BLACKSANDS PETROLEUM, INC. - FORM 10-Q

Attached files

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EX-31.1 - EXHIBIT 31.1 - BLACKSANDS PETROLEUM, INC.	ex311.htm
EX-32.2 - EXHIBIT 32.2 - BLACKSANDS PETROLEUM, INC.	ex322.htm
EX-32.1 - EXHIBIT 32.1 - BLACKSANDS PETROLEUM, INC.	ex321.htm
EX-31.2 - EXHIBIT 31.2 - BLACKSANDS PETROLEUM, INC.	ex312.htm

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period ended January 31, 2011

o TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ________

Commission File Number 000-51427

BLACKSANDS PETROLEUM, INC.

(Exact name of registrant as specified in its charter)

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

25025 I-45 N., Ste. 410

The Woodlands, TX 77380

(Address of principal executive offices) (zip code)

(713) 554-4491

(Registrant’s telephone number, including area code)

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 xNo 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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

There were 14,951,567 shares of registrant’s common stock outstanding as of March 16, 2011.

BLACKSANDS PETROLEUM, INC.

FORM 10-Q

For the Quarter Ended January 31, 2011

Table of Contents

PART I FINANCIAL INFORMATION		Page
Item 1.	Financial Statements
	Consolidated Balance Sheets as of January 31, 2011 and October 31, 2010 (unaudited)		1
	Consolidated Statements of Operations and Comprehensive Loss for the three months ended January 31, 2011 and 2010 (unaudited)		2
	Consolidated Statements of Cash Flows for the three months ended January 31, 2011 and 2010 (unaudited)		3
	Condensed Notes to Consolidated Financial Statements (unaudited)		4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		7
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		12
Item 4T.	Controls and Procedures		12

Item 1.	Legal Proceedings		13
Item 1A.	Risk Factors		13
Item 2.	Unregistered Sales of Securities and Use of Proceeds		13
Item 3.	Defaults Upon Senior Securities		13
Item 4.	Submission of Matters to a Vote of Security Holders		13
Item 5.	Other Information		13
Item 6.	Exhibits		13
SIGNATURES			14

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Blacksands Petroleum, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

	January 31, 2011			October 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	592,223		$	1,609,961
Accounts receivable		384,083			210,180
Prepaid expenses and deposits		10,310			12,423
Total Current Assets		986,616			1,832,564
Oil and gas property costs (successful efforts method of accounting)
Proved		3,174,902			1,897,767
Unproved, net of accumulated depletion of $905,751 and $691,002 respectively		2,068,208			1,786,997
Fixed assets, net		1,292			--
Other assets		230,000			50,000
TOTAL ASSETS	$	6,461,018		$	5,567,328
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Notes payable	$	1,560,000		$	--
Accounts payable and accrued expenses		424,701			729,360
Derivative liability		931,320			923,756
Total Current Liabilities		2,916,021			1,653,116
Note Payable		--			60,000
Asset Retirement obligation		725,817			523,060
Total Liabilities		3,641,838			2,236,176
Stockholders’ 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 January 31, 2011 and October 31, 2010, respectively		250			250
Common stock - $0.001 par value; 100,000,000 shares authorized; 14,951,567 and 14,951,567 shares issued and outstanding at January 31, 2011 and October 31, 2010, respectively		14,952			14,952
Additional paid-in capital		14,533,493			14,238,690
Accumulated deficit		(11,729,515	)		(10,922,740	)
Total Stockholders’ Equity		2,819,180			3,331,152
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	6,461,018		$	5,567,328

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

Blacksands Petroleum, Inc. and Subsidiaries

Consolidated Statements of Operations and Comprehensive Loss

(Unaudited)

	Three Months ended January 31,
	2011			2010
Revenue:
Oil and Gas Revenue	$	394,186		$	68,683

Expenses:
Selling, general and administrative		636,810			191,470
Depreciation and depletion		216,098			29,289
Accretion expense		13,999			1,796
Lease operating expenses		189,934			75,858
Oil and gas exploration		105,959			71,232

Total expenses		1,162,800			369,645
Loss from Operations		(768,614	)		(300,962	)

Other income and expense:
Interest income		--			54,297
Interest expense		(30,597	)		--
Loss on change in derivative liability		(7,564	)		--
Loss from currency transactions		--			(15,339	)
Total Other Income (Expense)		(38,161	)		38,958

Loss before provision for income taxes		(806,775	)		(262,004	)
Provision for income taxes		--			--
Net loss		(806,775	)		(262,004	)
Preferred stock dividends		50,000			--
Net loss attributable to common stockholders	$	(856,775	)		(262,004	)

Comprehensive Loss:
Net loss	$	(806,775	)	$	(262,004	)
Other comprehensive income, net of tax
Currency translation adjustment		--			20,237
Total comprehensive loss	$	(806,775	)	$	(241,767	)

Loss Per Share attributable to common shareholders
Basic and diluted	$	(0.06	)	$	(0.02	)
Weighted Average Shares Outstanding
Basic & diluted		14,951,567			14,951,567

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

Blacksands Petroleum, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	Three months Ended January 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(806,775	)	$	(262,004	)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss on derivative liability		7,564			--
Equity compensation expense		294,804			--
Depreciation, depletion and accretion		230,097			31,085
Changes in operating assets and liabilities:
Accounts receivable		(173,903	)		(59,084	)
Prepaid expense, deposits and other assets		(177,888	)		(4,738	)
Accounts payable		(304,660	)		109,352
Accounts payable related party		--			31,176
Net cash flows used in operating activities		(930,761	)		(154,213	)

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of oil and gas properties		(1,584,336	)		(491,952	)
Acquisition of fixed assets		(2,641	)		--
Investment in short-term investments		--			88,553
Net cash flows used in investing activities		(1,586,977	)		(403,399	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable		1,500,000			—
Net cash flows provided by financing activities		1,500,000			—
Effects of exchange on cash		--			20,237
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,017,738	)		(537,375	)
CASH AND CASH EQUIVALENTS - Beginning of period		1,609,961			2,797,690
CASH AND CASH EQUIVALENTS - End of period	$	592,223		$	2,260,315

Supplemental Disclosures

Cash paid for interest	$	--	$	--
Cash paid for income taxes	$	--	$	--

Supplemental non-cash activities

Asset retirement obligation acquired in acquisition	$	188,758	$	79,795

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

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. If the cost of the casing exceeds $233,700, the Company is required to pay 70% of the excess.

The Company commenced drilling on the W.D. Everett Well No. 3 during the quarter ended January 31, 2011. The Company incurred $637,671 in costs through January 31, 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 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.

3.	Note Payable

On November 19, 2010, the Company entered into a loan agreement with Silver Bullet Property Holdings for a promissory note totaling $1,500,000. 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. The note payable is due January 11, 2012 and incurs interest at the rate of 6%.

4.	Asset Retirement Obligation

The following table summarizes the change in the asset retirement obligation for the periods ended January 31,

	2011		2000
Beginning balance at November 1	$	523,060	$	--
Liabilities settled		--		--
Liabilities incurred through acquisition of assets		188,758		--
Accretion expense		13,999		--
Ending balance at January 31	$	725,817	$	--

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.	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	Derivative Instruments

In June 2008, the FASB ratified ASC 815-15, “ Derivatives and Hedging – Embedded Derivatives” (“ASC 815-15”). ASC 815-15, specifies that a contract that would otherwise meet the definition of a derivative, but is both (a) indexed to its own stock and (b) classified in stockholders’ equity in the statement of financial position would not be considered a derivative financial instrument. ASC815-15 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, including evaluating the instrument’s contingent exercise and settlement provisions, and thus able to qualify for the ASC 815-15 scope exception. It also clarifies the impact of foreign currency denominated strike prices and market-based employee stock option valuation instruments on the evaluation.

The Company evaluated all of its financial instruments and determined that 333,333 warrants associated with an October 2010 exchange agreement qualified for treatment under ASC 815-15. The fair value of these warrants was classified on the date of their issuance in the amount of $923,756 as derivative liability. There was no change in the value of the warrants from October 29, 2010 (date of issuance) to October 31, 2010.

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

	January 31, 2011				October 31, 2010

Expected volatility			159	%			154	%
Expected term	2.75 years					3 years
Risk free rate			.96	%			.51	%
Expected dividends			--				--
Fair Value		$	931,320			$	923,756

7	Subsequent Events

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 $1,745,000 (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, bridge loans aggregating $1,694,000 were converted into approximately 564,667 units offered pursuant to the private placement described below. The remaining $51,300 in bridge loans were repaid.

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 is to consist 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. 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.

On March 17, 2011, the Company closed on the initial proceeds of $1,226,000 for 408,666 units. The Company will continue to sell units pursuant to the private placement until 2,000,000 units have been sold.

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 and unconventional shale (Percha Shale) 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 conventional properties (“Non-Core Properties”) which we anticipate will provide the company with immediate cash flow and additional upside through recompletion potential and new drilling opportunities.

As of January 31, 2011, we owned interests in (i) approximately 9,260 gross (3,200 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 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 Non-Core Property located in the Gulf Coast region of Texas and one Core Focus Area property located in West Texas.

During the quarter ended January 31, 2011, we (i) acquired one operated, producing Non-Core Property in the Gulf Coast, (ii) drilled and set casing in the Everett Well No. 3 to 9,200’ (total depth), (iii) surveyed and acquired 37 linear miles of 2-D seismic data on the southern part of the Pedregosa Basin project, and (iv) built location on the northern part of the Pedregosa Basin project for the initial vertical test well to be drill to 7,000’ (total depth) in the first calendar quarter of 2011. In addition, we acquired 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 Non-Core 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.

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. Cost
Midland Basin	18.75-70%	4	New Drill	$3.8 MM
Pedregosa Basin	50%	2	New Drill	$4.3 MM
Colorado	50%	1	New Drill	$1.8 MM
Non Core	100%	3	Recompletions	$0.4 MM
Non Core	30%	1	New Drill	$0.5 MM
All Properties	various		New Leases	$2.4 MM
Total				$13.2 MM

While our base case drilling, recompletion/workover and leasing activity would result in estimated costs of $13.2 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. Subsequent to January 31, 2011, the Company obtained bridge loan financing totaling $1.745 million. In addition, we commenced a private placement offering with which we hope to raise an additional $1.5 to $6 million.

We have not entered into any commodity derivative arrangements or hedging transactions. Although we have no current plans to do so, 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.

In order to retain a strong balance sheet, we have sold equity and used joint venture agreements with other industry companies to limit or eliminate our financial exposure in early drilling.

Consolidated Results of Operations for the Three Months Ended January 31, 2011 Compared to the Three Months Ended January 31, 2010

Revenues for the three months ended January 31, 2011 totaled $394,186 as compared to revenues of $68,683 in the comparable period. The significant increase in revenues is directly related to the production from wells acquired after January 31, 2010. In addition, we acquired additional leases on several additional operating wells in November 2010.

Selling, general and administrative expenses increased $445,340, to $636,810 in the three months ended January 31, 2011 as compared to $191,470 during the comparable period. Included in selling general and administrative expenses during the three months ended January 31, 2011 was $291,804 in stock based compensation related to stock options granted to officers and directors during 2010. In addition, we hired several consultants later in 2010 to assist with operating the company.

Depreciation, depletion and accretion totaled $230,097 during the three months ended January 31, 2011 compared to $31,085 in the comparable period. In addition, we incurred lease operating expenses totaling $189,934 during the three months ended January 31, 2011 as compared to $75,858 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 $105,959 and $71,232 in the three months ended January 31, 2011 and 2010, respectively. The exploration expenses during the comparable period included costs associated with maintaining our interest in the A10 Project. We incurred exploration expenses in the current quarter related to the seismic work done on our property in the Pedregosa Basin. We expect to commence drilling on a section of this property in during March 2011.

We earned total interest income of $54,297 during the quarter ended January 31, 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.

We incurred a net loss for the three months ended January 31, 2011 of $806,775, compared to a net loss of $262,004 for comparable period.

Liquidity and Capital Resources

As of January 31, 2011, we had cash and cash equivalents on hand of $592,223. In addition, we raised an additional $1,745,000 in February 2011. These funds are being used primarily in the drilling of a test well in the Pedregosa Basin. We do not have sufficient funds on hand in order to 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.

On March 1, 2011, we commenced a private placement offering of between 500,000 and 2,000,000 units at a price of $3 per unit. Each unit is to consist 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. 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.

On March 17, 2011, we closed on the initial proceeds of $1,226,000 or 408,666 units, pursuant to the private placement. We will continue to raise funds pursuant to the private placement memorandum until the maximum number of units have been sold. We expect to complete the private placement offering within the next 60 days.

Net Cash Used In Operating Activities

Cash used in operating activities in the three months ended January 31, 2011 was $930,761, compared to $154,213 used for the comparative period. The increase in the cash used in operating activities was from the 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 three months ended January 31, 2011 was $1,586,977 compared to $403,399 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 quarter ended January 31, 2010 we acquired the Copano Bay property. During the current quarter we also commenced drilling on the W.D. Everett Well No. 3. In the comparable quarter, we acquired the Cabeza Creek property.

Cash Flows from Financing Activities

Cash provided by financing activities for the three months ended January 31, 2011 was $1,500,000, from the proceeds of a Note Payable financing. 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.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Contractual Obligations

	Total		2011		2012		2013		2014		2015		Thereafter
Notes Payable	$	1,560,000	$	1,560,000	$	--	$	--	$	--	$	--	$	--
Abandonment obligations		725,817		--		18,099		17,369		--		--		690,349
Operating lease obligations		--		--		--		--		--		--		--
Drilling and rig obligations		1,200,000		1,200,000		--		--		--		--		-
Other		8,000		8,000		--		--		--		--		--
Total	$	3,493,817	$	2,768,000	$	18,099	$	17,369	$	--	$	--	$	690,349

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.

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.

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 January 31, 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:

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.

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 amended

31.02 -		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 amended

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

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

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: March 17,2011	By:	/s/ David DeMarco
		Name: David DeMarco
		Title: Chief Executive Officer

Date: March 17, 2011	By:	/s/ DONALD GIANNATTASIO
		Donald Giannattasio
		Chief Financial Officer (Principal Accounting Officer)

BLACKSANDS PETROLEUM, INC. - FORM 10-Q - March 17, 2011

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