Hydrocarb Energy (HECCQ) 10-Q 2012 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, 2012

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)

361-884-7474

(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 13, 2012, 10,789,703 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	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	25
Part II. Other Information
Item 1.	Legal Proceedings	26
Item 1A.	Risk Factors	26
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3.	Defaults Upon Senior Securities	26
Item 4.	(Removed and Reserved)	26
Item 5.	Other Information	26
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 (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, 2012			July 31, 2011
Assets
Current assets
Cash and cash equivalents	$	1,827,654		$	1,082,099
Oil and gas revenues receivable		720,694			875,918
Accounts receivable – related party		92,453			69,880
Available for sale securities		382,300			-
Other receivables, net		422,623			225,057
Other current assets		548,416			292,973
Total current assets		3,994,140			2,545,927
Oil and Gas Property, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $1,137,503 and $567,189, respectively; and accumulated impairment of $373,335 and $373,335, respectively		12,730,782			7,395,198
Unevaluated property		50,000			-
Restricted cash		6,650,000			6,716,850
Other assets		472,675			255,942
Property and equipment, net of accumulated depreciation of $33,981 and $11,158, respectively		36,614			22,857
Total Assets	$	23,934,211		$	16,936,774
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued expenses	$	3,440,668		$	1,676,816
Line of credit		-			1,360,573
Notes payable		168,442			255,596
Advances		57,423			-
Asset retirement obligations – short term		648,396			468,500
Derivative warrant liability		1,517,016			2,543,223
Due to related parties		-			14,723
Total current liabilities		5,831,945			6,319,431
Asset retirement obligations – long term		5,703,680			3,987,428
Total liabilities		11,535,625			10,306,859
Stockholders’ equity:
Common stock, $.001 par; 500,000,000 shares authorized shares; 10,791,003 and 6,790,816 shares issued and outstanding		10,791			6,791
Additional paid in capital		38,833,020			27,970,520
Accumulated other comprehensive loss		(679,849	)		-
Accumulated deficit		(25,765,376	)		(21,347,396	)
Total stockholders’ equity		12,398,586			6,629,915
Total liabilities and stockholders’ equity	$	23,934,211		$	16,936,774

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

4

DUMA ENERGY CORP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three months ended April 30,						Nine months ended April 30,
	2012			2011			2012			2011
Revenues	$	1,878,907		$	1,258,815		$	5,281,747		$	1,487,949
Operating expenses
Lease operating expense		948,176			652,632			2,815,750			793,020
Depreciation, depletion, and amortization		201,294			162,066			593,137			213,991
Accretion		149,760			95,898			433,554			99,562
Impairment		-			-			-			140,029
Consulting fees – related party		96,759			2,929,550			189,372			2,929,550
Acquisition cost – related party		-			-			4,367,750			-
Acquisition related costs		-			2,558,580			-			2,558,580
Settlement expense		-			1,800,000			-			1,800,000
Other general and administrative expense		742,833			613,785			3,079,673			1,832,504
Total operating expenses		2,138,822			8,812,511			11,479,236			10,367,236
Loss from operations		(259,915	)		(7,553,696	)		(6,197,489	)		(8,879,287	)
Interest expense, net		(19,782	)		(71,866	)		(122,458	)		(86,645	)
Loss on settlement of debt		-			(50,737	)		-			(50,737	)
Gain (loss) on derivative warrant liability		40,376			(651,128	)		1,026,207			(927,677	)
Gain on sale of available for sale securities		28,359			-			461,527			-
Net loss before income taxes		(210,962	)		(8,327,427	)		(4,832,213	)		(9,944,346	)
Income tax benefit		284,050			-			414,233			-
Net Income (Loss)	$	73,088		$	(8,327,427	)	$	(4,417,980	)	$	(9,944,346	)
Other comprehensive loss, net of tax:
Change in market value of available for securities, including unrealized loss and reclassification adjustments to net income, net of  income tax of $0, $0, $0, and $0		(666,415	)		-			(679,849	)		-
Comprehensive Loss	$	(593,327	)	$	(8,327,427	)	$	(5,097,829	)	$	(9,944,346	)
Basic income (loss) per common share	$	0.01		$	(1.26	)	$	(0.44	)	$	(2.79	)
Diluted income (loss) per common share	$	0.01		$	(1.26	)	$	(0.44	)	$	(2.79	)
Basic weighted average shares outstanding		10,791,003			6,634,716			10,027,370			3,560,396
Diluted weighted average shares outstanding		14,345,880			6,634,716			10,027,370			3,560,396

 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,
	2012			2011
Cash Flows From Operating Activities
Net loss	$	(4,417,980	)	$	(9,944,346	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		593,137			213,991
Impairment		-			140,029
Accretion		433,554			99,562
Write off of reclamation deposit		-			19,317
Change in income taxes		(417,750	)		-
Amortization of debt discount, loan origination fees and prepaid interest expense		101,659			8,019
(Gain) loss on settlement of debt		-			50,737
Gain on sale of available for sale securities		(461,527	)		-
Warrants amortization – related party		189,372			2,929,550
Common stock granted for services and for investor relations		620,156			108,620
Share based compensation – amortization of the fair value of  stock options		556,972			276,708
Acquisition-related costs paid in common stock		-			2,546,342
Equity award vested in conjunction with settlement, net of cash payment of $1,043,750		-			756,250
Acquisition cost – related party		4,367,750			-
(Gain) loss on warrant derivative liability		(1,026,207	)		927,677
Changes in operating assets and liabilities:
Accounts receivable		(42,342	)		(199,117	)
Accounts receivable – related party		(22,573	)		(71,275	)
Accounts payable and accrued expenses		(842,112	)		71,357
Advances		56,193			-
Other assets		(103,093	)		43,105
Net cash used in operating activities		(414,791	)		(2,023,474	)
Cash Flows From Investing Activities
Purchases of oil and gas properties		(436,769	)		(312,546	)
Purchases of property, equipment and domain name		(66,847	)		(3,031	)
Proceeds from sale of oil and gas properties		-			2,425,000
Change in restricted cash		54,946			-
Purchase of Galveston Bay Energy, LLC, net of cash acquired		-			(9,900,000	)
Purchase of available for sale securities		(702,958	)		-
Proceeds from sale of available for sale securities		4,002,336			-
Net cash provided by (used in) investment activities		2,850,708			(7,790,577	)
Cash Flows From Financing Activities
Proceeds from sales of common stock		-			9,232,719
Proceeds from notes payable		-			845,000
Payments on notes payable		(1,675,639	)		(160,147	)
Proceeds from notes payable to related parties		-			203,300
Payments on notes payable – related party		(14,723	)		-
Net cash provided by (used in) financing activities		(1,690,362	)		10,120,872
Net increase in cash		745,555			306,821
Cash at beginning of period		1,082,099			247,851
Cash at end of period	$	1,827,654		$	554,672

 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,
	2012		2011
Supplemental Disclosures:
Interest paid in cash	$	35,951	$	6,457
Income taxes paid in cash		17		-
Non-cash investing and financing
Non-cash capitalized interest	$	-	$	51,670
Asset retirement obligations sold		32,772		875,081
Asset retirement obligations assumed		-		5,494,487
Asset retirement obligations incurred		1,389		-
Exercise of warrants classified as a derivative		-		153,445
Notes receivable for sale of oil and gas properties		-		100,000
Acquisition of SPE Navigation I, LLC for Duma common stock, including asset retirement obligation assumed of $1,493,977		5,132,250		-
Accounts payable for oil and gas properties		1,567,868		-
Notes payable for prepaid insurance		227,912		136,930
Stock for notes payable and accounts payable		-		393,115
Adjustment of purchase price of acquisition: environmental liability acquired		112,500		-
Unrealized loss on available for sale securities, net		679,849		-
Loan origination fees paid with note payable		-		60,573

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

7

DUMA ENERGY CORP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Description of business and basis of presentation

Duma Energy Corp (“we”, “us”, “Duma”, the “Company”) was formed for the purpose of oil and gas exploration, development, and production. On April 4, 2012, we changed our name from Strategic American Oil Corporation to Duma Energy Corp.

The unaudited consolidated financial statements of Duma 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, 2011. 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, 2011, as reported in the Form 10-K, have been omitted.

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”) and Galveston Bay Energy, LLC (“GBE”). All significant intercompany accounts and transactions have been eliminated in consolidation.

Reclassifications

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

Available for sale securities

We invest in marketable equity securities which are classified as available for sale. Available-for-sale securities are marked to market based on the fair values of the securities determined in accordance with ASC Section 820 (Fair Value Measurement), with the unrealized gains and losses, net of tax, reported as a component of Accumulated other comprehensive income (loss).

Restricted cash

Restricted cash consists of certificates of deposit that have been posted as collateral supporting reclamation bonds guaranteeing remediation of our oil and gas properties in Texas. As of April 30, 2012 and July 31, 2011, respectively, restricted cash totaled $6,650,000 and $6,716,850. During the nine months ended April 30, 2012, the bond requirement reduced and accordingly, $66,850 of restricted cash was released to us.  The paying bank deducted $11,904 of outstanding interest payable and we received a net release of $54,946.

Other assets

Other assets at July 31, 2011 consisted primarily of prepaid land use fees, which are payments that cover multiple years (typically ten years) rental for easements and surface leases.  We acquired prepaid land use fees as part of our acquisition of Galveston Bay Energy, LLC (see Note 2 – Acquisition of Galveston Bay Energy, LLC) and we pay for rentals as they come due on an ongoing basis. We paid $284,844 in land use costs during the nine months ended April 30, 2012.  Other assets at April 30, 2012 consist of primarily of prepaid land use fees.  In addition, during the quarter ended April 30, 2012, we purchased, for $30,267, a domain name, which is an intangible asset with an indefinite life due to the fact that it is renewable annually for nominal cost.  We evaluate intangible assets with an indefinite for possible impairment at least annually by comparing the fair value of the asset with its carrying value.

Advances

Advances consist of prepayments received from working interest partners pertaining to their share of the costs of drilling oil and gas wells.  Partners are billed in advance for the estimated cost to drill a well and as the work proceeds, the prepayment is applied against their share of the actual drilling cost.

8

Common Stock Split

On April 4, 2012, we effected a 1 for 25 reverse stock split, which has been retroactively applied to all periods presented.

Earnings per share

Basic earnings per share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is computed by dividing net income by the weighted average number of common and potential common shares outstanding during the period. For the nine months ended April 30, 2012 and the three and nine months ended April 30, 2011, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.  During 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.

Comprehensive Income

Comprehensive income consists of net income (loss) and other gains and losses affecting stockholders’ equity that, under accounting principles generally accepted in the United States, are excluded from net income (loss). Unrealized loss on available for sale securities of $679,849 is included in Accumulated other comprehensive income (loss).

Recently issued or adopted 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

Galveston Bay Energy, LLC

On February 15, 2011 we closed on the acquisition of a private Texas oil and gas company named Galveston Bay Energy, LLC (“GBE”) which owns working interests in and operates producing oil and natural gas properties and its related facilities in four fields located in Galveston Bay, Texas.   Immediately following our acquisition of GBE, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer.  Our agreement with SPE provided that SPE could acquire an additional 10% working interest in the properties for $1,150,000 paid within 90 days of the acquisition.  Effective May 1, 2011, SPE acquired an additional 10% of our aggregate working interest in the Galveston Bay fields for an additional $1,150,000 pursuant to our agreement.  During the quarter ended April 30, 2011, we incurred $2,558,580 of acquisition costs, which are more fully described in our annual report for the year ended July 31, 2011, and which consist primarily of stock-based finders fees, in conjunction with this acquisition.

During the nine months ended April 30, 2012, we determined that we could estimate a range of potential loss associated with an environmental liability at one of the properties we acquired when we acquired GBE (See Note 11 – Commitments and Contingencies).  We adjusted the purchase price allocation for the purchase by increasing accounts payable acquired and oil and gas properties acquired by the amount that we recognized, $112,500 ($37,500 of the cost was recognized with the acquisition of SPE, thus a total of $150,000 is accrued for this contingency).  The adjustment did not change the identifiable net assets acquired.

SPE Navigation I, LLC

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

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

The transaction was a related party transaction because SPE was owned by companies controlled by our CEO, his brother-in-law, and his sister-in-law, and SPE was managed by our CEO’s father-in-law. The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition. The assets and liabilities were recorded at SPE’s carrying value on the date of the acquisition and the excess purchase price over the net assets acquired was $4,367,750, which was recorded as compensation expense because this was a related party transaction.  The transaction is intended to be structured, for tax purposes, as a tax-free merger, and as such, Duma would assume a carry-over basis in SPE’s assets. Consequently, a deferred tax liability was established.

9

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

Recognized Amount of Identifiable Assets Acquired and Liabilities Assumed

Available for sale securities (1)	$	3,900,000
Oil and Gas Property, accounted for using the full cost basis of accounting
Evaluated property (2)		4,081,477
Accounts payable and accrued expenses		(37,500	)
Deferred tax liability (1)		(1,317,750	)
Asset retirement obligations (2)		(1,493,977	)
Total Identifiable Net Assets	$	5,132,250

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

(2) Oil and gas properties include the asset retirement obligations measured on the effective date of the transaction at $1,493,977 and $2,550,000, which was the cash price that SPE paid to obtain its 25% working interest in the oil and gas properties and represents the fair value of the properties.

Supplemental pro forma information

The unaudited pro forma results presented below for the three and nine months ended April 30, 2012 and 2011 have been prepared to give effect to the purchases described above as if they had been consummated on August 1, 2009.  The unaudited pro forma results do not purport to represent what our results of operations actually would have been if the acquisitions had been completed on such date or to project our results of operations for any future date or period.

	Three months ended April 30,						Nine months ended April 30,
	2012			2011			2012			2011
Revenues	$	1,878,907		$	1,744,365		$	5,429,746		$	4,303,209
Loss from operations		(259,915	)		(7,370,783	)		(6,388,425	)		(9,943,035	)
Net income (loss)		73,088			(8,145,063	)		(4,608,916	)		(11,008,643	)
Earnings per share, basic and diluted	$	0.01		$	(0.55	)		(0.46	)		(0.94	)

Note 3 – Available for Sale Securities

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

The cost, unrealized gains (loss), and fair value of available for sale securities at April 30, 2012 were as follows:

Cost	$	1,062,149
Unrealized loss		(679,849	)
Fair Value	$	382,300

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

We acquired securities with a market value of $3,900,000 in conjunction with our acquisition of SPE. (See Note 2 – Acquisitions) During the nine months ended April 30, 2012, we received cash proceeds of $4,002,336 from sales of securities with a cost basis of $3,540,809; thus, we had a realized gain on sale of available for sale securities of $461,527.  During the nine months ended April 30, 2012, we purchased securities at a market price of $702,958. We reclassified $5,784 unrealized loss from other comprehensive loss into earnings during the nine months ended April 30, 2012. Available for sale securities are re-measured at fair value at every reporting date.  (See Note 8 – Fair Value)

10

Note 4 - Oil and Gas Properties

Oil and natural gas properties as of April 30, 2012 and July 31, 2011 consisted of the following:

	April 30, 2012			July 31, 2011
Oil and gas properties
Evaluated Properties:
Costs subject to depletion	$	13,868,285		$	7,962,387
Depletion		(1,137,503	)		(567,189	)
		12,730,782			7,395,198
Unevaluated Properties:		50,000			-
Total oil and gas properties	$	12,780,782		$	7,395,198

Evaluated property

Significant additions to oil and gas properties during the nine months ended April 30, 2012 include:

● The acquisition of an aggregate of approximately 25% working interest in our properties in Galveston Bay as part of our acquisition of SPE, as discussed in Note 2 – Acquisitions, for $4,081,477, which includes asset retirement obligations assumed of $1,493,977;

● Adjustment of $112,500 to the purchase price of GBE to reflect recognition of an estimate of the cost of soil remediation required to be completed at one of GBE’s facilities.  The remediation liability existed as of the date of acquisition;

● Land acquisition costs of $31,109;

● Geological and geophysical costs of $116,736;

● Development costs of $1,465,673, which includes $1,354,429 spent on a new drill to access proved undeveloped reserves offshore in Galveston Bay and $111,243 which was expended on a recompletion of one of our Welder wells onshore in South Texas and infrastructure improvements; and

● Exploratory drilling costs of $129,747 incurred on our Duval County Palacios #1 prospect and Hardeman County Prospect, as described below.

In September 2011, the operator in our Markham City, Illinois project area commenced drilling of three wells, which were completed during the nine months ended April 30, 2012. As of April 30, 2012, the operator had expended approximately $1,140,000 towards the Earnings Threshold.  In accordance with our farmout agreement, we will be required to contribute our 10% working interest share toward development of the area after the Earnings Threshold, $1,350,000, has been met.  We are currently responsible for our 10% working interest pertaining to routine operational expenses for completed wells.  In February 2012, the operator commenced a pilot water flood project to re-pressurize the reservoir and enhance recovery of oil from the area. We are currently producing oil from in the project area as water is injected into the reservoir and results are being monitored.  

In September 2011, we purchased a non-operated working interest in mineral leases covering 460 acres onshore in Duval County, Texas.  Under the agreement, the operator commenced drilling a well, the Palacios #1, during November 2011.  Our working interest in the lease area is 6.70732% to the casing point of the first well drilled and 5.5% after the casing point of the initial well and for subsequent operations in the lease area.  Our net revenue interest in the prospect is 4.125%.  At January 31, 2012, we had accumulated $37,120 of costs associated with this prospect, which was reflected as Unevaluated property on that date. We have expended approximately $59,000 in drilling and completing this well. In April 2012, we successfully completed the Palacios #1 well. Because the well is producing, the costs were reclassified from Unevaluated to Evaluated properties.

In February 2012, we purchased a non-operated working interest in mineral leases covering 200 acres onshore in Hardeman County, Texas.  The operator had commenced drilling in the area on January 28, 2012.  Our working interest in the lease area is 13.3% to the casing point of the first well drilled and 10.0% after the casing point of the initial well and for subsequent operations in the lease area.  Our net revenue interest in the prospect is 7.50%. The well encountered no natural fracturing in the native limestone of the target geological formation which greatly limited the productivity of oil in the well. All parties chose to abandon and plug the well. We incurred approximately $73,000 of costs associated with the drilling of the well and $16,000 of land acquisition costs for this prospect.  We are evaluating further opportunities in the field, including horizontal drilling.

In January 2012, we sold half of our working interest in the development well in Galveston Bay to several parties who assumed their share of costs and expenses.  After the sale, we owned a 25% interest in the well.   As of April 30, 2012 we have incurred approximately $1,354,429 in development costs for the drilling of this well.  We are currently in the completion phase.

In January 2012, we sold our 100% working interest in an onshore well.  The buyer assumed the asset retirement obligation for the well, $32,772.  We received no cash proceeds in conjunction with either sale. The assumed asset retirement obligation was the only consideration we received for these transactions.  In accordance with full cost rules, we recognized no gain or loss on the sales.

11

Unevaluated property

In April 2012, we acquired 25% working interest in Chapman Ranch II Prospect in Nueces County, Texas.  We paid $50,000 in acquisition and land costs for our interest in this prospect. According to the terms of the agreement, we will pay 31.25% of costs to casing point of the initial well and of the plug and abandonment costs if the initial well is a dry hole. For subsequent wells, we will pay 25% of the costs before and after the casing point. We have paid approximately $206,000 to the operator for the drilling and dry hole costs.  Drilling for this well had not commenced as of April 30, 2012, and the cash call paid is included in the caption “Other current assets”.

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 April 30, 2012 and July 31, 2011.  At April 30, 2012 and July 31, 2011, our 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 5 - Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of April 30, 2012 and July 31, 2011:

	April 30, 2012			July 31, 2011
Liability for asset retirement obligation, beginning of period	$	4,455,928		$	57,623
Asset retirement obligations assumed		1,493,977			5,843,330
Asset retirement obligations sold		(32,772	)		(1,523,573	)
Asset retirement obligations incurred		1,389			-
Accretion		433,554			213,866
Costs incurred		-			(135,318	)
Liability for asset retirement obligation, end of period	$	6,352,076		$	4,455,928

Note 6 - 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. The note is collateralized by our Galveston Bay properties and substantially all of GBE’s assets. Duma has also executed a parental guarantee of payment.

During the nine months ended April 30, 2012 we repaid $1,360,573, the then amount outstanding on the line of credit. Thus, there were no amounts outstanding as of April 30, 2012.

In May 2012, we extended the maturity date for the credit facility to August 15, 2012. The credit agreement provides that we were to submit a midyear reserve report, which we have not done. The bank has agreed to allow draws of up to half of the note until such time that this deficiency is corrected. We currently have no amounts outstanding on the loan.

We incurred $64,151 of loan origination fees which were amortized straight line over one year, the term of the loan. As of April 30, 2012 the entire amount has been amortized.

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Note 7 - Notes Payable

In November 2011, we paid $6,423 principal on a note payable due to a director and the associated accrued interest.

In October 2011, we paid $8,300 of principal on a note payable due to an officer and director of Duma.

During September 2011, we modified our insurance coverage and financed $18,667 of the premium due attributable to the endorsement.  We also paid the remaining installments for this insurance financing arrangement during the quarter ended April 30, 2012.

During November 2011, we paid off the $175,000 note payable due to one of our former directors.

In February 2012, we entered into a premium financing arrangement to pay principal of $209,244 in conjunction with our commercial insurance program renewal.  We are obligated to make nine payments of $24,578 per month, which include principal and interest, beginning in March 2012. At April 30, 2012, there was $168,442 remaining outstanding on this note.

Note 8 - 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.

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 April 30, 2012.

	Carrying Value at April 30,		Fair Value Measurement at April 30, 2012
	2012		Level 1		Level 2		Level 3
Assets:
Available for sale securities	$	382,300	$	382,300		-		-
Liabilities:
Derivative warrant liability	$	1,517,016		-		-	$	1,517,016

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.

Note 9 –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.

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

● 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 of Duma’s stock prices.  

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, 2012:

Beginning balance – August 1, 2011	$	2,543,223
Change in fair value of derivative warrant liability		(1,026,207	)
At April 30, 2012	$	1,517,016

The $1,026,207 change in fair value was recorded as a reduction of the derivative liability and as an unrealized gain on the change in fair value of the liability in our statement of operations.

Note 10 – Stockholders’ Equity

Common Stock Issuances

On April 4, 2012, we effected a reverse stock split of our authorized and issued and outstanding shares of common stock on a one new share for twenty-five old share basis (1:25). The effect of the reverse stock split has been retroactively applied to all periods presented.

As a result of the reverse split, our authorized share capital decreased from 500,000,000 shares of common stock to 20,000,000 shares of common stock and correspondingly, our issued and outstanding share capital decreased from 269,742,986 shares of common stock to 10,791,003 shares of common stock.

Effective May 16, 2012, Duma increased the number of its authorized shares of common stock from 20,000,000 shares, par value $0.001 per share, to 500,000,000 shares, par value $0.001 per share.

During December 2011 we granted 13,036 shares of common stock as compensation for services valued at $27,703. The shares were valued using the closing market price on the date of the grant.

During August 2011, we granted 189,585 shares of common stock to certain investors who had participated in our October and November 2009 equity raises, and as a consequence owned derivative warrants. These investors had exercised some of their warrants prior to our equity raise in February 2011, which triggered the down-round ratchet provision in the warrants.  The warrant contracts specify that the ratchet adjustment is not made for warrants that were exercised prior to the repricing event.  As a consequence of their warrant exercises, they had forfeited their contractual right to receive ratchet warrant shares.  However, management granted stock to these investors as a goodwill gesture.  The stock grant was treated as an investor relations expense and valued at $592,453.  The shares were valued using the closing market price on the date of grant.

During September 2011, we issued 3,799,998 million shares of common stock to the members of SPE Navigation I, LLC towards acquisition of SPE.  The purchase price was calculated as $9,500,000, based on the quoted market price of our stock on the date of the acquisition. (See Note 2 - Acquisitions).

Settlement Expense

During the nine months ended April 30, 2011, we incurred settlement expense of $1,800,000 in conjunction with the modification of stock awards made to two former directors of Duma.  The transaction is more fully discussed in our annual report for the year ended July 31, 2011.

Stock Options and Warrants

Duma may grant up to 1,600,000 shares of common stock under several historical stock-based compensation plans (the “Plans”). During April 2011, the Board of Directors authorized and approved the adoption of the 2011 Stock Incentive Plan (the “2011 Plan”). An aggregate of 1,000,000 shares of our common stock may be issued under the 2011 Plan. During August 2010, the Board of Directors authorized and approved the adoption of the 2010 Stock Incentive Plan (the “2010 Plan”). An aggregate of 200,000 shares of our common stock may be issued under the 2010 Plan. An aggregate of 400,000 of our shares may be issued under the 2009 Re-Stated Stock Incentive Plan (the “2009 Plan”).  The Plans are administered by the Board of Directors which has substantial discretion to determine persons, amounts, time, price, exercise terms, and restrictions of the grants, if any.

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There were no options grants during the nine month period ended April 30, 2012.

Options granted to non-employees

The following table provides information about options granted to consultants under our stock incentive plans during the nine months ended April 30, 2012 and 2011:

	2012		2011
Number of options granted		-		897,200
Compensation expense recognized	$	358,000	$	269,337
Compensation cost capitalized		-		-
Weighted average fair value of options  granted		-	$	2.50

For the options on a graded vesting schedule, we estimate the fair value of the award, using the Black-Sholes option pricing method, 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. Based on the fair value of the options as of April 30, 2012 there was $690,826 of unrecognized compensation cost related to non-vested share based compensation arrangements granted to non-employees.

The following table details the significant assumptions used to compute the fair market values of stock option expense associated with options granted to non-employees during the nine months ended April 30, 2012 and 2011:

	2012	2011
Risk-free interest rate	0.12-1.66%	0.51 – 2.66%
Dividend yield	0%	0%
Volatility factor	135.20-147.92%	134.62 - 153%
Expected life (years)	1 - 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, 2012 and 2011:

	2012		2011
Number of options granted		-		260,000
Compensation expense recognized	$	198,972	$	7,371
Compensation cost capitalized		-		-
Weighted average fair value of options  granted		-	$	2.50

As of April 30, 2012, there was $378,950 of unrecognized compensation cost associated with these options.

Summary information regarding all stock options issued and outstanding as of April 30, 2012 is as follows:

	Options		Weighted  Average Share Price		Aggregate  intrinsic value		Weighted  average remaining contractual life (years)
Outstanding at year ended July 31, 2011		1,101,200	$	2.50	$	1,101,200		8.14
Granted		-		-
Exercised		-		-
Expired		(57,200)		2.50
Outstanding at April 30, 2012		1,044,000	$	2.50	$	-		7.47

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Warrants

Summary information regarding stock warrants issued and outstanding as of April 30, 2012 is as follows:

	Warrants			Weighted Average  Share Price		Aggregate  intrinsic  value		Weighted average remaining  contractual  life (years)
Outstanding at year ended July 31, 2011		3,758,455		$	2.50	$	3,710,880		3.83
Granted		-			-
Exercised		-			-
Expired		(2,000	)		25.00
Outstanding at April 30,2012		3,756,455		$	2.58	$	-		2.98

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. In conjunction with the agreement, we granted warrants to purchase 800,000 shares of common stock that vested immediately and 1,200,000 shares of common stock that vest solely upon achievement of a market condition. 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.  If our common stock attains a five day average closing price of $15 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.

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.  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. The warrants to purchase 600,000 shares of common stock at $7.50 per share and 600,000 shares of common stock at $15 per share will be amortized over the derived service periods of 2.08 years and 2.49 years, respectively.  As of April 30, 2012, the fair value of the warrants to purchase 600,000 shares of common stock at $7.50 per share was $274,077 and the fair value of the warrants to purchase 600,000 shares at $15 per share was $226,209.  We recognized $189,372 of expense associated with these warrants during the nine months ended April 30, 2012.

Note 11 – Commitments and Contingencies

We are subject to various federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment as an owner or lessee and operator of oil and gas properties.  These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages.  In some instances, we may be directed to suspend or cease operations in the affected area.  We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.

There is soil contamination at a tank facility owned by GBE.  As of July 31, 2011, we had determined that it was probable that remediation would be required and we were evaluating the extent of the contamination, the activities that will be required to perform the remediation, and whether the former owner would be required to assume the remediation.  As of July 31, 2011, we concluded that the cost of the remediation was not estimable and, accordingly, it had not been reflected in our financial results.

During the nine months ended April 30, 2012, we continued evaluation of the site and concluded that we could reasonably estimate a range of potential cost. Depending on the technique used to perform the remediation, we estimate the cost range to be between $150,000 and $500,000.  We cannot determine a most likely scenario, thus we have recognized the lower end of the range.  $150,000 has been recognized and is included in the balance sheet caption Accounts payable and accrued expenses.  Because the liability was acquired with the acquisitions, we have adjusted the cost of acquired oil and gas properties to reflect the estimate of loss.

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 a letter of credit in the amount of $6,610,000 issued by Green Bank. The letter of credit is collateralized by a certificate of deposit with Green Bank, which is included in long term assets under the caption “Restricted Cash”.  We pay a 1.5% per annum fee in conjunction with this letter of credit. The fee, $99,400 was prepaid in June 2011 and is being amortized on a straight line basis through the letter of credit’s renewal in October 2012. As of April 30, 2012, $66,267 had been amortized.  Subsequent to the balance sheet date, we were informed by the Railroad Commission of Texas that they would require a letter of credit in the amount of $6,670,000.  In June 2012, we added $60,000 to restricted cash and obtained the revised letter of credit.

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Note 12 – Related Party Transactions

A company controlled by one of our officers operates our Barge Canal properties.  The following table summarizes the activity associated with the Barge Canal properties:

	Three months ended April 30,				Nine months ended April 30,
	2012		2011		2012		2011
Revenues	$	149,042	$	143,344	$	424,923	$	325,202
Lease operating costs	$	48,710	$	49,042	$	139,832		134,462

As of April 30, 2012 and July 31, 2011 respectively, we had outstanding accounts receivable associated with these properties of $92,453 and $69,880 and no accounts payable.

In November 2011, we paid $6,423 principal on a note payable due to a director.  We also paid the associated accrued interest of $416.

In October 2011, we paid $8,300 of principal on a note payable due to an officer and director of Duma. We also paid the accrued interest associated with the note of $413.

On September 23, 2011, we purchased SPE Navigation I, LLC, as more fully discussed in Note 2 – Acquisitions, with 3,799,998 shares of Duma common stock.  The owners of SPE were companies owned by the CEO of Duma, his brother-in-law, and his sister-in-law. Because the purchase price, $9,500,000, as computed using the fair value of the 3,799,998 shares on the date of purchase, exceeded the net assets acquired, we recognized compensation expense on the excess, $4,367,750. (See Note 2 - Acquisitions).

We entered into a consulting contract with a company controlled by the father-in-law of our CEO, Michael Watts, in February 2011.  Under the contract, Mr. Watts will provide investor relations services.  Mr. Watts received warrants to purchase 800,000 shares of Duma common stock at $2.50 per share exercisable through February 2016 upon execution of the contract.  Additionally, he received warrants to purchase 1,200,000 shares of Duma common stock at $2.50 per share, which expire in February 2016.  The warrants vest if our common stock achieves certain market prices.  The compensation cost is determined using a lattice model as discussed in Note 10 – Stockholders’ Equity.  During the nine months ended April 30, 2012, we recognized $189,372 of compensation cost associated with these warrants.

Note 13 – Subsequent Events

In May 2012, GBE modified our revolving line of credit. The modification involved a change in the interest rate so that the Index is the floating prime interest rate as quoted by Wall Street Journal + 1% with no minimum specified rate. The interest rate currently is at 3.25%.  The maturity date of the loan has been extended to August 15, 2012.

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CAUTIONARY STATEMENT ON FORWARD-LOOKING INFORMATION

The Company is including the following cautionary statement to make applicable and take advantage of the safe harbor provision of the Private Securities Litigation Reform Act of 1995 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” and the “Company” mean Duma Energy Corp and its wholly owned subsidiaries, Penasco Petroleum Inc., and Galveston Bay, LLC 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, 2012 should be read in conjunction with our unaudited consolidated interim financial statements and related notes for the nine months ended April 30, 2012 included in this Quarterly Report, as well as our Annual Report on Form 10-K for the year ended July 31, 2011.

Operation Plans and Focus

We are currently focused on completing our ST9-12A #4 well in Fisher’s Reef Field in Galveston Bay which was drilled in early 2012. In addition to this newly drilled well, our broader focus is on increasing production from all four fields in Galveston Bay and Trinity Bay. Based upon our geological review and analysis, there exists numerous opportunities within each field to quickly and easily increase production without the necessity of additional drilling. It is our intention to focus on this “low hanging fruit” and then proceed to consider additional drilling projects.

Specifically, Red Fish Reef Field which was recently brought back on-line having been shut-in for over a year, holds a great deal of additional potential. We will first focus on the production infrastructure of the field and then focus on the individual wells. One of our initial projects in the field will be to reduce back pressure on all wells by implementing the use of a pump on the production platform in the bay. This reduction in back pressure could increase production by as much as 15-25% before additional work is done to increase the production rates from individual wells. Of course, the next step is to begin work on those wells that have the most potential for the least risk. Our field study has indicated several high priority projects that we expect to initiate within the coming months, including several wells that require only minimal mechanical repair to reestablish production.

Outside of Galveston Bay, our geological and engineering team headed by our Vice President, Steven Carter, have been actively developing drillable prospects in South Texas as well as participating in drilling projects on a minority basis. Our recent successful participation in the Palacios #1 well is beginning to bear fruit and we hope to continue on this track. The focus is primarily on generating our own in-house drilling projects which can then be promoted out to industry partners and investors on a traditional third-for-a-quarter basis. This strategy reduces our exploration and financial risk to an insignificant level.

In this process, our geologists must first locate and research hundreds of potential prospects before finally discovering projects they believe have significant potential. After an iterative process of review and rework between our engineering and geological staff, these prospects must then be submitted to management for investment review at which point a decision is made to move the project forward and begin capital investment, which likely entails leasing acreage to secure the prospect, drafting and printing of maps and presentation materials for marketing, and finally marketing the prospect to potential investors and partners. Our exploration department has already identified at least 4 different projects areas outside of Galveston Bay that appear to have significant potential in excess of a million barrels of oil equivalent, primarily focused on oil-rich targets rather than natural gas.

Results of Operations

Three months ended April 30, 2012 compared to the three months ended April 30, 2011:

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Production data:

	Three months ended April 30,
	2012						2011
	Oil (Bbls)		Gas (Mcf)		Total (Mcfe)		Oil (Bbls)		Gas (Mcf)		Total (Mcfe)
Production		15,966		36,161		131,957		12,274		13,785		87,428
Average sales price	$	112.29	$	2.38	$	14.24	$	98.03	$	4.03	$	14.40
Average lease operating expense					$	7.19					$	7.00

Statements of operations:

	Three months ended April 30,
	2012			2011			Increase/ (Decrease)			% Change
Revenues	$	1,878,907		$	1,258,815		$	620,092			49	%
Operating expenses										��
Lease operating expense		948,176			652,632			295,544			45	%
Depreciation, depletion, and amortization		201,294			162,066			39,228			24	%
Accretion		149,760			95,898			53,862			56	%
Consulting fees – related party		96,759			2,929,550			(2,832,791	)		(97)	%
Acquisition related costs		-			2,558,580			(2,558,580	)		(100)	%
Settlement expense		-			1,800,000			(1,800,000	)		(100)	%
Other general and administrative expense		742,833			613,785			129,048			21	%
Total operating expenses		2,138,822			8,812,511			(6,673,689	)		(76)	%
Loss from operations		(259,915	)		(7,553,696	)		(7,293,781	)		(97)	%
Interest expense, net		(19,782	)		(71,866	)		(52,084	)		(72)	%
Loss on settlement of debt		-			(50,737	)		(50,737	)		(100)	%
Gain (loss) on derivative warrant liability		40,376			(651,128	)		691,504			106	%
Gain on sale of marketable securities		28,359			-			28,359			100	%
Income  tax benefit		284,050			-			284,050			100	%
Net Income (Loss)	$	73,088		$	(8,327,427	)	$	(8,400,515	)		(101)	%

We recorded net income of $73,088, or $0.01 per basic and diluted common share, during the quarter ended April 30, 2012, as compared to a net loss of $8,327,427, or ($1.26) per basic and diluted common share, during the quarter ended April 30, 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.  We purchased SPE on September 23, 2011.  Our consolidated financial statements include the results associated with the working interest in oil and gas properties in Galveston Bay, Texas acquired in these two transactions.  Through these working interests, we produced from oil and gas wells in four fields. The results for 2011 consist of 2.5 months of operations as opposed to three months; also, our ownership during the three months ended April 30, 2012 included SPE’s share of the working interest in the Galveston Bay properties, 25%.

● 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.  This company is a related party, as it is controlled by the father-in-law of our CEO, Jeremy Driver. The decrease in the expense in relation to the comparable prior period is because the expenses in the prior period included the immediate vesting of options to purchase 800,000 shares of common stock.  In contrast, the current period includes the amortization of an award with a market condition whose cost is recognized over a multiple year service period.  Because the award carries a market condition, its value is lower than the grant that immediately vested.

● Acquisition related costs - we granted stock to consultants as finders’ fees for their role in effecting the acquisition of GBE and we also paid due diligence fees during the three months ending April 30, 2011.  This was a one-time charge.

● Settlement expenses – During the three months ended April 30, 2011, we reached 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.

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● Our increase in general and administrative expenses are attributable to increases in compensation cost, offset by decreases in consulting expenses.  Our compensation costs increased because of additional staffing as well as salary increases for staff members who had been originally been hired during the quarter ended April 30, 2011 on a provisional wage and because of increased compensation to our CEO and Vice President of Operations, which took effect in June 2011.  Consulting decreased because we discontinued investor relations programs.   Additionally, during the quarter ended April 30, 2012, we evaluated the collectability of a note receivable for the sale of some properties and determined that it should be reserved; accordingly we experienced a charge to bad debt expense of approximately $45,000.

● GBE maintains a letter of credit to satisfy a Texas Railroad Commission requirement and has a line of credit with a commercial bank.  During the three months ended April 30, 2012 we had no balance outstanding on the line of credit which resulted in a decrease in interest expense in relation to the comparable prior quarter.

● We re-measure our derivative warrants at fair value at every reporting date.  Change in the fair value of the derivative warrants, as determined using a lattice model, for the three months ending April 30, 2012 was less compared to the change in fair value for the three months ended April 30, 2011 and hence the decrease in the loss recognized.

● We acquired stock that had a tax basis that was lower than its book basis when we purchased SPE.  We sold shares of that stock during the nine months ended April 30, 2012, which resulted in realized gains and, accordingly, income tax payable.  However we also incurred expenses for tax purposes that were capitalized for book purposes, which reduced the amount that we expect to pay in income tax for the year ended July 31, 2012.  Thus, we adjusted income tax payable to reflect the taxes due based on estimated tax income.  This, as well as intangible drilling costs and dry hole costs incurred during 2012, results in a tax benefit.

We do not expect the gain on the sale of available for sale securities to occur on a recurring basis.  The increases in revenue, lease operating expense, depreciation, depletion, and amortization expense, accretion expense, general and administrative, and interest expense are associated with our expanded size and scope.  While we are evaluating areas where we can reduce costs in both lease operating expense and general and administrative expense, a major portion of the increase from 2011 will be an ongoing element in our financial results.

Nine months ended April 30, 2012 compared to the nine months ended April 30, 2011

Production data:

	Nine months ended April 30,
	2012						2011
	Oil (Bbls)		Gas (Mcf)		Total (Mcfe)		Oil (Bbls)		Gas (Mcf)		Total (Mcfe)
Production		43,581		146,059		407,547		14,828		21,198		110,168
Average sales price	$	109.55	$	3.47	$	12.96	$	94.76	$	3.90	$	13.51
Average lease operating expense					$	6.91					$	7.00

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Statements of operations:

	Nine months ended April 30,
	2012			2011			Increase/ (Decrease)			% Change
Revenues	$	5,281,747		$	1,487,949		$	3,793,798			255	%
Operating expenses
Lease operating expense		2,815,750			793,020			2,022,730			255	%
Depreciation, depletion, and amortization		593,137			213,991			379,146			177	%
Accretion		433,554			99,562			333,992			335	%
Impairment		-			140,029			(140,029	)		(100)	%
Consulting fees – related party		189,372			2,929,550			(2,740,178	)		(94)	%
Acquisition cost – related party		4,367,750			-			4,367,750			100	%
Acquisition related costs		-			2,558,580			(2,558,580	)		(100)	%
Settlement expense		-			1,800,000			(1,800,000	)		(100)	%
Other general and administrative expense		3,079,673			1,832,504			1,247,169			68	%
Total operating expenses		11,479,236			10,367,236			1,112,000			11	%
Loss from operations		(6,197,489	)		(8,879,287	)		2,681,798			(30)	%
Interest expense, net		(122,458	)		(86,645	)		(35,813	)		41	%
Loss on settlement of debt		-			(50,737	)		50,737			(100)	%
Gain (loss) on derivative warrant liability		1,026,207			(927,677	)		1,953,884			(211)	%
Gain on sale of available for sale securities		461,527			-			461,527			100	%
Income tax benefit		414,233			-			414,233			100	%
Net Loss	$	(4,417,980	)	$	(9,944,346	)	$	(5,526,366	)		(56)	%

We recorded a net loss of $4,417,980, or ($0.44) per basic and diluted common share, during the nine months ended April 30, 2012, as compared to a net loss of $9,944,346 or ($2.79) per basic and diluted common share, during the nine months ended April 30, 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 because of the inclusion of the results of our new subsidiaries, GBE and SPE.  We purchased GBE on February 15, 2011.  We purchased SPE on September 23, 2011.  Our consolidated financial statements include the results associated with the working interest in oil and gas properties in Galveston Bay, Texas acquired in these two transactions.  Through these working interests, we produced from oil and gas wells in four fields. This represents a substantial increase in our operations.

● We recorded an  impairment charge during the nine months ended April 30, 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 relates to the recognition of expense associated with warrants granted as compensation to a company for investor relations and public relations services in February 2011.  This company is a related party, as it is controlled by the father-in-law of our CEO, Jeremy Driver. The decrease in the expense in the current quarter in relation to the comparable prior quarter is because the expenses in the prior period were due to the recognition of the fair value of compensation whereas the current period has only changes in the fair value as of April 30, 2012 recorded.

● We incurred an expense charge 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.

● Acquisition related costs - we granted stock to consultants as finders’ fees for their role in effecting the acquisition of GBE and we also paid due diligence fees during the nine months ended April 30, 2011 and these were not incurred during the comparable period of 2012.

● Settlement expenses – During the nine months ended April 30, 2011, we reached 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 did not recur during the comparable current period.

● 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.   Additionally, as of June 2011, executive compensation increased by approximately $130,000 on an annualized basis.  Accordingly, general and administrative expenses increased by approximately $850,000, primarily due to increases in compensation, rent, and other general office costs. This includes an increase of approximately $300,000 of expense attributable to stock awards and amortization of option awards.  Audit and professional fees increased approximately $300,000 due to our larger scope of operations and some non-recurring expenditures such as acquisition audits and litigation costs.  Consulting and investor relations expense increased $85,000, which is attributable to approximately $600,000 associated with a stock grant during the quarter ended October 31, 2011 offset by an approximately $500,000 decrease in expense due to non-repeated programs from 2011.

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● GBE maintains a letter of credit to satisfy a Texas Railroad Commission requirement and has a line of credit with a commercial bank.  Because of these arrangements, interest expense increased.

● 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 April 30, 2012 as compared with July 31, 2011, resulting in a gain on derivative warrant liability; whereas the change in fair value of the warrants in the comparative prior period resulted in a loss.

● We acquired equity securities with our acquisition of SPE.  We sold securities with a cost basis of $3,540,809 for proceeds of $4,002,336, resulting in a gain on the sale of the securities.

● 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 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 Navigation 1, LLC.  In addition, we incurred intangible drilling costs and dry hole costs that resulted in tax losses that also offset the recognized tax gain on securities sold, and thus we recognized a tax benefit associated with the costs.

We do not expect the gain on the sale of available for sale securities to occur on a recurring basis.  The increases in revenue, lease operating expense, depreciation, depletion, and amortization expense, accretion expense, and interest expense are associated with our expanded size and scope.  While we are evaluating areas where we can reduce costs in both lease operating expense and general and administrative expense, a major portion of the increase from 2011 will be an ongoing element in our financial results.

Liquidity and Capital Resources

The following table sets forth our cash and working capital as of April 30, 2012 and July 31, 2011:

	April 30, 2012			July 31, 2011
Cash and cash equivalents	$	1,827,654		$	1,082,099
Working capital (deficit)	$	(1,837,805	)	$	(3,773,504	)

At April 30, 2012, we had $1,827,654 of cash on hand and a working capital deficit of $1,837,805 ($1,517,016 is attributable to a warrant derivative liability which would ordinarily be settled in stock). The current working capital deficit reflects the impact of our recent drilling and capital investment activities. We believe our working capital on April 30, 2012, as well as our revenues from currently producing wells and projects that are in progress, such as the completion of our well in Galveston Bay, is sufficient to enable us to pursue our lease operating costs, to pay our general and administrative expenses, and to pursue our plan of operations over the next 12 months.

Various conditions outside of our control may detract from our ability to raise the capital needed or to generate the revenue necessary to execute our plan of operations, including the price of oil as well as the overall market conditions in the international and local 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 as to a high of $114 per barrel, but they have decreased to approximately $87 per barrel as of May 2012. While we do receive a premium on most of our oil produced, if the price of oil drops to levels seen in previous years, we recognize that it will adversely affect our ability to fund our operations. Any of these factors could have a material impact upon our short-term or long-term liquidity.

Net Cash Used in Operating Activities

During the nine months ended April 30, 2012, operating activities used $414,791 in comparison to cash used of $2,023,474 during the nine months ended April 30, 2011. The decrease in the cash used in operating activities is primarily attributable to increase in income generated from properties acquired net of operating expenses. Also, prior to our acquisition of GBE, 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, we derive a much greater percentage of our cash flows from operations from revenues and direct operating costs.  Because the Galveston Bay properties will increase our contribution margin from our core activities, the acquisition should continue to enhance our cash flows from operations.

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Net Cash Provided by (Used in) Investing Activities

During the nine months ended April 30, 2012, investing activities provided cash of $2,850,708 compared to cash used of $7,790,577 during the nine months ended April 30, 2011. In 2012, the cash provided is mainly attributable to proceeds from the sale of available for sale securities offset partially by purchase of oil and gas properties and available for sale securities.  In 2011, cash was used towards the purchase of GBE. We also received proceeds from the sale of oil and gas properties. We expect to use cash in investing in the future due to our planned investment in the fields that we acquired when we acquired GBE.

Net Cash (Used in) Provided by Financing Activities

Financing activities during the nine months ended April 30, 2012 used cash of $1,690,362 in comparison to $10,120,872 provided during the comparable prior period. Financing activities during the current period consisted of payments of existing debt and the line of credit. During the comparable prior period our financing activities consisted primarily of sale of common stock and payments on notes payable.  As of April 30, 2012, we have minimal 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.

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.

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

Asset Retirement Obligations

We record the fair value of an asset retirement cost, and corresponding liability as part of the cost of the related long-lived asset and the cost is subsequently allocated to expense using a systematic and rational method. We record an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of our oil and natural gas wells and gas gathering systems. We estimate the expected cash flow associated with the obligation and discount the amount using a credit-adjusted, risk-free interest rate. At least annually, we reassess the obligation to determine whether a change in the estimated obligation is necessary. We evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), we will accordingly update our assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells and gas gathering systems as these obligations are incurred.

Fair Value

Accounting standards regarding fair value of financial instruments define fair value, establish a three-level hierarchy which prioritizes and defines the types of inputs used to measure fair value, and establish disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheets.

Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.

The three-level hierarchy is as follows:

● Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets.

● Level 2 inputs consist of quoted prices for similar instruments.

● Level 3 valuations are derived from inputs which are significant and unobservable and have the lowest priority.

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

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

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

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

Stock-Based Compensation

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

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

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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, 2011, 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, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II Other Information

Item 1. Legal Proceedings

As of April 30, 2012, 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.

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

Item 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 15, 2011. 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

None.

Item 3. Defaults Upon Senior Securities

None.

Item  4. (Removed and Reserved)

None.

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, 2012

/s/ Sarah Berel-Harrop

Sarah Berel-Harrop

Secretary, Treasurer and Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)

Date: June 14, 2012

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