UNITED STATES


SECURITIES AND EXCHANGE COMMISSION


Washington, D.C. 20549





FORM 10-Q





(Mark One)


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





For the Quarterly Period Ended April 30, 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: 000-51427





BLACKSANDS PETROLEUM, INC.


(Exact name of registrant as specified in its charter)





Nevada
20-1740044(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)





25025 I-45 N., Suite 410


The Woodlands, Texas 77380


(Address of principal executive offices) (zip code)





(713) 554-4491


(Registrant’s telephone number, including area code)





(Former name, former address and former fiscal year, if changed since last report)





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





Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 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 o   No o





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.





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





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





As of June 13, 2011, there were 16,185,625 shares of the registrant’s common stock outstanding.







BLACKSANDS PETROLEUM, INC.


FORM 10-Q


For the Quarter Ended April 30, 2011





Table of Contents





PART I  FINANCIAL INFORMATION

PageItem 1.
Financial StatementsConsolidated Balance Sheets as of April 30, 2011 and October 31, 2010 (unaudited)


1Consolidated Statements of Operations and Comprehensive Loss for the three and six months ended April 30, 2011 and 2010 (unaudited)


2Consolidated Statements of Cash Flows for the six months ended April 30, 2011 and 2010 (unaudited)


3Condensed Notes to Consolidated Financial Statements (unaudited)


4Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations


8Item 3.
Quantitative and Qualitative Disclosures About Market Risk


14Item 4.
Controls and Procedures


14Item 1.
Legal Proceedings


15Item 1A.
Risk Factors


15Item 2.
Unregistered Sales of Securities and Use of Proceeds


15Item 3.
Defaults Upon Senior Securities


15Item 4.
(Reserved)


15Item 5.
Other Information


15Item 6.
Exhibits


15SIGNATURES


16










PART I.  FINANCIAL INFORMATION





Item 1.
Financial Statements.








Blacksands Petroleum, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)








April 30, 2011


October 31, 2010ASSETSCurrent Assets:Cash and cash equivalents

$
544,993


$
1,609,961Accounts receivable


353,359



210,180Prepaid expenses and deposits


24,000



12,423Total Current Assets


922,352



1,832,564Oil and gas property costs (successful efforts method of accounting)Unproved


6,215,608



1,786,997Proved, net of accumulated depletion of $1,030109 and $690,949 respectively


1,883,819



1,897,767Fixed assets, net


2,443



--Other assets


230,000



50,000TOTAL ASSETS

$
9,254,222


$
5,567,328LIABILITIES AND STOCKHOLDERS’ EQUITYCurrent Liabilities:Notes payable

$
1,560,000


$
--Accounts payable and accrued expenses


482,822



729,360Derivative liability


--



923,756Total Current Liabilities


2,042,822



1,653,116Note Payable


--



60,000Asset Retirement obligation


742,353



523,060Total Liabilities


2,785,175



2,236,176Stockholders’ Equity:Preferred stock - $0.01 par value; 10,000,000 shares authorized:


--



--Series A - $.001 par value, 310,000 shares authorized, 250,000 and nil shares issued and outstanding at April 30, 2011 and October 31, 2010, respectively


250



250Common stock - $0.001 par value; 100,000,000 shares authorized; 15,969,900 and 14,951,567 shares issued and outstanding at April 30, 2011 and October 31, 2010, respectively


15,970



14,952Additional paid-in capital


20,523,969



14,238,690Accumulated deficit


(14,071,142
)


(10,922,740
)Total Stockholders’ Equity


6,469,047



3,331,152TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

$
9,254,222


$
5,567,328





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


1




Blacksands Petroleum, Inc. and Subsidiaries

Consolidated Statements of Operations and Comprehensive Loss

(Unaudited)






Six Months Ended April 30,


Three Months Ended April 30,2011


2010


2011


2010Revenue:Oil and gas revenue

$
892,763


$
494,092


$
498,577


$
425,409Expenses:Selling, general and administrative


1,330,829



336,057



694,019



144,587Depreciation and depletion


339,107



79,184



123,009



49,895Accretion expense


30,535



2,424



16,536



628Lease operating expenses


352,236



204,856



162,302



128,998Oil and gas exploration


106,394



146,571



435



75,339Total expenses


2,159,101



769,092



996,301



399,447(Loss) earnings from operations


(1,266,338
)


(275,000
)


(497,724
)


25,962Other income and (expense):Interest income


--



113,309



--



59,012Interest expense


(1,833,471
)


--



(1,802,874
)


--Change in value of derivative liability


(52,725
)


--



(45,161
)


--Loss on currency transactions


22



(178,549
)


22



(163,210
)Gain on sale of equipment


4,110



--



4,110



--Gain on sale of Access


--



2,715,130



--



2,715,130Total other income (expense)


(1,882,064
)


2,649,890



(1,843,903
)


2,610,932(Loss) income before provision for income taxes


(3,148,402
)


2,374,890



(2,341,627
)


2,636,894Provision for income taxes


--



--



--



--Net (loss) income


(3,148,402
)


2,374,890



(2,341,627
)


2,636,894Preferred stock dividends


100,000



--



50,000



--Net (loss) income attributable to common shareholders

$
(3,248,402
)

$
2,374,890


$
(2,391,627
)

$
2,636,894Comprehensive loss:Net (loss) income

$
(3,148,402
)

$
2,374,890


$
(2,391,627
)

$
2,636,894Other comprehensive income, net of taxCurrency translation adjustment


--



123,001



--



102,764Total comprehensive (loss) income

$
(3,148,402
)

$
2,497,891


$
(2,391,627
)

$
2,739,658(Loss) income per share attributable to common shareholdersBasic and diluted

$
(0.21
)

$
0.16


$
(0.15
)

$
0.18Weighted Average Shares OutstandingBasic  and diluted


15,189,173



14,951,567



15,434,788



14,951,567





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





2


BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)







Six months Ended April 302011


2010CASH FLOWS FROM OPERATING ACTIVITIES:Net (loss) income

$
(3,148,402
)

$
2,374,890Adjustments to reconcile net loss to net cash used in operating activities:Loss on derivative liability


52,725



--Gain on sale of Access


--



(2,715,130
)Stock based compensation expense


558,298



--Amortization of debt discount


1,745,300



--Depreciation and depletion


339,107



81,608Accretion


30,535Changes in operating assets and liabilities:Accounts receivable


(143,179
)


(326,876
)Prepaid expense, deposits and other assets


(191,577
)


3,904Accounts payable


(245,189
)


346,927Accounts payable related party


--



43,412Net cash flows used in operating activities


(1,002,382
)


(191,265
)CASH FLOWS FROM INVESTING ACTIVITIESPurchase of oil and gas properties


(4,565,012
)


(1,478,440
)Acquisition of fixed assets


(3,792
)


--Payment on sale of Access


--



(75,000
)Investment in short-term investments


--



88,553Net cash flows used in investing activities


(4,568,804
)


(1,464,887
)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from sale of common stock


1,338,500Proceeds from  note payable


1,500,000



—Net proceeds from bridge notes payable


1,719,018Repayment of notes payable


(51,300
)Net cash flows provided by financing activities


4,506,218



—Effects of exchange on cash


--



123,001NET (DECREASE) IN CASH AND CASH EQUIVALENTS


(1,064,968
)


(1,533,151
)CASH AND CASH EQUIVALENTS - Beginning of period


1,609,961



2,797,690CASH AND CASH EQUIVALENTS - End of period

$
544,993


$
1,264,539





Supplemental Disclosures





Cash paid for interest

$
15,379


$
--Cash paid for income taxes

$
--


$
--Supplemental non-cash activitiesAsset retirement obligation acquired in acquisition

$
188,758


$
92,006Conversion of notes payable to common stock

$
1,694,000



--Reclassification of derivative liability to equity

$
976,481



--Discount on debenture for warrants and beneficial conversion feature

$
1,745,300



--





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


3





Blacksands Petroleum, Inc.


Notes to Consolidated Financial Statements


(Unaudited)





1.
DESCRIPTION OF BUSINESS, AND SIGNIFICANT ACCOUNTING POLICIES





Blacksands Petroleum, Inc. (hereinafter referred to as the “Company”) was incorporated in the State of Nevada on October 12, 2004 as Lam Liang Corp.  The Company changed its name to Blacksands Petroleum, Inc. on June 9, 2006.  Since August 2007, the Company has been engaged in the exploration, development, exploitation and production of oil and natural gas.  Until November 9, 2009 when the Company acquired its interest in the J.E. Pettus Gas Unit, the Company was considered an exploration stage company in accordance with Accounting Standards Codification (“ASC”) No. 915.  The Company sells its oil and gas products primarily to domestic pipelines and refineries.  Its operations are presently focused in the States of Texas and New Mexico.





The accompanying unaudited interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited financial statements and notes thereto contained in annual report on Form 10-K for the year ended October 31, 2010 filed with the SEC on February 2, 2011. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited financial statements as reported in the 2010 annual report on Form 10-K have been omitted.





2.
Oil and Gas Properties





AP Clark II Prospect Acquisition in November 2010





On November 29, 2010, the Company entered into a leasehold acquisition and participation agreement (the “LAPA”) with Westerly Exploration, Inc. (“Westerly”) pursuant to which (i) the Company  acquired the leasehold interests and rights thereto in the AP Clark II Prospect (as defined in the LAPA) located in Borden County, Texas from Westerly for $260,000 (ii) the Company paid Westerly $119,000 as advance payment towards 70% of the actual third party costs to receive an extension of certain leasehold properties included in the AP Clark II Prospect (as defined in the LAPA) (the “Extension Monies”) and (iii) the Company and Westerly agreed to drill the W.D. Everett Well No. 3 located within the AP Clark II Prospect (as defined in the LAPA) whereby all costs of such drilling operation shall be borne 30% by Westerly and 70% by the Company.  Upon execution of the LAPA, the Company paid Westerly $163,590 for the sole purpose of acquisition of casing for the W.D. Everett Well No. 3.





The Company commenced drilling on the W.D. Everett Well No. 3 during the quarter ended April 30, 2011.  The Company incurred $1,130,245 in capitalized exploration costs through April 30, 2011 in connection with drilling the well.





Copano Bay Acquisition in December 2010





On November 1, 2010, the Company purchased the Copano Bay Lease located in Aransas County, Texas for $100,000. The Copano Bay Lease includes four (4) active wells and 7 non-producing wells located on 1,920 acres in Aransas County, Texas. The leases are currently held by production.  The leasehold working interest acquired by Copano Bay Holdings LLC is 50% leasehold working interest (37.5% net revenue interest) from the surface to 8,000 feet below the surface. NRG Assets Management LLC, a Texas LLC and Texas registered operating company owned by the Company is the operator at all depths.  In connection with the acquisition, the Company recorded an asset retirement obligation totaling $188,758.





The preliminary purchase price allocation:




Total purchase price

$
100,000Oil and gas properties


233,316Pre-purchase production


55,442Asset retirement obligations


(188,758
)Total purchase price

$
100,000




4





Pedregosa





During the quarter ended April 30, 2011, the Company began drilling on a test well.  The Company incurred $1,937,194 in capitalized exploration costs through April 30, 2011.




3.
Note Payable




Promissory Note





On November 19, 2010, the Company borrowed $1,500,000 from Silver Bullet Property Holdings pursuant to a promissory note agreement.  The note bears interest at the rate of 10% per annum and is due on the earlier of the date the Company closes on an offering with gross proceeds of at least $5 million or November 19, 2011.





In November 2009, the Company received an interest-free advance from an unrelated third party totaling $60,000.  In January 2011, the interest-free advances were converted into a note payable, which is due on January 11, 2012 and has a stated annual interest rate of 6%.





Bridge Loans





On February 2, 2011, the Company entered into a securities purchase agreement (the “Purchase Agreement”) with six accredited investors (the “Investors”), providing for the sale by the Company to the Investors of an aggregate of (i) 8% debentures in the principal amount of $1,745,300 (the “Debentures”) and (ii) warrants to purchase 581,767 shares of common stock of the Company (the “Warrants”).





The Debentures mature on the earlier of the (i) date the Company closes an offering that results in gross proceeds to the Company of at least $1,000,000 or (ii) first anniversary of the date of issuance (the “Maturity Date”) and bears interest at the annual rate of 8%.  The Company is not required to make any payments until the Maturity Date.  The Warrants are exercisable for a period of three years from the date of issuance and are exercisable into shares of common stock of the Company at an exercise price of $4.50 per share. The Company is required to register the shares underlying the warrants within 60 days of the closing of the offering.





On March 17, 2011, the bridge loans came due as a result of obtaining at least $1,000,000 in gross proceeds from the private placement (Note 7).  On that date, $1,694,000 of the Bridge Loans were converted into 564,667 shares of the Company’s common stock and an option to purchase 564,667 shares of the Company’s common stock at an exercise price of $4.50 per share.  The remaining $51,300 in Bridge Loans was repaid.  The warrants to purchase 581,767 shares of the Company’s common stock were not affected by the conversion or repayment.





In connection with the issuance of the Debentures, the Company reported a beneficial conversion feature of $872,404 and a discount related to the issuance of the warrants of $872,896.  The beneficial conversion feature and discount were amortized to interest expense on the date of the conversion of the debentures to common stock.  The relative fair value of the warrants was calculated using the Black-scholes method using the following assumptions: Discount rate of 1.2% to 1.4%, volatility of 155% and expected term of 3 years.  The Company evaluated the warrants and concluded they were not derivatives.




4.
Asset Retirement Obligation  The following table summarizes the change in the asset retirement obligation for the periods ended April 30,





2011


2010Beginning balance at November 1

$
523,060


$
--Liabilities settled


--



--Liabilities incurred through acquisition of assets


188,758



--Accretion expense


30,535



--Ending balance at April 30

$
742,353


$
--








The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.




5
  5.
Stockholders’ Equity





Preferred Stock





In June 2006, the Company amended its certificate of incorporation to authorize 10,000,000 shares of preferred stock at a par value of $.001.





In October 2010, the Board of Directors designated 310,000 shares of the Company’s preferred stock as Series A Convertible Preferred Stock (“Series A Preferred”).  The Series A Preferred are convertible into shares of common stock at a conversion price of $1.25.  The shares are entitled to dividends at a rate of 8% of the stated value per share per annum.  The dividends are payable annually on December 31 in cash or additional shares of the Series A Preferred, at the option of the Company.  The Series A Preferred and any accrued and unpaid dividends will mandatorily convert into common shares on October 29, 2013.  The Company has reported the preferred dividends for the period on the statement of operations in the calculation of net income (loss) available for common stockholders.  The Company has not accrued any dividends as no dividends have been declared.





Stock Options





A summary of the Company’s stock option activity and related information is as follows:





Number of Shares


Weighted Average Exercise PriceOutstanding at November 1, 2010


1,033,333


$
3.00Granted


-



-Exercised


-



-Cancelled


-



-Outstanding at April 30, 2011


1,033,333


$
3.00Exercisable at April 30, 2011


266,667


$
3.00





During the Fiscal year ended October 31, 2010, stock options were granted to certain directors, officers and consultants to the Company for options representing 1,033,333 common shares. The exercise price of the options is $3, with a five to six year term, with vesting occurring at varying rates over the first three years. The fair value of the option grants were estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 188% to 158%, risk free interest rate of 1.76% to 2.74%; and expected lives of five to ten years.









Warrants





A summary of the Company’s stock warrant activity and related information for the six months ended April 30, 2011 is as follows:





Warrants


Weighted Average Exercise PriceOutstanding at November 1, 2010


333,333


$
2.00Granted


1,600,101


$
4.50Exercised


--



--Cancelled


--



--Outstanding and Exercisable at April 30, 2011


1,933,434


$
3.54





1-For-3 Reverse Stock Split





On January 11, 2011, the Company effectuated a 1 for 3 split.  On the date of the 1 for 3 split, the Company amended its certificate of incorporation to reduce the number of authorized common shares from 300,000,000 to 100,000,000.  The effect of the split has been reflective retroactively for all periods presented.


6





6.
Derivative Instruments





The Company evaluated all of its financial instruments and determined that 333,333 warrants associated with an October 2010 exchange agreement qualified for derivative treatment under ASC 815-15 due to a full ratchet provision.  The fair value of these warrants on the date of issue ($923,756) was recorded as a derivative liability. On April 30, 2011, the warrant agreement was amended to remove the full ratchet provision. On that date, the warrant ceased to be considered a derivative liability. As a result, the derivative liability was marked-to-market through April 30, 2011 and reclassified to equity. For the six months ended April 30, 2011, we recorded a loss on derivatives of $52,725.





The fair values of the warrants were estimated using the following assumptions:





April 30, 2011


October 31, 2010Expected volatility


154
%


154
%Expected term

2.5 years



3 yearsRisk free rate


.81
%


.51
%Expected dividends


--



--Fair Value


976,481


$
923,756





7.
Private Placement





On March 1, 2011, the Company commenced a private placement offering of between 500,000 and 2,000,000 units at a price of $3 per unit.  Each unit consists of one share of common stock and a warrant to purchase one share of common stock at an exercise price of $4.50 per common share.  The warrants may be exercised for a period of three years and can be called by the Company if the closing bid price of the common stock is at least $6 per share for 10 consecutive trading days.  The Company is required to register the shares underlying the warrants within 60 days of the closing of the offering (there are no monetary damages for non-compliance).  In addition, the shares included in the units, if not previously registered, are to be included in such future registration statements, subject to SEC limitations.  Through April 30, 2011, the Company sold 453,667 units for gross proceeds totaling $1,361,001 ($1,338,500 in net proceeds including costs of $22,501).  During May 2011, an additional 215,667 units were sold for proceeds totaling $647,000.  In addition, $1,694,000 of the Bridge Loans was converted into 564,667 units (Note 3). The Company evaluated the warrants and concluded they were not derivatives.










7


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





CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS





This Management's Discussion and Analysis of Financial Condition and Results of Operations includes a number of forward-looking statements that reflect Management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as “may” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words.  Those statements include statements regarding the intent, belief or current expectations of us and members of its management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-looking statements.





Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission.  Important  factors  currently  known  to us could  cause  actual  results  to differ  materially  from  those in forward-looking  statements.  We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that its assumptions are based upon reasonable data derived from and known about our business and operations and the business and operations of the Company.  No assurances are made that actual results of operations or the results of our future activities will not differ materially from its assumptions.  Factors that could cause differences include, but are not limited to, expected market demand for the Company’s services, fluctuations in pricing for materials, and competition.





Overview





We currently focus our oil and natural gas exploration, exploitation and development operations on projects located in Colorado, New Mexico and Texas. The higher potential impact projects (“Core Focus Areas”) are concentrated on (i) Spraberry, Wolfberry, Strawn and Mississippian formations in the Midland Basin in W. Texas, (ii) conventional reef structures in the Pedregosa Basin in S.W. New Mexico and (iii) conventional structure and stratigraphic formations and unconventional resource formations in Southern Colorado.  In addition to the Core Focus Areas, our management team is pursuing producing conventional and unconventional properties which we anticipate will provide the company with immediate cash flow and additional upside through recompletion potential and new drilling opportunities.





As of April 30, 2011, we owned interests in (i) approximately 9,260 gross (4,900 net) acres in the Midland Basin, (ii) approximately 147,262 gross (73,631 net) acres in the Pedregosa Basin and (iii) approximately 3,300 gross (1,650 net) acres in Colorado.  Approximately, 125,115 gross acres (2,720 gross acres in Midland Basin, 118,607 gross acres in the Pedregosa Basin, and approximately 3,788 gross acres in the Non-Core Properties) are held by production or by continuous drilling operations.





We began oil and gas operations in the United States on November 1, 2009, with the purchase of a producing conventional oil and gas field, located in the Gulf Coast region of Texas, from Pioneer Natural Resources.  Additionally, we acquired interests in one property located in the Gulf Coast region of Texas and one Core Focus Area property located in West Texas.





During the quarter ended April 30, 2011, we (i) acquired one operated, producing property in the Gulf Coast, (ii) drilled, set casing, perforated and fracture stimulated the Everett Well No. 3 which is currently producing, (iii) surveyed and acquired 37 linear miles of 2-D seismic data on the southern part of the Pedregosa Basin project, and (iv) drilled plugged and abandoned a well in the northern part of the Pedregosa Project.  In addition, we acquired additional term leasehold in our Core Focus Areas.





The Core Focus Areas provide us with the opportunity to grow reserves and cash flow by drilling and developing the properties.   Our other properties currently provide cash flow for overhead and administrative costs, while we develop our Core Focus Areas.





We continue to pursue avenues to reduce or eliminate our financial exposure on a case by case basis for each project.  Joint venture arrangements may be considered for others to participate for a disproportionate share of the initial leasing and/or drilling costs, further reducing our exposure.




8





2011 Projects, subject to raising the capital requirements:





Subject to obtaining additional financing, the following drilling, recompletion/work-over and leasing activity may be pursued.  The projects and our share of the estimated costs are listed below:





Estimated cost based on expected participating working interest.





Project

Current WI%


No. Wells

Procedure

Est. CostMidland Basin


62.5-85
%


3

New Drill

$
3.25 MMPedregosa Basin


50
%


1

New Drill

$
1.8 MMColorado


50
%


1

New Drill

$
0.9 MMOther producing properties


100
%


3

Recompletions

$
0.4 MMOther producing properties


30
%


1

New Drill

$
0.5 MMAll Properties

various





New Leases

$
2.4 MMTotal










$
9.25 MM








While our base case drilling, recompletion/workover and leasing activity would result in estimated costs of $9.25 MM, we may expand drilling, recompletion/workover and leasing activity to as much as $22 MM, if project economics and general economic conditions support the more aggressive drilling program. If we elect to expand drilling activities, we will need to access additional capital. During the current fiscal year to date, we obtained bridge loan financing totaling $1.745 million and raised an additional $2,008,000 in connection with a private placement offering.





We have not entered into any commodity derivative arrangements or hedging transactions. We may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. We have no off-balance sheet arrangements.





We have sold equity and used joint venture agreements with other industry companies to limit or eliminate our financial exposure in early drilling.





Results of operations





Consolidated Results of Operations for the Three Months Ended April 30, 2011 Compared to the Three Months Ended April 30, 2010:





Revenues for the three months ended April 30, 2011 totaled $498,577 as compared to revenues of $425,409 for the three months ended April 30, 2010.  The increase in revenues is directly related to the production from wells acquired after April 30, 2010.  In addition, we acquired additional leases on several additional operating wells in November 2010.





Selling, general and administrative expenses increased $549,432, to $694,019 in the three months ended April 30, 2011 as compared to $144,587 for the three months ended April 30, 2010.  Included in selling general and administrative expenses during the three months ended April 30, 2011 was $263,495 in stock based compensation related to stock options granted to officers and directors during 2010 that vested during the period.  In addition, we hired several consultants later in 2010 to assist with operating the company.   The cost of these consultants during the three months ended April 30, 2011 was approximately $175,000 as compared to approximately $25,000 in the three months ended April 30, 2010.





Depreciation, depletion and accretion totaled $139,545 during the three months ended April 30, 2011 compared to $50,523 for the three months ended April 30, 2010.  In addition, we incurred lease operating expenses totaling $162,302 during the three months ended April 30, 2011 as compared to $128,998 for the three months ended April 30, 2010.   We expect lease operating expenses to remain significant as many of our properties have older wells and will incur repairs and other age related costs.





Exploration costs totaled $435 and $75,339 in the three months ended April 30, 2011 and 2010, respectively   The exploration expenses during the three months ended April 30, 2010 included costs associated with maintaining our interest in the A10 Project.  There were no costs subsequent to April 30, 2010 for this project as a result of our disposing of our interest in Access.





We earned total interest income of $59,012 during the three months ended April 30, 2010.The interest during the period was earned from the investment of proceeds of a private placement of our common stock and common stock purchase warrants on August 9, 2006, which remained in interest bearing instruments until needed, and which balance has been used toward the purchase of Access and with ongoing operations.   There was no interest earned during the three months ended April 30, 2011.





We incurred interest expense totaling $1,802,874 during the three months ended April 30, 2011.  The interest was incurred on promissory notes totaling $1,560,000 and bridge notes totaling $1,745,300 as well as on the discount and beneficial conversion features on the bridge notes. In March 2011, $1,694,000 of the bridge notes were converted into common stock and the remaining $51,300 was repaid.  There were no interest expenses during the three months ended April 30, 2010.





During the three months ended April 30, 2010, we reported a gain of $2,715,130 on the sale of our 55.2% interest in Access Energy, and being relieved of our liability for funding the Access operations.




9





As a result of the above, we incurred a net loss for the three months ended April 30, 2011 of $2,341,627, compared to net income of $2,636,894 for comparable period.





Consolidated Results of Operations for the Six Months Ended April 30, 2011 Compared to the Six Months Ended April 30, 2010:





Revenues for the six months ended April 30, 2011 totaled $892,763 as compared to revenues of $494,092 for the six months ended April 30, 2010.  The increase in revenues is directly related to the production from wells acquired after April 30, 2010.  In addition, we acquired additional leases on several additional operating wells in November 2010.





Selling, general and administrative expenses increased $994,772, to $1,330,829 in the six months ended April 30, 2011 as compared to $336,057 for the six months ended April 30, 2010.  Included in selling general and administrative expenses during the six months ended April 30, 2011 was $558,298 in stock based compensation related to stock options granted to officers and directors during 2010 that vested during the six month period. In addition, we hired several consultants later in 2010 to assist with operating the company.The cost of these consultants totaled approximately $350,000 in the six months ended April 30, 2011 as compared to approximately $50,000 in the six months ended April 30, 2010.




Depreciation, depletion and accretion totaled $369,642 during the six months ended April 30, 2011 compared to $81,608 for the six months ended April 30, 2010.  The increase is primarily related to depletion in the amount of $339,107, relating to an increase in the number of producing wells and properties. In addition, we incurred lease operating expenses totaling $352,236 during the six months ended April 30, 2011 as compared to $204,856 in the comparable period.   We expect lease operating expenses to remain significant as many of our properties have older wells and will incur repairs and other age related costs.





Exploration costs totaled $106,394 and $146,571 in the six months ended April 30, 2011 and 2010, respectively. We incurred exploration expenses in the current fiscal year related to the seismic work done on our property in the Pedregosa Basin.   The exploration expenses during the six months ended April 30, 2010 included costs associated with maintaining our interest in the A10 Project.





We earned total interest income of $113,309 during the six months ended April 30, 2010. The interest during the period was earned from the investment of proceeds of a private placement of our common stock and common stock purchase warrants on August 9, 2006, which remained in interest bearing instruments until needed, and which balance has been used toward the purchase of Access and with ongoing operations.   There was no interest income during the six months ended April 30, 2011.





We incurred interest expense totaling $1,833,471 during the six ended April 30, 2011.  The interest was incurred on promissory notes totaling $1,560,000 and bridge notes totaling $1,745,300 as well as the discount and beneficial conversion feature on the bridge notes.   In March 2011, $1,694,000 of the bridge notes were converted into common stock and the remaining $51,300 was repaid.  There was no interest expense in the six months ended April 30, 2010.





During the six months ended April 30, 2010, we reported a gain of $2,715,130 on the sale of our 55.2% interest in Access Energy, and being relieved of our liability for funding the Access operations.





As a result of the above, we incurred a net loss for the six months ended April 30, 2011 of $3,148,402, compared to net income of $2,374,890 for comparable period.





Liquidity and Capital Resources





As of April 30, 2011, we had cash and cash equivalents on hand of $544,993.  In addition, we raised an additional $647,000 in May 2011. These funds are being used primarily in the drilling of a test well in the Pedregosa Basin and completion of a well in the AP Clark Field.  We have a working capital deficiency totaling $1,120,469 on April 30, 2011 compared to working capital of $179,448 at October 31, 2010.  We do not have sufficient funds on hand in order to repay the notes payable due in the next twelve months, fund any capital expenditures for the drilling of new wells or the recompletion of existing wells and expect to need additional funds for general and administrative expenses.  We expect to rely on external sources of capital in order to fund our capital expenditures.  We do not have any firm commitments to raise additional capital nor is there any assurance sufficient capital will be available at acceptable terms, if at all.





On February 2, 2011, we entered into a securities purchase agreement (the “Purchase Agreement”) with six accredited investors (the “Investors”), providing for the sale of an aggregate of (i) 8% debentures in the principal amount of $1,745,300 (the “Debentures”) and (ii) warrants to purchase 581,767 shares of our common stock (the “Bridge Warrants”).





The Debentures mature on the earlier of the (i) date we close an offering that results in gross proceeds to us of at least $1,000,000 or (ii) first anniversary of the date of issuance (the “Maturity Date”) and bear interest at the annual rate of 8%.  We are not required to make any payments until the Maturity Date.  The Bridge Warrants are exercisable for a period of three years from the date of issuance and are exercisable into shares of our common stock at an exercise price of $4.50 per share, which may be exercised on a cashless basis six months after issuance if there is not an effective registration statement for the resale of the shares issuable upon exercise of the Bridge Warrants.




10





On March 17, 2011, the Debentures came due as a result of obtaining at least $1,000,000 in gross proceeds from the private placement (see below).   On that date, $1,694,000 of the Debentures were converted into (i) 564,667 shares of our common stock and (ii) warrants to purchase 564,667 shares of our common stock at an exercise price of $4.50 per share.  The remaining $51,300 in Debentures was repaid.  The Bridge Warrants were not affected by the conversion or repayment.





Between March and May 2011, we sold to certain investors units (“Units”) for aggregate cash gross proceeds of $2,008,001 at a price of $3.00 per Unit and the exchange of $1,694,000 in previously issued debentures that were converted into Units at a price of $3.00 per Unit (the “Financing”). Each Unit consisted of (i) one (1) share of common stock (“Common Stock”) and (ii) a warrant (“Warrant”) to purchase one (1) share of Common Stock at an exercise price of $4.50.





Pursuant to the Warrants, no holder may exercise such holder’s Warrant if such exercise would result in the holder beneficially owning in excess of 4.99% of our then issued and outstanding common stock. A holder may, however, increase or decrease this limitation (but in no event exceed 9.99% of the number of shares of Common Stock issued and outstanding) by providing us with 61 days’ notice that such holder wishes to increase or decrease this limitation.





We entered into a registration rights agreement with the investors, under which we agreed to prepare and file with the SEC and maintain the effectiveness of a “resale” registration statement providing for the resale of (i) all of the shares of Common Stock (ii) all of the shares of Common Stock issuable upon exercise of the Warrants, and (iii) any securities issued or issuable upon any stock split, dividend or other distribution, recapitalization or similar event with respect to the foregoing.





Under the terms of the registration rights agreement, we are required to have a registration statement filed with the SEC within 90 days after the final closing date of the Financing, and declared effective by the SEC not later than 120 days from the closing date (or 180 days in the event of a full review by the SEC).





A summary of our stock option activity and related information is as follows:





Number of Shares


Weighted Average Exercise PriceOutstanding at November 1, 2010


1,033,333


$
3.00Granted


-



-Exercised


-



-Cancelled


-



-Outstanding at April 30, 2011


1,033,333


$
3.00Exercisable at April 30, 2011


316,667


$
3.00





During the fiscal year ended October 31, 2010, stock options were granted to certain directors, officers and consultants for options representing 1,033,333 common shares. The exercise price of the options is $3.00, with a five to six year term, with vesting occurring at varying rates over the first three years. The fair value of the option grants were estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 188% to 158%, risk free interest rate of 1.76% to 2.74%; and expected lives of five to ten years.





During the six months ended April 30, 2011 and 2010, we recorded stock-based compensation of $558,298 and $0, respectively, as general and administrative expense.  The unamortized amount of stock-based compensation as April 30, 2011 was $969,763.





A summary of our stock warrant activity and related information for the six months ended April 30, 2011 is as follows:





Warrants


Weighted Average Exercise PriceOutstanding at November 1, 2010


1,000,000


$
2.00Granted


1,600,101


$
4.50Exercised


--



--Cancelled


--



--Outstanding and Exercisable at April 30, 2011


2,600,101


$
3.54





11





Net Cash Used In Operating Activities





Cash used in operating activities in the six months ended April 30, 2011 was $1,002,382, compared to $191,265 used for the comparative period.  The increase in the cash used in operating activities was from the net loss for the period, increased accounts receivable for the increased production, an additional deposit with the Texas Railroad Commission for the operation by NRG Management of the new wells acquired in Copano Bay and from the payment of accounts payable, primarily from amounts remaining on the acquisition of our interest in the Pedregosa Basin.





Cash Flows Used In Investing Activities





Net cash used in investing activities for the six months ended April 30, 2011 was $4,568,804 compared to $1,464,887 used for the comparative period. The cash flows from investing activities for the periods presented relate to costs incurred in the acquisition of oil and gas properties.  During the current period we acquired the Copano Bay property and commenced drilling on the W.D. Everett Well No. 3.





Cash Flows from Financing Activities





Cash provided by financing activities for the three months ended April 30, 2011 was $4,506,218, from the proceeds of a Note Payable financing and the net proceeds from the sale private placement units totaling $1,338,500.





Off-Balance Sheet Arrangements





We have no off-balance sheet arrangements.





Contractual Obligations





Total


2011


2012


2013


2014


2015


ThereafterNotes Payable

$
1,560,000


$
1,560,000


$
--


$
--


$
--


$
--


$
--Abandonment obligations


742,353



--



18,099



17,369



--



--



706,885Operating lease obligations


--



--



--



--



--



--



--Other


--



--



--



--



--



--



--Total

$
2,302,353


$
1,560,000


$
18,099


$
17,369


$
--


$
--


$
706,885





Critical Accounting Policies





Oil and Gas Accounting





Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.





Property Acquisition Costs





For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.





This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization.




12





Exploratory Costs





For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the project’s development economically profitable. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.





Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.





Proved Reserves





Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.





Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineers have policies and procedures in place consistent with these authoritative guidelines.





Proved reserve estimates are adjusted annually and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.





Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. The estimation of proved developed reserves also is important to the statement of operations because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that asset.





Impairments





Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group and annually following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, commodity prices, operating costs, refining margins and capital project decisions, considering all available information at the date of review.





13





Asset Retirement Obligations





Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and plug wells at the end of operations at operational sites. The fair values of obligations for dismantling and removing these facilities are accrued at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.




Item 3.
Quantitative and Qualitative Disclosures About Market Risk.





Not required under Regulation S-K for “smaller reporting companies.”





Item 4.
Controls and Procedures.





(a) Evaluation of disclosure controls and procedures.





Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of April 30, 2011. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.





Based on our evaluation, our chief executive officer and chief financial officer concluded that, as a result of the following material weaknesses in internal control over financial reporting, our disclosure controls and procedures are not designed at a reasonable assurance level and are not effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure:





i.
We did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements.  We have limited experience in the areas of financial reporting and disclosure controls and procedures.  Also, we do not have an independent audit committee.  As a result, there is a lack of monitoring of the financial reporting process and there is a reasonable possibility that material misstatements of the consolidated financial statements, including disclosures, will not be prevented or detected on a timely basis.





(b) Changes in internal control over financial reporting.





There were no changes in our internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.





Management’s Remediation Plans





We are committed to improving our financial organization. As part of this commitment, we will look to increase our personnel resources and technical accounting expertise within the accounting function by the end of 2011 to resolve non-routine or complex accounting matters. In addition, when funds are available, which we expect to occur by the latter half of 2011, we will take the following action to enhance our internal controls: Hiring additional knowledgeable personnel with technical accounting expertise to further support our current accounting personnel, which management estimates will cost approximately $100,000 per annum. We currently engage an outside accounting firm to assist us in the preparation of our consolidated financial statements. As necessary, we will engage consultants in the future as necessary in order to ensure proper accounting for our consolidated financial statements.





Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the following material weakness: insufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements.  Management believes that the hiring of additional personnel who have the technical expertise and knowledge with the non-routine or technical issues we have encountered in the past will result in both proper recording of these transactions and a much more knowledgeable finance department as a whole. We believe this will greatly decrease any control and procedure issues we may encounter in the future.




14




PART II: OTHER INFORMATION





Item 1.
Legal Proceedings.





We are currently not a party to any material legal proceedings or claims.





Item 1A.
Risk Factors.





Not required under Regulation S-K for “smaller reporting companies.”





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





None.





Item 3.
Defaults Upon Senior Securities





None.




Item 4.
Reserved






Item 5.
Other Information.


(a)
Form 8-K Information





None.





(b)
Director Nomination Procedures





We do not have a standing nominating committee nor are we required to have one.  We do not have any established procedures by which security holders may recommend nominees to our Board of Directors, however, any suggestions on directors, and discussions of board nominees in general, is handled by the entire Board of Directors.


Item 6.
Exhibits.




31.01

Certification of Principal Executive Officer pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended31.02

Certification of Principal Financial Officer pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended32.01

Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.




15





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.





BLACKSANDS PETROLEUM, INC.Date:  June 14, 2011
By:
/s/ David DeMarcoName:  David DeMarcoTitle:    Chief Executive OfficerDate:  June 14, 2011
By:
/s/ Donald GiannattasioName:  Donald GiannattasioTitle:    Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)