Hydrocarb Energy (HECCQ) 10-K/A 2010 FY Annual report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

S ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended July 31, 2010

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

STRATEGIC AMERICAN OIL CORPORATION

(Exact name of registrant as specified in its charter)

Nevada	98-0454144
(State or other jurisdiction of incorporation of organization)	(I.R.S. Employer Identification No.)
800 Gessner, Suite 200, Houston, Texas	77024
(Address of Principal Executive Offices)	(Zip Code)

(281) 408-4880

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, Par Value $0.001

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No S

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of Section 15(d) of the Act. Yes o No S

Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes xNo o

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer £	Accelerated filer £
Non-accelerated filer £ (do not check if a smaller reporting company)	Smaller reporting company S

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed by reference to the price at which the registrant’s common equity was last sold, as of January 31, 2010 (the last day of the registrant’s most recently completed second fiscal quarter) was approximately $13,000,000.

The registrant had 53,409,155 shares of common stock outstanding as of November 12, 2010.

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EXPLANATORY NOTE

This amendment to our annual report on Form 10-K for our fiscal year ended July 31, 2010 is being filed in response to guidance that we have received from staff at the Securities and Exchange Commission.  The purpose of this amendment is to:

· restate our previously issued consolidated financial statements to recognize an expense for the fair market value of modifications to the terms of certain warrants;

· restate our previously issued consolidated financial statements to reflect a change in the valuation model from a black-sholes option pricing model to a lattice model for certain warrants;

· add Note 2, “Restatement of Previously Issued Consolidated Financial Statements,” to show the effects of the restatement on the Consolidated Balance Sheet and Statement of Operations as of and for the year ended July 31, 2010;

· reflect the restatements of our financial statements in our management discussion and analysis and risk factors;

· correct the Summary Compensation Table to reflect the grant-date fair value of option awards (originally the compensation expense recognized was reflected); and

· to include an additional exhibit under Item 15, specifically, exhibit 99.1

The following table summarizes the financial statement caption adjustments to our previously reported consolidated statement of operations (in thousands):

	Year Ended July 31, 2010
Balance Sheet
Warrant derivative liability	$	$(909,009	)
Additional paid in capital	$	$571,401
Accumulated deficit	$	$337,608
Statement of Operations
Revenues	$	-
Operating expenses		742,202
Gain on warrant derivative liability		1,079,810
Effect on net loss	$	337,608

All other financial information and other information in the originally filed Form 10-K for the reported periods remains unchanged.

This Form 10-K/A does not reflect events occurring after the filing of the original Form 10-K for our year ended July 31, 2010, or modify or update the disclosure therein in any way other than as required to reflect the amendments set forth herein.  Readers are cautioned to review our Company Exchange Act filings subsequent to the filing of the original Form 10-K for our year ended July 31, 2010, including without limitation our current reports on Form 8-K.

FORWARD LOOKING STATEMENTS

This annual report contains forward-looking statements that involve risks and uncertainties. Any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “should”, “expect”, “plan”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential” or “continue”, the negative of such terms or other comparable terminology. In evaluating these statements, you should consider various factors, including the assumptions, risks and uncertainties outlined in this annual report under “Risk Factors”. These factors or any of them may cause our actual results to differ materially from any forward-looking statement made in this annual report. Forward-looking statements in this annual report include, among others, statements regarding:

· our capital needs;

· business plans; and

· expectations.

While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding future events, our actual results will likely vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested herein. Some of the risks and assumptions include:

· our need for additional financing;

· our exploration activities may not result in commercially exploitable quantities of oil and gas on our properties;

· the risks inherent in the exploration for oil and gas such as weather, accidents, equipment failures and governmental restrictions;

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· our limited operating history;

· our history of operating losses;

· the potential for environmental damage;

· our lack of insurance coverage;

· the competitive environment in which we operate;

· the level of government regulation, including environmental regulation;

· changes in governmental regulation and administrative practices;

· our dependence on key personnel;

· conflicts of interest of our directors and officers;

· our ability to fully implement our business plan;

· our ability to effectively manage our growth; and

· other regulatory, legislative and judicial developments.

We advise the reader that these cautionary remarks expressly qualify in their entirety all forward-looking statements attributable to us or persons acting on our behalf. Important factors that you should also consider, include, but are not limited to, the factors discussed under “Risk Factors” in this annual report.

The forward-looking statements in this annual report are made as of the date of this annual report and we do not intend or undertake to update any of the forward-looking statements to conform these statements to actual results, except as required by applicable law, including the securities laws of the United States.

AVAILABLE INFORMATION

Strategic American Oil Corporation files annual, quarterly and current reports, proxy statements, and other information with the Securities and Exchange Commission (the “SEC”). You may read and copy documents referred to in this Annual Report on Form 10-K/A that have been filed with the SEC at the SEC’s Public Reference Room, 450 Fifth Street, N.W., Washington, D.C. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You can also obtain copies of our SEC filings by going to the SEC’s website at http://www.sec.gov.

REFERENCES

As used in this annual report: (i) the terms “we”, “us”, “our”, “Strategic American” and the “Company” mean Strategic American Oil Corporation; (ii) “SEC” refers to the Securities and Exchange Commission; (iii) “Securities Act” refers to the United States Securities Act of 1933, as amended; (iv) “Exchange Act” refers to the United States Securities Exchange Act of 1934, as amended; and (v) all dollar amounts refer to United States dollars unless otherwise indicated.

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TABLE OF CONTENTS

		PAGE
ITEM 1.	BUSINESS	6
ITEM 1A.	RISK FACTORS	12
ITEM 1B.	UNRESOLVED STAFF COMMENTS	16
ITEM 2.	PROPERTIES	16
ITEM 3.	LEGAL PROCEEDINGS	16
ITEM 4.	[REMOVED AND RESERVED]	16
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	17
ITEM 6.	SELECTED FINANCIAL DATA	18
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	24
ITEM 8.	FINANCIAL STATEMENTS	25
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	58
ITEM 9A.	CONTROLS AND PROCEDURES	58
ITEM 9B.	OTHER INFORMATION	59
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	59
ITEM 11.	EXECUTIVE COMPENSATION	63
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	67
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	68
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	69
ITEM 15.	EXHIBITS	70

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PART I

ITEM 1.  BUSINESS

Corporate Organization

We were incorporated under the laws of the State of Nevada on April 12, 2005 under the name “Carlin Gold Corporation”. On July 19, 2005, we changed our name to “Nevada Gold Corp.” On October 18, 2005, we changed our name to “Gulf States Energy, Inc.” and increased our authorized capital from 100,000,000 shares of common stock to 500,000,000 shares of common stock, par value $0.001 per share. On September 5, 2006, we changed our name to “Strategic American Oil Corporation”.

We own 100% of the issued and outstanding share capital of Penasco, which was formed under the laws of the State of Nevada on November 23, 2005.

Our principal offices are located at 600 Leopard Street, Suite 2015, Corpus Christi, Texas, 78401. Our telephone number is (361) 884-7474 and our fax number is (361) 884-7347.

General

We are a natural resource exploration and production company engaged in the exploration, acquisition and development of oil and gas properties in the United States. We maintain an aggregate of approximately 395 gross (217 net) developed acres and approximately 6,120 gross (4,456 net) undeveloped acres pursuant to leases or acquisitions as described below. Of that acreage, we maintain approximately 176 gross (132 net) developed acres in Louisiana, 219 gross (85 net) developed acres in Texas, 4,614 gross (3,123 net) undeveloped acres in Illinois, 160 gross (150 net) undeveloped acres in Louisiana, and 1,346 gross (1,183 net) undeveloped acres in Texas.

Total developed and undeveloped acreage is approximately 6,515 gross acres (4,673 net).

Exploration and Production Activities

Our oil and gas interests are as follows:

The Welder Lease (Barge Canal), Texas

On November 16, 2006 we completed an assignment and purchase agreement with OPEX Energy, LLC with an effective date of August 1, 2006. Under the terms of the agreement, we acquired a 100% working interest (90% after payout) and a 72.5% net revenue interest (65.25% after payout) in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas. At the time of the acquisition, the two wells on the Welder lease were producing assets.

Effective January 1, 2010, we acquired the remaining 10% working in the Welder Leases from Treydan Corporation and own 100% of the working interest.

As of the date of this annual report, two wells are producing gas and oil from the property. The wells are operated using a gas lift system. A third well is utilized for salt water disposal. The wells have additional proven non-producing zones behind pipe. We intend to develop the proved developed non-producing (PDNP) zones as current producing horizons deplete.

South Delhi/Big Creek Field, Louisiana

On August 24, 2006, we entered into an assignment of oil and gas interests purchase agreement with Energy Program Accompany, LLC (the “EPA Purchase Agreement”). At the time of the acquisition, one of four wells on the Holt lease and the one well on the Strahan lease were producing assets. Under the terms of the EPA Purchase Agreement, we paid $250,000 to acquire the Holt Lease, the Strahan Lease and the McKay Lease (no longer owned), as described below.

The Holt Lease

Pursuant to the EPA Purchase Agreement, we acquired a 97% working interest and an 81.25% net revenue interest in approximately 136 acres in Franklin Parish, Louisiana (the “Holt Lease”).

As of the date of this annual report, we are producing oil from the Holt No.’s 10 and 22 wells. The Holt No. 4 and 24 wells are off-line pending workover or offset drilling. The Holt No. 15 well is utilized as a salt water disposal well.

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The Strahan Lease

Pursuant to the EPA Purchase Agreement, we acquired a 100% working interest and an 81.25% net revenue interest in approximately 40 acres in Richland Parish, Louisiana (the “Strahan Lease”).

As of the date of this annual report, we are producing oil from the Strahan No. 1 well.

Assignment of Interests to Tradestar Resources Corporation

In conjunction with our acquisition of the Holt Lease and the Strahan Lease, we assigned a 25% working interest with respect to each lease to Tradestar Resources Corporation (“Tradestar Resources”) as a finder’s fee. The 25% working interest consisted of two parts, (i) a 12.5% working interest assigned upon acquisition of the leases, and (ii) a 12.5% back in assigned with an effective date of January 1, 2007. Tradestar Energy Inc. (“Tradestar Energy”), a wholly owned subsidiary of Tradestar Resources Corporation, became the operator of record for the Holt and Strahan Leases as of December 1, 2007.

Janssen Lease, Texas

In October 2005, we entered into an agreement to purchase a 25% working interest and an 18.75% net revenue interest in approximately 138 acres of an oil and gas lease (the “Janssen Lease”) located in Karnes County, Texas. This lease interest was acquired from Rockwell Energy. An unsuccessful attempt was made to re-enter and re-complete a Roeder gas sand at 10,300 feet using side track drilling techniques. As the original lease was set to expire, we negotiated a new oil and gas lease with the mineral owners and farmed out 97% of the working interest to ETG Energy Resources. We retained a 3% working interest on any producing zones and a 5% non-promoted option to participate in any offset drilling within the leased area. ETG successfully re-completed in the Roeder Sand and the Janssen A-1 well is currently producing between 250-300 mcf gas per day and approximately six (6) barrels per day of condensate.

Koliba Lease, Texas

The Koliba Lease property is located near our Welder lease and has one shut-in oil/gas well. The well previously produced 30 Bbls oil per day plus water. The well is in close proximity to our Welder gas sales line and salt water disposal system. The Koliba No. 2 well was drilled June 2010 and found to be slightly down-dip from the No.1 well. We elected to plug the No. 2 and plan to drill the No. 3 well in anticipation of getting up-dip to the No. 1 well.

Illinois

Through the date of this annual report, we have entered into numerous oil and gas leases in Jefferson and other counties in Illinois. Currently these leases total approximately 2,994 gross acres pursuant to which we have a working interest of 100% and a net revenue interest of 87.5%. We plan to drill one or more wells during 2011 offsetting past producing wells to a depth of no greater than 4,000 feet.

We have an additional 1,620 gross acres under lease in Illinois.

Recent Activities

The Koliba No. 2 well was drilled June 2010 and found to be slightly down-dip from the No.1 well. We elected to plug the No. 2 and plan to drill the No. 3 well in anticipation of getting up-dip to the No. 1 well.

We continue to review and evaluate submittals on properties in Texas, Illinois, Louisiana, and other areas of the continental United States.

Productive Wells

The following table sets forth information regarding the total gross and net productive wells, expressed separately for oil and gas. All of our productive oil and gas wells were located in Texas and Louisiana. For the purposes of this subsection: (i) one or more completions in the same bore hole have been counted as one well, and (ii) a well with one or multiple completions at least one of which is an oil completion has been classified as an oil well. We do not have any wells with multiple completions.

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	Number of Operating Wells
	Oil		Gas
	Gross	Net	Gross	Net
Louisiana	4	3.00
Texas	2	2.00	1	0.03
	6	5.00	1	0.03

A productive well is an exploratory well, development well, producing well or well capable of production, but does not include a dry well. A dry well, or a hole, is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

A gross well is a well in which a working interest is owned, and a net well is the result obtained when the sum of fractional ownership working interests in gross wells equals one. The number of gross wells is the total number of wells in which a working interest is owned, and the number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. The “completion” of a well means the installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency.

Production and Price History

The table below sets forth the net quantities of oil and gas production, net of royalties, attributable to us in the years ended July 31, 2010 and 2009. For the purposes of this table, the following terms have the following meanings: (i) “Bbl” means one stock tank barrel or 42 U.S. gallons liquid volume; (ii) “MBbls” means one thousand barrels of oil; (iii) “Mcf” means one thousand cubic feet; (iv) “Mcfe” means one thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil; (v) “MMcfe/d” means one million cubic feet equivalent per day, determined by using the ratio of six Mcf of natural gas to one Bbl of oil; and (vi) “MMcf” means one million cubic feet.

	For the Year Ended July 31, 2010		For the Year Ended July 31, 2009
Production Data
Oil (MBbls)		6.4		6.5
Natural gas (MMcf)		15.7		14.9
Total (MMcfe)		54.4		53.8
Average Prices:
Oil (per Bbl)	$	72.89	$	63.74
Natural gas (per Mcf)	$	3.95	$	5.22
Total (per Mcfe)	$	9.78	$	9.12
Average Costs (per Mcfe):
Lease operating expenses(1)	$	10.49	$	7.25

(1) Taxes, transportation and production-related administrative expenditures are included in lease operating expenses.

Net production includes only production that is owned by us, whether directly or beneficially, and produced to our interest, less royalties and production due to others. Production of natural gas includes only marketable production of gas on an “as sold” basis. Production of natural gas includes only dry, residue and wet gas, depending on whether liquids have been extracted before we passed title, and does not include flared gas, injected gas and gas consumed in operations. Recovered gas, lift gas and reproduced gas are not included until sold.

The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers.

Summary of Oil and Gas Reserves as of July 31, 2010 Based on Average Fiscal-Year Prices
	Oil (bbls)		Gas (Mcf)		Equivalent (Mcfe)
Proved developed producing		59,220		122,550		477,870
Proved developed non-producing		37,930		40,690		268,270
Total Proved developed reserves		97,150		163,240		746,140

The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Previous periods were not restated for the new rules. Key revisions include a change in pricing used to prepare reserve estimates to a 12-month un-weighted average of the first-day-of-the-month prices, the inclusion of non-traditional resources in reserves, definitional changes, and allowing the application of reliable technologies in determining proved reserves, and other new disclosures (Revised SEC rules). The Revised SEC rules did not affect the quantities of our proved reserves.

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The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques.

Acreage

The following table sets forth information regarding our gross and net developed and undeveloped oil and natural gas acreage under lease through the date of this annual report:

	Gross (1)		Net
Developed Acreage
Illinois		-		-
Louisiana		175.89		131.92
Texas		219.00		85.14
Undeveloped Acreage
Illinois		4,614.30		3,122.99
Louisiana		160.00		150.08
Texas		1,345.72		1,182.56
Total		6,514.91		4,672.69

(1) The gross acreage cited includes leasehold acreage to be earned under the farm-out agreements.

A developed acre is an acre spaced or assignable to productive wells, a gross acre is an acre in which a working interest is owned, and a net acre is the result that is obtained when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not such acreage contains proved reserves, but does not include undrilled acreage held by production under the terms of a lease. As is customary in the oil and gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the lease or by payment of delay rentals during the remaining primary term of the lease. The oil and natural gas leases in which we have an interest are for varying primary terms; however, most of our developed lease acreage is beyond the primary term and is held so long as oil or natural gas is produced.

Plan of Operations

Our plan of operations for our Louisiana properties is to sell the Holt and Strahan Leases.  We sold our Dixon property in September 2010.  With the sale of Holt and Strahan, we would no longer operate properties in Louisiana.

In Illinois, we will continue leasing in Jefferson and Wayne Counties with emphasis on a potential secondary recovery (waterflood) project. Once leasing in the project area is completed, we plan to commence a “pilot” flood operation using several injection wells and at least one recovery well. If the pilot operation is successful, we will move to put in a full scale waterflood recovery system.

In Texas, we plan to continue producing oil and gas from our Welder (Barge Canal) lease. We will continue to maintain our 3.0% non-operated working interest in the Janssen No. A-1 well (gas and minor condensate) in Karnes County, Texas.

The Company has acquired 5 non-proprietary 3D seismic surveys in Kenedy, Kleburg, Bee, Refugio and Matagorda Counties. To date, we have identified a significant seismic target in the Kenedy survey and have entered into an agreement.  In September 2010, we assigned 81.25% working interest in the Kenedy Ranch lease to Chinn Exploration Company “Chinn” for $200,000 cash. The agreement provides that Chinn will operate the property and will drill a test well within 18 months of the date of the agreement. We retained an 18.75% working interest, which will be carried to the casing point with respect to the test well. We compensated a marketing consultant with a 5% working interest carved out from our interest. Thus, after compensation of the consultant, our working interest in Kenedy Ranch is 13.75%.

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Government Regulation

General

The availability of a ready market for oil and gas production depends upon numerous factors beyond our control. These factors include local, state, federal and international regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels. State and federal regulations are generally intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, and control contamination of the environment.

Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and a consequent increase in the cost of doing business and decrease in profitability. Numerous federal and state departments and agencies issue rules and regulations imposing additional burdens on the oil and gas industry that are often costly to comply with and carry substantial penalties for non-compliance. Our production operations may be affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.

The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (FERC) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations. Many states have statutes and regulations governing various environmental and conservation matters, including the establishment of maximum rates of production from oil and gas wells, and restricting production to the market demand for oil and gas. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced. Most states impose a production or severance tax with respect to the production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. State production taxes are generally applied as a percentage of production or sales.

Oil and gas rights may be held by individuals and corporations, and, in certain circumstances, by governments having jurisdiction over the area in which such rights are located. As a general rule, parties holding such rights grant licenses or leases to third parties, such as us, to facilitate the exploration and development of these rights. The terms of the licenses and leases are generally established to require timely development. Notwithstanding the ownership of oil and gas rights, the government of the jurisdiction in which the rights are located generally retains authority over the manner of development of those rights.

Environmental

General.  Our activities are subject to local, state and federal laws and regulations governing environmental quality and pollution control in the United States. The exploration, drilling and production from wells, natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing natural gas and other products, are subject to stringent environmental laws and regulations by state and federal authorities, including the Environmental Protection Agency (“EPA”). These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Such regulation can increase our cost of planning, designing, installing and operating such facilities.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Moreover, some environmental laws provide for joint and several strict liability for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances, such as oil and gas related products.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

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Waste Disposal.  We currently lease, and intend in the future to own or lease, additional properties that have been used for production of oil and gas for many years. Although we and our operators utilize operating and disposal practices that are standard in the industry, previous owners or lessees may have disposed of or released hydrocarbons or other wastes on or under the properties that we currently own or lease or properties that we may in the future own or lease. In addition, many of these properties have been operated in the past by third parties over whom we had no control as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and gas wastes and properties may require us to remediate property, including ground water, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

We may generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA has limited the disposal options for certain wastes that are designated as hazardous under RCRA. Furthermore, it is possible that certain wastes generated by our oil and gas projects that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly operating and disposal requirements.

CERCLA.  The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons or so-called potentially responsible parties include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of the hazardous substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. We may in the future be an owner of facilities on which hazardous substances have been released by previous owners or operators of our properties that are named as potentially responsible parties related to their ownership or operation of such property.

Air Emissions.  Our projects are subject to local, state and federal regulations for the control of emissions of air pollution. Major sources of air pollutants are subject to more stringent, federally imposed permitting requirements, including additional permits. Producing wells, gas plants and electric generating facilities generate volatile organic compounds and nitrogen oxides. Some of our producing wells may be in counties that are designated as non-attainment for ozone and may be subject to restrictive emission limitations and permitting requirements. If the ozone problems in the applicable states are not resolved by the deadlines imposed by the federal Clean Air Act, or on schedule to meet the standards, even more restrictive requirements may be imposed, including financial penalties based upon the quantity of ozone producing emissions. If we fail to comply strictly with air pollution regulations or permits, we may be subject to monetary fines and be required to correct any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air emission sources.

Clean Water Act.  The Clean Water Act imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. Permits must be obtained to discharge pollutants into federal waters. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.

Oil Pollution Act.The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act, and similar legislation enacted in Texas, Louisiana and other coastal states, impose certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in United States waters and adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility or vessel that is a source of an oil discharge or poses the substantial threat of discharge, or the lessee or permittee of the area in which a facility covered by OPA is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs, remediation of environmental damage and a variety of public and private damages. OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs of a potential spill. Few defenses exist to the liability imposed by OPA. In the event of an oil discharge, or substantial threat of discharge from our properties, vessels and pipelines, we may be liable for costs and damages.

We believe that we are in substantial compliance with current environmental laws and regulations in each of the jurisdictions in which we operate. Although we have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

11

Competition

The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources.

Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States and other countries, as well as factors that we cannot control, including international political conditions, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources. Intense competition occurs with respect to marketing, particularly of natural gas.

Employees

We currently have four employees, all of whom are full-time employees.

Subsidiaries

We own 100% of the issued and outstanding share capital of Penasco, which was formed under the laws of the State of Nevada on November 23, 2005.

ITEM A.  RISK FACTORS

An investment in our common stock involves a number of very significant risks. You should carefully consider the following risks and uncertainties in addition to other information in this annual report in evaluating our company and its business before purchasing shares of our common stock. Our business, operating results and financial condition could be seriously harmed due to any of the following risks. The risks described below may not be all of the risks facing our company. Additional risks not presently known to us or that we currently consider immaterial may also impair our business operations. You could lose all or part of your investment due to any of these risks.

Risks Related to Our Company

Because we have only recently commenced business operations, we face a high risk of business failure.

We were incorporated on April 12, 2005 and originally planned to explore for gold and other minerals, but we soon shifted our focus to oil and gas exploration. We began production of oil in August 2006 with the acquisition of the Holt, Strahan and McKay leases in Franklin and Richland Parish, Louisiana, but to date, we have earned limited revenues and have not achieved profitability. Potential investors should be aware of the difficulties normally encountered by companies in the early stages of their life cycle and the high rate of failure of such enterprises. These potential problems include, but are not limited to, unanticipated problems relating to costs and expenses that may exceed current estimates. We have no history upon which to base any assumption as to the likelihood that our business will prove successful, and we may never achieve profitable operations.

We expect to incur operating losses for the foreseeable future, and if we are unable to generate significant revenues, our business will likely fail.

We have earned limited revenues and we have never been profitable. Going forward, we anticipate that we will incur increased operating expenses without realizing any significant revenues. We therefore expect to incur significant losses into the foreseeable future. If we are unable to generate significant revenues from our properties, our business will likely fail.

We may not be able to effectively manage the demands required of a new business in our industry, such that we may be unable to successfully implement our business plan or achieve profitability.

We have earned limited revenues to date and we have never been profitable. We may not be able to effectively execute our business plan or manage any growth, if any, of our business. Future development and operating results will depend on many factors, including access to adequate capital, the demand for oil and gas, price competition, our success in setting up and expanding distribution channels and whether we can control costs. Many of these factors are beyond our control. In addition, our future prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a new business in the oil and gas industry, which is characterized by intense competition, rapid technological change, highly litigious competitors and significant regulation. If we are unable to address these matters, or any of them, then we may not be able to successfully implement our business plan or achieve revenues or profitability.

12

Because we have earned limited revenues from operations, all our capital requirements have been met through financing and we may not be able to continue to find financing to meet our operating requirements.

We will need to obtain additional financing in order to pursue our business plan. As of July 31, 2010, we had cash on hand of $247,851 and a working capital deficit of $1,615,780. Our business plan calls for expenses of approximately $3,000,000 over the next twelve months in connection with the exploration and development of our properties as well as corporate overhead. As such, we estimate that we will need to receive additional funds of approximately the same to fund our planned operations over the next twelve months. We may not be able to obtain such financing at all or in amounts that would be sufficient for us to meet our current and expected working capital needs. It is not anticipated that any of our officers, directors or current stockholders will provide any significant portion of our financing requirements. Furthermore, in the event that our plans change, our assumptions change or prove inaccurate, we could be required to seek additional financing in greater amounts than is currently anticipated. Any inability to obtain additional financing when needed would have a material adverse effect on us, including possibly requiring us to significantly curtail or possibly cease our operations. In addition, any future equity financing may involve substantial dilution to our existing stockholders.

Our auditors have expressed substantial doubt about our ability to continue as a going concern.

Our audited financial statements for the years ended July 31, 2010 and 2009 have been prepared assuming that we will continue as a going concern. Since inception to July 31, 2010, we have incurred an accumulated net loss of $11,062,153, and our auditors have expressed substantial doubt about our ability to continue as a going concern. Our financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Because we have a history of losses and anticipate continued losses unless and until we are able to generate sufficient revenues to support our operations, we may lack the financial stability required to continue operations.

Since inception we have suffered recurring losses. We have funded our operations through the issuance of common stock in order to meet our strategic objectives. Our current level of oil production is not sufficient to completely fund our exploration and development budget, such that we will require additional financing in order to pursue our plan of operations. We anticipate that our losses will continue until such time, if ever, as we are able to generate sufficient revenues to support our operations. Our ability to generate revenue primarily depends on our success in developing our properties. We may not be able to adequately develop our properties, attain revenues or achieve profitable operations, in which case our business would fail.

Oil and gas resources, even if discovered, may not be commercially viable, which would cause our business to fail.

Even if oil and gas resources are discovered on our properties, we may not be able to achieve commercial production at all or at a level that would be sufficient to pay drilling and completion costs. Our properties may not contain commercial quantities of oil and gas. In addition, the cost of drilling, completing and operating wells is often uncertain. Drilling operations on our properties or on properties we may acquire in the future may be curtailed, delayed or cancelled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit or a recovery of drilling, completion and operating costs. As a result, our business, results of operations and financial condition may be materially adversely affected.

Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, which could have a material adverse effect on our business, results of operations and financial condition.

There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the producer. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at different times may vary substantially, and such reserve estimates may be subject to downward or upward adjustment based upon such factors. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, when and if made, and such variances may be material, which could have a material adverse effect on our business, results of operations and financial condition.

13

Our future oil and natural gas production is highly dependent upon our ability to find or acquire reserves.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves, if any, will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in finding or acquiring reserves in the future. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. The failure of an operator of our wells to adequately perform operations, or such operator’s breach of the applicable agreements, could adversely impact us. In addition, we may not obtain additional proved reserves or be able to drill productive wells at acceptable costs, in which case our business would fail.

Oil and gas resources may contain certain hazards which may, in turn, create certain liabilities or prevent the resources from being commercially viable.

Our properties may contain hazards such as unusual or unexpected formations and other conditions. Our projects may become subject to liability for pollution, fire, explosion, blowouts, cratering and oil spills, against which we cannot insure or against which we may decide to not insure. Such events could result in substantial damage to oil and gas wells, producing facilities and other property and/or result in personal injury. Costs or liabilities related to those events would have a material adverse effect on our business, results of operations, financial condition and cash flows.

Oil and gas prices are highly volatile, and a decline in oil and gas prices could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Oil and gas prices and markets are highly volatile. Prices for oil and gas are subject to significant fluctuation in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty and a variety of additional factors. Our profitability will be substantially dependent on prevailing prices for natural gas and oil. The amounts of and prices obtainable for our oil and gas production may be affected by market factors beyond our control, such as:

● the extent of domestic production;

● the amount of imports of foreign oil and gas;

● the market demand on a regional, national and worldwide basis;

● domestic and foreign economic conditions that determine levels of industrial production;

● political events in foreign oil-producing regions; and

● variations in governmental regulations and tax laws or the imposition of new governmental requirements upon the oil and gas industry.

These factors or any one of them could result in the decline in oil and gas prices, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

As a result of our intensely competitive industry, we may not gain enough market share to be profitable.

We compete in the sale of oil and natural gas on the basis of price and on the ability to deliver products. The oil and natural gas industry is intensely competitive in all phases, including the exploration for new production and the acquisition of equipment and labor necessary to conduct drilling activities. The competition comes from numerous major oil companies as well as numerous other independent operators in the United States and elsewhere. Because we are pursuing potentially large markets, our competitors include major, multinational oil and gas companies. There is also competition between the oil and natural gas industry and other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. We are a minor participant in the industry and compete in the oil and natural gas industry with many other companies having far greater financial, technical and other resources. If we are unable to compete successfully, we may never be able to sell enough product at a price sufficient to permit us to generate profits.

The oil and natural gas market is heavily regulated, and existing or subsequently enacted laws or regulations could limit our production, increase compliance costs or otherwise adversely impact our operations or revenues.

We are subject to various federal, state and local laws and regulations. These laws and regulations govern safety, exploration, development, taxation and environmental matters that are related to the oil and natural gas industry. To conserve oil and natural gas supplies, regulatory agencies may impose price controls and may limit our production. Certain laws and regulations require drilling permits, govern the spacing of wells and the prevention of waste and limit the total number of wells drilled or the total allowable production from successful wells. Other laws and regulations govern the handling, storage, transportation and disposal of oil and natural gas and any by-products produced in oil and natural gas operations. These laws and regulations could materially adversely impact our operations and our revenues.

14

Laws and regulations that affect us may change from time to time in response to economic or political conditions. Thus, we must also consider the impact of future laws and regulations that may be passed in the jurisdictions where we operate. We anticipate that future laws and regulations related to the oil and natural gas industry will become increasingly stringent and cause us to incur substantial compliance costs.

The nature of our operations exposes us to environmental liabilities.

Our operations create the risk of environmental liabilities. We may incur liability to governments or to third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. We could potentially discharge oil or natural gas into the environment in any of the following ways:

● from a well or drilling equipment at a drill site;

● from a leak in storage tanks, pipelines or other gathering and transportation facilities;

● from damage to oil or natural gas wells resulting from accidents during normal operations; or

● from blowouts, cratering or explosions.

Environmental discharges may move through the soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to obtain the proper permits for, to control the use of, or to notify the proper authorities of a hazardous discharge. Such liability could have a material adverse effect on our financial condition and our results of operations and could possibly cause our operations to be suspended or terminated on such property.

We may also be liable for any environmental hazards created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. Such liability would affect the costs of our acquisition of those properties. In connection with any of these environmental violations, we may also be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable.

We could lose or fail to attract the personnel necessary to run our business.

Our success depends, to a large extent, on our ability to attract and retain key management and operating personnel. As we develop additional capabilities and expand the scope of our operations, we will require more skilled personnel. Recruiting personnel for the oil and gas industry is highly competitive. We may not be able to attract and retain qualified executive, managerial and technical personnel needed for our business. Our failure to attract or retain qualified personnel could delay or result in our inability to complete our business plan.

Our directors may experience conflicts of interest which may detrimentally affect our profitability.

Certain directors and officers may be engaged in, or may in the future be engaged in, other business activities on their own behalf and on behalf of other companies and, as a result of these and other activities, such directors and officers may become subject to conflicts of interest, which could have a material adverse effect on our business.

Some of our directors and officers are outside the United States, with the result that it may be difficult for investors to enforce within the United States any judgments obtained against us or any of our directors or officers.

Some of our directors and officers are nationals and/or residents of countries other than the United States, and all or a substantial portion of such persons’ assets are located outside the United States. As a result, it may be difficult for investors to effect service of process on our directors or officers, or enforce within the United States or Canada any judgments obtained against us or our officers or directors, including judgments predicated upon the civil liability provisions of the securities laws of the United States or any state thereof. Consequently, you may be effectively prevented from pursuing remedies under U.S. federal securities laws against them. In addition, investors may not be able to commence an action in a Canadian court predicated upon the civil liability provisions of the securities laws of the United States. The foregoing risks also apply to those experts identified in this annual report that are not residents of the United States.

Risks Related to Our Common Stock

The trading price of our common stock may be volatile.

The price of our common shares may increase or decrease in response to a number of events and factors, including: trends in the oil and gas markets in which we operate; changes in the market price of oil and gas; current events affecting the economic situation in North America; changes in financial estimates; our acquisitions and financings; quarterly variations in our operating results; the operating and share price performance of other companies that investors may deem comparable; and purchase or sale of blocks of our common shares. These factors, or any of them, may materially adversely affect the prices of our common shares regardless of our operating performance.

15

A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.

A decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise additional capital for our operations. Because our operations to date have been principally financed through the sale of equity securities, a decline in the price of our common stock could have an adverse effect upon our liquidity and our continued operations. A reduction in our ability to raise equity capital in the future would have a material adverse effect upon our business plan and operations, including our ability to continue our current operations. If our stock price declines, we may not be able to raise additional capital or generate funds from operations sufficient to meet our obligations.

Our stock is a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations and FINRA’s sales practice requirements, which may limit a stockholder’s ability to buy and sell our stock.

Our common stock will be subject to the “Penny Stock” Rules of the SEC, which will make transactions in our common stock cumbersome and may reduce the value of an investment in our common stock.

Our common stock is quoted on the OTC Bulletin Board, which is generally considered to be a less efficient market than markets such as NASDAQ or the national exchanges, and which may cause difficulty in conducting trades and difficulty in obtaining future financing. Further, our securities will be subject to the “penny stock rules” adopted pursuant to Section 15(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The penny stock rules apply generally to companies whose common stock trades at less than $5.00 per share, subject to certain limited exemptions. Such rules require, among other things, that brokers who trade “penny stock” to persons other than “established customers” complete certain documentation, make suitability inquiries of investors and provide investors with certain information concerning trading in the security, including a risk disclosure document and quote information under certain circumstances. Many brokers have decided not to trade “penny stock” because of the requirements of the “penny stock rules” and, as a result, the number of broker-dealers willing to act as market makers in such securities is limited. In the event that we remain subject to the “penny stock rules” for any significant period, there may develop an adverse impact on the market, if any, for our securities. Because our securities are subject to the “penny stock rules”, investors will find it more difficult to dispose of our securities. Further, it is more difficult: (i) to obtain accurate quotations, (ii) to obtain coverage for significant news events because major wire services, such as the Dow Jones News Service, generally do not publish press releases about such companies, and (iii) to obtain needed capital.

In addition to the “penny stock” rules promulgated by the SEC, FINRA has adopted rules that require a broker-dealer to have reasonable grounds for believing that an investment is suitable for a customer when recommending the investment to that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

We hold certain oil and gas interests, as described in Item 1 hereto. In addition, we rent office space at 600 Leopard Street, Suite 2015, Corpus Christi, Texas, 78401 for $1,328 per month.

ITEM 3.  LEGAL PROCEEDINGS

We are not a party to any material legal proceedings nor are we aware of any legal proceedings pending or threatened against us or our properties.

ITEM 4.  [REMOVED AND RESERVED]

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Shares of our common stock became quoted on the OTC Bulletin Board under the symbol “SGCA” on August 14, 2008.

The following tables set forth the high and low bid price per share of our common stock, as quoted on the OTC Bulletin Board, for the periods indicated. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not represent actual transactions.

Quarter Ended	High (1)		Low (1)
July 31, 2010	$	0.30	$	0.16
April 30, 2010	$	0.44	$	0.215
January 31, 2010	$	0.49	$	0.235
October 31,2009	$	0.455	$	0.15
July 31, 2009	$	0.70	$	0.30
April 30, 2009		N/A		N/A
January 31, 2009		N/A		N/A
October 31, 2008		N/A		N/A

(1) Shares of our common stock became quoted on the OTC Bulletin Board on August 14, 2008, but the first reported trade not occur until on or about May 12, 2009.

On November 12, 2010, the low bid price of our common stock was $0.1550 per share, the high ask price of our common stock was $0.18 per share, and the closing price was $0.16 per share. We do not have any securities that are currently traded on any other exchange or quotation system.

Holders

As of November 12, 2010, we had 89shareholders of record.

Dividend Policy

No dividends have been declared or paid on our common stock. We have incurred recurring losses and do not currently intend to pay any cash dividends in the foreseeable future.

Securities Authorized For Issuance Under Compensation Plans

The following table sets forth information as of July 31, 2010:

Equity Compensation Plan Information

		Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)			Weighted average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a) (c)
(a)	Equity compensation plans approved by security holders (2009 Stock Incentive Plan)		8,705,000		$	0.30		1,010,715
(b)	Equity compensation plans not approved by security holders		1,512,201	(1)	$	0.25		N/A

(1) On July 5, 2007 we issued 385,000 share purchase warrants exercisable at $0.35 per share, 4,000 share purchase warrants exercisable at $0.50 per share, and 163,041 share purchase warrants exercisable at $0.60 per share pursuant to finders’ fees agreements.  Warrants to purchase 132,340 shares expired and on February 12, 2010, we extended 419,701 of these warrants.  During October and November 2009, we granted warrants to purchase 1,257,500 shares of common stock exercisable at $0.35 per share pursuant to finders’ fees agreements and as compensation for business development services provided to us.  The exercise price of these warrants was reduced to $0.23 per share in April 2010.  Warrants to purchase 165,000 shares at $0.23 per share were exercised in April 2010.

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2009 Restated Stock Incentive Plan

On May 21, 2009, our Board of Directors authorized and approved the adoption of the 2009 Restated Stock Incentive Plan (the “2009 Plan”), which absorbs and replaces the 2007 Stock Incentive Plan, under which an aggregate of 10,000,000 of our shares may be issued.

The purpose of the 2009 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.

The 2009 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of two or more members of the Board of Directors, which shall determine, among other things, (i) the persons to be granted awards under the 2009 Plan; (ii) the number of shares or amount of other awards to be granted; and (iii) the terms and conditions of the awards granted. The Company may issue restricted shares, options, stock appreciation rights, deferred stock rights, dividend equivalent rights, among others, under the 2009 Plan. An aggregate of 10,000,000 of our shares may be issued pursuant to the grant of awards under the 2009 Plan.

An award may not be exercised after the termination date of the award and may be exercised following the termination of an eligible participant’s continuous service only to the extent provided by the administrator under the 2009 Plan. If the administrator under the 2009 Plan permits a participant to exercise an award following the termination of continuous service for a specified period, the award terminates to the extent not exercised on the last day of the specified period or the last day of the original term of the award, whichever occurs first. In the event an eligible participant’s service has been terminated for “cause”, he or she shall immediately forfeit all rights to any of the awards outstanding.

The foregoing summary of the 2009 Plan is not complete and is qualified in its entirety by reference to the 2009 Plan, a copy of which has been filed with the SEC.

During the year ended July 31, 2010, we granted 284,285 shares of common stock to consultants under the 2009 Plan.

Recent Sales of Unregistered Securities

During our fourth quarter ended July 31, 2010, we issued the following unregistered equity securities:

Effective June 15, 2010, we issued 21,622 shares of restricted common stock at a deemed price of $0.35 per share to one shareholder pursuant to the terms of a services agreement. We relied on an exemption from registration under Regulation S and/or Section 4(2) of the Securities Act.

Effective June 15, 2010, we issued 100,000 shares of restricted common stock at a deemed price of $0.20 per share to one shareholder pursuant to the terms of a services agreement. We relied on an exemption from registration under the Securities Act provided by Regulation S.

ITEM 6.  SELECTED FINANCIAL DATA

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.

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

The following discussion of our financial condition, changes in financial condition, plan of operations and results of operations should be read in conjunction with (i) our audited consolidated financial statements as at July 31, 2010 and 2009 and (ii) the section entitled “Business”, included in this annual report. The discussion contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including, but not limited to, those set forth under “Risk Factors” and elsewhere in this annual report.

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Restatement of Previously Issued Consolidated Financial Statements

On September 15, 2011, the Company received a SEC Comment letter questioning the treatment of certain warrant modifications as previously disclosed.  Upon further review, the company agreed that instead of certain term extensions or modifications of the warrants in question being treated as deemed dividends, the company would record a warrant modification expense in the operating expense section of the Statement of Operations.  The original accounting treatment was a deemed dividend which had no impact on the financial statements. See Note 2 included in the Notes to the Consolidated Financial Statements for details of the modification and the basis for calculation.

Additionally, we reviewed the valuation techniques we used to value our warrants.  Upon further review, we concluded that a Black-Sholes option pricing model does not sufficiently model the fair value of complex derivatives, such as warrants that contain a down-round ratchet provision.

Results of Operations

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

	Year Ended July 31, 2010 (As Restated)			Year Ended July 31, 2009			Increase/ (Decrease)			% change
Revenues	$	531,736		$	490,991		$	40,745		$	8	%
Operating expenses
Lease operating expense		571,009			389,547			181,462			47	%
Depreciation, depletion, and amortization		92,944			80,303			12,641			16	%
Accretion		23,632			—			23,642			100	%
Consulting fees		2,155,850			1,586,622			569,228			36	%
Management fees		902,866			799,768			103,098			13	%
Warrant modification expense		743,189		__				743,189			100	%
Other general and administrative expense		641,866			360,556			281,310			78	%
Total operating expenses		5,131,356			3,216,796			1,915,547			60	%
Loss from operations		(4,599,620	)		(2,725,805	)		(1,873,815	)		69	%
Interest expense, net		(68,359	)		(56,698	)		(11,661	)		21	%
Gain on warrant derivative liability		1,176,103			—			1,176,103			100	%
Net loss	$	(3,491,876	)	$	(2,782,503	)	$	(709,373	)		25	%

We recorded a net loss of $3,491,876 during the year ended July 31, 2010 compared to a net loss of $2,782,503 during the year ended July 31, 2009.

Revenue

Revenue from oil and gas properties was $531,736 in the year ended July 31, 2010 compared to $490,991 in the year ended July 31, 2009.  Significant developments or changes between these periods are outlined below:

● Barge Canal: Revenue from the Barge Canal project was $295,574 for the year ended July 31, 2010, as compared to $355,880 for the year ended July 31, 2009. This represents a decrease of $60,306 or 17%. The oil production was 30% less than the prior fiscal year, while average oil selling prices were 16% higher than the prior year. Gas production was 2% less than the prior fiscal year, while average gas selling prices also decreased by 15% from the prior fiscal year.

● South Delhi/Big Creek Field: Revenue from the South Delhi and Big Creek Field projects was $230,950 for the year ended July 31, 2010, as compared to $122,653 for the year ended July 31, 2009. This represents an increase of $108,297 or 88%. This was due to the increase in oil production by 73%. During the year, we completed workover that brought a new well, the Dixon #1, online. Additionally, we experienced an increase in average oil prices by 16%.  Janssen Lease: Revenue from the Janssen Lease project was $5,212 for the year ended July 31, 2010, as compared to $12,458 for the year ended July 31, 2009. This is primarily due to decrease in gas production by 39% complemented by decrease in average gas prices per mcf by 15%.

19

Operating Expenses

Operating expenses incurred during the fiscal year ended July 31, 2010 were $5,131,356 compared to $3,216,796 in the year ended July 31, 2009.  Significant changes and expenditures are outlined as follows:

● Oil and gas operating costs were $571,009 in the year ended July 31, 2010, compared to $389,547 in the prior year. This represents an increase of 47% or $181,462.  Significant developments or changes in direct operating costs per project are outlined as follows:

1. Barge Canal: Direct operating costs were $229,097 during the year ended July 31, 2010 as compared to costs of $157,969 during the year ended July 31, 2009. This represents an increase of $71,128 or 45%. The increase in operating costs from the prior period was primarily due to maintenance and work over costs incurred during the period in Welder wells. This was due to weather, specifically to flooding, and associated costs to repair line leaks.

2. South Delhi/Big Creek Field: Direct operating costs of $337,524 were incurred for the fiscal year ended July 31, 2010 as against costs of $205,279 for the fiscal year ended July 31, 2009 .This represents an increase of $132,245 or 25%. These are the costs associated directly to the increase in production during the current year.  Operating costs in the current period included workover required to bring the Dixon #1 online.

3. Janssen Lease: Direct operating costs of $3,574 for the fiscal year ended July 31, 2010. Direct operating costs of $4,424 for the fiscal year ended July 31, 2009. This represents a decrease of $850 or 19%.  The decrease can be attributed to decrease in production of gas by 39%.

● Depreciation and depletion expense was $92,944 in the year ended July 31, 2010, compared to $80,303 in the prior year. This represents an increase of 16% or $12,641.The increase is primarily due to $23,221 increase in amortization with a corresponding offset in depreciation of $10,580. The decrease in depreciation is due to the fact that we determined that the equipment classified under fixed assets was in use in our oil and gas operations, which led to reclassification of the net book value of the equipment to oil and gas properties as of July 31, 2010.

● Accretion expense were $23,632 during the year ended July 31, 2010 as compared to $ - during the relevant prior period. This represents an increase of 100% or $23,642. We discount the fair value of our asset retirement obligations and record accretion expense due to the passage of time using the interest method of allocation. Accordingly, the accretion expense is a function of the balance of the asset retirement obligation. The increase is due to the higher asset retirement obligation balance.

● Consulting fees were $2,155,850 in the year ended July 31, 2010, compared to $1,586,622 during the year ended July 31, 2009. This represents an increase of 36% or $569,228. The increase is due to an increase in consulting expenses of $391,980 and increase in stock based compensation of consultants by $177,248.The increase is attributable to bonus shares issued to employees and signing up new ongoing contracts with share based compensation and recognition of fair value of options granted during the year and prior years based on the vesting period.

● Management fees were $902,866 in the year ended July 31, 2010, compared to $799,768 in the prior year. This represents an increase of 13 % or $103,098.The increase in management fees is primarily attributable to amortization of the fair value of new options granted to the members of management. Further there was an addition of a member to the executive team and the related expenses.

● Warrant modification expense was $743,189 in the year ended July 31, 2010, compared to $- during the year ended July 31, 2009.  This represents an increase of 100% or $743,189.  The modification expense is a result of a modification of original terms of certain investor warrants.  The modification extended the term of a total of 5,577,939 outstanding warrants resulting in an incremental cost of $743,189.  The $743,189 represents the estimated incremental fair market value of the awards immediately prior to and subsequent to the modification.

● General and administrative expenses were $641,866 in the year ended July 31, 2010, compared to $360,556 in the prior year. This represents an increase of 78% or $281,310. The primary driver was the increase in professional fees of $175,644. Other significant increases were $52,739 increase in foreign exchange loss, $22,283 increase in general and administrative ex penses, $7,560 increase due to retirement of assets, $ 35,641 increase in travel expenses. These were offset by a gain on settlement of debt of $12,559. We incurred a loss on retirement due to the write off of leasehold improvements of $7,560.

Other items

● Interest and financing charges increased to $68,359 during the year ended July 31, 2010 from $56,698 during the same period ended July 31, 2009.  $72,860 was capitalized to oil and gas properties.  The total interest cost incurred in 2010 was $140,219.  This represents an increase of 147% or $83,541. The increase is due to the interest on the 2010 promissory note and the amortization of the discount relating to the note. Amortization of the discount and accrued interest relating to the 2009 convertible debenture were for the entire year as compared to part of the previous year.

● The gain on warrant derivative liability was $1,176,103 during the year ended July 31, 2010, compared to $ - during the prior period. This represents an increase of 100%. This is due to the warrants issued during the current period which 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.” 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 “Other income (expense) – Gain (loss) on warrant derivative liability.”

20

Our net loss for the year ended July 31, 2010 was $3,491,876 or $0.08 per share compared to a net loss for the year ended July 31, 2009 of $2,782,503 or $0.10 per share.

Liquidity and Capital Resources

The following table sets forth our cash and working capital as of July 31, 2010 and July 31, 2009:

	July 31, 2010			July 31, 2009
Cash reserves	$	247,851		$	18,793
Working capital (deficit)	$	(1,615,780	)	$	(767,435	)

Subject to the availability of additional financing, we intend to spend approximately $3,000,000 over the next twelve months in carrying out our plan of operations. At July 31, 2010, we had $247,851 of cash on hand and a working capital deficit of $1,615,780 ($1,502,700 is attributable to a warrant derivative liability which would ordinarily be settled in stock). As such, our working capital will not be 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 twelve months. We estimate that we will need to receive additional funds of approximately $3,000,000 during the next twelve months, either through the sale of capital stock, borrowing, or from increased oil/gas production revenue. Our management is currently making significant efforts to secure the needed capital, but we have not yet secured any commitments with respect to such financing. If we are not able to obtain financing in the amounts required or on terms that are acceptable to us, we may be forced to scale back, or abandon, our plan of operations.

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 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 but has increased to approximately $80 per barrel as of late October 2010. If the price of oil drops to levels seen earlier in the year or in previous years, we recognize that it will adversely affect our ability to raise additional capital. Any of these factors could have a material impact upon our ability to raise financing and, as a result, upon our short-term or long-term liquidity.

Going Concern

Our current sources of revenue are inadequate to provide incoming cash flows to sustain our future operations. As outlined above, our ability to pursue our planned business activities is dependent upon our successful efforts to raise additional equity financing. These factors raise substantial doubt regarding our ability to continue as a going concern. Our consolidated financial statements have been prepared on a going concern basis, which implies that we will continue to realize our assets and discharge our liabilities in the normal course of business. As at July 31, 2010, we had accumulated losses of $11,062,153 since inception. Our financial statements do not include any adjustments to the recoverability and classification of recorded asset amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern. If we do not raise capital sufficient to fund our business plan, Strategic may not survive.

Net Cash Used in Operating Activities

Operating activities in the year ended July 31, 2010 used cash of $2,643,485 compared to $1, 129,963 in the year ended July 31, 2009. 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.

Net Cash Used in Investing Activities

In the year ended July 31, 2010, investing activities used cash of $575,412 compared to $120,251 in the year ended July 31, 2009. The changes between such periods relates primarily to an increase in investments in oil and gas properties over the prior year.

Net Cash Provided by Financing Activities

As we have had limited revenues since inception, we have financed our operations primarily through private placements of our stock. Financing activities in the year ended July 31, 2010 provided cash of $3,447,955compared to $1,201,357 in the year ended July 31, 2009.

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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.

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

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

Asset Retirement Obligation

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

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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 the Black-Sholes option pricing method with any change in fair value during the period recorded in earnings as “Other income (expense) – Gain (loss) on warrant derivative liability.”

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

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2010.

	Carrying Value at July 31,		Fair Value Measurement at July 31, 2010
	2010		Level 1		Level 2		Level 3
Derivative warrant liability	$	1,502,700		-	$	-	$	1,502,700

The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the year ended July 31, 2010:

Beginning balance – July 31, 2009	$	-
Issuance of derivative warrants		3,381,032
Reduced for warrants exercised		(702,229	)
Change in fair value of derivative liability		(1,176,103	)
At July 31, 2010	$	1,502,700

The $1,878,332 change in fair value was recorded as a reduction of the derivative liability; specifically, as a $1,176,103 unrealized gain on the change in fair value of the liability in our statement of operations and as an $702,229 adjustment to paid in capital related to the exercise during the period of warrants classified as derivative liabilities.

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The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable – related party, accounts payable and accrued expenses, and convertible 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.

We recognize the cost associated with share-based awards that have a graded vesting schedule on a straight-line basis over the requisite service period of the entire award.

See Note 1 of our consolidated financial statements for our year ended July 31, 2010 for a summary of other significant accounting policies.

Off-Balance Sheet Arrangements

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

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information required under this item.

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ITEM 8.  FINANCIAL STATEMENTS

STRATEGIC AMERICAN OIL CORPORATION

Index to Consolidated Financial Statements

TABLE OF CONTENTS

25

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Strategic American Oil Corporation

Corpus Christi, Texas

We have audited the accompanying consolidated balance sheet of Strategic American Oil Corporation as of July 31, 2010 and the related consolidated statement of operations, cash flows and changes in stockholders’ deficit for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Strategic American Oil Corporation as of July 31, 2010, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2, the accompanying consolidated financial statements have been restated due to an error in accounting for the modification of certain warrants.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company has suffered losses from operations and has a working capital deficit. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regards to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ MaloneBailey, LLP

www.malone-bailey.com

Houston, Texas

November 15, 2010, except for Note 2, which is November 14, 2011

26

REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of Strategic American Oil Corporation

We have audited the accompanying consolidated balance sheet of Strategic American Oil Corporation as of July 31 2009 and the related consolidated statements of operations, stockholders’ equity and cash flows for the year ended July 31, 2009.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, and assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Strategic American Oil Corporation as of July 31, 2009 and the results of its operations and its cash flows for the year ended July 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern.  As discussed in Note 1 to the financial statements, the Company has not generated significant revenues since inception, has incurred losses in developing its business, and further losses are anticipated.  The Company requires additional funds to meet its obligations and the costs of its operations.  These factors raise substantial doubt about the Company’s ability to continue as a going concern.  Management’s plans in this regard are described in Note 3.  The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

“DMCL”

DALE MATHESON CARR-HILTON LABONTE LLP

CHARTERED ACCOUNTANTS

Vancouver, Canada

November 12, 2009

Vancouver (Head Office) Suite 1500 - 1140 West Pender Street, Vancouver, B.C., Canada V6E 4G1, Tel: 604 687 4747 • Fax: 604 689 2778 - Main Reception

South Surrey Suite 301 - 1656 Martin Drive, White Rock, B.C., Canada V4A 6E7, Tel: 604 531 1154 • Fax: 604 538 2613

Port Coquitlam Suite 700 - 2755 Lougheed Highway, Port Coquitlam, B.C., Canada V3B 5Y9, Tel: 604 941 8266 • Fax: 604 941 0971

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STRATEGIC AMERICAN OIL CORPORATION

CONSOLIDATED BALANCE SHEETS

	July 31,
	2010			2009
	(As Restated)
Assets
Current assets
Cash and cash equivalents	$	247,851		$	18,793
Restricted cash		40,000			40,000
Accounts receivable		6,580			707
Accounts receivable – related party		28,975			34,366
Other current assets		251,328			44,478
Total current assets		574,734			138,344
Oil and Gas Property, accounted for using the full cost method of accounting
Evaluated property, net of accumulated depletion of $265,872 and $176,101, respectively		1,193,680			986,926
Unevaluated property		734,533			295,454
Other Assets		19,317			19,317
Property and equipment, net of accumulated depreciation of $7,624 and $35,366, respectively		5,747			29,830
Total Assets	$	2,528,011		$	1,469,871
Liabilities and Stockholder’s Equity
Current liabilities
Accounts payable and accrued expenses	$	583,250		$	621,197
Notes payable, net of unamortized discount of $45,436 and $107,282, respectively		104,564			42,718
Warrant derivative liability		1,502,700			—
Due to related parties		—			241,864
Total current liabilities		2,190,514			905,779
Asset retirement obligations		57,623			22,662
Total liabilities		2,248,137			928,441
Stockholder’s equity:
Common stock, $.001 par; 500,000,000 shares authorized shares; 52,432,486 and 30,933,990 shares issued and outstanding		52,432			30,934
Additional paid in capital		11,289,595			8,080,773
Accumulated deficit		(11,062,153	)		(7,570,277	)
Total stockholder’s equity		279,874			541,430
Total liabilities and stockholder’s equity	$	2,528,011		$	1,469,871

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

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STRATEGIC AMERICAN OIL CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended
	July 31,
	2010				2009
	(As Restated)
Revenues	$	531,736			$	490,991
Operating expenses
Lease operating expense		571,009		��		389,547
Depreciation, depletion, and amortization		92,944				80,303
Accretion		23,632				—
Consulting fees		2,155,850				1,586,622
Management fees		902,866				799,768
Warrant modification expense		743,189				-
Other general and administrative expense		641,866				360,556
Total operating expenses		5,131,356				3,216,796
Loss from operations		(4,599,620	)			(2,725,805	)
Interest expense, net		(68,359	)			(56,698	)
Gain on warrant derivative liability		1,176,103				—
Net loss	$	(3,491,876	)		$	(2,782,503	)
Basic and diluted loss per common share	$	(0.08	)		$	(0.10	)
Weighted average shares outstanding (basic and diluted)		45,642,982				28,611,028

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

29

STRATEGIC AMERICAN OIL CORPORATION

STATEMENT OF CHANGES IN STOCKHOLDER’S EQUITY ()

	Common Stock				Additional Paid in			Accumulated
	Shares		Amount		Capital			Deficit			Total
Balance at July 31, 2008		27,731,204	$	27,731	$	5,926,548		$	(4,787,774	)	$	1,166,505
Common stock issued for:
Cash, net of share issuance costs		2,271,832		2,272		786,928			—			789,200
Accounts payable		271,429		271		119,729			—			120,000
Services		659,525		660		307,722			—			308,382
Amortization of fair value of options		—		—		801,912			—			801,912
Discount on convertible debt		—		—		137,934			—			137,934
Net loss		—		—		—			(2,782,503	)		(2,782,503	)
Balance at July 31, 2009		30,933,990		30,934		8,080,773			(7,570,277	)		541,430
Common stock issued for:
Cash and exercise of warrants, net of share issuance costs and proceeds allocated to derivative warrants		17,975,870		17,976		1,122,703			—			1,140,679
Accounts payable to consultants and directors, net of amounts allocated to derivative warrants		1,093,749		1,093		142,708			—			143,801
Services provided by consultants, and directors		1,493,294		1,493		517,622			—			519,115
Notes payable – related party, net of amounts allocated to derivative warrants		935,583		936		(936	)		—			—
Share-based compensation: amortization of fair value of stock options		—		—		639,469			—			639,469
Warrants issued:
With debt		—		—		28,067			—			28,067
With debt – related party		—		—		16,000			—			16,000
Warrant extension modification	__		__			743,189		__				743,189
Net loss		—		—		—			(3,491,876	)		(3,491,876	)
Balance at July 31, 2010 (As Restated)		52,432,486	$	52,432	$	11,289,595		$	(11,062,153	)	$	279,874

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

30

STRATEGIC AMERICAN OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended
	July 31,
	2010			2009
	(As Restated)
Cash Flows From Operating Activities
Net loss	$	(3,491,876	)	$	(2,782,503	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		92,943			80,303
Accretion		23,632			—
Realized loss on retirement of assets		7,560			—
Amortization of debt discount		85,865			63,364
Common stock issued for services		519,115			265,104
Share based compensation- amortization of the fair value of  stock options		639,469			801,912
Warrant modification		743,189		__
Derivative warrants granted for services		12,170			—
Gain on warrant derivative liability		(1,176,103	)		—
Gain on settlement of accounts payable		(12,559	)		—
Write-off of reclamation bond		—			21,875
Changes in operating assets and liabilities:		—
Accounts receivable		(5,873	)		51,551
Accounts payable and accrued expenses		125,833			327,990
Other assets		(206,850	)		40,441
Net cash used in operating activities		(2,643,485	)		(1,129,963	)
Cash Flows From Investing Activities
Purchases of oil and gas properties		(571,403	)		(119,705	)
Purchases of fixed assets		(4,009	)		(546	)
Net cash used in investing activities		(575,412	)		(120,251	)
Cash Flows From Financing Activities
Proceeds from sales of common stock, net		638,450			789,200
Proceeds from sales of derivative warrants		2,858,862			—
Proceeds from notes payable		100,000			150,000
Payments on notes payable		(100,000	)		—
Proceeds from notes payable to related parties		100,500			146,000
Payments on notes payable to related parties		(160,500	)		(10,000	)
Other changed in due to (from) related parties		10,643			126,157
Net cash provided by financing activities		3,447,955			1,201,357
Net increase (decrease) in cash		229,058			(48,857	)
Cash at beginning of period		18,793			67,650
Cash at end of period	$	247,851		$	18,793

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

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STRATEGIC AMERICAN OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

	Years Ended
	July 31,
	2010		2009
Supplemental Disclosures:
Interest paid in cash	$	20,867	$	—
Income taxes paid in cash		—		—
Non-cash investing and financing
Accounts payable for oil and gas assets	$	84,519	$	—
Asset retirement obligation incurred and changes in estimates		11,329		7,297
Non-cash capitalized interest		50,883		—
Stock and derivative warrants for accounts payable		266,685		120,000
Stock and derivative warrants for note payable to related parties		187,116		—
Stock for prepaid consulting fees		—		43,278
Debt discount		44,067		137,934
Reclassification due to exercise of warrants classified as a derivative		702,229	—

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

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STRATEGIC AMERICAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Description of business and basis of presentation

Strategic American Oil Corporation (“we”, “us”, “Strategic”, the “Company”) was formed for the purpose of oil and gas exploration, development, and production. We were incorporated as Carlin Gold Corporation on April 12, 2005 in Nevada, U.S.A. On July 11, 2005, we changed our name to Nevada Gold Corp., on October 18, 2005 we changed our name to Gulf States Energy Inc. and on September 5, 2006, we changed our name to Strategic American Oil Corporation. In prior fiscal years, we were an exploration stage company; as of July 31, 2010, due to our revenues and the commencement of planned operations, we are no longer an exploration or development stage company. We own 100% of Penasco Petroleum Inc. (“Penasco”), a Nevada corporation incorporated on November 23, 2005.  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”).

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 Strategic and our wholly owned subsidiary, Penasco. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. We base our estimates and judgments on historical experience and on various other assumptions and information that we believe to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

Significant areas requiring management’s estimates and assumptions include the determination of the fair value of transactions involving stock-based compensation and financial instruments and oil and natural gas proved reserve quantities.  Oil and natural gas proved reserve quantities which form the basis for the calculation of amortization of oil and natural gas properties and for asset impairment tests. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories.

Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.

Concentrations

Our operations are concentrated in Louisiana and Texas and in the oil and gas exploration and production industry. If the oil and natural gas exploration and production industry in general and the natural gas industry in particular were adversely affected, we would experience adverse effects.

In 2009, we had two purchasers, who are the operators of our currently producing properties, who accounted for over 99% of our revenues.

We are the non-operator on our proved properties. As such, we have a concentration risk associated with the business success of our operators. If our operators are not successful in operating our properties, we could experience material adverse effects.

We place cash with high quality financial institutions and at times may exceed the federally insured limits. We have not experienced a loss in such accounts nor do we expect any related losses in the near term.

Foreign currency

Our functional currency is the United States dollars.  Transactions denominated in foreign currencies are translated into their United States dollar equivalents using current exchange rates.  Monetary assets and liabilities are translated using exchange rates that prevailed as of the balance sheet date.  Non-monetary assets and liabilities are translated using exchange rates that prevailed as of the transaction date.  Revenue, if applicable, and expenses are translated using average exchange rates over the accounting period.  We have had no revenue denominated in foreign currencies. Gains or losses resulting from foreign currency transactions are included in results of operations.

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Cash and Cash Equivalents

Cash and cash equivalents are all highly liquid investments with an original maturity of three months or less at the time of purchase and are recorded at cost, which approximates fair value.

Restricted Cash

Restricted cash consists of a CD that renews daily.  It has been posted as collateral supporting a reclamation bond guaranteeing remediation of our oil and gas properties in Texas. As of July 31, 2010 and 2009, restricted cash totaled $40,000.

Accounts receivable and allowance for doubtful accounts

Trade accounts receivable are recorded at the invoiced amount and do not bear any interest. We regularly review collectability and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.

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.

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

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

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Asset Retirement Obligation

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

Other Assets

Other assets consists of cash deposited with our operator that supports a reclamation bond guaranteeing remediation of our oil and gas properties in Louisiana. As of July 31, 2010 and 2009, other assets totaled $19,317.  During the year ended July 31, 2009, we wrote off a $21,875 deposit with the prior operator of our South Delhi/Big Creek properties in Louisiana.

Property and Equipment, other than Oil and Gas

Property and equipment are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally 3 – 5 years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. We perform ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred.

Impairment of Long-Lived Assets

We periodically review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. We recognize an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. We recorded no impairment during the years ended July 31, 2010 and 2009.

Revenue Recognition

We recognize revenue when persuasive evidence of an arrangement exists, services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, so we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned.

Income Taxes

We account for income taxes using the asset and liability method. Under this method, deferred income tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

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.

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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 “Other income (expense) – Gain (loss) on warrant derivative liability.”

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

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of July 31, 2010.

	Carrying Value at July 31,		Fair Value Measurement at July 31, 2010
	2010		Level 1		Level 2		Level 3
Derivative warrant liability	$	1,502,700		-	$	-	$	1,502,700

The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the year ended July 31, 2010:

Beginning balance – July 31, 2009	$	-
Issuance of derivative warrants		3,381,032
Reduced for warrants exercised		(702,229	)
Change in fair value of derivative liability		(1,176,103	)
At July 31, 2010	$	1,502,700

The $1,878,332 change in fair value was recorded as a reduction of the derivative liability; specifically, as a $1,176,103 unrealized gain on the change in fair value of the liability in our statement of operations and an $702,229 adjustment to paid in capital related to the exercise during the period of warrants classified as derivative liabilities.

The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts receivable – related party, accounts payable and accrued expenses, and convertible 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.

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.

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Earnings Per Share

We compute basic loss per share using the weighted average number of shares of common stock outstanding during each period. Diluted loss per share includes the dilutive effects of common stock equivalents on an “as if converted” basis. For the years ended July 31, 2010 and 2009, potential dilutive securities had an anti-dilutive effect and were not included in the calculation of diluted net loss per common share.

Contingencies

Legal

We are subject to legal proceedings, claims and liabilities which arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. Legal fees are charged to expense as they are incurred.  See Note 13 - Commitments and Contingencies for more information on legal proceedings.

Environmental

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.

Recent Accounting Pronouncements

In August 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-05, Fair Value Measurements and Disclosures (ASU 2009-05). ASU 2009-05 amends Subtopic 820-10, Fair Value Measurements and Disclosures, to provide guidance on the fair value measurement of liabilities. ASU 2009-05 provides clarification for circumstances in which a quoted price in an active market for the identical liability is not available. ASU 2009-05 is effective for interim and annual periods beginning after August 26, 2009. We adopted the provisions of ASU 2009-05 for the period ended January 31, 2010. There was no impact on our operating results, financial position or cash flows.

In June 2009, the FASB issued ASU No. 2009-01, Generally Accepted Accounting Principles (ASU 2009-01). ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009. We adopted the provisions of ASU 2009-01 for the period ended October 31, 2009. There was no impact on our operating results, financial position or cash flows.

In April 2009, the FASB issued FASB Staff Position (FSP) No. FAS 107-1 and Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of Financial Instruments (ASC 825-10-65) to change the reporting requirements on certain fair value disclosures of financial instruments to include interim reporting periods. We adopted ASC 825-10-65 in the fourth quarter of 2009. There was no impact on our operating results, financial position or cash flows.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, (ASC 320-10-65), to expand other-than-temporary impairment guidance for debt securities to enhance the application of the guidance and improve the presentation and disclosure of other-than temporary impairments on debt and equity securities within the financial statements. The adoption of ASC 320-10-65 in the second quarter of 2009 did not have a significant impact on our operating results, financial position or cash flows.

In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (ASC 2010-3), which amends the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, as well as adding a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Energy companies affected by Release No. 33-8995 are now required to price proved oil and gas reserves using the un-weighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009.We adopted this release effective July 31, 2010.

In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted ASU 2010-03 effective July 31, 2010.

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In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU

2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on our operating results, financial position or cash flows.

In February 2010, FASB issued ASU No. 2010-09, Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filer, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. ASU 2010-09 becomes effective upon issuance of the final update. We adopted the provisions of ASU 2010-09 for the period ended April 30, 2010.

Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on the Company’s financial position or results from operations.

Note 2 – Restatement of Previously Issued Consolidated Financial Statements

Accounting Treatment of certain warrant modifications

On September 15, 2011, the Company received a SEC Comment letter questioning the treatment of certain warrant modifications as previously disclosed.  Upon further review, the company agreed that instead of certain term extensions or modifications of the warrants in question being treated as deemed dividends, the company would record a warrant modification expense in the operating expense section of the Statement of Operations.  The original accounting treatment was a deemed dividend which had no impact on the financial statements.

During August 2009, we extended the term of 5,158,238 warrants which were originally issued in conjunction with equity issues during 2006, 2007, and 2008. The modification resulted in a warrant modification expense of $679,199 which was estimated as the difference in the fair value of the warrants immediately before and after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modification:

	Before			After
Risk-free interest rate		0.47	%		0.47	%
Dividend yield		0	%		0	%
Volatility factor		154.60	%		154.60	%
Remaining term (years)		0			1

During February 2010, we extended the term of 419,701 warrants from February 12, 2010 to February 12, 2011. These warrants were originally issued for finder’s fees. The modification resulted in a warrant modification expense of $63,990 which was estimated as the difference in the fair value of the warrants immediately before and after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modification:

	Before			After
Risk-free interest rate		0.35	%		0.35	%
Dividend yield		0	%		0	%
Volatility factor		162.97	%		162.97	%
Remaining term (years)		0			1

This treatment is analogous to the accounting treatment in ASC 718–20-35, “Compensation - Stock Compensation-Modification.”  Under the modification analogy, the awards are to be treated as if exchanged for new awards with their fair market value equaling the incremental cost incurred by comparing the value immediately prior to the modification and immediately after the modification.

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Valuation of derivative warrants

We reviewed the valuation techniques we used to value our warrants.  Upon further review, we concluded that a Black-Sholes option pricing method does not sufficiently model the fair value of complex derivatives, such as warrants that contain a down-round ratchet provision.  The Black-Sholes method does not permit consideration of factors that affect the fair value at the time of issuance, such as likelihood that management will enter into transactions that would trigger the down-round ratchet provision.  Thus, the Black-Sholes method does not provide an accurate estimate of the fair value of the warrants and a lattice model or binomial computation technique is appropriate to use to value the instruments.  Accordingly, we have recomputed the value of our derivative warrants, which are described in Note 7 – Warrant Derivative Liability, using a lattice model.

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 our common stock began trading.

The following table provides the basis for the volatility curve used in the model:

Date of valuation	1 year			2 year			3 year			4 year			5 year
October 15, 2009 (Issuance of  warrants to purchase 12,977,500 shares of common stock)		121	%		255	%		304	%		320	%		331	%
November 13, 2009 (issuance of warrants to purchase 6,030,000 shares of common stock)		219	%		272	%		284	%		300	%		350	%
April 12, 2010 (exercise of warrants to purchase 2,775,870 shares of common stock)		219	%		272	%		284	%		300	%		350	%
July 31, 2010 (year end remeasurement)		132	%		271	%		300	%		312	%		329	%

Impact of restatements

The following tables present the effects of the restatements to the Company’s previously reported Consolidated Balance Sheet, Consolidated Statement of Operations and Consolidated Statement of Cash Flows as of and for the year ended July 31, 2010:

	July 31, 2010
Balance Sheet	As reported			Adjustments			As restated
Total Assets	$	2,528,011		$	-		$	2,528,011
Warrant derivative liability	$	2,411,709		$	(909,009	)	$	1,502,700
Current liabilities		3,099,523			(909,009	)		2,190,514
Total liabilities		3,157,146			(909,009	)		2,248,137
Stockholder’s equity :
Common stock, $.001 par; 500,000,000 shares authorized shares; 52,432,486 and 30,933,990 shares issued and outstanding		52,432			-			52,432
Additional paid in capital		10,718,194			571,401			11,289,595
Accumulated deficit		(11,399,761	)		337,608			(11,062,153	)
Total stockholder’s equity		(629,135	)		909,009			279,874
Total liabilities and stockholder’s equity	$	2,528,011		$	-		$	$ 2,528,011

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	July 31, 2010
Statement of Operations	As reported			Adjustments			As restated
Revenue	$	531,736		$	-		$	531,736
Total operating expenses		4,389,154			742,202			5,131,356
Loss from operations		(3,857,418	)		(742,202	)		(4,599,620	)
Interest expense, net		(68,359	)		-			(68,359	)
Gain on warrant derivative liability		96,293			1,079,810			1,176,103
Net loss	$	(3,829,484	)	$	337,608		$	(3,491,876	)
Basic and diluted loss per common share	$	(0.08	)	$	-		$	(0.08	)
Weighted average shares outstanding (basic and diluted)		45,642,982			-			45,642,982

	July 31, 2010
Statement of Cash Flows	As reported			Adjustments			As restated
Cash Flows from Operating Activities
Net loss	$	(3,829,484	)	$	337,608		$	(3,491,876	)
Adjustments to reconcile net loss to net cash used in operating activities:
Derivative warrants granted for services		13,157			(987	)		12,170
Warrant modification expense		-			743,189			743,189
Gain on warrant derivative liability		(96,293	)		(1,079,810	)		(1,176,103	)
Net cash used in operating activities		(2,643,485	)		-			(2,643,485	)
Net cash provided by (used in) investment activities		(575,412	)		-			(575,412	)
Net cash provided by financing activities		3,447,955			-			3,447,955
Net increase (decrease) in cash		229,058			-			229,058
Cash at beginning of period		18,793			-			18,793
Cash at end of period	$	247,851		$	-		$	247,851

Note 3 – Going Concern

The accompanying consolidated financial statements have been prepared on the basis of a going concern which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. At July 31, 2010, we had a working capital deficiency of $1,615,780, an accumulated deficit of $11,062,153, and have incurred significant losses since inception. The ability of the Company to continue as a going concern is dependent on raising additional capital to fund ongoing exploration and development and ultimately on generating future profitable operations.

The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Since internally generated cash flow will not fund development and commercialization of the Company’s oil and gas properties, we will require significant additional financial resources and will be dependent on future financings to fund its ongoing exploration and development as well as other working capital requirements. Our future capital requirements will depend on many factors including the rate and extent of progress in its exploration and development programs. There can be no assurance we will be successful in our efforts to raise additional financing or if financing is available, that it will be on terms that are acceptable to us.

Management is addressing going concern remediation through raising additional sources of capital for operations and planned property acquisitions. During the year ended July 31, 2010, we raised approximately $3.5 million from the sale of common stock and the exercise of warrants.We continue to seek equity funding.Management’s plans are intended to increase our financial stability and improve the efficiency of continuing operations. These measures, if successful, will contribute to reducing the risk of going concern uncertainties for us over the next twelve to twenty-four months.

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If we do not raise capital sufficient to fund our business plan, Strategic may not survive.

Note 4 – Oil and Gas Properties

Oil and natural gas properties as of July 31, 2010 and 2009 consisted of the following:

	July 31,
	2010			2009
Evaluated Properties
Costs subject to depletion	$	1,459,858		$	1,163,027
Depletion		(265,872	)		(176,101	)
Total evaluated properties		1,193,680			986,926
Unevaluated properties		734,533			295,454
Net oil and gas properties	$	1,928,213		$	1,282,380

Evaluated properties

Barge Canal, Texas

On November 16, 2006 we completed an assignment and purchase agreement with OPEX Energy, LLC with an effective date of August 1, 2006. Under the terms of the agreement, we paid $500,000 plus a finder’s fee of $50,000 for a 100% working interest (90% after payout) and a 72.5% net revenue interest (65.25% after payout) in approximately 81 acres of an oil and gas lease (the “Welder Lease”) located in Calhoun County, Texas.

South Delhi / Big Creek Field, Louisiana

On August 24, 2006, we entered into an assignment of oil and gas interests purchase agreement with Energy Program Accompany, LLC (the “EPA Purchase Agreement”). Under the terms of the EPA Purchase Agreement, the Company paid $250,000 to acquire the Holt Lease, the Strahan Lease and the McKay Lease, as described below.

The Holt Lease

Pursuant to the EPA Purchase Agreement, we acquired a 97% working interest and an 81.25% net revenue interest in approximately 136 acres in Franklin Parish, Louisiana (the “Holt Lease”).

The Strahan Lease

Pursuant to the EPA Purchase Agreement, we acquired a 100% working interest and an 81.25% net revenue interest in approximately 40 acres in Richland Parish, Louisiana (the “Strahan Lease”).

Assignment of Interests to Tradestar Resources Corporation

In conjunction with the acquisition of the Holt Lease, the Strahan Lease and the McKay Lease, we assigned a 25% working interest with respect to each lease to Tradestar Resources Corporation as a finder’s fee. In each case, the 25% working interest consists of two parts - a 12.5% working interest prior to payout and a 12.5% back in after payout agreement working interest. Tradestar Energy Inc., a wholly owned subsidiary of Tradestar Resources Corporation, became the operator of record for the Holt, Strahan and McKay Leases as of December 1, 2007.

The Dixon Lease, Louisiana

We have leased 93.82% of 81.25% net revenue mineral interests in the Dixon 160 acre tract in Franklin Parish, Louisiana. The Dixon lease has two oil wells and one currently permitted salt water disposal well. We reworked the wells during January 2010 and reestablished production as of May 31, 2010.

Janssen Lease, Texas

In October 2005 we entered into an agreement to purchase a 25% working interest and an 18.75% net revenue interest in approximately 138 acres of an oil and gas lease (the “Janssen Lease”) located in Karnes County, Texas. This lease interest was acquired from Rockwell Energy of Texas LLC for $220,000 plus additional payments of $13,800 to negotiate new oil, gas and mineral leases. On December 20, 2006 we farmed out 100% of the working interest to ETG Energy Resources, retaining a 3% back in after payout on any producing zones and a 5% non-promoted option to participate in any offset drilling within the leased area.

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Unevaluated properties

Koliba Prospect, Texas

We have leased over 95% of the minerals rights on this tract of a 79 acre tract (the “Koliba Lease”) in Victoria County, Texas. Additionally, we paid $70,000 for an assignment of oil and gas leases on 64 adjacent and contiguous acres. This Assignment includes several leases with numerous mineral owners.During the current fiscal year, we entered into participation agreements whereby a total of a 75% working interest has been assigned to other parties. We will retain a carried 16.33% working interest to casing point, and have a 25% working interest (not carried) after casing point in the completed well. As of July 31, 2010, we had drilled an exploratory well on the Koliba lease which was determined to be unsuccessful and thus we plugged and abandoned the well.We have classified the drilling costs as evaluated, unproductive costs as of July 31, 2010.We are evaluating the leases for additional prospects, and thus the acquisition cost and geological and geophysical costs associated with the leases are classified as unevaluated as of July 31, 2010.We received a reimbursement of costs of $92,362 associated with the prospect during the year ended July 31, 2010. The proceeds received in this transaction were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.

Kenedy Prospect, Texas

Through July 31, 2010 we have entered into a lease agreement with certain mineral owners of a 1,203 acre tract (the “Kenedy Lease”) in Kenedy County, Texas. We paid $187,824 for a 100% working interest and a 75% net revenue interest.

Oakdale NE, Donoho, Markham City North and DST Prospects, Illinois

Through July 31, 2010 we have entered into numerous oil and gas leases in Jefferson and other counties in Illinois. The leases total approximately 2,994 gross acres pursuant to which the Company has a 100% working interest and an 87.5% net revenue interest.

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.

At July 31, 2010 the ceiling test value of our reserves was calculated using a base price based on the first day average of the 12-months ended July 31, 2010 of the NYMEX (Cushing, OK WTI) posted price of $76.51 per barrel, and the first day average of the 12-months ended July 31, 2010 of the NYMEX (Cushing, OK WTI) price of $4.51 per MMbtu. The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements. 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.

At July 31, 2009, the ceiling test value of our reserves was calculated using a base price based on the July 31, 2009 the NYMEX (Cushing, OK WTI) posted price of $69.26 per barrel and $3.65 per million British thermal unit (MMbtu). The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements.

At July 31, 2010 and 2009, our net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.

Note 5 – Asset Retirement Obligation

The following is a reconciliation of our asset retirement obligation liability as of July 31, 2010 and 2009:

	2010		2009
Liability for asset retirement obligation, beginning of period	$	22,662	$	15,365
Additions		10,598		7,297
Revisions in estimated cash flows		731		—
Accretion		23,632		—
Liability for asset retirement obligation, end of period	$	57,623	$	22,662

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Note 6 – Notes Payable

2009 Convertible note payable

During March 2009, we sold $150,000 convertible debentures, convertible at the greater of $0.25 per share or 90% of the current market price. The investor also received warrants to purchase 600,000 shares of common stock at an exercise price of $.60 per share for an exercise period that expires September 25, 2010. We retained the right to redeem the convertible promissory notes at any time upon giving certain notice to the holder(s), and subject to paying a 20% premium. The debentures carry interest at 15% to be accrued semiannually and payable in arrears. This sale resulted in net cash proceeds of $150,000.

We analyzed the convertible debentures for derivative accounting consideration under FASB ASC Topic No. 815-10 (formerly SFAS 133) and ASC Topic No. 815-40(formerly EITF 00-19). We determined the conversion feature met the criteria for classification in stockholders’ equity as the terms limit the number of shares to be delivered upon conversion by specifying the floor on the conversion price. Therefore, derivative accounting is not applicable for the convertible instruments.

We evaluated the warrants for derivative accounting consideration under FASB ASC Topic No. 815-10 (formerly SFAS 133) and ASC Topic No. 815-40(formerly EITF 00-19).We have concluded that the warrants, limiting the number of shares issuable, meet the criteria for classification in stockholders’ equity. Therefore, derivative accounting is not applicable for the warrants.

The fair value of the proceeds was allocated among the debentures and warrants as follows:

Relative fair value of the warrants	$	91,221
Relative fair value of the convertible debentures		58,779
Total	$	150,000

The fair value of the warrant was calculated using the Black-Scholes method, assuming volatility of 150.70%, expected term of 1.5 years, and a risk adjusted interest rate of 0.78%.

We analyzed the convertible debentures for the existence of a beneficial conversion feature under EITF 98-5 and 00-27.The intrinsic value of the beneficial conversion feature was $58,779.The relative fair value of the warrants and the intrinsic value of the beneficial conversion feature totaling to $150,000 were recorded as a discount to the notes.

These discounts will be amortized and charged to interest expense over the life of the notes using the effective interest rate method. The effective interest rate on the notes, including the discount, is 278% per annum. As of July 31, 2010 and July 31, 2009, respectively, $104,564 and $30,652 of the discount had been amortized.

2010 Promissory Note

On September 2, 2009, we issued a $100,000 promissory note that bear interest at 3% per term, due 90 days from the date of issuance. Additionally, we issued warrants to purchase 100,000 shares of common stock at an exercise price of $0.25 per share and for an exercise period of three years. We recognized the relative fair value of the warrants of $16,000 as a discount on the note and a component of stockholders’ equity. The fair value of the warrants was estimated using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.39%, a dividend yield of 0%, and an expected volatility of 142%. We amortized the discount over the term of the note, three months.The note and accrued interest was repaid in November 2009.

Note 7 – Warrant Derivative 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, 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 “Other income (expense) – 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 exercise price of all the 12,977,500 warrants issued to investors, vendors, and for finders’ fees in October 2009, as more fully discussed in Note 9 – Stockholders’ Equity, is subject to “reset” provisions in the event we subsequently issue common stock, stock warrants, stock options or convertible debt with a stock price, exercise price or conversion price lower than $0.35. If these provisions are triggered, the exercise price of all their warrants will be reduced.

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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 our common stock began trading.

The following table provides the basis for the volatility curve used in the model:

Date of valuation	1 year			2 year			3 year			4 year			5 year
October 15, 2009 (Issuance of  warrants to purchase 12,977,500 shares of common stock)		121	%		255	%		304	%		320	%		331	%
November 13, 2009 (issuance of warrants to purchase  6,030,000 shares of common stock)		219	%		272	%		284	%		300	%		350	%
April 12, 2010 (exercise of warrants to purchase  2,775,870 shares of common stock)		219	%		272	%		284	%		300	%		350	%
July 31, 2010 (year end remeasurement)		132	%		271	%		300	%		312	%		329	%

The total fair value of the warrants issued during October 2009, amounting to $3,349,984, was recognized as a derivative liability on the date of issuance.The fair value on the date of issuance includes the net cash proceeds from the sale of stock of $2,042,112, the value of accounts payable and debt settled of $310,000, and an unrealized loss as of the date of issuance of $997,872.

The exercise price of all the 6,030,000 warrants issued to investors, consultants, and for finders’ fees in November 2009 is subject to “reset” provisions in the event we subsequently issue common stock, stock warrants, stock options or convertible debt with a stock price, exercise price or conversion price lower than $0.35. If these provisions are triggered, the exercise price of all their warrants will be reduced.

The total fair value of the warrants issued during November 2009, amounting to $1,467,759, was recognized as a derivative liability on the date of issuance.The fair value on the date of issuance includes net cash proceeds from the sale of stock of $1,016,750, the fair value of warrants granted to a consultant for business development services of $12,170, and an unrealized loss as of the date of issuance of $438,839.

In April 2010, the exercise price of the 19,007,500 derivative warrants issued during October and November 2009 was reduced from $0.35 to $0.23 per share. Because these warrants are measured at fair value, with changes in fair value recognized currently in earnings in our consolidated statement of operations under the caption "Other Income (expense) - Gain (loss) on warrant derivative liability", this repricing had no accounting impact.

During April 2010, 2,775,870 of the warrants classified as derivatives and issued during October 2009 were exercised for $638,450. This reduced the derivative liability by $702,229 and increased the additional paid-in capital by the same amount.

The following table sets forth the changes in the fair value measurement of our Level3 derivative warrant liability during the year ended July 31, 2010:

Beginning balance – July 31, 2009	$	-
Issuance of derivative warrants		3,381,032
Reduced for warrants exercised		(702,229	)
Change in fair value of derivative liability		(1,176,103	)
At July 31, 2010	$	1,502,700

The $1,878,332 change in fair value was recorded as a reduction of the derivative liability and as a $1,176,103 unrealized gain on the change in fair value of the liability in our statement of operations and an $702,229 adjustment to paid in capital related to the exercise during the period of warrants classified as derivative liabilities.

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Note 8 - Stockholder’s Equity

Share Capital

The Company’s capitalization at July 31, 2010 was 500,000,000 authorized common shares with a par value of $0.001 per share.

Common Stock Issuances

For cash:

In April 2010, an aggregate of 2,775,870 share purchase warrants were exercised for net proceeds of $638,450.The warrants were derivative warrants; accordingly, the warrant derivative liability as of the date of exercise, $702,229, was reclassified to paid in capital.A total value of $1,340,679 was recorded in conjunction with this transaction.

In November 2009, we completed a private placement for 5,250,000 units at a subscription price of $0.20 per Unit for gross proceeds of $1,050,000.Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 5,250,000 shares of common stock had an exercise price of $0.35 per warrant share and expire five years from the date of issuance. The proceeds, net of $147,888 of finder’s fees, were allocated to the warrants because the warrants are derivatives (see Note 7) and fair value of the warrants was classified as a liability.

On October 15, 2009, we completed a private placement for 10,950,000 units at a subscription price of $0.20 per Unit for gross proceeds of $2,190,000.Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 10,950,000 shares of common stock had an exercise price of $0.35 per warrant share and expire five years from the date of issuance.The purchase price for 1,000,000 units, or $200,000, was collected during the year ended June 31, 2009 and the shares are deemed as issued as of July 31, 2009.The proceeds, net of $33,250 of finder’s fees, were allocated to the warrants because the warrants are derivatives (see Note 7) and the relative fair value of the warrants was classified as a liability.

We paid $181,138 of cash offering costs associated with the placements completed in October and November 2009.Accordingly, the net cash proceeds, which were allocated to the warrants, raised from these placements totaled $2,858,862.

In addition, during October and November 2009, we granted warrants to purchase 1,207,500 shares of common stock at $.35 per share which expire five years from the date of issuance as finder’s fees.The fair value of the warrants was calculated using the Black-Sholes method as $354,367. The warrants are derivatives (see Note 7) and the fair value of the warrants was classified as a liability at issuance.

During May and June 2009, we collected $138,050 cash for a private placement for 460,166 Units, which were issued in September 2009, at a subscription price of $0.30 per Unit. The shares are deemed as issued as of July 31, 2009. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 10,950,000 shares of common stock had an exercise price of $0.40 per share and expire three years from the date of issuance. The proceeds were allocated to the warrants and stock, respectively, based on their relative fair values as $42,553 and $95,497.

In August, September, and October 2008, we completed private placements for an aggregate of 811,666 Units at a subscription price of $0.60 per Unit for gross proceeds of $487,000.Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 811,666 shares of common stock had an exercise price of $1.00 per warrant share and expire on August 14, 2009, one year from the date our common shares are first listed for trading on any stock exchange or over-the-counter bulletin board market.

For services:

During the year ended July 31, 2010, we issued 1,493,294 shares of common stock to consultants and directors for services valued at $519,115.The shares were valued using the closing market price on the date of grant.

During the year ended July 31, 2009, we issued 659,525 shares of common stock to consultants and directors for services valued at $308,382.The shares were valued using the closing market price on the date of grant.

For accounts payable:

In September 2009, we settled $143,800 of outstanding accounts payable to consultants with Units having the same terms as the September 2009 private placement.Thus, 479,332 Units at a price of $0.30 per Unit were used to settle the accounts payable. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 479,332 shares of common stock had an exercise price of $0.40 per share and expire three years from the date of issuance. The proceeds were allocated to the warrants and stock, respectively, based on their relative fair values as $44,325 and $99,475.

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In October 2009, we settled $122,885 of outstanding accounts payable to consultants, officers, and directors with Units having the same terms as the October 2009 private placement.Thus, 614,417 Units at a price of $0.20 per Unit were used to settle the accounts payable. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 617,417 shares of common stock had an exercise price of $0.35 per share and expire five years from the date of issuance. The proceeds were allocated to the warrants, which are derivatives (see Note 7) and classified as a liability.

In June 2009, we issued 171,429 shares of common stock to settle accounts payable to a consultant with a value of $60,000 for $0.35 per share.

In August 2008, we settled accounts payable with a value of $60,000 to a consultant for an aggregate of 100,000 Units with a subscription price of $0.60 per Unit, with each such Unit being comprised of one common share of common stock and warrants to purchase one-half of one common stock share for each unit. The warrants to purchase 50,000 shares of common stock had an exercise price of $1.00 per share and on August 14, 2011, three years from the date that our common shares were first listed for trading on any stock exchange or over-the-counter bulletin board market, being August 14, 2008.

For debt – related parties:

In October 2009, we settled $187,116 of principal and interest outstanding on notes payable to three related parties with Units having the same terms as the October 2009 private placement.Thus, 935,583 Units at a price of $0.20 per Unit were used to settle the debt. Each Unit is comprised of one common share and one warrant to purchase the same number of shares of common stock. The warrants to purchase 935,583 shares of common stock had an exercise price of $0.35 per share and expire five years from the date of issuance. The proceeds were allocated to the warrants, which arederivatives (see Note 7) and was classified as a liability.

Stock options

During the year ended July 31, 2010, we granted options to purchase 2,600,000 shares of common stock to a consultant and an officer.The compensation expense associated with compensatory stock options during the year ended July 31, 2010 was $639,469. During the year ended July 31, 2009, we granted options to purchase 2,730,000 shares of common stock to our consultants, officers, and directors.The compensation expense associated with compensatory stock options during the year ended July 31, 2009 was $801,912. See Note 9 for additional information.

Warrants

For services:

During the year ended July 31, 2010, we granted warrants to purchase 50,000 shares of common stock to a consultant.The compensation expense associated with this grant was expensed in the year ended July 31, 2010 and was $12,170.The warrants have a down-round ratchet provision on the exercise price; thus, the fair value of the warrants was classified as a liability.

With debt:

During the year ended July 31, 2010, we issued warrants to purchase 100,000 shares of common stock with an exercise price of $.25 per share and a three year term with a promissory note payable.We recognized the relative fair value of the warrants of $16,000 as a discount on the note and a component of stockholders’ equity. The fair value of the warrants was estimated using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.39%, a dividend yield of 0%, and an expected volatility of 142%. In addition, we adjusted the debt discount related to the convertible note payable issued in March 2009 by increasing it by $12,067 during the year ended July 31, 2010.

During the year ended July 31, 2009, we issued warrants to purchase 600,000 shares of common stock with an exercise price of $.60 per share and a 1.5 year term with a convertible note payable.We recognized a discount on the debt of $137,933, which consisted of the relative fair value of the warrant and the beneficial conversion feature on the debt.

With debt – related party:

During the year ended July 31, 2010, we issued warrants to purchase 100,000 shares of common stock with an exercise price of $.25 per share and a three year term with a promissory note payable to a related party.We recognized the relative fair value of the warrants of $16,000 as a discount on the note and a component of stockholders’ equity. The fair value of the warrants was estimated using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.39%, a dividend yield of 0%, and an expected volatility of 142%.

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Warrant modification

During August 2009, we extended the term of 5,158,238 warrants which were originally issued in conjunction with equity issues during 2006, 2007, and 2008. The modification resulted in modification expense of $679,199 which was calculated as the difference in the fair value of the warrants immediately before and after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modification:

	Before	After
Risk-free interest rate	0.47%	0.47%
Dividend yield	0%	0%
Volatility factor	154.60%	154.60%
Remaining term (years)	0	1

During February 2010, we extended the term of 419,701 warrants from February 12, 2010 to February 12, 2011. These warrants were originally issued for finder’s fees. The modification resulted in modification expense of $63,990 which was calculated as the difference in the fair value of the warrants immediately before and after the modification using the Black-Scholes option pricing model. The following table details the significant assumptions used to compute the fair market value of the warrant modification:

	Before	After
Risk-free interest rate	0.35%	0.35%
Dividend yield	0%	0%
Volatility factor	162.97%	162.97%
Remaining term (years)	0	1

Note 9 – Stock Options and Warrants

Strategic American Oil Corporation adopted the 2007 Stock Incentive Plan during 2007. A maximum of 10,000,000 shares were issuable under the Plan.

During 2009, the Board of Directors authorized and approved the adoption of the 2009 Re-Stated Stock Incentive Plan (the “2009 Plan”), which absorbs and replaces the 2007 Stock Incentive Plan. An aggregate of 10,000,000 of the Company’s shares may be issued under the plan. The Stock Incentive 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.

The fair value of each option or warrant award is estimated using the Black-Scholes valuation model. Expected volatility is based solely on historical volatility because we do not have traded options. The volatility was determined by referring to the average historical volatility of a peer group of public companies because we do not have sufficient trading history to determine our historical volatility.Beginning with computations after May 2009, when there was an active trading market for our stock, we have included our own historical volatility in determining the volatility used.We will continue to use a peer group until we have sufficient trading history to determine our own historical volatility.

The expected term calculation for stock options is based on the simplified method as described in the Securities and Exchange Commission Staff Accounting Bulletin number 107. We use this method because we do not have sufficient historical information on exercise patterns to develop a model for expected term. The risk-free interest rate is based on the U. S. Treasury yield in effect at the time of grant for an instrument with a maturity that is commensurate with the expected term of the stock options. The dividend yield rate of zero is based on the fact that we have never paid cash dividends on our common stock and we do not intend to pay cash dividends on our common stock.

Stock Options

We have granted no options to employees.

Options granted to non-employees during the years ended July 31, 2010 and 2009

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 and the measurement date is the vesting date, which is considered the date performance is complete.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.Options granted during the years ended July 31, 2010 and 2009 were as follows:

● Options to purchase 2,500,000 shares of common stock with an exercise price of $.20 per share and a term of three years were granted to our new CEO in November 2009.The initial fair value of the options was $770,020.Options to purchase 625,000 shares (25% of the award) vested immediately; the remaining options vest 25% each six months over the following 18 months.The expected term of the options that vested immediately, computed using the simplified method, was two years.The expected term of the options with graded vesting, computed using the simplified method, was 2.125 years.

47

● Options to purchase 100,000 shares of common stock with an exercise price of $.20 per share and a term of three years were granted to employee consultant as a signing bonus.The fair value of the options was $31,445.The options vest 25% each six months over the 24 months following the award.The expected term of the options, computed using the simplified method, was two years.

● In May 2009, we granted a total of 2,230,000 stock options to purchase common stock with an exercise price of $0.35 per share and a term of ten years to consultants, officers, and directors. The fair value of the options was $1,285,989.Options to purchase 1,270,000 shares vested immediately and the remaining options to purchase 960,000 shares vest 25% each six months over the 18 months following the grant. The expected term of the options that vested immediately, computed using the simplified method, was five years.The expected term of the options with graded vesting, computed using the simplified method, was 5.5 years.

● In March 2009, we granted options to purchase 500,000 shares of common stock at an exercise price of $0.35 per share and a term of three years to a consultant.The fair value of the options was $219,380.The options vested immediately. The expected term of the options, computed using the simplified method, was 1.5 years.

● The following table details the significant assumptions used to compute the fair market values of stock options granted:

	2010			2009
Risk-free interest rate		0.47-0.68	%		0.71-2.16	%
Dividend yield		0	%		0	%
Volatility factor		159.50-162.03	%		148.93-155.67	%
Expected life (years)	1.5-2.13 years			1.5-5.5 years

The following table provides information about options granted to consultants during the years ended July 31,

	2010		2009
Number of options granted		2,600,000		2,730,000
Compensation expense recognized	$	639,469	$	801,912
Compensation cost capitalized		-		-
Weighted average fair value of optionsgranted	$	0.20	$	0.35

Summary information regarding stock options issued and outstanding as of July 31, 2010 is as follows:

	Options			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2008		3,800,000		$	0.33		-		8.94
Granted		2,730,000			0.35
Exercised		-			-
Expired		-			-
Outstanding at year ended July 31, 2009		6,530,000			0.34	$	62,500		8.16
Granted		2,600,000			0.20
Exercised		-
Expired		(425,000	)		0.35
Outstanding at year ended July 31,2010		8,705,000		$	0.30	$	20,000		5.32

Options outstanding and exercisable as of July 31, 2010:
Exercise Price	Outstanding Number of Shares	Remaining Life	Exercisable Number of Shares
0.10	250,000	6.93 years	250,000
0.20	2,600,000	2.33 years	1,275,000
0.35	425,000	1 year or less	425,000
0.35	500,000	1.63 years	500,000
0.35	3,200,000	6.93 years	3,200,000
0.35	1,730,000	8.81 years	1,535,000
	8,705,000		7,185,000

Options outstanding and exercisable as of July 31, 2009:
Exercise Price	Outstanding Number of Shares	Remaining Life	Exercisable Number of Shares
0.10	250,000	7.93 years	250,000
0.35	500,000	2.63 years	500,000
0.35	3,750,000	7.93 years	3,750,000
0.35	2,030,000	9.81 years	1,070,000
	6,530,000		5,570,000

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Warrants

We issued or modified the following warrants during the years ended July 31, 2010 and 2009:

● During April 2010, we reduced the exercise price of warrants to purchase 19,007,500 shares of common stock from $.35 per share to $.23 per share.The modification is treated as the exchange of the $.35 per share warrants for an equal number of new warrants with an exercise price of $.23 per share.

● During February 2010 we extended the term of warrants to purchase 419,701 shares of common stock for one year. These warrants were originally issued for finder’s fees. The warrants were scheduled to expire on the extension date.The modification is treated as the expiration of the original warrant and the grant of a new warrant. (See Note 8).

● In November 2009, we issued warrants to purchase 5,250,000 shares of common stock with an exercise price of $0.35 per warrant share and a five year term.We also issued as finder’s fees warrants to purchase 730,000 shares of common stock with an exercise price of $0.35.(See Note 8).

● During November 2009, we granted warrants to purchase 50,000 shares of common stock with an exercise price of $0.35 per share and a five year term to a consultant.(See Note 8).

● In October 2009, we issued warrants to purchase 12,500,000 shares of common stock with an exercise price of $0.35 per share and a five year term in conjunction with the sale of stock and the settlement of accounts payable and debt to related parties. We also issued as finder’s fees warrants to purchase 477,500 shares of common stock with an exercise price of $0.35 and a five year term. (See Note 8).

● During September 2009, we issued warrants to purchase 939,498 shares of common stock with an exercise price of $0.40 per share and a three year term in conjunction with the sale of stock and the settlement of accounts payable (See Note 8).

● In September 2009, we issued warrants to purchase 100,000 shares of common stock with an exercise price of $0.25 per share and a 3 year term in connection with the issuance of a note payable to an investor. (See Note 6).

● In September 2009, we issued warrants to purchase 100,000 shares of common stock with an exercise price of $0.25 per share and a 3 year term in connection with the issuance a note payable to a related party. (See Note 10).

● In August 2009, we extended the term of warrants to purchase 5,158,238 shares of common stock which were originally issued in conjunction with an equity issue for one year. The warrants were scheduled to expire on the extension date.The modification is treated as the expiration of the original warrant and the grant of a new warrant.

● During the year ended July 31, 2009, we issued warrants to purchase 811,666 shares of common stock with an exercise price of $1.00 per share and expiration date of August 14, 2009.Warrants to purchase an additional 83,333 shares with the same terms associated with units subscribed prior to July 31, 2008 were also issued during the year ended July 31, 2009.

● During the year ended July 31, 2009, we issued warrants to purchase 600,000 shares of common stock with an exercise price of $.60 per share and a 1.5 year term with a convertible note payable.

● During the year ended July 31, 2009, we issued warrants to purchase 50,000 shares of common stock with an exercise price of $1.00 per share and an expiration date of August 14, 2009 as part of the settlement of an account payable.

Summary information regarding common stock warrants issued and outstanding as of July 31, 2010 is as follows:

	Options			Weighted Average Share Price		Aggregate intrinsic value		Weighted average remaining contractual life (years)
Outstanding at year ended July 31, 2008		7,117,425		$	0.83		-		.79
Granted		1,544,999			1.00		-		-
Exercised		-			-		-		-
Expired		(2,302,145	)		.60		-		-
Outstanding at year ended July 31, 2009		6,360,279			0.91		-		0.20
Granted		44,732,437			0.37		-		-
Exercised		(2,775,870	)		0.23		-		-
Expired		(24,717,779	)		0.49		-		-
Outstanding at year ended July 31,2010		23,599,067		$	0.42		-		3.02

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Warrants outstanding and exercisable as of July 31, 2010:
Exercise Price	Outstanding Number of Shares	Remaining Life	Exercisable Number of Shares
0.23	16,231,630	4.21 years	16,231,630
0.25	200,000	2.09 years	200,000
0.35	346,143	1 year or less	346,143
0.40	939,498	2.15 years	939,498
0.60	673,558	1 year or less	673,558
1.00	5,158,238	1 year or less	5,158,238
1.00	50,000	1.03 years	50,000
	23,599,067		23,599,067

Warrants outstanding and exercisable as of July 31, 2009
Exercise Price	Outstanding Number of Shares	Remaining Life	Exercisable Number of Shares
0.35	385,000	1 year or less	385,000
0.50	4,000	1 year or less	4,000
0.60	163,041	1 year or less	163,041
0.60	600,000	1.15 years	600,000
1.00	5,158,238	1 year or less	5,158,238
1.00	50,000	2.03 years	50,000
	6,360,279		6,360,279

Note 10 – Related Party Transactions

Related party debt

From time to time, officers, directors, and family members of officers and directors have loaned us funds.The following table provides a summary of related party debt outstanding as of July 31,

	2010		2009
Note payable to a director, interest rate 18% per annum, due on demand		-	$	25,000
Note payable to an officer, interest rate 18% per annum, due on demand		-		44,000
Note payable to a family member of an officer and director, interest rate 15% per annum, due on demand		-		100,000
Note payable to an officer, interest rate 18%, due on demand		-		27,500
Note payable to a director, interest rate 18%, due on demand		-		18,500
Total notes payable		-		215,000
Accrued interest on notes payable		-		26,864
Notes payable, including accrued interest payable		-	$	241,864

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The activity involving related party debt is as follows:

	Notes payable			Accrued Interest			Transaction loss			Total due
Balance, July 31, 2008	$	79,000		$	3,597			-		$	82,597
Advances		146,000						-			146,000
Payments in cash		(10,000	)					-			(10,000	)
Settlement in common stock											-
Interest incurred					23,267			-			23,267
Balance, July 31, 2009		215,000			26,864			-			241,864
Advances		100,500									100,500
Interest incurred					8,870			-			8,870
Transaction loss(1)							$	21,827			21,827
Payments in cash		(160,500	)		(17,867	)		(7,578	)		(185,945	)
Settlement in common stock		(155,000	)		(17,867	)		(14,249	)		(187,116	)
											-
Balance, July 31, 2010	$	-		$	-		$	-		$	-

(1) Our arrangement with one of the lenders provided that, at his option, the debt would be settled in Canadian or US dollars.At the time we repaid the debt, he requested Canadian dollar equivalents, which resulted on a transaction loss on the settlement.

Barge Canal Properties

A company controlled by one of our officers operates our Barge Canal properties. Revenues generated from these properties were $295,574 and $355,880 for the years ended July 31, 2010 and 2009, respectively. In addition, lease operating costs incurred from these properties were $229,067 and $157,969 for the years ended July 31, 2010 and 2009, respectively.

As of July 31, 2010 and 2009, respectively, we had outstanding accounts receivable associated with these properties of $28,975 and $34,366 and no accounts payable.

Note 11 - Income Taxes

As of July 31, 2010, we had approximately $7,436,000 of U.S. federal and state net operating loss carry-forward available to offset future taxable income, which begins expiring in 2026, if not utilized. Future tax benefits that may arise as a result of these losses have not been recognized in these financial statements.The deferred tax asset generated by the loss carry-forward has been fully reserved due to the uncertainty we will be able to realize the benefit from it.

Our deferred income taxes reflect the net tax effects of operating loss and tax credit carry forwards and temporary differences between carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which temporary differences representing net future deductible amounts become deductible.

Components of deferred tax assets as of July 31, 2010 and 2009 are as follows:

	July 31,
	2010			2009
Stock based compensation	$	223,814		$	546,226
Property, including depreciable property		88,897			83,250
Other liabilities		(4,265	)		11,772
Net operating loss carry-forward		2,537,892			1,652,203
		2,850,603			2,293,451
Valuation allowance for deferred tax assets		(2,850,603	)		(2,293,451	)
	$	—		$	—

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The reconciliation of income tax provision at the statutory rate to the reported income tax expense is as follows:

	July 31,
	2010			2008
US statutory federal rate		35	%		35	%
State income tax rate		.99	%		.99	%
Net operating loss for which no tax benefit is currently available		(35.99	)%		(35.99	)%
		—	%		—	%

The valuation allowance is evaluated at the end of each year, considering positive and negative evidence about whether the deferred tax asset will be realized. At that time, the allowance will either be increased or reduced; reduction could result in the complete elimination of the allowance if positive evidence indicates that the value of the deferred tax assets is no longer impaired and the allowance is no longer required.

We have no positions for which it is reasonable that the total amounts of unrecognized tax benefits at July 31, 2010 will significantly increase or decrease within 12 months.

Generally, our income tax years 2006 through 2009 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas which are the jurisdictions where we have our principal operations. No material amounts of the unrecognized income tax benefits have been identified to date that would impact our effective income tax rate.

Note 12 - Commitments and Contingencies

Contingencies

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued based on our best estimate of the potential loss. While the outcome and impact of currently pending legal proceedings cannot be predicted with certainty, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated operating results, financial position or cash flows.

Commitments

We have the following management and employment contract obligations:

● $10,000 per month cash payable as a management fee pursuant to a contract with an officer that automatically renews every three months as of November 30, 2008

● $8,333 per month cash compensation for an officer pursuant to a contract with a term of one year that expires on December 1, 2010.

● $4,000 per month cash compensation for a contract geologist pursuant to a contract with a term of one year that expires on December 1, 2010

We lease office space in Corpus Christi, Texas. Our office lease is due to expire in October 2010. Lease expense for the years ended July 31, 2010 and 2009 was $31,739 and $32,344, respectively.

Note 13 – Additional Financial Statement Information

Other current assets

	At July 31,
	2010		2009
Prepaid rent	$	1,328	$	1,200
Prepaid consulting		250,000		43,278
Total Other current assets	$	251,328	$	44,478

Prepaid consulting as of July 31 is an advance payment for an investor response program.The program occurred during September 2010.Prepaid consulting as of July 31 is a payment to two investor relations consultants who completed the work involved during August 2009.

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Property and Equipment

Property and equipment consisted of the following:

		at December 31,
	Approximate Life	2009			2008
Furniture and fixtures	5 years	$	5,597		$	4,632
Computer equipment and software	2 years		7,774			8,320
Leasehold	7 years		-			11,294
Equipment	5 years		-			40,950
Total property and equipment			13,371			65,196
Less accumulated depreciation			(7,624	)		(35,366	)
Net book value		$	5,747		$	29,830

Depreciation expense was $3,172 and $13,753 for the years ended July 31, 2010 and 2009, respectively.Management reviewed its fixed assets and capitalization policy as of July 31, 2010.We incurred a loss on retirement due to the write off of leasehold improvements of $7,560.In addition, we determined that equipment was in use in our oil and gas operations and we reclassified the net book value of the equipment to oil and gas properties as of July 31, 2010.

Note 14 – Subsequent Events

In August 2010, we executed an agreement with an investment consulting company.Under the terms of the agreement, the company will assist us in structuring a funding raise and will use its best efforts to obtain up to $50,000,000 of financing for us through the sale of equity, debt, a combination of equity and debt, or a royalty agreement.The consultant will receive 150,000 shares of common stock immediately and introduction fees ranging from $106,246 to $1,384,354, depending on the level of funding obtained.In September 2010, in accordance with the terms of the agreement, we issued 150,000 shares of common stock to the consultant, which was valued using the closing price on the grant date at $36,000.

In August 2010, 50,000 shares of common stock due to a consultant for services vested in accordance with their contract.We valued the award using the closing price on the vesting date at $8,750.

In August 2010, we granted a stock option to purchase 1,400,000 shares of common stock with an exercise price of $.20 per share and a term of three years to one of our officers.The fair value of the options, as calculated using the Black-Sholes valuation model, was $178,225.Options to purchase 350,000 shares (25% of the award) vested immediately; the remaining options vest 25% each six months over the following 18 months.

In August 2010, we entered into an agreement with a consultant to assist in marketing the Kenedy Ranch lease to investors. Under the terms of the agreement, the consultant would receive a 5% working interest, carried to the casing point, carved out from our retained portion of the lease. In September 2010, we were successful in marketing this lease as discussed below.

In September 2010, we assigned 81.25% working interest in the Kenedy Ranch lease to Chinn Exploration Company “Chinn” for $200,000 cash. The agreement provides that Chinn will operate the property and will drill a test well within 18 months of the date of the agreement. We retained an 18.75% working interest, which will be carried to the casing point with respect to the test well. As discussed above, our marketing consultant received a 5% working interest carved out from our interest. Thus, after compensation of the consultant, our working interest in Kenedy Ranch is 13.75%.

If Chinn does not perform its obligations under the assignment, the agreement provides that the retained working interest reverts to us. The cash proceeds we received in conjunction with this agreement are treated as a reduction of capitalized cost in accordance with rules governing full cost companies.

In September 2010, we sold our interest in the Dixon lease. We received $75,000 cash in conjunction with the sale, which is treated as a reduction of capitalized oil and gas costs in accordance with rules governing full cost companies.

In October 2010, an investor exercised warrants to purchase 870,000 shares of common stock at $.23 per share.We received cash proceeds of $200,100 from this transaction.

In October 2010, we granted stock options to purchase 2,000,000 shares of common stock with an exercise price of $.10 per share and a term of ten years to two consultants.The options vested immediately.The fair value of the options, as calculated using the Black-Sholes valuation model, was $412,578.

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Note 15 – Supplemental Oil and Gas Information (Unaudited)

The following supplemental information regarding our oil and gas activities is presented pursuant to the disclosure requirements promulgated by the SEC and ASC 932, Extractive Activities —Oil and Gas, (ASC 932).

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

In the following table, natural gas liquids are included in natural gas reserves. The oil and natural gas liquids price as of July 31, 2010 is based on the 12-month unweighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) posted price which equates to $76.51 per barrel. Oil and natural gas liquids prices as of July 31, 2009 are based on the respective year-end NYMEX (Cushing, OK WTI) posted price of $69.26 per barrel. The gas price as of July 31, 2010 is based on the 12-month unweighted average of the first of the month prices of the NYMEX (Cushing, OK WTI) spot price which equates to $4.51 per MMbtu. Gas prices as of July 31, 2009 are based on the respective year-end NYMEX (Cushing, OK WTI) spot market price of $3.65 per MMbtu. The base prices were adjusted for heating content, premiums and product differentials based on historical revenue statements. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States; specifically, in on-shore Louisiana and Texas.

The following table illustrates our estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by third party reservoir engineers.

Proved Reserves

	Oil (Barrels)			Gas (MCF)			Total (MCFE)
Balance – July 31, 2008		165,718			148,110			1,142,418
Revisions of previous estimates		(44,169	)		63,224			(201,790	)
Production		(6,480	)		(14,944	)		(53,824	)
Balance – July 31, 2009		115,069			196,390			886,804
Revisions of previous estimates		(19,610	)		(17,423	)		(135,083	)
Production		(6,449	)		(15,727	)		(54,421	)
Purchase of minerals in place		8,140			-			48,840
Balance – July 31, 2010		97,150			163,240			746,140

	Proved Developed Reserves as of July 31, 2010
	Oil (bbls)		Gas (Mcf)		Equivalent (Mcfe)
Proved developed producing		59,220		122,550		477,870
Proved developed non-producing		37,930		40,690		268,270
Total Proved developed reserves		97,150		163,240		746,140

	Proved Developed Reserves as of July 31, 2009
	Oil (bbls)		Gas (Mcf)		Equivalent (Mcfe)
Proved developed producing		66,600		158,730		558,330
Proved developed non-producing		48,469		37,660		328,474
Total Proved developed reserves		115,069		196,390		886,804

The SEC amended its definitions of oil and natural gas reserves effective December 31, 2009. Previous periods were not restated for the new rules. Key revisions include a change in pricing used to prepare reserve estimates to a 12-month un-weighted average of the first-day-of-the-month prices, the inclusion of non-traditional resources in reserves, definitional changes, and allowing the application of reliable technologies in determining proved reserves, and other new disclosures (Revised SEC rules). The Revised SEC rules did not affect the quantities of our proved reserves.

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The reserves in this report have been estimated using deterministic methods. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. Proved undeveloped locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers.

Capitalized Costs Related to Oil and Gas Activities

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization. All oil and gas properties are located in the United States of America as of July 31,

	2010			2009
Unevaluated properties	$	734,533		$	295,454
Evaluated properties		1,692,858			1,396,333
Less impairment		(233,306	)		(233,306	)
		2,194,085			1,458,481
Less depreciation, depletion, and amortization		(265,872	)		(176,101	)
Net capitalized cost	$	1,928,213			1,282,380

Costs Incurred in Oil and Gas Activities

All costs incurred associated with oil and gas activities were incurred in the United States of America. Costs incurred in property acquisition, exploration and development activities were as follow as of July 31,

	2010			2009
Property acquisition
Unproved	$	388,248		$	100,022
Proved		68,250			-
Exploration		295,771			19,683
Development		75,697			7,297
Adjustment of interest in investee		(92,362	)		-
Total costs incurred	$	735,604		$	127,002

Costs Excluded

Our excluded costs relate to two projects in Texas, the Koliba and Kenedy Ranch prospects, and lease acreage we hold in Illinois, United States of America.

Koliba

We have leased over 95% of the minerals rights on this tract of a 79 acre tract (the “Koliba Lease”) in Victoria County, Texas. Additionally, we obtained an assignment of oil and gas leases on 64 adjacent and contiguous acres.In July 2010, we drilled an exploratory well in the area, which was not successful.We are evaluating the leases for additional prospects, and thus the acquisition cost and geological and geophysical costs associated with the leases are classified as unevaluated as of July 31, 2010.We anticipate including the excluded costs in the amortization base within the next fiscal year.

Kenedy Ranch

Through July 31, 2010 we have entered into a lease agreement with certain mineral owners of a 1,203 acre tract (the “Kenedy Lease”) in Kenedy County, Texas. We paid $187,824 for a 100% working interest and a 75% net revenue interest.In September 2010, we assigned 81.25% working interest to an exploration and production company which became the operator for the property.Our 18.75% working interest will be carried to the casing point for a test well that the operator is obligated to drill pursuant to the agreement. We anticipate including the excluded costs in the amortization base within the next fiscal year.

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Illinois Prospects

Through July 31, 2010 we have entered into numerous oil and gas leases in Jefferson County, Illinois. The leases total approximately 2,994 gross acres pursuant to which the Company has a 100% working interest and an 87.5% net revenue interest.We are conducting geological and geophysical analysis to identify drilling prospects.We anticipate including the excluded costs in the amortization base within the next two years.

Costs Excluded by Year Incurred

	Year Cost Incurred									Excluded at July 31,
	Prior		2008		2009		2010			2010
Property Acquisition	$	144,318	$	34,814	$	73,378	$	356,705		$	609,215
Exploration		-		-		-		217,680			217,680
Cost Recovery		-		-		-		(92,362	)		(92,362	)
Total	$	144,318	$	34,814	$	73,378	$	482,023		$	734,533

Changes in Costs Excluded by Country

	United States
Balance at July 31, 2008	$	398,222
Additional Cost Incurred		119,705
Cost Recovery		-
Costs Transferred to DD&A Pool		(222,743	)
Balance at July 31, 2009		295,454
Additional Costs Incurred		639,969
Cost Recovery		(92,362	)
Costs Transferred to DD&A Pool		(108,528	)
Balance at July 31, 2010	$	734,533

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flow information has been developed utilizing ASC 932, Extractive Activities —Oil and Gas, (ASC 932) procedures and based on estimated oil and natural gas reserve and production volumes. It can be used for some comparisons, but should not be the only method used to evaluate us or our performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of our current value.

We believe that the following factors should be taken into account when reviewing the following information:

● future costs and selling prices will probably differ from those required to be used in these calculations;

● due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;

● a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

● future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, for the year ended July 31, 2009 the future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices were required. At July 31, 2010, as specified by the SEC, the prices for oil and natural gas used in this calculation were the un-weighted 12-month average of the first day of the month (12-month un-weighted average) cash price quotes, except for volumes subject to fixed price contracts.

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The Standardized Measure is as follows:

	2010			2009
Future cash inflows	$	7,767,660		$	8,686,900
Future production costs		(4,405,336	)		(4,514,560	)
Future development costs		(150,000	)		(99,570	)
Future income tax expenses		—			—
Future net cash flows		3,212,324			4,072,770
10% annual discount for estimated timing of cash flows		(1,463,695	)		(1,980,910	)
Future net cash flows at end of year	$	1,748,629		$	2,091,860

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for our proved oil and natural gas reserves during each of the years in the two year period ended July 31, 2010:

	2010			2009
Standardized measure of discounted future net cash flows at beginning of year	$	2,091,860		$	4,386,512
Net changes in prices and production costs		(95,884	)		(2,289,522	)
Changes in estimated future development costs		(27,452	)		124,632
Sales of oil and gas produced, net of production costs		(245,237	)		(253,238	)
Purchases of minerals in place		119,805			—
Revisions of previous quantity estimates		(331,359	)		(315,175	)
Development costs incurred		27,709			—
Accretion of discount		209,186			438,651
Standardized measure of discounted future net cash flows at year end	$	1,748,629		$	2,091,860

The following schedule includes only the revenues from the production and sale of gas, oil, condensate and NGLs. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include DD&A allowances, after giving effect to permanent differences. Due to net operating loss carryforwards related to producing activities, income taxes have not been provided at July 31, 2010 and 2009. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.

Results of Operations for Producing Activities

	2010			2009
Net revenues from production	$	531,736		$	490,991
Expenses
Oil and gas operating		571,009			389,547
Accretion		23,632			—
Operating expenses		594,641			389,547
Depreciation, depletion and amortization		92,944			80,303
Total expenses		687,585			469,850
Income (Loss) before income tax		(155,849	)		21,141
Income tax expenses		—			—
Results of operations	$	(155,849	)	$	21,141
Depreciation, depletion and amortization rate per net equivalent MCFE	$	1.71		$	1.49

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

As we previously reported in our Current Report on Form 8-K filed with the Securities and Exchange Commission on September 29, 2010, on August 31, 2010, we dismissed our former certifying accountant, Dale Matheson Carr-Hilton LaBonte LLP Chartered Accountants (“DMCL”) of Vancouver, Canada. During the prior two fiscal years and during the interim period since July 31, 2009, there were no adverse opinions or disclaimers of opinion, or qualifications or modifications as to uncertainty, audit scope, or accounting principles by DMCL in those reports. The decision to change accountants was approved by our audit committee of the board of directors. There were no disagreements with the former accountant, whether or not resolved, on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which, if not resolved to the former accountant’s satisfaction, would have caused it to make reference to the subject matter of the disagreement(s) in connection with its report. The former accountant did not advise us: that internal controls necessary to develop reliable financial statements did not exist; or that information has come to the attention of the former accountant which made the accountant unwilling to rely on management’s representations, or unwilling to be associated with the financial statements prepared by management; or that the scope of the audit should be expanded significantly, or that information has come to the accountant’s attention that the accountant has concluded will, or if further investigated might, materially impact the fairness or reliability of a previously issued audit report or the underlying financial statements, or the financial statements issued or to be issued covering the fiscal period(s) subsequent to the date of the most recent audited financial statements (including information that might prevent the issuance of an unqualified audit report), and the issue was not resolved to the accountant’s satisfaction prior to its resignation or dismissal. We have authorized the former accountant to respond fully to the inquiries of the successor accountant concerning the subject matter of each of such disagreements, if any, or events.

On August 6, 2010, we engaged Malone & Bailey, PC. (“M&B”) of Houston, Texas as our new certifying accountant. We did not consult the new accountant regarding: the application of accounting principles to a specific completed or contemplated transaction, or the type of audit opinion that might be rendered on our financial statements and neither written or oral advice was provided that was an important factor considered by us in reaching a decision as to the accounting, auditing or financial reporting issue; or any matter that was the subject of a disagreement or event identified in response to the immediately preceding paragraph above.

We have provided the disclosure contained in our Current Report on Form 8-K filed on September 29, 2010 (as repeated herein) to the former accountant. The former accountant provided a letter addressed to the Commission stating whether it agreed with the statements made by us and, if not, stating the respects in which it did not agree. The letter was included as an exhibit in our Current Report on Form 8-K filed September 29, 2010.

ITEM 9A. 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 below.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting.

As of July 31, 2010, we assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control -Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and SEC guidance on conducting such assessments. Based on that evaluation, we concluded that, as at July 31, 2010, our internal controls and procedures were not effective to detect the inappropriate application of US GAAP rules as more fully described below. This was due to deficiencies that existed at the time in which the internal control procedures were implemented that adversely affected our internal controls and that may be considered to be a material weakness.

The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the Public Company Accounting Oversight Board were: (1) inadequate entity level controls due to: (i) weak tone at the top to implement an effective control environment, and (ii) ineffective audit committee due to a lack of a majority of independent members (1 of 3) on the current audit committee and a lack of a majority of outside directors on our board of directors; (2) inadequate segregation of duties consistent with control objectives; and (3) insufficient written policies and procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements.

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Management believes that the material weaknesses set forth in items (2) and (3) above did not have a material adverse effect on our financial results for the year ended July 31, 2010. However, we believe that the material weaknesses in entity level controls set forth in item (1) results in ineffective oversight in the establishment and monitoring of required internal controls and procedures, which could result in a material misstatement in our financial statements in future periods.

We are committed to improving our financial organization. As part of this commitment, when resources become available to us we will i) expand our personnel to improve segregation of duties consistent with control objectives, ii) appoint one or more outside directors to our board of directors who shall be appointed to our audit committee resulting in a fully functioning audit committee who will undertake the oversight in the establishment and monitoring of required internal controls and procedures such as reviewing and approving estimates and assumptions made by management; and iii) prepare and implement sufficient written policies and checklists which will set forth procedures for accounting and financial reporting with respect to the requirements and application of US GAAP and SEC disclosure requirements.

We will continue to monitor and evaluate the effectiveness of our internal controls and procedures over financial reporting on an ongoing basis and are committed to taking further action by implementing additional enhancements or improvements, or deploying additional human resources as may be deemed necessary.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during our fourth quarter of our fiscal year ended July 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Officers and Directors

Our directors and executive officers and their respective ages as of the date of this annual report are as follows:

Name	Age	Position with the Company
Randall Reneau	61	Chairman of the Board and a director
Jeremy G. Driver	33	President, Chief Executive Officer and a director
Jonathan Lindsay	34	Secretary, Treasurer, Chief Financial Officer, Principal Accounting Officer and a director
Alan P. Lindsay	60	Director
Leonard Garcia	60	Director
Steven L. Carter	51	Vice President of Operations and a director

The following describes the business experience of each of our directors and executive officers, including other directorships held in reporting companies:

Randall Reneau, President, Chief Executive Officer, Principal Executive Officer and a director

Mr. Reneau has been a director of our Company since April 17, 2006, and he has served as Chairman of the Board since August 5, 2007. He also served as our President and Chief Executive Officer until December 2009. Mr. Reneau is a certified professional geologist and holds licenses to practice geology in the states of Texas, Washington and Alaska. He has more than 30 years combined mineral and oil and gas experience both domestic and foreign. Mr. Reneau served as President of Reneau Exploration and Development Company, Inc. (“REDCO”) from 1980 to 1988. REDCO drilled and operated wells in Stephens County, Oklahoma and Navarro, Milam, Wilson and Guadalupe Counties in Texas. From 1988 to 1990, Mr. Reneau was employed as a senior consulting geologist with Western Mining Corporation’s Canadian subsidiary, Westminer Canada. Mr. Reneau’s role at Westminer Canada included mineral exploration in West Africa. From 1990 to 1999, Mr. Reneau served as Principal Geologist for Reneau and Associates, a Geo-Environmental firm. From 1997 to December 2003, Mr. Reneau served as senior consulting geologist for AZCO Mining, Inc., managing exploration projects in Mali, West Africa and Sonora, Mexico. From December 2003 to December 2004, Mr. Reneau served as Chief Geologist for Oromex Resources in Durango, Mexico. Mr. Reneau served as Chief Exploration Officer and a director of Uranium Energy Corp., a uranium exploration company publicly traded on the American Stock Exchange, from January 2005 to July 2007. Mr. Reneau has a B.A. in Geology from Central Washington University and an M.S. in Environmental Engineering from Kennedy-Western University. Mr. Reneau currently resides in Austin, Texas.

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Jeremy Glenn Driver, President, Chief Executive Officer and a director

Mr. Driver has been the President and Chief Executive Officer since December 2009 and a director of the Company since June 2010. He is an oil and gas operations and financial professional with a background in land-based E&P operations with public companies. Prior to joining the Company, Mr. Driver served as President of HYD Resources Corporation (a wholly-owned subsidiary of publicly traded firm Hyperdynamics Corporation) with operations primarily focused in Texas and Louisiana from 2005 to 2008. He was able to lead the operational turnaround of that company and bring it to profitability, later being divested at a profit. Mr. Driver has also served as the President of KD Navigation, an investment and holding company in Texas since 2007. Mr. Driver also served as an active duty officer in the United States Air Force until 2005, specializing in foreign intelligence as a Chinese Linguist. Mr. Driver holds a Masters of Business Administration and a Master of Science in Accounting from Northeastern University, Boston, MA. He also earned his Bachelor of Science in Liberal Studies - Chinese Language from Excelsior College.

Johnathan Lindsay, Secretary, Treasurer, Chief Financial Officer, Principal Accounting Officer and a director

Johnathan Lindsay (a Canadian resident) has been our Secretary since July 11, 2005. In addition, he served as our President, Treasurer and as our sole director from July 11, 2005 until April 17, 2006. He was subsequently reappointed as a director on April 17, 2007 and at which time he was also appointed as our Treasurer, Chief Financial Officer and Principal Accounting Officer. Mr. Lindsay was responsible for organizing initial financing for our Company. From May 16, 2003 to August 31, 2006, Mr. Lindsay served as corporate secretary for Uranium Energy Corp., a uranium exploration company publicly traded on the American Stock Exchange, where he helped the company go public. From 1999 to 2004, Mr. Lindsay was employed by Alan Lindsay and Associates as Vice President, Marketing and Corporate Secretary. In 1997, Mr. Lindsay worked with the Investor Relations Group and for National Media, two North American public sector marketing firms. Following his position with National Media, he studied marketing and business management from 1998 to 1999 at the British Columbia Institute of Technology.

Alan P. Lindsay, a director

Alan Lindsay (a Canadian resident), who was our founding officer and director, resigned from his position as an officer and director on July 11, 2005. Alan Lindsay was subsequently reappointed as a director on April 17, 2007. Mr. Lindsay has extensive experience and expertise in the mining and bio-technology sectors. From May 2003 to the present, he has been the Chairman of Uranium Energy Corp., a uranium exploration company that has been publicly traded on the American Stock Exchange since September 2007. Since October 2001, Mr. Lindsay has served as Chairman and CEO of MIV Therapeutics Inc, a publicly-listed biomedical company focused on biocompatible coating technology for stents and medical devices. Since December 2005, Mr. Lindsay has served as a director of TapImmune Inc., a U.S. reporting company.

Mr. Lindsay was the founder of AZCO Mining, Inc., a base metals exploration company. Mr. Lindsay served as Azco’s Chief Executive Officer and President from 1991 to 1994, its Chairman and Chief Executive Officer from 1994 to 1997 and its President, Chairman and Chief Executive Officer from 1997 to 2000. Azco was listed on the Toronto Stock Exchange in 1993 and on the American Stock Exchange in 1994. Mr. Lindsay currently serves as a director of Hana Mining Ltd., a TSX Venture Exchange reporting company. Mr. Lindsay also co-founded Anatolia Minerals Development Limited, a junior resource company that trades on the TSX, and New Oroperu Resources Inc., a junior resource company that trades on the TSX Venture Exchange.

Leonard G. Garcia

Mr. Garcia has been a director since April 17, 2006 and has served as our Land Manager from February 2006 to the present date. In addition, Mr. Garcia served as our President and Chief Executive Officer from April 17, 2006 until August 5, 2007. From August 2004 to the present date, Mr. Garcia has also served as the Land Manager for Uranium Energy Corp., a uranium exploration company that has been publicly traded on the American Stock Exchange since September 2007. Mr. Garcia is an Independent Petroleum Landman with over thirty years experience in oil and gas title research, lease negotiations and acquisitions, contracts, exploration and production. Prior to August 2004, Mr. Garcia worked under contract for various companies, including Harkins & Co., Sun Oil Company, Oryx Energy Co., Texaco, Monsanto Exploration and Production Company, Trans Texas Energy, Kerr-McGee Oil & Gas Corp., and Mestena Oil & Gas. His corporate experience includes serving as Chief Executive Officer of Texas corporations with annual sales in excess of eighteen million dollars. Mr. Garcia attended the University of Texas-Austin, The University of Texas-Pan American and Texas A&M University-Kingsville. He currently resides in Austin, Texas.

Steven L. Carter, Vice President of Operations

Mr. Carter has served as our Vice President of Operations since December 20, 2006 and as a director since July 2010. Mr. Carter is a registered professional engineer with twenty-five years of management and engineering experience in oil and gas exploration, production operations, reservoir management and drilling. Mr. Carter served as Operations Manager and Operations Engineer for T-C Oil Company from 1990 to June 2003, where he managed significant production, supervised drilling, provided economic evaluations and designed project workovers, as well as performing numerous other engineering services. In July 2003, Mr. Carter started Carter E&P, LLC, an independent oil and gas company, where he has worked from 2003 to the present. Mr. Carter has a B.S. in Petroleum Engineering from the University of Texas at Austin.

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Term of Office

Our directors are appointed for a one-year term to hold office until the next annual general meeting of our stockholders or until they resign or are removed from the board in accordance with our bylaws. Our officers are appointed by our Board of Directors and hold office until they resign or are removed from office by the Board of Directors.

Significant Employees

We have no significant employees other than our executive officers.

Audit Committee

We have an Audit Committee of our Board of Directors comprised of Leonard Garcia (chair), Alan P. Lindsay and Randall Reneau. The audit committee operates pursuant to a charter adopted by the board. Our board of directors has determined that we do not currently have an audit committee financial expert (as such term is defined in Item 407 of Regulation S-K) serving on our audit committee. We intend to appoint an audit committee financial expert to our Audit Committee in the near future.

Family Relationships

Alan P. Lindsay is the father of Johnathan Lindsay. There are no other family relationships among our directors and officers.

Involvement in Certain Legal Proceedings

Except as disclosed in this annual report, during the past ten years none of the following events have occurred with respect to any of our directors or executive officers:

1. A petition under the Federal bankruptcy laws or any state insolvency law was filed by or against, or a receiver, fiscal agent or similar officer was appointed by a court for the business or property of such person, or any partnership in which he was a general partner at or within two years before the time of such filing, or any corporation or business association of which he was an executive officer at or within two years before the time of such filing;

2. Such person was convicted in a criminal proceeding or is a named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);

3. Such person was the subject of any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from, or otherwise limiting, the following activities:

i. Acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, any other person regulated by the Commodity Futures Trading Commission, or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliated person, director or employee of any investment company, bank, savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;

ii. Engaging in any type of business practice; or

iii. Engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal commodities laws;

4. Such person was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described in paragraph (3)(i) above, or to be associated with persons engaged in any such activity;

5. Such person was found by a court of competent jurisdiction in a civil action or by the Commission to have violated any Federal or State securities law, and the judgment in such civil action or finding by the Commission has not been subsequently reversed, suspended, or vacated;

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6. Such person was found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended or vacated;

7. Such person was the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of:

i. Any Federal or State securities or commodities law or regulation; or

ii. Any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or

iii. Any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

8. Such person was the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

There are currently no legal proceedings to which any of our directors or officers is a party adverse to us or in which any of our directors or officers has a material interest adverse to us.

Code of Conduct

We have adopted a Code of Conduct that applies to all directors and officers. The code describes the legal, ethical and regulatory standards that must be followed by the directors and officers of the Company and sets forth high standards of business conduct applicable to each director and officer. As adopted, the Code of Conduct sets forth written standards that are designed to deter wrongdoing and to promote, among other things:

1. honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

2. compliance with applicable governmental laws, rules and regulations;

3. the prompt internal reporting of violations of the code to the appropriate person or persons identified in the code; and

4. accountability for adherence to the code.

A copy of our Code of Conduct is incorporated by reference to our Form 10-K for the fiscal year ended July 31, 2009.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than 10% of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that these persons have complied with all applicable filing requirements during the year ended July 31, 2010, except as follows:

Section 16(a) of the Exchange Act requires our directors and officers, and the persons who beneficially own more than 10% of our common stock, to file reports of ownership and changes in ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Rule 16a-3 promulgated under the Exchange Act. Based solely on the reports received by us and on the representations of the reporting persons, we believe that these persons have complied with all applicable filing requirements during the year ended July 31, 2010, except as set forth below:

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Name	Form Type	Number of forms filed late	Number of late transactions reported late
Johnathan Lindsay	4	1	2
Alan Lindsay	4	1	2
Randall Reneau	4	1	2
Leonard Garcia	4	1	2
Jeremy Driver	4	1	1

ITEM 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The following table sets forth the compensation paid to our executive officers during our fiscal years ended July 31, 2010 and 2009:

Summary Compensation

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)	Option Awards ($)	Non- Equity Incentive Plan Compen- sation ($)	Non- qualified Deferred Compen- sation Earnings ($)	All Other Compen- sation ($)	Total ($)
Randall Reneau Former President, CEO & Principal Executive Officer	2010 2009	$72,486 88,300 (1)	$8,000 Nil	$27,428 Nil	Nil $172,076 (4)	Nil Nil	Nil Nil	Nil Nil	$107,914 260,376
Johnathan Lindsay Secretary, Treasurer, CFO & Principal Accounting Officer	2010 2009	$94,000 72,000 (2)	$8,000 Nil	$27,428 Nil	Nil 172,076 (4)	Nil Nil	Nil Nil	Nil Nil	$129,428 244,076
Steven Carter Vice President of Operations	2010 2009	$120,000 120,000 (3)	$10,000 Nil	$34,285 Nil	Nil Nil	Nil Nil	Nil Nil	Nil Nil	$164,285 120,000
Jeremy G. Driver (5) President and CEO	2010 2009	$92,752 Nil	Nil Nil	Nil Nil	$770,020 Nil	Nil Nil	Nil Nil	Nil Nil	$862,772 Nil

(1) Randall Reneau received varying amounts per month for the fiscal years ending July 31, 2009 and 2010 for the provision of management consulting services provided by Mr. Reneau to us on a monthly basis and from time to time. In December 2009, Mr. Reneau received a stock bonus of 68,571 shares of common stock.The stock was valued at $0.40 per share, the market closing price on the date of grant.In May 2009, Mr. Reneau was granted options to purchase 300,000 shares of common stock with an exercise price of $0.35 per share and a ten year term.The grant date fair value, estimated using the Black-Sholes valuation model, was $172,080; $144,000 of expense was reflected in the year ended July 31, 2009 and $28,080 of expense was reflected in the year ended July 31, 2010.

(2) Johnathan Lindsay received varying amounts per month for the fiscal years ending July 31, 2009 and 2010 for the provision of management consulting services provided by Mr. Lindsay to us on a monthly basis and from time to time. . In December 2009, Mr. Lindsay received a stock bonus of 68,571 shares of common stock.The stock was valued at $0.40 per share, the market closing price on the date of grant.In May 2009, Mr. Lindsay was granted options to purchase 300,000 shares of common stock with an exercise price of $0.35 per share and a ten year term.The grant date fair value, estimated using the Black-Sholes valuation model, was $172,080; $144,000 of expense was reflected in the year ended July 31, 2009 and $28,080 of expense was reflected in the year ended July 31, 2010.

(3) Steven Carter received $10,000 per month pursuant to the Carter Professional Services Agreement which is more particularly described below under Employment, Consulting and Services Agreements. In December 2009, Mr. Carter received a stock bonus of 85,713 shares of common stock.The stock was valued at $0.40 per share, the market closing price on the date of grant.

(4) These amounts represent the fair value of these options at the date of grant which was estimated using the Black-Scholes pricing model. The fair value of these options at the date of grant was estimated using the Black-Scholes pricing model with the following inputs: expected term, as computed using the simplified method as described in SEC Staff Accounting Bulletin 107, of 5 years, risk-free interest rate of 2.16%, dividend yield of 0%, and volatility of 154.43%.

(5) Mr. Driver joined our company in November 2009. He received a signing bonus of $20,000 and $8,333 per month pursuant to his Consulting Agreement which is more particularly described below under Employment, Consulting and Services Agreements.In addition, he received options to purchase 2,500,000 shares of common stock with an exercise price of $0.20 per share and a term of three years in November 2009.The initial fair value of the options was $770,020.Options to purchase 625,000 shares (25% of the award) vested immediately; the remaining options vest 25% each six months over the following 18 months.Because he is a non-employee, his options are accounted for under the provisions of ASC 505-50. 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, the vesting date. 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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The following table sets forth information as at July 31, 2010 relating to outstanding equity awards for each Named Executive Officer:

Outstanding Equity Awards at Year End

	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexer-cised Options (#) (exercise-able)	Number of Securities Underlying Unexer-cised Options (#) (unexer-ciseable)	Equity Incentive Plan Awards: Number of Securities Underlying Unexer-cised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Randall Reneau	600,000 300,000	N/A N/A	N/A N/A	0.35 0.35	07/04/17 05/21/19	N/A N/A	N/A N/A	N/A N/A	N/A N/A
Johnathan Lindsay	300,000 300,000	N/A N/A	N/A N/A	0.35 0.35	07/04/17 05/21/19	N/A N/A	N/A N/A	N/A N/A	N/A N/A
Steven L. Carter	600,000	N/A N/A	N/A N/A	0.35	07/04/17	N/A	N/A N/A	N/A	N/A N/A
Jeremy G. Driver	1,250,000	1,250,000	N/A	$.20	11/27/12	N/A	N/A	N/A	N/A

The following table sets forth information relating to compensation paid to our directors in the fiscal years ended July 31, 2008 and 2009 and 2010:

Director Compensation

We do not have a standard director compensation arrangement.Compensation is negotiated with each director on a case by case basis.Mr. Garcia, Mr. Reneau, Mr. Johnathan Lindsay, Mr. Carter, and Mr. Driver receive compensation for management services provided to the Company and they do not receive separate compensation for their services as directors.Mr. Alan Lindsay receives $3,000 per month for his service as a director. The following table provides information regarding compensation during the year ended July 31, 2010 earned by directors who are not executive officers.Our directors who are executive officers do not receive additional compensation for their service as directors and their compensation is disclosed in the “Summary Compensation” Table above.

Name	Year	Fees Earned or Paid in Cash ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compen-sation ($)	Non-qualified Deferred Compen-sation Earnings ($)	All Other Compen-sation ($)	Total ($)
Leonard Garcia (1)	2010	N/A	$8,572	Nil	N/A	N/A	$29,383	$37,955
Alan Lindsay (2)	2010	10,000	$10,286	Nil	N/A	N/A	$39,000	$59,286

 (1) Leonard Garcia received varying amounts per month for the fiscal year ended July 31, 2010 for the provision of land work management consulting services provided by Mr. Garcia to us on a monthly basis and from time to time.In December 2009, Mr. Garcia received a stock bonus of 21,479 shares of common stock.The stock was valued at $0.40 per share, the market closing price on the date of grant.In May 2009, Mr. Garcia was granted options to purchase 300,000 shares of common stock with an exercise price of $0.35 per share and a ten year term.The grant date fair value, estimated using the Black-Sholes valuation model, was $172,080; $144,000 of expense was reflected in the year ended July 31, 2009 and $28,080 of expense was reflected in the year ended July 31, 2010.

(2) Alan Lindsay received $3,000 per month during the fiscal year ending July 31, 2010 for his service as a director of the Company.He earned an additional $10,000 the provision of management consulting services during our capital raises in October and November 2009. In December 2009, Mr. Lindsay received 25,714 shares of common stock and $3,000 cash as a bonus.The stock was valued at $0.40 per share, the market closing price on the date of grant.In May 2009, Mr. Lindsay was granted options to purchase 300,000 shares of common stock with an exercise price of $.35 per share and a ten year term.The grant date fair value, estimated using the Black-Sholes valuation model, was $28,680; $24,000 of expense was reflected in the year ended July 31, 2009 and $4,680 of expense was reflected in the year ended July 31, 2010.

(3) The fair value of these options at the date of grant was estimated using the Black-Scholes pricing model with the following inputs: expected term, as computed using the simplified method as described in SEC Staff Accounting Bulletin 107, of 5 years, risk-free interest rate of 2.16%, dividend yield of 0%, and volatility of 154.43%.

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Employment, Consulting and Services Agreements

The following summary of certain material terms of the employment, consulting or services agreements we have entered into with certain of our officers or employees is not complete and is qualified in its entirety to the full text of each such agreement, which have been filed with the SEC as described in the list of exhibits to this annual report.

Thomas Consulting Services and Option Agreement

We have entered into a Consulting Services and Option Agreement dated April 1, 2006 with Jim Thomas, our Chief Geologist. Under the agreement, Mr. Thomas has agreed to provide geological consulting services to us including, among other things, assisting in the initiation, coordination, implementation and management of all aspects of any program or project in connection with the geological development and maintenance of our various business interests. In consideration for these consulting services, we have agreed to pay Mr. Thomas a daily fee of $350. In addition, we issued to Mr. Thomas options to acquire an aggregate of 250,000 shares of our common stock at an exercise price of $0.10 per share exercisable until April 1, 2016. We have also agreed to reimburse Mr. Thomas for all reasonable expenses incurred by him in connection with the provision of such consulting services. The initial term of the agreement is 18 months from April 1, 2006 and the agreement renews automatically on a month-to-month basis if not specifically terminated in accordance with the provisions of the agreement. The agreement may be terminated by either party upon providing not less than 30 calendar days’ prior written notice to the other party. However, either party may terminate the agreement upon not less than ten calendar days’ written notice in the event the other party fails to cure a material breach of any of the provisions of the agreement during such ten day period, the other party is non-compliant in the performance of its duties under the agreement and fails to become complaint within five calendar days of receipt of the notice, or a party commits fraud or serious misconduct in the discharge of its duties.

On October 1, 2007 our Board of Directors authorized and approved the execution of a modified Consulting Services and Option Agreement with Jim Thomas, our Chief Geologist. The modified agreement has an initial term of 18 months expiring on March 31, 2009. Pursuant to the terms and provisions of the Consulting Services and Option Agreement: (i) we shall pay a daily fee of $400 on a as requested basis; (ii) we will issue 200,000 shares of our restricted common stock; and (iii) we agreed to grant an aggregate of not less than 250,000 options to purchase shares of our common stock at $0.10 for a ten year term. The option grant was completed on July 5, 2007.

Combest Consulting Services and Option Agreement

We have entered into a Consulting Services and Option Agreement dated August 1, 2006 with Kyle Combest, one of our geologists. Under the agreement, Mr. Combest has agreed to provide geological consulting services to us including, among other things, assisting in the initiation, coordination, implementation and management of all aspects of any program or project in connection with the geological development and maintenance of our various business interests. In consideration for these consulting services, we have agreed to pay Mr. Combest a daily fee of $400. In addition, we issued to Mr. Combest options to acquire an aggregate of 250,000 shares of our common stock at an exercise price of $0.35 per share exercisable until April 1, 2016. We have also agreed to reimburse Mr. Combest for all reasonable expenses incurred by him in connection with the provision of such consulting services. The initial term of the agreement is 18 months from August 1, 2006 and the agreement renews automatically on a month-to-month basis if not specifically terminated in accordance with the provisions of the agreement. The agreement may be terminated by either party upon providing not less than 30 calendar days’ prior written notice to the other party. However, either party may terminate the agreement upon not less than ten calendar days’ written notice in the event the other party fails to cure a material breach of any of the provisions of the agreement during such ten day period, the other party is non-compliant in the performance of its duties under the agreement and fails to become complaint within five calendar days of receipt of the notice, or a party commits fraud or serious misconduct in the discharge of its duties.

Carter Professional Services Agreement

On December 20, 2006, our Board of Directors authorized and approved the execution of the “Carter Professional Services Agreement”. The term of the agreement is two years expiring on November 30, 2008. Pursuant to the terms and provisions of the Carter Professional Services Agreement: (i) Steven Carter shall provide duties to us commensurate with his current executive position as our Vice President of Operations; (ii) we shall pay to Mr. Carter a monthly fee of $10,000; (iii) we approved the issuance of 500,000 shares of our common stock at a price of $0.001 per share; (iv) we approved the granting of an aggregate of not less than 600,000 options to purchase shares of our common stock at $0.35 for a ten year term; and (v) the Carter Professional Services Agreement may be terminated without cause by either of us by providing prior written notice of the intention to terminate at least 90 days (in the case of our Company after the initial term) or 30 days (in the case of Mr. Carter) prior to the effective date of such termination.

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Jeremy G. Driver Agreement

Effective December 1, 2009, we entered into an executive services agreement with Mr. Driver, pursuant to which he is to perform such duties and responsibilities as set out in the agreement and as our Board of Directors may from time to time reasonably determine and assign as is customarily performed by a person in an executive position with our Company.In consideration for his services under the agreement, we have agreed:

● to pay Mr. Driver a monthly fee of $8,333.33;

● to pay Mr. Driver a one-time signing bonus of $20,000;

● to provide Mr. Driver with industry standard bonuses, from time to time, based, in part, on the performance of the Company and the achievement by Mr. Driver of reasonable management objectives, as determined by the Company’s Board of Directors in good faith;

● to provide Mr. Driver with three weeks paid vacation;

● to provide Mr. Driver with a monthly benefits stipend of $450 together with full participation, at the Company’s expense, in the Company’s current medical services and life insurance benefits programs for management and employees; and

● to grant Mr. Driver incentive stock options to purchase not less than an aggregate of 2,500,000 common shares of the Company, at an exercise price $0.20 per optioned common share, vesting as to one-quarter of said stock options on the date of grant (that being as to 625,000) and on each day which is six months thereafter in succession for each remaining one-quarter of the optioned common shares, and all being exercisable for a period of three years from the date of grant and in accordance with the provisions of the Company’s current Stock Incentive Plan.

The initial term of the agreement is one year ending on December 1, 2010, and the agreement is subject to automatic renewal on a monthly basis unless either the Company or Mr. Driver provides written notice of an intention not to renew the agreement not later than 30 days prior to the end of the then-current initial term or renewal of the agreement.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth certain information concerning the number of shares of our common stock owned beneficially as of November 12, 2010 by: (i) each person (including any group) known to us to own more than 5% of our shares of common stock; (ii) each of our directors; (iii) each of our officers; and (iv) our officers and directors as a group. To our knowledge, each holder listed possesses sole voting and investment power with respect to the shares shown.

Title of Class	Name and Address of Beneficial Owner(1)	Amount and Nature of Beneficial Owner	Percent of Class(2)
	Directors and Officers:
Common Stock	Leonard Garcia 10105 Grand Oak Drive Austin, Texas, U.S.A., 78750	2,046,079 (3)	3.8%
Common Stock	Johnathan Lindsay 1917 West 12th Avenue Vancouver, B.C., Canada, V6J 2G1	1,218,164 (4)	2.2%
Common Stock	Alan P. Lindsay 2701 - 1500 Hornby Street Vancouver, B.C., Canada, V6Z 2R1	1,919,868 (5)	3.5%
Common Stock	Randall Reneau 9302 Mystic Oak Trail Austin, Texas, U.S.A., 78750	2,487,821 (6)	4.6%
Common Stock	Steven L. Carter 615 Leopard, Suite 540 Corpus Christi, Texas, U.S.A., 78401	1,535,713 (7)	2.8%
Common Stock	Jeremy Glenn Driver 615 Leopard, Suite 540 Corpus Christi, Texas, U.S.A., 78401	1,875,000(8)	3.4%
Common Stock	OFFICERS AND DIRECTORS Major Stockholders:	11,082,645(9)	18.5%
Common Stock	Barry Honig 595 S. Federal Highway Suite 600 Boca Raton, FL 33432	3,975,050 (10)	7.4%

(1) Under Rule 13d-3 of the Exchange Act a beneficial owner of a security includes any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares: (i) voting power, which includes the power to vote, or to direct the voting of shares; and/or (ii) investment power, which includes the power to dispose or direct the disposition of shares. In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire the shares within 60 days of the date as of which the information is provided.

(2) Based on the 53,409,155 shares of our common stock issued and outstanding as of November 12, 2010.

(3) This figure includes (i) 1,096,254 shares of common stock, (ii) stock options to purchase 900,000 shares of our common stock, and (iii) stock purchase warrants to purchase 49,825 shares of our common stock.

(4) This figure includes (i) 218,537 shares of common stock, (ii) 186,348 shares of common stock held of record by Johnathan Lindsay’s wife, (iii) 26,931 shares of common stock held of record by Ocean Tower Productions, a company controlled by Johnathan Lindsay, (iv) stock options to purchase 600,000 shares of our common stock, and (v) stock purchase warrants to purchase 186,348 shares of our common stock held of record by Johnathan Lindsay’s wife.

(5) This figure includes (i) 687,464 shares of common stock, (ii) 100,000 shares of common stock held of record by Alan P. Lindsay’s wife, (iii) 391,202 shares of common stock held of record by Alan Lindsay & Associates, a company controlled by Alan P. Lindsay (iv) stock options to purchase 350,000 shares of our common stock, and (v) stock purchase warrants to purchase 391,202 shares of our common stock held of record by Alan Lindsay & Associates, a company controlled by Alan P. Lindsay.

(6) This figure includes (i) 1,428,196 shares of common stock, (ii) stock options to purchase 900,000 shares of our common stock, and (iii) stock purchase warrants to purchase 159,625 shares of our common stock.

(7) This figure includes (i) 585,713 shares of common stock, and (ii) stock options to purchase 950,000 shares of our common stock.Options to purchase an additional 1,050,000 share vest over the next 18 months.

(8) This figure includes stock options to purchase 1,875,000 shares of our common stock.Options to purchase an additional 625,000 shares of common stock vest in May 2011.

(9) This figure includes (i) 4,720,645 shares of common stock, (ii) stock options to purchase 5,565,000 shares of our common stock, and (iii) stock purchase warrants to purchase 787,100 shares of our common stock.

(10) This figure includes securities held individually by Mr. Honig and by GRQ Consultants, Inc. 401(K), a company controlled by Mr. Honig.

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Changes in Control

We are unaware of any contract, or other arrangement or provision, the operation of which may at a subsequent date result in a change of control of our company.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Except as described below, none of the following parties has had any material interest, direct or indirect, in any transaction with us during our last two fiscal years or in any presently proposed transaction that has or will materially affect us:

1. any of our directors or officers;

2. any person proposed as a nominee for election as a director;

3. any person who beneficially owns, directly or indirectly, shares carrying more than 5% of the voting rights attached to our outstanding shares of common stock; or

4. any member of the immediate family (including spouse, parents, children, siblings and in-laws) of any of the above persons.

We had transactions with certain of our officers and directors during our fiscal years ended July 31, 2010 as follows:

Related party debt

From time to time, officers, directors, and family members of officers and directors have loaned us funds.The following table provides a summary of related party debt outstanding as of July 31,

	2010		2009
Note payable to a director, interest rate 18% per annum, due on demand		-	$	25,000
Note payable to an officer, interest rate 18% per annum, due on demand		-		44,000
Note payable to a family member of an officer and director, interest rate 15% per annum, due on demand		-		100,000
Note payable to an officer, interest rate 18%, due on demand		-		27,500
Note payable to a director, interest rate 18%, due on demand		-		18,500
Total notes payable		-		215,000
Accrued interest on notes payable		-		26,864
Notes payable, including accrued interest payable		-	$	241,864

The activity involving related party debt is as follows:

	Notes payable			Accrued Interest			Transaction loss			Total due
Balance, July 31, 2008	$	79,000		$	3,597			-		$	82,597
Advances		146,000						-			146,000
Payments in cash		(10,000	)					-			(10,000	)
Settlement in common stock											-
Interest incurred					23,267			-			23,267
Balance, July 31, 2009		215,000			26,864			-			241,864
Advances		100,500									100,500
Interest incurred					8,870			-			8,870
Transaction loss(1)							$	21,827			21,827
Payments in cash		(160,500	)		(17,867	)		(7,578	)		(185,945	)
Settlement in common stock		(155,000	)		(17,867	)		(14,249	)		(187,116	)
											-
Balance, July 31, 2010	$	-		$	-		$	-		$	-

(1) Our arrangement with one of the lenders provided that, at his option, the debt would be settled in Canadian or US dollars.At the time we repaid the debt, he requested Canadian dollar equivalents, which resulted on a transaction loss on the settlement.

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Barge Canal Properties

A company controlled by one of our officers operates our Barge Canal properties. Revenues generated from these properties were $295,574 and $355,880 for the years ended July 31, 2010 and 2009, respectively. In addition, lease operating costs incurred from these properties were$229,067 and $157,969 for the years ended July 31, 2010 and 2009, respectively.

As of July 31, 2010 and 2009, respectively, we had outstanding accounts receivable associated with these properties of $28,975 and $34,366 and no accounts payable.

Independent Directors

Leonard Garcia is an independent director of our Company as provided in the listing standards of the NYSE Amex Equities Exchange.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Our current independent auditor, Malone & Bailey, P.C., served as our independent registered public accounting firm and audited our financial statements for the fiscal year ended July 31, 2010.Aggregate fees for professional services rendered to us by our auditor are set forth below:

	Year Ended July 31, 2010
Audit Fees	$	35,000
Audit-Related Fees		-
Tax Fees		-
Total	$	35,000

Our former independent auditor, Dale Matheson Carr-Hilton LaBonte LLP, served as our independent registered public accounting firm until August 2010 and audited our for the fiscal year ended July 31, 2009 and provided audit services to us during our fiscal year ended July 31, 2010.. Aggregate fees for professional services rendered to us by our auditor are set forth below:

	Year Ended July 31, 2010		Year Ended July 31, 2009
Audit Fees	$	24,500	$	39,000
Audit-Related Fees		-		18,000
Tax Fees		6,500		6,500
Total	$	31,000	$	63,500

Audit Fees

Audit fees are the aggregate fees billed for professional services rendered by our independent auditors for the audit of our annual financial statements, the review of the financial statements included in each of our quarterly reports and services provided in connection with statutory and regulatory filings or engagements.

Audit Related Fees

Audit related fees are the aggregate fees billed by our independent auditors for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not described in the preceding category.

Tax Fees

Tax fees are billed by our independent auditors for tax compliance, tax advice and tax planning.

All Other Fees

All other fees include fees billed by our independent auditors for products or services other than as described in the immediately preceding three categories.

Policy on Pre-Approval of Services Performed by Independent Auditors

It is our audit committee’s policy to pre-approve all audit and permissible non-audit services performed by the independent auditors. We approved all services that our independent accountants provided to us in the past two fiscal years.

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ITEM 15. EXHIBITS

The following exhibits are filed with this Annual Report on Form 10-K/A:

Exhibit Number	Description of Exhibit
3.1 (1)	Articles of Incorporation and amendments thereto, dated July 19, 2005, October 18, 2005 and September 5, 2006
3.2 (1)	Bylaws
4.1 (2)	Form of Warrant Certificate issued to Subscribers pursuant to the October 15, 2009 Private Placement
4.2(3)	Form of Warrant Certificate issued to Subscribers pursuant to the November 13, 2009 Private Placement
10.1 (1)	Sale Contract for Oil and Gas Leases between Energy Program Accompany, LLC and Penasco Petroleum, Inc., dated August 24, 2006 (regarding the Holt, McKay and Strahan Leases)
10.2 (1)	Letter Agreement between Penasco Petroleum, Inc. and Tradestar Resources Corporation, dated September 1, 2006
10.3 (1)	Assignment, Bill of Sale and Conveyance between OPEX Energy LLC and Penasco Petroleum, Inc., dated effective August 1, 2006 (regarding the Welder Lease)
10.4 (1)	Participation Agreement between Rockwell Energy, LLC and the Company, dated October 2005 (regarding the Janssen Lease)
10.5 (1)	Oil, Gas and Mineral Lease between Henry J. Janssen Jr. and Penasco Petroleum, Inc., dated July 2006 (regarding the Janssen Lease)
10.6 (1)	Assignment and Bill of Sale between Penasco Petroleum, Inc. and ETG Energy Resources, dated October 2006, and Assignment between ETG Energy Resources and Penasco Petroleum, Inc., dated December 2006 (regarding the Janssen Lease)
10.7 (1)	Ratification Letter between Marmik Oil Company and Penasco Petroleum, Inc., dated October 2007 (regarding Little Mule Creek Project)
10.8 (1)	Assignment between Marmik Oil Company and Penasco Petroleum, Inc., dated November 2007 (regarding Little Mule Creek Project)
10.9 (4)	2009 Restated Stock Incentive Plan
10.10 (1)	Consulting Services and Options Agreement between the Company and Jim Thomas, dated April 2006, and Amended and Restated Consulting Services and Option Agreement between the Company and Jim Thomas, dated November 2007
10.11 (1)	Consulting Services and Options Agreement between the Company and Kyle Combest, dated August 2006
10.12 (1)	Professional Services Retainer Contract between the Company and Steven Carter, dated December 2006
10.13 (2)	Form of Securities Purchase Agreement regarding October 15, 2009 Private Placement
10.14 (2)	Form of Registration Rights Agreement regarding October 15, 2009 Private Placement
10.15 (3)	Form of Securities Purchase Agreement regarding November 13, 2009 Private Placement
10.16 (3)	Form of Registration Rights Agreement regarding November 13, 2009 Private Placement
10.17 (5)	Executive Services Consulting Agreement between the Company and Jeremy Glenn Driver dated for reference effective on December 1, 2009.
14.1 (4)	Code of Conduct
31.1 (6)	Certification of Chief Executive Officer pursuant to Securities Exchange Act of 1934 Rule 13a-14(a) or 15d-14(a).
31.2 (6)	Certification of Chief Financial Officer pursuant to Securities Exchange Act of 1934 Rule 13a-14(a) or 15d-14(a).
32.1 (6)	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350
99.1(6)	Report of Lonquist & Co. LLC, Petroleum Engineers, dated September 29, 2010

(1) Filed as an exhibit to our registration statement on Form S-1/A (Amendment No.1) filed with the Securities and Exchange Commission on February 8, 2008.

(2) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on October 16, 2009.

(3) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2009.

(4) Filed as an exhibit to our Annual Report on Form 10-K filed with the Securities and Exchange Commission on November 12, 2009.

(5) Filed as an exhibit to our Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2009.

(6) Filed herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15 (d) 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.

STRATEGIC AMERICAN OIL CORPORATION

By:	/s/   Jeremy Glenn Driver
	Jeremy Glenn Driver
	President, Chief Executive Officer, Principal Executive Officer and a director
	Date: November 14, 2011

By:	/s/   Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer
	Date: November 14, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By:	/s/   Jeremy Glenn Driver
	Jeremy Glenn Driver
	President, Chief Executive Officer, Principal Executive Officer and a director
	Date: November 14, 2011

By:	/s/   Sarah Berel-Harrop
	Sarah Berel-Harrop
	Secretary, Treasurer and Chief Financial Officer
	Date: November 14, 2011

By:	/s/   Steven L. Carter
	Steven L. Carter
	Vice President of Operations and a director
	Date: November 14, 2011

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