UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


WASHINGTON, DC 20549




FORM 10-Q





þ
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934: For the quarterly period ended January  31, 2011





or




£
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
30-0420930(State or other jurisdiction of incorporation or organization)
(IRS Employer Identification No.)







600 Leopard Street, Suite 2015




Corpus Christi, Texas, 78401


(Address of principal executive offices, including zip code)





361-884-7474


(registrant's principal executive office telephone number)








Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ   No £




Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).


Yes £    No £




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





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





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




APPLICABLE ONLY TO CORPORATE ISSUERS





As of March 14, 2011, 141,393,677 shares of common stock, $0.001 par value, were outstanding.












Table of Contents





Part I. Financial Information





Item 1.
Financial StatementsConsolidated Balance Sheets (Unaudited) at January 31, 2011 and July 31, 2010
3Consolidated Statements of Operations (Unaudited) for the three and six months ended January 31,  2011 and  2010
4Consolidated Statements of Cash Flows (Unaudited) for the six months ended January 31, 2011 and  2010
5Notes to Consolidated Financial Statements (Unaudited)
7Item 2.
Management’s Discussion and Analysis of Financial Condition and Results Of Operations
16Item 3.
Quantitative and Qualitative Disclosures About Market Risk
25Item 4.
Controls and Procedures
26Part II. Other InformationItem 1.
Legal Proceedings
27Item 1A.
Risk Factors
27Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
27Item 3.
Defaults Upon Senior Securities
27Item 4.
(Removed and Reserved)
27Item 5.
Other Information
27Item 6.
Exhibits
27Signatures
28




2
 Table of Contents




Part I. Financial Information


Item 1. Financial Statements





STRATEGIC AMERICAN OIL CORPORATION


CONSOLIDATED BALANCE SHEETS


(Unaudited)





January 31,

2011


July 31,

2010AssetsCurrent assetsCash and cash equivalents

$
7,803


$
247,851Restricted cash


40,000



40,000Accounts receivable


598



6,580Accounts receivable – related party


52,899



28,975Other current assets


-



251,328Total current assets


101,300



574,734Oil and Gas Property, accounted for using the full cost method of accountingEvaluated property, net of accumulated depletion of $316,030 and $265,872, respectively


1,316,671



1,193,680Unevaluated property


266,954



734,533Note receivable


98,084Other Assets


19,317



19,317Property and Equipment, net of accumulated depreciation of $9,391 and $7,624, respectively


3,980



5,747Total Assets

$
1,806,306


$
2,528,011Liabilities and Stockholders’ DeficitCurrent liabilitiesAccounts payable and accrued expenses

$
616,009


$
583,250Notes payable, net of unamortized discount of $0 and $45,436, respectively


110,000



104,564Derivative warrant liability


2,534,813



2,411,709Due to related parties


203,300



-Total current liabilities


3,464,122



3,099,523Asset retirement obligations


10,380



57,623Total liabilities


3,474,502



3,157,146Stockholders’ deficit:Common stock, $.001 par; 500,000,000 shares authorized shares; 53,602,486 and 52,432,486 shares issued and outstanding


53,602



52,432Additional paid in capital


11,294,882



10,718,194Accumulated deficit


(13,016,680
)


(11,399,761
)Total stockholders’ deficit


(1,668,196
)


(629,135
)Total Liabilities and Stockholders’ Deficit

$
1,806,306


$
2,528,011





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





3
 Table of Contents




STRATEGIC AMERICAN OIL CORPORATION


CONSOLIDATED STATEMENTS OF OPERATIONS


(Unaudited)





Three months ended January 31,


Six months ended January 31,2011


2010


2011


2010Revenues

$
116,261


$
137,763


$
229,134


$
220,696Operating expensesLease operating expense


39,124



161,702



140,388



214,171Depreciation, depletion, and amortization


28,925



23,651



51,925



39,701Accretion


1,270



-



3,664



-Impairment


140,029



-



140,029



-Consulting fees


67,389



601,271



595,524



910,334Management fees


66,042



540,964



222,912



643,510Other general and administrative expense


244,575



223,381



400,283



422,441Total operating expenses


587,354



1,550,969



1,554,725



2,230,157Loss from operations


(471,093
)


(1,413,206
)


(1,325,591
)


(2,009,461
)Interest expense, net


11,806



(32,098
)


(14,779
)


(102,166
)Gain (loss) on derivative warrant liability


(191,988
)


680,739



(276,549
)


(1,357,487
)Net Loss

$
(651,275
)

$
(764,565
)

$
(1,616,919
)

$
(3,469,114
)Basic and diluted loss per common share

$
(0.01
)

$
(0.02
)

$
(0.03
)

$
(0.09
)Weighted average shares outstanding (basic and diluted)


53,601,127



47,761,124



53,408,220



39,872,984





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





4
 Table of Contents




STRATEGIC AMERICAN OIL CORPORATION


CONSOLIDATED STATEMENTS OF CASH FLOWS


(Unaudited)




Six months ended

January 31,2011


2010Cash Flows From Operating ActivitiesNet loss

$
(1,616,919
)

$
(3,469,114
)Adjustments to reconcile net loss to net cash used in operating activities:Depreciation, depletion, and amortization


51,925



39,701Impairment


140,029



-Accretion


3,664



-Amortization of debt discount


3,886



77,978Common stock issued for services


62,008



-Share based compensation - amortization of the fair value of  stock options


158,559



873,171Loss on derivative warrant liability


276,549



1,357,487Gain on settlement of accounts payable


-



(12,559
)Changes in operating assets and liabilities:Accounts receivable


7,898



707Accounts payable and accrued expenses


36,505



(261,317
)Other changes in due to (from) related parties


(23,924
)


(31,623
)Other assets


251,328



(30,816
)Net cash used in operating activities


(648,492
)


(1,456,385
)Cash Flows From Investing ActivitiesPurchases of oil and gas properties


(229,956
)


(219,589
)Purchases of fixed assets


-



(48,302
)Proceeds from sale of oil and gas properties


275,000



-Net cash provided by (used  in) investment activities


45,044



(267,891
)Cash Flows From Financing ActivitiesProceeds from sales of common stock


200,100



2,858,862Proceeds from notes payable


45,000



100,000Payments on notes payable


(85,000
)


(100,000
)Proceeds from notes payable to related parties


203,300



100,500Payments on notes payable to related parties


-



(160,500
)Net cash provided by financing activities


363,400



2,798,862Net increase (decrease) in cash


(240,048
)


1,074,586Cash at beginning of period


247,851



18,793Cash at end of period

$
7,803


$
1,093,379





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





5
 Table of Contents




STRATEGIC AMERICAN OIL CORPORATION


CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)





Six months ended

January 312011


2010Supplemental Disclosures:Interest paid in cash

$
-


$
-Income taxes paid in cash

$
-


$
-Non-cash investing and financingNon-cash capitalized interest

$
41,550


$
-Asset retirement obligation sold


50,907



-Stock for accounts payable


-



453,800Stock for prepaid consulting fees


-



43,278Notes receivable for sale of oil and gas properties


100,000



-Debt discount


-



32,000Exercise of warrants classified as a derivative


153,445



-




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




6
 Table of Contents




STRATEGIC AMERICAN OIL CORPORATION


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)





Note 1 – Basis of presentation





The unaudited consolidated financial statements of Strategic American Oil Corporation (“Strategic”) have been prepared in accordance with accounting principles generally accepted in the United States and the rules of the Securities and Exchange Commission ("SEC"), and should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report filed with the SEC on Form 10-K for the year ended July 31, 2010. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein.  The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosures contained in the audited consolidated financial statements for the most recent fiscal year ended July 31, 2010, as reported in the Form 10-K, have been omitted.


Reclassifications


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





Recently issued or adopted accounting pronouncements


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





Note 2 – 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. As reflected in the accompanying consolidated financial statements, we had a working capital deficit of $3,362,822 and an accumulated deficit of $13,016,680 as of January 31, 2011.  These factors raise substantial doubt about Strategic’s ability to continue as a going concern. Our ability 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.





Subsequent to the balance sheet date, we raised $8,996,200, net of offering costs, in an equity private placement and acquired a Texas company that operates producing oil and gas properties in five fields located in Galveston, Texas with a view to enhancing our cash flow from operations.  We are have procured a line of credit of up to $5,000,000 from a commercial bank to support improvements to the properties that would enhance these cash flows.





If we do not raise additional capital sufficient to fund our business plans, we may not survive.





The consolidated financial statements do not include any adjustments that might be necessary if we were unable to continue as a going concern.





Note 3 – Oil and Gas Property





Oil and natural gas property as of January 31, 2011 and July 31, 2010 consisted of the following:





January 31, 2011


July 31, 2010Evaluated PropertyCosts subject to depletion

$
1,632,701


$
1,459,552Depletion


(316,030
)


(265,872
)Total evaluated property


1,316,671



1,193,680Unevaluated property


266,954



734,533Net oil and gas property

$
1,583,625


$
1,928,213




7
 Table of Contents





Evaluated property


In September 2010, we sold our interest in the Dixon lease for cash proceeds of $75,000. The buyer assumed the asset retirement obligation, which was $12,132, associated with the property. The proceeds and the assumption of the asset retirement obligation were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
 
 In November 2010, we sold our working interest in the Holt and Strahan properties for $100,000 and a retained overriding royalty interest of 6.25%. The buyer assumed the asset retirement obligation, which was $38,775, associated with the property. We executed a note receivable for the purchase price of $100,000.  The buyer will pay 5% of its production revenue, net of severance tax, until the balance is repaid.  As of January 31, 2011, the balance on the note was $98,084. The proceeds and the assumption of the asset retirement obligation were treated as a reduction of capitalized costs in accordance with rules governing full cost companies.
 
 During the six months ended January 31, 2011, we built lease improvements of $36,394 at our Barge Canal properties and we incurred land acquisition costs of $10,428 and geological and geophysical costs of $23,514.  In addition, we reclassified properties with accumulated costs of $468,747 from unevaluated to evaluated based on our determination that no reserves would be assigned to the properties as follows:


·
$166,361, which is net of cost recovery of $200,000 and which includes capitalized interest of $46,969, related to the Kenedy Ranch lease.
 ·
$103,681, including capitalized interest of $7,110, accumulated on the Koliba property.
 ·
$198,705, including capitalized interest of $25,922, of acquisition costs for properties in Texas, Louisiana, and Illinois.


In February 2011, we acquired a company that operates producing oil and natural gas properties and its related facilities in five fields located in Galveston Bay, Texas.  The transaction is more fully described in Note 10 - Subsequent Events.





Unevaluated property





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 assigned 81.25% working interest in the Kenedy Ranch lease to Chinn Exploration Company (“Chinn”) for $200,000 cash. The agreement provided that Chinn would operate the property and would drill a test well within 18 months of the date of the agreement. We retained an 18.75% working interest and 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 was 13.75%. The cash proceeds we received in conjunction with this agreement were treated as a reduction of capitalized cost in accordance with rules governing full cost companies. As of January 31, 2011, we declined to participate further in the project and reclassified the net accumulated costs, $166,361, to evaluated property.





As of December 31, 2010, we had drilled two dry holes on the Koliba lease.  We determined that we would not perform further exploration activities and reclassified the accumulated costs, $103,681, to evaluated property.





During the quarter ended January 31, 2011, we determined that we would not pursue further exploration activities on multiple leases in Texas, Louisiana, and Illinois, and reclassified the accumulated costs, $198,705, to evaluated property.





Additions to unevaluated property during the six months ended January 31, 2011 include interest capitalized of $41,551, exploration costs of $98,037, and acquisition costs of $61,581.  We also realized a cost recovery of $200,000 attributable to the Chinn agreement as described above.


In January 2011, we executed a farmout agreement with Core Minerals Management II, LLC (“Core”) pertaining to our Markham City prospect.  Under the farmout agreement, we retained a 10% working interest and assigned the balance of our working interest in the Markham City prospect to Core.  Core will be the operator of the property.  Our working interest is carried until the Core meets the “Earnings Threshold”, $1,350,000.  Core will perform exploration activities on the prospect.  Core will spud the initial well by June 30, 2011 or the working interest reverts to us.  If Core does not expend one-half of the Earnings Threshold by April 1, 2012, our working interest reverts to 50% and if Core does not expend the entire Earnings Threshold by January 24, 2013, Core will reassign to us working interest equal to the proportion of the Earning Threshold which up to that time it has not spent.  After payout of the property, $1,350,000 or 29,000 barrels, provided that we hold less than 25% working interest in the property at payout, our working interest will be adjusted to 25%.





8
 Table of Contents





Impairment





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





We evaluated our capitalized costs using the full cost ceiling test as prescribed by the Securities and Exchange Commission at January 31, 2011 and July 31, 2010.  As of January 31, 2011, the net book value of oil and gas properties exceeded the ceiling amount by $140,029 and, accordingly, an impairment has been recorded.  As of July 31, 2010, the net book value of oil and gas properties did not exceed the ceiling amount and thus, there was no impairment.





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





Note 4 – Asset Retirement Obligations





The following is a reconciliation of our asset retirement obligation liability as of January 31, 2011 and July 31, 2010:




January 31, 2011


July 31, 2010Liability for asset retirement obligation, beginning of period

$
57,623


$
22,662Additions


-



10,598Liabilities sold


(50,907
)


-Revisions in estimated cash flows


-



731Accretion


3,664



23,632Liability for asset retirement obligation, end of period

$
10,380


$
57,623





Note 5 – Notes Payable





2009 Convertible Debentures





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 expired 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.  The fair value of the proceeds was allocated among the debentures and warrants based on their relative fair values.





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 $150,000 were recorded as a discount to the notes. The discount was amortized and charged to interest expense over the life of the note using the effective interest rate of 278% per annum.





As of January 31, 2011 and July 31, 2010, respectively, $150,000 and $104,564 of the discount had been amortized. The note was scheduled to mature in September 2010.  We made principal payments of $50,000 and $35,000 during the three months ended October 31, 2010 and January 31, 2011 respectively. Principal of $65,000 on the note remains unpaid as of January 31, 2011.  We paid an additional $10,000 of principal in February 2011.  We are working with the lender to repay the remaining outstanding balance and there is no formal payment schedule as of the date of this report.





During the six months ended January 31, 2011, we accrued interest of $8,583 at the contracted rate of 15% on the principal outstanding on the note.





2010 Promissory Notes





We issued promissory notes for funds received from two private lenders of $20,000 and $25,000 during January 2011. The principal on the notes are due after one year and bear interest at 15% per annum payable on a quarterly basis.





During the six months ended January 31, 2011, we issued promissory notes for funds received from three directors, two of whom were also officers of Strategic, for aggregate proceeds of $203,300.  The notes are more fully described in Note 9 – Related Party Transactions.





9
 Table of Contents





Note 6 - 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 consolidated 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.”. (See Note 7 – Warrant Derivative Liability)





The fair value of these warrants is measured using significant unobservable inputs (Level 3) and 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 and the risk-free interest rate.





Our derivative warrant liability is our only financial asset or liability that is accounted for at fair value on a recurring basis as of January 31, 2011.





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





Note 7 – Derivative Warrant Liability





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





Certain warrants we issued during the year ended July 31, 2010 are not afforded equity treatment because these warrants have a down-round ratchet provision on the exercise price. As a result, the warrants are not considered indexed to our own stock, and as such, 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, have been recognized as a derivative liability.





870,000 of the warrants classified as derivatives and issued during November 2009 were exercised during the six months ended January 31, 2011 for $200,100. This reduced the derivative liability by $153,445 and increased the additional paid-in capital by the same amount.





10
 Table of Contents





The following table sets forth the changes in the fair value measurement of our Level 3 derivative warrant liability during the six months ended January 31, 2011:





Beginning balance – August 1, 2010

$
2,411,709Issuance of derivative warrants


-Reduced for warrants exercised


(153,445
)Change in fair value of derivative liability


276,549At January 31, 2011

$
2,534,813





Subsequent to the balance sheet date, we participated in an equity raise which triggered the down-round provisions of the warrant agreements.  As a result, the exercise price of the warrants was reduced to $.10 per share and we issued warrants to purchase an additional 15,982,369 shares of common stock. (See Note 10 - Subsequent Events)





Note 8 - Stockholders’ Deficit





Common Stock Issuances





For exercise of warrants for cash:


During October 2010, an aggregate of 870,000 share purchase warrants were exercised for net proceeds of $200,100.  The warrants were derivative warrants; accordingly, the warrant derivative liability as of the date of exercise, $153,445 was reclassified to paid in capital.





For services:


During the three months ended October 31, 2010, we issued 291,666 shares of common stock to consultants for services valued at $60,758.  The shares were valued using the closing market price on the date of grant.





During the three months ended January 31, 2011, we issued 8,334 shares of common stock to consultants for services valued at $1,250. The shares were valued using the closing market price on the date of grant.





Stock options





During the six months ended January 31, 2011, we granted options to purchase 1,400,000 shares of common stock to one of our officers.  The compensation expense associated with compensatory stock options during the six months ended January 31, 2011 was $158,559.





During August 2010, the Board of Directors authorized and approved the adoption of the 2010 Stock Incentive Plan (the “2010 Plan”). An aggregate of 5,000,000 shares of our common stock may be issued under the plan. The 2010 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 following is a description of options granted under the 2010 Plan:





·
In August 2010, options to purchase 1,400,000 shares of common stock with an exercise price of $.20 per share and a term of three years were granted to one of our officers.  The options vest 25% each six months over the 18 months following the award with the first 25% or 350,000 shares vesting immediately.  Because the officer is a non-employee, the award will be recorded at fair value as of each vesting date.  The fair value of the total option award on the date of grant was $173,611, of which $39,942 was associated with immediately vesting options and recorded in expense.  The cost of the award will be amortized over the service period by estimating the fair value of the earned portion at each reporting date.


·
No new options were granted under the plan during the three months ended January 31, 2011.





During 2009, the Board of Directors authorized and approved the adoption of the 2009 Re-Stated Stock Incentive Plan (the “2009 Plan”). An aggregate of 10,000,000 of our 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.  There were no grants under the 2009 plan during the six months ended January 31, 2011.





The following table provides information about options granted to consultants under our stock incentive plans during the six months ended January 31, 2011 and 2010:




2011


2010Number of options granted


1,400,000



-Compensation expense recognized

$
158,599


$
76,800Compensation cost capitalized


-



-Weighted average fair value of options  granted

$
0.14


$
-




11
 Table of Contents





The following table details the significant assumptions used to compute the fair market values of stock option expense during the six months ended January 31, 2011 and 2010:





2011


2010Risk-free interest rate


0.51 - 1.27
%


2.31
%Dividend yield


0
%


0
%Volatility factor


134.62 - 153.00
%


149.71
%Expected life (years)

1.5 - 5 years


5.5 years





For the options on a graded vesting schedule, we estimate the fair value of the award as of the end of each reporting period and recognize an appropriate portion of the cost based on the fair value on that date.  When the award vests, we adjust the cost previously recognized so that the cost ultimately recognized is equivalent to the fair value on the date the performance is complete.





Based on the fair value of the options as of January 31, 2011, there was $163,428 of unrecognized compensation costs related to non-vested share based compensation arrangements granted under the plan.





Summary information regarding stock options issued and outstanding as of January 31, 2011 is as follows:





Options


Weighted Average Share Price


Aggregate intrinsic value


Weighted average remaining contractual life (years)Outstanding at year ended July 31, 2010


8,705,000


$
0.30


$
20,000



5.40Granted


1,400,000



.20Exercised


-



--Expired/cancelled


(725,000
)


0.35Outstanding at January 31, 2011


9,380,000


$
0.28


$
25,000



4.58





Warrants





During the six months ended January 31, 2011, 870,000 derivative warrants granted during November 2009 were exercised for cash.





Summary information regarding common stock warrants issued and outstanding as of January 31, 2011 is as follows:





Warrants


Weighted Average Share Price


Aggregate intrinsic value


Weighted average remaining contractual life (years)Outstanding at year ended July 31, 2010


23,599,067


$
0.42



-



3.02Granted


-



-



-



-Exercised


(870,000
)


0.23



-



-Expired


(5,758,238
)


0.96



-



-Outstanding at January 31, 2011


16,970,829


$
0.25



-



3.47




12
 Table of Contents





Note 9 – Related Party Transactions





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




Three months ended January 31,


Six months ended January 31,2010


2009


2010


2009Revenues

$
114,358


$
86,605


$
181,859


$
133,789Lease operating costs

$
37,840


$
40,375


$
87,420


$
70,194





As of January 31, 2011 and July 31, 2010, respectively, we had outstanding accounts receivable associated with these properties of $52,899 and $28,975 and no accounts payable.





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:





January 31, 2011


July 31, 2010Note payable to a director, interest rate 6% per annum, due on demand after February 2011

$
10,000


$
-Note payable to an officer, and director, interest rate 6% per annum, due on demand after February 2011


8,300



-Note payable to an officer and director, interest rate 6% per annum, due on demand after February 2011


10,000



-Note payable to an officer and director, interest rate 6% per annum, due in December 2011


175,000



-Notes payable, including accrued interest payable

$
203,300


$
-





Subsequent to the balance sheet date, we settled $13,577 of the outstanding notes payable to the related parties with the issuance of 135,769 shares of common stock using a conversion rate of $.10 per share. (See Note 10 – Subsequent Events)





Subsequent to the balance sheet date, we entered into a consulting contract with a company controlled by Michael Watts, the father-in-law of Jeremy Driver, our Chief Executive Officer and a Director.  We also sold 15% of the working interest we acquired when we acquired Galveston Bay Energy, LLC for $1,400,000 to a different company controlled by Mr. Watts. This company may purchase an additional 10% of our working interest for $1,150,000 by mid-May 2011. (See Note 10 – Subsequent Events)





Note 10 – Subsequent Events





2011 Private Placement





During February 2011, we completed a private placement in which we sold 91,390,000 shares of common stock for $.10 per share to raise gross proceeds of $9,139,000 (the “2011 private placement”).  We paid $142,800 in cash offering costs and netted $8,996,200 from this transaction.  This capital raise triggered the anti-dilution provisions of the units previously sold in October and November 2009.  The investors involved in the previous capital raise received 17,750,000 shares of common stock in accordance with these provisions.  Additionally, the exercise price of the warrants issued with the 2009 raise decreased to $.10 per share and the warrant holders received warrants to purchase an additional 15,982,369 shares of common stock.  The warrants are derivative warrants; accordingly, they are remeasured at fair value on a recurring basis.  The fair value associated with the issuance of the additional warrants and the reduction in price of the warrants will be incorporated into the recurring measurement and will be recognized currently in earnings in our consolidated statement of operations under the caption “Other income (expense) – Gain (loss) on warrant derivative liability”.  After the transaction, derivative warrants to purchase 31,343,999 shares of common stock at $.10 per share with a remaining life of approximately 3.7 years were outstanding.





In connection with the 2011 private placement, we granted equity based compensation for finder’s fees as follows: 1,500,000 shares of common stock, warrants to purchase 1,300,000 shares of common stock at an exercise price of $.10 per share with a contractual term of three years, and warrants to purchase 128,000 shares of common stock at an exercise price of $.10 per share with a contractual term of three years.  The stock was valued as $240,000 using the closing stock price on the date of grant.  The fair value of the warrants to purchase 1,300,000 shares of common stock, as computed using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.41%, a dividend yield of 0%, and an expected volatility of 150.78%, was $177,506.  The fair value of the warrants to purchase 128,000 shares of common stock, as computed using the Black-Scholes option pricing model with an expected life of three years, a risk free interest rate of 1.22%, a dividend yield of 0%, and an expected volatility of 151.24%, was $15,108.  As finder’s fees, the cost of the compensation will be recognized as an adjustment to equity.





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 Table of Contents





During February 2011, we settled accounts payable to consultants, officers, and directors and $ 13,577 of principal on notes payable to officers totaling $195,914 with the issuance of 1,959,140 shares of common stock.  The fair value of the stock, as determined using the closing stock price on the date of grant, was $274,280; the excess fair value over the outstanding debt was $78,366.   $26,616 was associated with balances owed to officers and directors and was recognized as additional compensation costs. $51,750 was associated with balances due to consultants of the company and was recognized as a loss on settlement of accounts payable.





We are evaluating whether the private placement resulted in an ownership change, as defined by Internal Revenue Code Section 382, of Strategic.  If such an ownership change has occurred, the net operating loss generated before February 15, 2011 will be limited by the provisions of the Internal Revenue Code Section 382.





Acquisition of Galveston Bay Energy, LLC (“GBE”)





On February 15, 2011 we closed on the acquisition of a private Texas oil and gas company named Galveston Bay Energy, LLC (“GBE”) which owns fractional interests in and operates producing oil and natural gas properties and its related facilities in five fields located in Galveston Bay, Texas.  We paid $10,259,055 cash in February 2011.  Post-closing adjustments, if any, will be determined within 90 days of the closing date.  The following table summarizes the preliminary allocation of the purchase price to the assets acquired and liabilities assumed recognized at the acquisition date:





Recognized Amount of Identifiable Assets Acquired and Liabilities Assumed





Oil and Gas Property, accounted for using the full cost basis of accountingEvaluated Property

$
9,828,045Escrow Funds


6,670,000Accounts payable and accrued expenses


(724,600
)Asset retirement obligation


(5,514,390
)Total Identifiable Net Assets

$
10,259,055





Immediately following our acquisition of GBE, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. As a result of these transactions, GBE is our wholly owned subsidiary and owns approximately 72% of the aggregate working interest in the five fields. SPE may acquire an additional 10% of our own aggregate working interest in the Galveston Bay fields within 90 days for $1,150,000.  As of the date of this report, SPE had paid $450,000 against the purchase of the additional 10% working interest.





On February 15, 2011, we granted 914,634 shares of common stock to a consultant for his role in bringing us the opportunity to make the acquisition.  The shares were valued at $146,341 based on the closing stock price on the grant date.  This acquisition cost will be recognized as expense in our income statement for the quarter ended March 31, 2011.





On February 15, 2011, we granted 15 million shares of common stock to Alan D. Gaines in part as compensation for bringing us the opportunity to make the acquisition described above and in part as new director and officer compensation. 50% of shares vested that date and are valued at $1,200,000 based on the closing stock price on the grant date.  Our agreement with Mr. Gaines provides for a proportional increase in the shares awarded if we raise in excess of $11 million within three months of the closing of the GBE transaction, inclusive of the $8,996,200 raised in the 2011 private placement.  The cost associated with the vested portion of this stock grant will be recognized as expense in our income statement for the quarter ended March 31, 2011. The remaining shares vest as follows: 3,750,000 on February 15, 2012 and 3,750,000 on February 15, 2013.





On February 15, 2011, we granted 15 million shares of common stock to Amiel David in part as compensation for bringing us the opportunity to make the acquisition described above and in part as new director and officer compensation. 50% of shares vested on that date and are valued at $1,200,000 based on the closing stock price on the grant date. Our agreement with Mr. David provides for a proportional increase in the shares awarded if we raise in excess of $11 million within three months of the closing of the GBE transaction, inclusive of the $8,996,200 raised in the 2011 private placement. The cost associated with the vested portion of this stock grant will be recognized as expense in our income statement for the quarter ended March 31, 2011. The remaining shares vest as follows: 3,750,000 on February 15, 2012 and 3,750,000 on February 15, 2013.





14
 Table of Contents





Other events





On February 15, 2011, we entered into a consulting agreement with Geoserve Marketing, LLC (“Geoserve”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. We amended this agreement effective on March 9, 2011.  Geoserve will provide investor relations services.  The agreement has a three year term. The consulting agreement as amended provides that we will compensate Geoserve with warrants to purchase 20,000,000 shares of common stock at an exercise price of $0.10 per share with a five year term (expiring February 15, 2016) as prepayment for the first year of service.  If our common stock attains a five day average closing price of $.30 per share, an additional 15,000,000 warrants with the same terms shall be issued.  If our common stock attains a five day average closing price of $.60 per share, a further 15,000,000 warrants with the same terms will be issued. We may terminate the agreement after the first year with thirty days notice. On February 15, 2011, the first tranche of warrants to purchase 20,000,000 shares of common stock vested. The warrants had an estimated fair value of $2,885,807 as computed using the Black-Scholes option pricing model with an expected life of five years, a risk free interest rate of  2.35%, a dividend yield of 0%, and an expected volatility of 134.26%.  The entire amount of the award will be recognized as a consulting expense in the quarter ended March 31, 2011.





On March 8, 2011, we executed a lease for office space in Houston, Texas.  The lease term is three years and we have an option to extend the lease for an additional three years.  Our scheduled rent is $6,406 per month plus common area maintenance cost for the first year, $6.673 plus common area maintenance cost for the second year, and $6,940 per month plus common area maintenance cost for the third year.





On March 17, 2011, GBE secured a one year revolving line of credit of up to $5,000,000 with a commercial bank.  The note carries interest at a rate of prime + 1% (currently 6%) with a minimum interest rate of 5%. Interest is payable monthly.  We must use proceeds from the line of credit solely to enhance our Galveston Bay properties.   The note is collateralized by our Galveston Bay properties and substantially all GBE’s assets.  Strategic has also executed a parental guarantee of payment.  As of the date of this report, we had not drawn any advances from this line of credit.





15
 Table of Contents





CAUTIONARY STATEMENT ON FORWARD-LOOKING INFORMATION


The Company is including the following cautionary statement to make applicable and take advantage of the safe harbor provision of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. This quarterly report on Form 10-Q contains “forward looking statements” (as that term is defined in Section 27A(i)(1) of the Securities Act of 1933), including statements concerning plans, objectives, goals, strategies, expectations, future events or performance and underlying assumptions and other statements which are other than statements of historical facts.  Such forward looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward looking statements.  Some of the factors that could cause actual results to differ materially from those expressed in such forward looking statements are set forth in the section entitled “Risk Factors” and elsewhere throughout this Form 10-Q.  Our expectations, beliefs and projections are expressed in good faith and are believed by us to have a reasonable basis, but there can be no assurance that our expectations, beliefs or projections will result or be achieved or accomplished.  We have no obligation to update or revise forward looking statements to reflect the occurrence of future events or circumstances.





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





OVERVIEW





As used in this Quarterly Report: (i) the terms "we", "us", "our", "Strategic", "Penasco" and the "Company" mean Strategic American Oil Corporation and its wholly owned subsidiary, Penasco Petroleum Inc., unless the context otherwise requires; (ii) "SEC" refers to the Securities and Exchange Commission; (iii) "Securities Act" refers to the Securities Act of 1933, as amended; (iv) "Exchange Act" refers to the Securities Exchange Act of 1934, as amended; and (v) all dollar amounts refer to United States dollars unless otherwise indicated.





The following discussion of our plan of operations, results of operations and financial condition as at and for the six months ended January 31, 2011 should be read in conjunction with our unaudited consolidated interim financial statements and related notes for the six months ended January 31, 2011 included in this Quarterly Report, as well as our Annual Report on Form 10-K for the year ended July 31, 2010.





General





We are a natural resource exploration and production company engaged in the exploration, acquisition, development, and production of oil and gas properties in the United States.  As of January 31, 2011, we maintain developed acreage in Texas and undeveloped acreage in Illinois.  As of January 31, 2011, we were producing oil and gas from our working interest in three wells in Texas.  Prior to November 1, 2010, we held producing properties in Louisiana.





Our undeveloped acreage in the Illinois basin is adjacent to current or past producing wells. Drilling and completion costs are lower than in many other producing basins and the net revenues are higher. Our leases in Illinois average 87.5% net revenue interest with 100% working interest. Multiple pay zones are indicated in leasehold areas including the Cypress, Levias, Aux Vases, Ste. Genevieve, Salem, Saint Lewis and Warsaw formations. Maximum drill depths will be approximately 4,000 feet.  In January 2011, we farmed out our interest in the Markham City prospect to Core Minerals Management II, LLC (“Core”).  Under the farmout agreement, we retained a 10% working interest and assigned the balance of our working interest in the Markham City prospect to Core.  Core will be the operator of the property.  Core will perform exploration activities on the prospect.  The agreement provides that Core must spud the initial well by June 30, 2011. Our working interest is carried until Core meets the “Earnings Threshold”, $1,350,000.
  As part of our ongoing business strategy, we continue to review and evaluate acquisition opportunities in Texas, Illinois and other areas of the continental United States.





Recent Activities





2011 Private Placement





During February 2011, we completed a private placement in which we sold 91,390,000 shares of common stock for $.10 per share to raise gross proceeds of $9,139,000 (the “2011 private placement”).  We paid $142,800 in cash offering costs and netted $8,996,200 from this transaction.   We used substantially all of the proceeds of the private placement to fund our acquisition of Galveston Bay Energy, LLC (“GBE”) as described below.





16
 Table of Contents





Acquisition of GBE





On February 15, 2011 we closed on the acquisition of a private Texas oil and gas company, GBE, which owns fractional interests in and operates producing oil and natural gas properties and its related facilities in five fields located in Galveston Bay, Texas.





Immediately following our acquisition of GBE, we sold 15% of our own aggregate working interest in the Galveston Bay fields for $1,400,000 in cash to SPE Navigation 1, LLC (“SPE”), a company controlled by Michael Watts, who is the father-in-law of Jeremy Driver, a Director and our Chief Executive Officer. As a result of these transactions, GBE is our wholly owned subsidiary and owns approximately 72% of the aggregate working interest in the five fields. SPE may acquire an additional 10% of our own aggregate working interest in the Galveston Bay fields within 90 days for $1,150,000.  As of the date of this report, SPE had paid $450,000 against the purchase of the additional 10% working interest.





In order to maximize production from our Galveston Bay properties, we plan approximately $2.6 million in improvements in the next 12 months to the properties to include upgrading production facilities, new pipelines, recompleting of existing shut-in wells, and other various projects aimed specifically at increasing production.  In March 2011, we secured an initial line of credit from a commercial bank for up to $5,000,000 to support our work on these properties.





Results of Operations





Three Months Ended January 31, 2011 Compared to the Three Months Ended January 31, 2010





Production data:




Three months ended January 31,2011


2010Oil (Bbls)


Gas (Mcf)


Total (Mcfe)


Oil (Bbls)


Gas (Mcf)


Total (Mcfe)Production


1,173



4,542



11,581



1,467



4,470



13,271Average sales price

$
85.26


$
3.57


$
10.04


$
82.09


$
3.88


$
10.38Average lease operating expense









$
3.00










$
12.18








Statements of operations:





Three months ended January 31,2011


2010


Increase/

(Decrease)


%

ChangeRevenues

$
116,261


$
137,763


$
(21,502
)


16
%Operating expensesLease operating expense


39,124



161,702



(122,578
)


(76
)%Depreciation, depletion, and amortization


28,925



23,651



5,274



22
%Accretion


1,270



-



1,270



100
%Impairment


140,029



-



140,029



100
%Consulting fees


67,389



601,271



(533,882
)


(89
)%Management fees


66,042



540,964



(474,922
)


(88
)%Other general and administrative expense


244,575



223,381



21,194



9
%Total operating expenses


587,354



1,550,969



(963,615
)


(62
)%Loss from operations


(471,093
)


(1,413,206
)


942,113



67
%Interest expense, net


11,806



(32,098
)


43,904



(137
)%Gain/ (loss) on warrant derivative liability


(191,988
)


680,739



(872,727
)


(128
)%Net Loss

$
(651,275
)

$
(764,565
)

$
(113,290
)


(15
)%




17
 Table of Contents





We recorded a net loss for the three months ended January 31, 2011 of $651,275 or $0.01 basic and diluted loss per common share compared to a net loss of $764,565 or $0.02 basic and diluted loss per common share for the comparable quarter of 2010.





Revenues





Revenues from oil and gas properties were $116,261 during the three months ended January 31, 2011 compared to $137,763 during the three months ended January 31, 2010. The primary reason for the reduction in revenue was the sale of our property in Louisiana. Significant developments or changes between these periods are outlined below:





·
Texas: Revenue from the Barge Canal and Janssen projects totaled $116,261for the three months ended January 31, 2011, as compared to $87,833 for the three months ended January 31, 2010. This represents an increase of $28,428. This was primarily due to higher oil and gas prices in the current period.


·
Louisiana: Revenue from the properties located in Louisiana was $0 for the three months ended January 31, 2011 as compared to $49,930 for the comparable period in 2009. We sold our Louisiana properties effective in November and thus earned no revenue in the quarter ended January 31, 2011.





Operating expenses





Lease operating expense





Oil and gas operating costs were $39,124 during the three months ended January 31, 2011 compared to $161,702 in the prior year. This represents a decrease of 76% or $122,578. The primary reason for the reduction in lease operating expense was the sale of our property in Louisiana. Significant developments or changes in direct operating costs per project are outlined as follows:





·
Texas: Direct operating costs were $39,124 during the three months ended January 31, 2011 as compared to costs of $41,757 during the three months ended January 31, 2010.


·
Louisiana: Because we sold these properties in November 2010, direct operating costs were $0 during the three months ended January 31, 2011. This compares to costs of $119,945 during the three months ended January 31, 2010.





Depreciation, depletion and amortization (DD&A)





For the three months ended January 31, 2011, we recorded DD&A expense of $28,925 compared to $23,651 for the three months ended January 31, 2010, which represents an increase of $5,274. This increase is primarily due to a higher depletable base in fiscal 2011.





Accretion





Accretion expense for asset retirement obligations increased by $1,270 for the three months ended January 31, 2011 compared to the same period in 2010. 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, which was minimal in 2010.





Impairment





Impairment expense for the three months ended January 31, 2011 were $140,029 as compared to $0 for the comparable quarter of 2010. We recorded an impairment charge during the current quarter because the net book value of our oil and gas properties exceeded the ceiling by $140,029 on January 31, 2011.





Consulting fees





Consulting fees for the three months ended January 31, 2011 decreased by $533,882 from the comparable quarter of 2010. The decrease is primarily due to the absence of new option grants in 2011. We expect consulting expenses to significantly increase in the quarter ended March 31, 2011 because of awards made in February 2011.





18
 Table of Contents





Management fees





Management fees represent compensation for our officers and directors who are not employees of the company.  Management fees for the three months ended January 31, 2011 decreased by $474,922 from the comparable quarter of 2010 to $66,042. The decrease in management fees was attributable to contract and bonus payments in the prior period which were not incurred during the current period.  Equity-based compensation decreased approximately $400,000 because stock options vested in 2010 which were not repeated in 2011 and because stock bonuses were granted in December 2010.  In addition, cash compensation reflected as management fees decreased because cash bonuses granted in 2010 were not repeated in 2011 and because the CEO became an employee of the company, with his compensation reflected as a payroll (G & A) expense, as of August 2010.





Other general and administrative expense (G&A expense)





G&A expense for the three months ended January 31, 2011 increased 9%, or $21,194, from the comparable quarter of 2010 to $244,975.  The increase is primarily attributable to decreases in professional fees of approximately $50,000, travel and promotion expenses of approximately $20,000, and gain on debt settlement of approximately $8,000 offset by increases in compensation expense of approximately $55,000. The increase in compensation expense reflects our decision to conduct our operations using employed staff as opposed to consultants.  Professional fees and travel expense were substantially higher in 2010 because of costs related to our capital raises in October and November of 2009.





Interest expense, net





Interest expense for the quarter ended January 31, 2011 amounted to net income of $11,806 compared to net expense of $32,098 in the comparable quarter ended January 31, 2010.  The variation in interest expense is primarily attributable to amortization of debt discount of approximately $26,000 in 2010. The discount was fully amortized as of October 1, 2010.  Additionally, interest was capitalized to oil and gas projects in the current quarter; capitalization of interest did not occur in the comparable quarter of 2010.





Gain/ (loss) on derivative warrant liability





For the three months ended January 31, 2011, we incurred a loss on derivative warrant liability of $191,988. This loss compared to a $680,739 gain for the comparable quarter of 2010. The gain of $680,739 during the three months ended January 31, 2010 consists of the unrealized loss on the date of initial recognition of the derivative warrant liability for the warrants issued in November 2009 of $556,820 offset by the gain due to the periodic mark-to-market valuation at January 31, 2010 of $1,237,559. The loss at initial recognition is attributable to the fact that the fair value of the warrants exceeded the consideration received for the warrants on that date.  The mark-to-market gain or loss is attributable to the difference in fair value, as computed using the Black-Sholes option pricing model, as of January 31, 2011 and October 31, 2010 and January 1, 2010 and October 31, 2009, respectively.





Sensitive inputs to the Black-Sholes option pricing model include expected term, volatility, and the spread between the exercise price and the stock price on the date of the valuation.   The exercise price of the warrants as of October 31, 2009 was generally lower than the stock price whereas of January 31, 2010, the warrants were no longer in the money; this was the primary factor responsible for the gain in this period.  Conversely, as of both October 31, 2010 and January 31, 2011, the warrants were out of the money and the spread between the exercise price and stock price was closer on each of the valuation dates; thus the difference between the valuations was much lower.





In February 2011, as a consequence of our capital raise, the exercise price of the warrants issued with the 2009 raise decreased to $.10 per share and the warrant holders received warrants to purchase an additional 15,982,369 shares of common stock.  The warrants are derivative warrants; accordingly, they are remeasured at fair value on a recurring basis.  After the transaction, derivative warrants to purchase 31,343,999 shares of common stock at $.10 per share with a remaining life of approximately 3.7 years were outstanding.  We expect the loss on derivative warrants to significantly increase in the quarter ended March 31, 2011 due to increase in fair value attributable to the lower exercise price and higher number of warrants outstanding.





Net Loss





For the quarter ended January 31, 2011, net loss decreased $113,290 from the comparable quarter of 2010. This change is due to the factors discussed above.





19
 Table of Contents





Six Months Ended January 31, 2011 Compared to the Six Months Ended January 31, 2010





Production data:




Six months ended January 31,2011


2010Oil (Bbls)


Gas (Mcf)


Total (Mcfe)


Oil (Bbls)


Gas (Mcf)


Total (Mcfe)Production


2,554



7,413



22,741



2,580



7,513



22,993Average sales price

$
79.06


$
3.66


$
10.08


$
75.60


$
3.41


$
9.60Average lease operating expense









$
6.00










$
9.31







Statements of operations:





Six months ended January 31,2011


2010


Increase/

(Decrease)


%

changeRevenues

$
229,134


$
220,696


$
8,438



4
%Operating expensesLease operating expense


140,388



214,171



(73,783
)


(34
)%Depreciation, depletion, and amortization


51,925



39,701



12,224



31
%Accretion


3,664



-



3,664



100
%Impairment


140,029



-



140,029



100
%Consulting fees


595,524



910,334



(314,810
)


(35
)%Management fees


222,912



643,510



(420,598
)


(65
)%Other general and administrative expense


400,283



422,441



(22,158
)


(5
)%Total operating expenses


1,554,725



2,230,157



(675,432
)


(30
)%Loss from operations


(1,325,591
)


(2,009,461
)


(683,870
)


(34
)%Interest expense, net


(14,779
)


(102,166
)


(87,387
)


(86
)%Loss on warrant derivative liability


(276,549
)


(1,357,487
)


(1,080,938
)


(80
)%Net Loss

$
(1,616,919
)

$
(3,469,114
)

$
(1,852,195
)


(53
)%





We recorded a net loss for the six months ended January 31, 2011 of $1,616,919, or $0.03 basic and diluted loss per common share compared to a net loss of $3,469,114, or $0.09 basic and diluted loss per common share for the six months ended January 31, 2010.





Revenues





Revenues from oil and gas properties were $229,134 during the six months ended January 31, 2011 compared to $220,696 during the six months ended January 31, 2010. The primary reason for the reduction in revenue was the sale of our property in Louisiana. Significant developments or changes between these periods are outlined below:





·
Texas: Revenue from the Barge Canal and Janssen projects totaled $184,583 for the six months ended January 31, 2011 as compared to $136,023 for the six months ended October 31, 2010.  The increase is attributable to increased oil production and higher oil sales prices.


·
Louisiana properties: Revenue from the properties located in Louisiana was $44,551 for the six months ended January 31, 2011 as compared to $84,673 for the comparable period in 2010. This represents a decrease of $40,122.    During September 2010, we sold our working interest in the Dixon project. Effective November 1, 2010, we sold our working interest in our remaining oil and gas properties in Louisiana.





20
 Table of Contents





Operating expenses





Lease operating expense





Oil and gas operating costs were $140,388 during the six months ended January 31, 2011 compared to $214,171 in the prior year. This represents a decrease of 34% or $73,783. The primary reason for the reduction in lease operating expense was the sale of our property in Louisiana. Significant developments or changes in direct operating costs per project are outlined as follows:





·
Texas: Direct operating costs were $89,167 during the six months ended January 31, 2011 as compared to costs of $72,322 during the six months ended January 31, 2010.


·
Louisiana: Direct operating costs were $51,221 during the six months ended January 31, 2011 as compared to costs of $141,849 during the six months ended January 31, 2010.  The decrease is due to sale of the properties during the current period.





Depreciation, depletion, and amortization (DD&A)





For the six months ended January 31, 2011, we recorded DD&A expense of $51,925 compared to $39,701 for the six months ended January 31, 2010 representing an increase of $12,224. This increase is primarily due to a higher depletable base in fiscal 2011.





Accretion





Accretion expense for asset retirement obligations increased by $3,664 for the six months ended January 31, 2011 compared to the same period in 2010.  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, which was minimal in 2010.





Impairment





Impairment expenses for the three months ended January 31, 2011 were $140,029 as compared to $0 for the comparable quarter of 2010. We recorded an impairment charge during the current quarter because the net book value of our oil and gas properties exceeded the ceiling by $140,029 on January 31, 2011.





Consulting fees





Consulting fees for the six months ended January 31, 2011 decreased by $314,810 from the comparable period of 2010 to $595,524. During the six months ended January 31, 2011, stock based consulting expenses decreased by $337,558 offset by an increase in general consulting fees of $22,748.  The decrease is primarily due to fewer stock option grants and consulting contracts during 2011 in comparison to 2010.  We expect consulting expenses to significantly increase in the quarter ended March 31, 2011 because of awards made in February 2011.





Management fees





Management fees for the six months ended January 31, 2011 decreased by $420,598 from the comparable period of 2010 to $222,912. This is attributable to a decrease in general management expenses of $111,798 and a decrease in stock based management fees of $308,800. The decrease is primarily due to fewer equity grants and fewer management consulting contracts in comparison to 2010. Equity-based compensation decreased approximately $310,000 because more stock options vested in 2010 than in 2011 and because stock bonuses were granted in December 2010.  In addition, cash compensation reflected as management fees decreased because cash bonuses granted in 2010 were not repeated in 2011 and because the CEO became an employee of the company, with his compensation reflected as a payroll (G & A) expense as of August 2010.





Other general and administrative expense (G&A expense)





G&A expense for the six months ended January 31, 2011 decreased by $22,158 from the comparable period in the prior year to $400,283. During the six months ended January 31, 2011, compensation expense increased by $96,406 and rent expense increased by $4,456. These increases were offset by decreases in professional fees of $68,745, travel expenses of $33,122, foreign exchange transaction loss of $38,093, and gain on debt settlement of $13,184.  The increase in compensation expense reflects our decision to conduct our operations using employed staff as opposed to consultants.  Professional fees were higher in 2010 because of costs related to our capital raises in October and November of 2009.  The exchange loss was higher in 2010 in association with the repayment of Canadian denominated debt.   We have significantly reduced our accounts with Canadian vendors.





Interest expense, net





Interest expense for the six months ended January 31, 2011 amounted to $14,779 compared to $102,166 in the comparable period in the prior year.  The variation in interest expense is primarily attributable to amortization of debt discount of approximately $78,000 in 2010. The discount was fully amortized as of October 1, 2010.  Additionally, interest was capitalized to oil and gas projects during the six months ended January 31, 2011; capitalization of interest did not occur in the comparable period of 2010.





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Loss on derivative warrant liability





For the six months ended January 31, 2011, we incurred a loss on derivative warrant liability of $276,549.This loss compared to a $1,357,487 loss for the comparable period of 2010. The loss during the six months ended January 31, 2010 consists of the unrealized loss on the date of initial recognition of the derivative warrant liability of $2,615,075 offset by the gain due to the change in the mark-to-market valuation at January 31, 2010 of $1,257,588. During the six months ended January 31, 2011, the expense consists of only the change in the mark-to-market valuation for the six months of $276,549. The loss at initial recognition is attributable to the fact that the fair value of the warrants exceeded the consideration received for the warrants when they were issued. The mark-to-market gain or loss is attributable to the difference in fair value, as computed using the Black-Sholes option pricing model, as of January 31, 2011 and July 31, 2010 and January 1, 2010 and the value at inception, October and November 2009, respectively.





Sensitive inputs to the Black-Sholes option pricing model include expected term, volatility, and the spread between the exercise price and the stock price on the date of the valuation.  The exercise price of the warrants when they were issued was generally lower than the stock price whereas, as of January 31, 2010, the warrants were no longer in the money; this was the primary factor responsible for the gain in this period.  Conversely, as of both July 31, 2010 and January 31, 2011, the warrants were out of the money with closer spreads, thus the difference between the valuations was much lower.





In February 2011, as a consequence of our capital raise, the exercise price of the warrants issued with the 2009 raise decreased to $.10 per share and the warrant holders received warrants to purchase an additional 15,982,369 shares of common stock.  The warrants are derivative warrants; accordingly, they are remeasured at fair value on a recurring basis.  After the transaction, derivative warrants to purchase 31,343,999 shares of common stock at $.10 per share with a remaining life of approximately 3.7 years were outstanding.  We expect the loss on derivative warrants to significantly increase in the quarter ended March 31, 2011 due to increase in fair value attributable to the lower exercise price and higher number of warrants outstanding.





Net Loss





For the six months ended January 31, 2011, net loss decreased $1,852,195 from the comparable period of 2010. This change is due to the factors discussed above.





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.





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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.





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.





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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 and the risk-free interest rate.





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.





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.





Liquidity and Capital Resources





The following table sets forth our cash and working capital as of January 31, 2011 and July 31, 2010:





January 31, 2011


July 31, 2010Cash

$
7,803


$
247,851Working capital (deficit)

$
(3,362,822
)

$
(2,524,789
)





At January 31, 2011, we had $7,803 of cash on hand and a working deficit of $3,362,822 ($2,534,813 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.  In February 2011, we raised net proceeds of $8,996,200 from a private placement in which we sold 91,390,000 shares of common stock for $.10 per share.   We used substantially all of the proceeds of the private placement to fund our acquisition of GBE.





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Subject to the availability of additional financing, we intend to spend approximately $4,000,000 over the next twelve months in carrying out our current plan of operations, which includes improvements to our recently acquired properties in Galveston Bay. We estimate that we will need to receive additional funds of approximately $5,000,000 during the next twelve months, either through the sale of capital stock, borrowing, or from increased oil and 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 prices of oil and natural gas as well as the overall market conditions in the international and local economies. 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 there is no certainty that these levels will stabilize or reverse. We recognize that the price of oil decreased from approximately $140 per barrel in 2008 to under $40 per barrel in February of 2009. While it has increased to approximately $100 per barrel as of early March 2011, if the price of oil drops to levels experienced in previous years, the price drop 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 of January 31, 2011, we had accumulated losses of $13,016,680 since inception. Our ability to pursue our planned business activities is dependent upon our successful efforts to raise additional equity or debt 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. Our consolidated financial statements do not include any adjustments 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





Net cash used in operating activities during the six months ended January 31, 2011 have decreased significantly in comparison to the prior year; we used cash of $648,492 compared to $1,456,385 during the six months ended January 31, 2010. This decrease is primarily attributable to decreases in management and consulting fees in 2011.  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.  Because of the start-up nature of our business, the bulk of our operating costs have been consulting, management, and general and administrative costs.  With our acquisition of GBE, we expect to derive a much greater percentage of our cash flows from operations from revenues and direct operating costs.  Because the GBE properties will increase our contribution margin from our core activities, the acquisition should enhance our cash flows from operations.





Net Cash Provided by (Used in) Investing Activities





During the six months ended January 31, 2011, investing activities provided cash of $45,044 compared to a use of cash of $267,891 during the six months ended January 31, 2010. The changes between such periods relates primarily to proceeds from the sale of working interest in our Kenedy and Dixon projects in fiscal 2011. Our future cash flows used in investing will increase due to our acquisition of GBE and our planned investment in the fields that we acquired.





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 during the six months ended January 31, 2011 provided cash of $363,400 compared to $2,798,862 during the six months ended January 31, 2010.  This is attributable to a significant stock private placement in fiscal 2010.  Our future cash flows from financing will increase due to the 2011 private placement.





Item 3. Quantitative and Qualitative Disclosures About Market Risk





Not required because we are a smaller reporting company.





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Item 4. Controls and Procedures





Evaluation of Disclosure Controls and Procedures





We maintain disclosure controls and procedures (as defined in Exchange Act Rules 240.13a — 15(e) and 240.15d — 15(e)) that are designed to ensure that information required to be disclosed in our Securities and Exchange Commission reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures are also designed to accumulate and communicate information to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, we recognize that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. Accordingly, management must apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.





Our Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures as of the end of the quarter ended January 31, 2011. Based on that evaluation, they have concluded that our disclosure controls and procedures as of the end of the period covered by this report are not effective in providing reasonable assurance that information required to be disclosed by us in the reports we file under the Exchange Act were recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules, regulations and forms.





Internal Control over Financial Reporting





There have not been any changes in our internal controls over financial reporting that occurred during our second fiscal quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.





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Part II Other Information





Item 1. Legal Proceedings





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 1A. Risk Factors





For information regarding our risk factors see the risk factors disclosed in Item 1A of our Annual Report on Form 10-K filed on November 15, 2010. There have been no material changes from the risk factors previously disclosed in such Annual Report.





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





During the three months ended January 31, 2011, we issued 100,000 shares of unregistered, restricted shares of our common stock to one consultant in payment of services rendered under a services agreement.  These shares were issued at a deemed issuance price of $0.20 per share.  We relied on an exemption from the registration requirements of the Securities Act under Section 4(2) thereunder and Regulation S.





Item 3. Defaults Upon Senior Securities





None.





Item 4. (Removed and Reserved)





None.





Item 5. Other Information





None.





Item 6. Exhibits





Exhibit 31.1 - Certification of Chief Executive Officer of Strategic American Oil Corporation required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.





Exhibit 31.2- Certification of Chief Financial Officer of Strategic American Oil Corporation required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.





Exhibit 32.1 - Certification of Chief Executive Officer of Strategic American Oil Corporation pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63.





Exhibit 32.2- Certification of Chief Financial Officer of Strategic American Oil Corporation pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and Section 1350 of 18 U.S.C. 63.





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Signatures





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








STRATEGIC AMERICAN OIL CORPORATION


/s/ "Jeremy Glenn Driver"


Jeremy Glenn Driver


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


Date: March 21, 2011





/s/ "Johnathan Lindsay"


Johnathan Lindsay


Secretary, Treasurer, Chief Financial Officer, Principal Accounting Officer


Date: March 21, 2011






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