30, 2013 compared to the nine months ended April 30, 2012:

Production data:

	Nine months ended April 30,
	2013									2012
	Oil (Bbls)			Gas (Mcf)			Total (Mcfe)			Oil (Bbls)			Gas (Mcf)			Total (Mcfe)
Production			44,433			128,959			395,557			43,581			146,059			407,547
Average sales price		$	105.62		$	3.18		$	12.90		$	109.55		$	3.47		$	12.96
Average lease operating expense								$	8.29								$	6.91

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Statements of operations:

	Nine months ended April 30,
	2013			2012			Increase/ (Decrease)			% Change
Revenues	$	5,102,991		$	5,281,747		$	(178,756	)		(3	)%
Operating expenses
Lease operating expense		3,279,345			2,815,750			463,595			16	%
Depreciation, depletion, and amortization		759,527			593,137			166,390			28	%
Accretion		682,614			433,554			249,060			57	%
Consulting fees – related party		178,959			189,372			(10,413	)		(5	)%
Acquisition-related costs – related party		37,234,752			4,367,750			32,867,002			752	%
General and administrative expense		2,460,957			3,079,673			(618,716	)		(20	)%
Total operating expenses		44,596,154			11,479,236			33,116,918			288	%
Loss from operations		(39,493,163	)		(6,197,489	)		(33,295,674	)		537	%
Interest expense, net		(130,704	)		(122,458	)		(8,246	)		7	%
Gain on derivative warrant liability		1,056,224			1,026,207			30,017			3	%
Net gain (loss) on sale of available for sale securities		(793,247	)		461,527			(1,254,774	)		(272	)%
Income tax benefit		122,949		$	414,233			(291,284	)		(70	)%
Net Loss	$	(39,237,941	)	$	(4,417,980	)	$	(34,819,961	)		788	%

We recorded a net loss of $39,237,941, or ($3.03) per basic and diluted common share, during the nine months ended April 30, 2013, as compared to a net loss of $4,417,980, or ($0.44) per basic and diluted common share, during the nine months ended April 30, 2012.

● Revenues decreased primarily due to lower oil and gas prices in 2013.

● Lease operating expense increased primarily due to the fact that an offshore field, Redfish Reef, that had been shut in during the nine months ended April 30, 2012 was online during the nine months ended April 30, 2013.

● 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 and to a reduction in estimated reserves because of unsuccessful drilling and recompletion results since 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. The reduction in expense is attributable to the reduction in the value of the award.

● During the nine months ended April 30, 2013, we incurred $37,234,752 of expense in conjunction with our acquisition of NEI. The transaction, which is a related party transaction, is discussed in detail in Note 2 of our Consolidated Financial Statements. This charge is the most significant difference in the results of operations from the comparable period in fiscal 2012. 2,490,000 shares of common stock were issued to the sellers of NEI and up to 22,410,000 additional shares of Duma common stock may be issued based on the achievement of certain market conditions over the next ten years. The estimated fair value of our commitment to issue the 22,410,000 shares was charged to expense as of the date of the transaction as required by relevant accounting standards. The estimated fair value of the contingently issuable shares was $31,612,000, the bulk of the charge. During the nine months ended April, 2012, we recognized a charge of $4,367,750 from the issuance of stock whose value exceeded the fair value of the assets 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 nine months ended April 30, 2012 and to a decrease in legal and professional expenses due to fewer litigation costs during the current year. The decrease in expense was offset by an increase in the expense associated with the amortization of stock option grants due to new option grants during the current year.

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● Interest expense increased because of the note payable acquired with Namibia Exploration, Inc. in August 2012, which was offset by a decrease in other notes payable balances outstanding during 2013 as compared with the comparable period in 2012.

● We re-measured our derivative warrants at fair value at every reporting date until the derivative feature expired in October and November 2012. Change in the fair value of the derivative warrants, as determined using a lattice model, during the nine months ending April 30, 2013 was more compared to the change in fair value for the nine months ended April 30, 2012, which resulted in a minor increase in the gain recognized.

● We incurred a loss on the sale of securities during the nine months ended April 30, 2013 due to the sale of securities that had declined in value since the time of acquisition. During the comparable period of 2012, we sold securities at a gain.

● We recognized an income tax benefit during the nine months ended April 30, 2012 due to an adjustment of the valuation allowance for our deferred tax assets. We determined that current deferred tax assets sufficient to offset deferred tax liabilities that had been acquired with the purchase of SPE Navigation 1, LLC existed. We also recognized an income tax benefit in comparable period of 2013 because our estimate of income tax payable for the year ended July 31, 2012 was higher than the actual income tax payable.

Liquidity and Capital Resources

The following table sets forth our cash and working capital as of April 30, 2013 and July 31, 2012:

	April 30, 2013				July 31, 2012
Cash and cash equivalents		$	513,155			$	1,102,987
Working capital (deficit)		$	(3,964,282	)		$	(1,865,472	)

At April 30, 2013, we had $513,155 of cash on hand and a working capital deficit of $3,964,282 ($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 April 30, 2013 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. We have several strategies underway to increase our working capital. The first is our divestiture of our southernmost field in Galveston Bay, Bolivar. This could bring in some additional cash, but more importantly it will streamline our operations and cut operating costs in the bay. Secondly, we plan to divest 25% working interest in our three northern fields in Galveston Bay. This may bring in several million dollars and allow us to accelerate our cash flow from production in the bay. The third strategy is by achieving a listing on a major stock exchange such as the NASDAQ, for which we have already applied. This could result in significantly more liquidity and viability for equity financing options sufficient to fund our operations. The fourth strategy is closely linked the third. We have several million warrants and options priced at $2.50 which, if exercised, could bring in a significant amount of cash.

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 volatile 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. 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 nine months ended April 30, 2013, operating activities provided $469,179 in comparison to cash used of $414,791 during the nine months ended April 30, 2012. The major reason for the difference was the paydown of accounts payable and accrued expenses that occurred during 2012.

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Net Cash  Provided by (Used in) Investing Activities

During the nine months ended April 30, 2013, investing activities used cash of $900,487 compared to cash provided of $2,850,708 during the nine months ended April 30, 2012. In 2013, the use of cash is attributable to investment in oil and gas assets. In 2012, the cash provided is attributable to proceeds from the sale of available for sale securities that had been acquired with the acquisition of SPE.

Net Cash Used in Financing Activities

Financing activities during the nine months ended April 30, 2013 used cash of $158,524 in comparison to $1,690,362 used during the nine months ended April 30, 2012. Financing activities during the current period consisted of payments relating to our insurance financing arrangements. During 2012, we repaid the balances outstanding on the line of credit and existing debt.

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.

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

The fair value of these warrants was determined using a lattice model with any change in fair value during the period recorded in earnings as “Gain (loss) on derivative warrant liability.”

Significant inputs used to calculate the fair value of the warrants include expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision.

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.

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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.

Off-Balance Sheet Arrangements

We have not entered into any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes of financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not required because we are a smaller reporting company.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Principal Executive Officer and Principal Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our Principal Executive Officer and Principal Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not effective, due to the deficiencies in our internal control over financial reporting as described in our Annual Report on Form 10-K for our fiscal year ended July 31, 2012, which deficiencies have not yet been remedied.

Internal Control over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during our fiscal quarter ended April 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except as disclosed below.

In February 2013, we hired an additional certified public accountant to serve as our controller. With the addition of this staff member, we now have two full time certified public accountants and a part time certified public accountant on staff. With the additional staff, we have implemented levels of review and approvals that will enhance our existing system of internal control. We have seen improvements in the segregation of duties relating to the financial reporting system, as the CFO has reduced participation in the preparation of the financial statements and in transaction processing and can now perform an effective review function.  In addition, senior management has had more time to dedicate to the overall design and monitoring of the system of internal controls.

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Part II Other Information

Item 1. Legal Proceedings

As of April 30, 2013, we were a party to the following legal proceedings:

1.         Cause No. 2011-37552; Strategic American Oil Corporation v. ERG Resources, LLC, et al.; In the 55th District Court, Harris County, Texas. The Company is a plaintiff in this suit. In this case, Company brought claims for injunctive relief, breach of contract and fraudulent inducement against the defendant regarding the purchase of Galveston Bay Energy, LLC from ERG. The Company intends to prosecute its claims and defenses vigorously. As of the date of filing of this report, the Company is no longer seeking injunctive relief. Additionally, the below listed case has been consolidated into this case since the subject matter of the below case is subsumed within the subject matter of this case. From this point forward, there will be only this one piece of litigation. The matter is set for trial in August 2013.

2.         Cause No. 2011-54428; ERG Resources, LLC v. Galveston Bay Energy, LLC, in the 125th Judicial District Court, Harris County, Texas. This case deals with the operating agreements for the processing of product by the entities owned by ERG. It is an action seeking payments of charges and expenses by ERG that are refuted by GBE. The Company intends to prosecute its claims and defenses vigorously. As indicated above, this case has been consolidated into the case listed above.As such, the claims in this case will be decided in cause No. 2011-37552, which is set for trial in August 2013.

Item 1A. Risk Factors

For information regarding our risk factors see the risk factors disclosed in Item 1A of our Annual Report on Form 10-K filed on November 13, 2012. There have been no material changes from the risk factors previously disclosed in such Annual Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

We issued no unregistered equity securities during the three months ended April 30, 2013.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit No.	Description of Exhibit
31.1	Certification of Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63.
101.INS	XBRL INSTANCE DOCUMENT
101.SCH	XBRL TAXONOMY EXTENSION SCHEMA
101.CAL	XBRL TAXONOMY EXTENSION CALCULATION LINKBASE
101.DEF	XBRL TAXONOMY EXTENSION DEFINITION LINKBASE
101.LAB	XBRL TAXONOMY EXTENSION LABEL LINKBASE
101.PRE	XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE

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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

DUMA ENERGY CORP.

/s/ Jeremy Glenn Driver

Jeremy Glenn Driver

President, Chief Executive Officer and a director

(Principal Executive Officer)

Date: June 14, 2013

/s/ Sarah Berel-Harrop

Sarah Berel-Harrop

Secretary, Treasurer and Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)

Date: June 14, 2013

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