Edgar Filing: BLACKSANDS PETROLEUM, INC.

form10q.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 July 31, 2010

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

For the transition period from ___________ to ________

Commission File Number 000-51427

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 44,854,700 shares of registrant’s common stock outstanding as of September 14, 2010.

BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

INDEX

PART I.	FINANCIAL INFORMATION
	ITEM 1.	Financial Statements
		Consolidated balance sheets at July 31, 2010 (unaudited) and October 31, 2009	3

		Consolidated statements of operations for the three and nine months ended July 31, 2010 and 2009 (unaudited)	4

		Consolidated statements of cash flows for the nine months ended July 31, 2010 and 2009 (unaudited)	5

		Notes to unaudited consolidated financial statements	6-8

	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	9-14

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	15

	ITEM 4.	Controls and Procedures	15

PART II.	OTHER INFORMATION

	ITEM 1	Legal proceedings	16
	ITEM 1A	Risk factors	16
	ITEM 2	Unregistered sales of equity securities and use of proceeds	16
	ITEM 3	Defaults upon senior securities	16
	ITEM 4	Reserved	16
	ITEM 5	Other information	16
	ITEM 6	Exhibits	16

	SIGNATURES		17

PART I: FINANCIAL INFORMATION

Item 1.Financial Statements.

Blacksands Petroleum, Inc.

Consolidated Balance Sheets

(Unaudited)

	As of			As of
	31-Jul-10			31-Oct-09
ASSETS

Current Assets
Cash and cash equivalents	$	2,477,392		$	2,797,690
Short-term investments		-			88,553
Accounts receivable		255,957			4,892
Prepaid expenses and deposits		17,824			6,672
Total Current Assets		2,751,173			2,897,807

Oil and gas property costs (successful efforts method of accounting)
Proved		1,527,180			-
Unproved		1,500,000			-
Total Assets	$	5,778,353		$	2,897,807

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Accounts payable and accrued liabilities	$	113,504		$	1,426,543
Accounts payable to related parties		68,398			43,639
Short Term Debt		3,000,000			-
Total Current Liabilities		3,181,902			1,470,182

Asset Retirement Obligation		96,428			-
Total Liabilities		3,278,330			1,470,182

Stockholders’ Equity
Preferred Stock 10,000,000 authorized and none issued and outstanding		-			-
Common stock 300,000,000 authorized
44,854,700 issued and outstanding		44,855			44,855
Additional paid-in capital		11,464,081			11,949,465
Accumulated comprehensive loss		(302,556	)		(425,557	)
Accumulated deficit		(8,706,357	)		(10,141,138	)
Total Stockholders’ Equity		2,500,023			1,427,625
Total Liabilities and Stockholders’ Equity	$	5,778,353		$	2,897,807

See accompanying notes to Consolidated Financial Statements.

Blacksands Petroleum, Inc.

Consolidated Statements of Operations

(Unaudited)

	For Nine Months Ended 31-Jul-10			For Nine Months Ended 31-Jul-09			For Three Months Ended 31-Jul-10			For Three Months Ended 31-Jul-09
Revenues:
Revenue	$	851,371		$	-		$	357,279		$	-
Total Revenues		851,371			-			357,279			-

Expenses:
Professional Fees		296,543			431,820			111,304			140,264
Management and directors’ fees		853,994			148,067			767,033			45,271
Depreciation, Depletion and Accretion		178,991			-			97,383			-
Office and administration		109,886			91,028			46,029			29,165
Lease operating expenses		350,798						145,942
Oil and gas exploration		166,607			964,754			20,036			897,861
Total Expenses		1,956,819			1,635,669			1,187,727			1,112,561
Loss from Operations		(1,105,448	)		(1,635,669	)		(830,448	)		(1,112,561	)

Other Income and Expenses:
Interest income		113,309			69,957			-			35,278
Interest expense		(13,260	)					(13,260	)
Funding on behalf of minority stockholder					(54,439	)					(4,676	)
Impairment of oil & gas		-			(3,831,190	)
property interest								-			-
Gain (loss) on sale of Access shares		2,644,008						(71,122	)
Gain (loss) from currency transactions		(203,828	)		(1,801	)		(25,279	)		(471	)
Income/(Loss) before Taxes		1,434,781			(5,453,142	)		(940,109	)		(1,082,430	)

Provision for Income Taxes:
Provisions for Income Tax		-			-			-			-
Net Income/(Loss) before minority interest		1, 434,781			(5,453,142	)		(940,109	)		(1,082,430	)

Minority interest		-			539,442			-			4,676
Net Income/(Loss) for the Period	$	1,434,781		$	(4,913,700	)	$	(940,109	)	$	(1,077,754	)

Other comprehensive (loss),
net of tax:
Foreign currency translation adjustment	$	123,001		$	230,507		$	-		$	181,571
Total Comprehensive Income/(Loss)	$	1,557,782		$	(4,683,193	)	$	(940,109	)	$	(896,183	)

Income (Loss) Per Common
Basic	$	0.03		$	(0.11	)	$	(0.02	)	$	(0.02	)
Diluted	$	0.03		$	(0.11	)	$	( 0.02	)	$	(0.02	)

Weighted Average Number of Common Shares Outstanding
Basic	44,854,700	44,854,700	44,854,700	44,854,700
Diluted	45,354,700	44,854,700	44,854,700	44,854,700

See accompanying notes to Consolidated Financial Statements.

Blacksands Petroleum, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine months ended			Nine months ended
	July 31, 2010			July 31, 2009
Cash Flows from Operating Activities:
Net Income (Loss)	$	1,434,781		$	(4,913,700	)

Write-down of minority interest		-			(539,442	)
Gain on sale of Access shares		(2,644,008	)		-
Depreciation, Depletion and Accretion		178,991			-
Stock based compensation		634,879			-
Impairment of oil & gas property		-			3,831,190
Changes in operating assets and liabilities:
Accounts receivable		(251,065	)		101,955
Prepaid expenses and deposits		(7,142	)		(8,683	)
Accounts payable and accrued liabilities		284,113			848,179
Related Party payable		24,759			(68,348	)
Net Cash Provided (Used) in Operating Activities		(344,692	)		(748,849	)
Cash Flows from Investing Activities:
Purchase of subsidiary, net of cash acquired		-			-
Oil and gas property costs during period		(2,612,160	)		(2,038	)
Payment on sale of Access shares		(75,000	)		-
Investment in short-term investments		88,553			(89,298	)
Net Cash Used in Investing Activities		(2,598,607	)		(91,336	)
Cash Flows from Financing Activities:
Short Term Debt		2,500,000			-
Net Cash Provided by Financing Activities		2,500,000			-
Effects of exchange on cash		123,001			271,838
Net (Decrease) Increase in Cash and Cash Equivalents		(320,298	)		(568,347	)
Cash and Cash Equivalents Balance, Beginning of Period		2,797,690			2,610,232
Cash and Cash Equivalents Balance, End of Period	$	2,477,392		$	2,041,885
Supplemental Disclosures:
Cash Paid for interest	$	-		$	-
Cash Paid for income taxes	$	-		$	-
Non-cash financing activities:
ARO incurred in acquisition and revision of estimate		96,426			-
Purchase of Oil and Gas properties with Note Payable	$	500,000			-

See accompanying notes to Consolidated Financial Statements

Blacksands Petroleum, Inc.

Notes to Consolidated Financial Statements

Unaudited

1.	DESCRIPTION OF BUSINESS, AND SIGNIFICANT ACCOUNTING POLICIES

Blacksands Petroleum, Inc. is a public company (OTCBB:BSPE) engaged in the acquisition, exploration and development of conventional and unconventional oil and gas fields in North America.

Blacksands Petroleum, Inc. (hereinafter referred to as the “Company”) was incorporated in Nevada. The Company owns 19.88% of the issued and outstanding shares of Access Energy Inc. (“Access” or “Access Energy”), and 100% of Blacksands Petroleum Texas LLC (“BSPE Texas”). Access is a private company, formed under the laws of Ontario, Canada on August 26, 2005, and BSPE Texas was formed under the laws of Texas on November 9, 2009.

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, 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, 2009 filed with the SEC on January 28, 2010. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited financial statements as reported in the 2009 annual report on Form 10-K have been omitted.

New Accounting Pronouncements Adopted

In June and December 2009, the FASB amended the accounting guidance for transfers of financial assets. This amendment requires greater transparency and additional disclosures for transfers of financial assets and the entity’s continuing involvement with them and changes the requirements for de-recognizing financial assets. In addition, this amendment eliminates the concept of a qualifying special-purpose entity. The amendment must be applied as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. Earlier application is prohibited. The Company is currently assessing the impact that this amendment may have on its consolidated financial statements.

In June 2009, the FASB amended the accounting guidance for the consolidation of variable interest entities. This amendment revised the evaluation criteria to identify the primary beneficiary of a variable interest entity. Additionally, this amendment requires ongoing reassessments of whether an enterprise is the primary beneficiary of the variable interest entity. In December 2009, the FASB amended consolidation guidance previously issued in June to eliminate the quantitative approach previously required for determining the primary beneficiary of a variable interest entity, among other changes. The amendments are effective for the Company’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. The Company is currently assessing the impact that this amendment may have on its consolidated financial statements.

Management has determined that there are no other new accounting pronouncements, other than those described herein or in the Company’s Form 10-K at October 31, 2009, that will impact the Company.

2.	OIL AND GAS PROPERTY

ACQUISITION

Beech Creek Oil Wells (known as “Beech Creek Field”) Acquisition in April 2010

On April 5, 2010, the Company purchased different leasehold working interests in the Beech Creek Wells No. 1 and No A-2 located in Hardin County, Texas for $740,798 in cash. These property interests were previously owned by a group of five different working interest owners. A 30.0587% working interest (21.942851% net revenue interest) was acquired in the Beech Creek #1 well. A 24.4337% (18.3253% Net Revenue Interest) working interest was acquired in the Beech Creek A-2 well. The Company does not operate these wells. Total revenues and lease operating expenses associated with these properties during the nine months ended July 31, 2010 were $103,098 and $9,575, respectively.

The preliminary purchase price allocation:

Total purchase price	$	740,798

Oil and gas properties		753,009
Asset retirement obligation		(12,211	)
Total purchase price	$	740,798

J.E. Pettus Gas Unit (known as “Cabeza Creek Field”) Acquisition in November 2009

On November 9, 2009, the Company purchased the J.E. Pettus Gas Unit located in Goliad County, Texas for $402,569 in cash. The Company also incurred approximately $25,000 in fees associated with the acquisition, which were expensed when incurred. These properties were previously owned by Pioneer Natural Resources USA, Inc. The Gas Unit includes four (4) active gas wells, (1) active oil well and 22 non-producing wells located on 3,689 acres in Goliad County, Texas. The leasehold working interest acquired by BSPE is 100% leasehold working interest (80% net revenue interest) from the surface to 8,500 feet below the surface and 10.67% leasehold working interest (8.536% net revenue interest) below 8,500 feet. NRG Assets management LLC, a Texas LLC and Texas registered operating company owned by the Company is the operator of all depths. Total revenues and lease operating expenses associated with these properties during the nine months ended July 31, 2010 were $748,273 and $341,223, respectively.

The preliminary purchase price allocation:

Total purchase price	$	402,569

Oil and gas properties		457,795
Oil inventory		22,152
Prepaid ad valorem tax		4,010
Revenue payable		(1,593	)
Asset retirement obligation		(79,795	)
Total purchase price	$	402,569

Pedregosa Basin Field Acquisition in June 2010

On June 18, 2010, BSPE Texas acquired a 50% undivided leasehold working interest (with an associated 40% net revenue interest) in and to approximately 147,262 acres of land, located in the Pedregosa Basin (SW New Mexico) from Dan A. Hughes Company (“DAH”) for an initial acquisition cost of $1.5 million (the “Exploration Agreement”) (see Note 5 Debt). Pursuant to the agreement, $1 million was paid at purchase with $500 thousand due November 1, 2010. The property has no production and was accounted for as an acquisition of unproved property. In addition, Blacksands is responsible for paying all costs associated with 37 linear miles of 2-D seismic data, which is estimated at $400,000. As a result of this acquisition, the Company recorded $1.5 million in unproved properties and a $500,000 note payable.

3. ASSET RETIREMENT OBLIGATION

The following table describes the changes in the asset retirement obligations for the nine months ended July 31, 2010.

Beginning balance at October 1, 2009	$	-
Fair value of liabilities incurred in acquisitions		92,006
Accretion expense		4,421
Ending balance at July 31, 2010	$	96,427

4. RELATED PARTY TRANSACTIONS

During the nine months ended July 31, 2010, Coniston Investment Corp. (“Coniston”) charged Access management fees of approximately $79,108 plus Goods and Services Tax (5%), which is included in the consolidated statement of operations for the services of Paul A. Parisotto as President and CEO of Access. Mr. Parisotto served as a director of the Company until April 30, 2010.

5. GAIN ON SALE OF ACCESS SHARES

On April 30, 2010, the Company sold 441 of the 600 shares it held in Access Energy to the other stockholder of Access Energy, Mr. Reg Burden. Following the transfer, Blacksands holds 19.9% of the outstanding Access shares and Mr. Burden holds 80.1%. As consideration for the transfer, the Company paid Mr. Burden $75,000 cash and the Company is relieved of its contractual obligation to fund Access’ annual plan and budget including Access’ commitments to First Nations’ communities. In addition, the Company is released of any rights and obligations related to any joint venture agreements between Access and other counterparties. In connection with the sale, Mr. Burden’s warrants to purchase additional shares of Access were cancelled. The fair value of the warrants on April 30th, 2010 was $1,120,263, which was included in the gain calculation for the sale of the Access shares. The weighted variables used in the Black-Scholes option-pricing model, include (1) 1.3% risk-free interest rate (2) 2.27 years expected term, (3) expected volatility of 176%, and (4) zero expected dividends.

Access had no assets and liabilities of $1,637,104. Because the Company continues to own 19.9% of the outstanding shares of Access, the transaction does not result in discontinued operations. As a result of this sale, the Company recorded a gain of $2,644,008, which primarily represents the release from liabilities associated with Access.

6. DEBT

On June 18, 2010, the Company entered into a bridge loan agreement (the “Bridge Loan Agreement”) with Talras Overseas S.A. as investor (“Talras”). On such date, Talras made a bridge loan to the Company in the amount of $1,000,000 (the “Bridge Loan”). Under the Bridge Loan Agreement, the principal face amount of $1,000,000 was provided in the first tranche and subsequent tranches of $500,000 or more were permitted up to $2,500,000 in the aggregate to be funded by June 30, 2010. As of July 31, 2010 the Company has borrowed the total amount under the agreement of $2,500,000. This Bridge Loan is unsecured.

The Bridge Loan bears interest at a rate of 6.0% per annum which amount shall, at the option of the Company, be payable either (i) in cash or (ii) by adding such interest to the accreted principal amount which is the outstanding principal amount including all PIK amounts (the “Accreted Principal Amount”).

The Company must pay the Accreted Principal Amount together with all interest accrued and unpaid at the earliest of (i) June 30, 2011 or (ii) the closing date of an investment or series of related investments in equity securities of the Company in an aggregate amount of at least $10 million including the Accreted Principal Amount and interest outstanding under the Bridge Loan Agreement and any other bridge loan agreements. Should an aggregate $10 million investment or series of related investments in equity securities of the Company occur prior to June 30, 2011, then all of the obligations due under this note will be converted automatically into equity shares of the Company.

The proceeds of the Bridge Loan will be used to fund acquisitions and working capital.

In addition, the Company recorded a note payable in the amount of $500,000 in connection with its acquisition of unproved property in the Pedregosa Basin (see Note 2).

7. EMPLOYEE STOCK OPTIONS

During the nine months ended July 31, 2010, the Company granted 2,900,000 options to various employees.

The options have an exercise price of $1.00 and have a weighted average remaining term of 9.8 years. The fair value of the options on the grant date was $2,316,448, which will be recognized ratably over the request service period, which is equal to the vesting period. The weighted average variables used in the Black-Scholes option-pricing model, include (1) 2.0% risk-free interest rate (2) 5.79 years expected term, (3) expected volatility of 157.7%, and (4) zero expected dividends. In connection with these grants, the Company recognized $634,879 of share-based compensation during the nine months ended July 31, 2010.

The aggregate intrinsic value of the stock options was $0 for the options that were vested at July 31, 2010 and the unamortized stock option expense was $1,681,570 at July 31, 2010.

8. SUBSEQUENT EVENTS

West Texas Acquisition in August 2010

On August 13, 2010, BSPE Texas acquired a (i) 25% working interest (18.75% of net revenue interest) in two producing wells for $325,000 and an 18.75% of leasehold working interest (14.0625% of net revenue interest) in 1,257 acres of land located in West Texas for $135,000 from an undisclosed Party (“the Party”). Pursuant to the agreement between BSPE-Texas and the Party (“Agreement”), the Party will be carried by BSPE Texas for a 2.5% of working interest (1.875% net revenue interest) until sales point (capped at $1.5M) on the first well drilled on the 1,257 acres. Additionally, the Party will receive a 3.75% working interest (2.8125% net revenue interest) back-in at 100% payout as defined in the Agreement in the first well drilled on the 1,257 acres. Therefore, on the first well drilled, BSPE-Texas will be responsible for 25% of the costs, expenses and liabilities until either (i) the cumulative total well costs reach 1.5M or (ii) the well is completed as a producer or plugged and abandoned as a dry hole. At such time, the interests of the Parties shall be (i) the Party 2.5% of working interest (1.875% of net revenue interest) and BSPE-Texas 22.5% of working interest (16.875% of net revenue interest). In the event the first well is completed as a commercial completion and the cumulative net revenue generated from production from the well equals the cumulative well costs associated with the well, than the Party will back-in for an additional 3.75% of working interest (2.8125% of net revenue interest). At payout of the first well, the Parties interests shall be the Party 6.25% of working interest (4.6875% of net revenue interest) and BSPE-Texas 18.75% of working interest (14.0625% of net revenue interest). The interest of the parties in all subsequent wells drilled on the 1,257 acres is: the Party 6.25% leasehold working interest (4.6875% net revenue interest) and BSPE-Texas 18.75% leasehold working interest (14.0625% net revenue interest).

In August, the Company granted 200,000 options to Olen Overstreet an consultant, at an exercise price of $1.00, that vest at 30% on the 1 year anniversary, 30% on the 2nd year anniversary, and 40% on the 3rd year anniversary from the grant date with a 10 year expiration period.

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

Certain statements in this report, other than purely historical information, including estimates, projections, statements relating to our business plans, objectives, and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “may,” “should,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties, which may cause actual results to differ materially from the forward-looking statements. A detailed discussion of risks and uncertainties that could cause actual results and events to differ materially from such forward-looking statements is included in our most recent annual report on Form 10-K under the heading “Risk Factors and Uncertainties” (see Part 1, Item 1 in such report), as amended as needed in this report under the heading “Risk Factors” (see Part II, Item 1A). We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events, or otherwise.

Unless the context otherwise requires, all references in this report to "Blacksands", "the Company", "we", "us" or "our" refer to both Blacksands and Access. In our consolidated financial statements, this management's discussion and analysis and elsewhere in this report, unless otherwise noted, we include 100% of the accounts of Access. For a discussion of our principles of consolidation, see Note 1 to the audited consolidated financial statements included in our annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on January 27, 2010. The following is management’s discussion and analysis of certain significant factors, which have affected our financial position and operating results during the periods included in the accompanying unaudited interim consolidated financial statements and it should be read in conjunction with our unaudited consolidated financial statements for the three month period ended July 31, 2010 as well as our audited consolidated financial statements for the year ended October 31, 2009.

Business Overview

We are an independent oil and gas exploration and production company, engaged in the exploration, development, acquisition and production of crude oil and natural gas in North America. Our current operations are currently focused primarily in four main project areas that we call (i) Beech Creek, (ii) Cabeza Creek, (iii) Pedregosa Basin and (iv) West Texas.

Beech Creek Field

On April 5, 2010, we purchased different working interests in the Beech Creek wells No. 1 and No. A-2 located in Hardin County, Texas for $740,798 in cash. These property interests were previously owned by a group of five different working interest owners. The two oil wells each included hold by production 44 acres. A 30.0587% working interest was acquired in the Beech Creek Well No. 1. A 24.4337% working interest was acquired in the Beech Creek Well No. A-2. The wells are not operated by us or any of our affiliates. Total revenues and lease operating expenses associated with these properties during the nine months ended July 31, 2010 were $103,098 and $9,575, respectively.

Cabeza Creek Field

On November 9, 2009, we purchased the J.E. Pettus Gas Unit located in Goliad County, Texas for $402,569 in cash. We also incurred approximately $25,000 in fees associated with the acquisition, which were expensed when incurred. These properties were previously owned by Pioneer Natural Resources USA, Inc. The Gas Unit includes four active gas wells, one producing oil well and 22 non-producing gas wells located on 3,689 acres in Goliad County, Texas. The interest acquired by BSPE is 100% to all right, title and interest from the surface to 8,500 feet below the surface and 10.67% below 8,500 feet. NRG Assets Management, LLC, owned by BSPE-Texas is the operator. Total revenues and lease operating expenses associated with these properties during the nine months ended July 31, 2010 were $748,273 and $341,223, respectively.

The lease operating expenses included several non-recurring costs associated with the unsuccessful attempt to recomplete the Pettus No. 4 well, and plugging and abandoning the No. 15 well as required by the Texas Railroad Commission. The No. 4 well is currently shut in and temporarily abandoned.

Blacksands purchased 6.5 squares of 3-D seismic over the Cabeza Creek Field from Western Geophysical for approximately $98,000. This seismic data is being utilized to help identify potential proven developed non-producing and proven undeveloped reserves on the property.

Pedregosa Basin Field

On June 18, 2010, BSPE Texas acquired a 50% undivided leasehold working interest (with a contributing 40% net revenue interest) in and to approximately 147,262 acres of land, located in the Pedregosa Basin (SW New Mexico) from Dan A. Hughes Company (“DAH”) for an initial acquisition cost of $1.5 million.

The Pedregosa Basin project is located in Hidalgo County, New Mexico. The basin has long been compared to the Permian Basin of West Texas, more specifically as a “sister” basin to the oil and gas producing Delaware and Midland Basins. Although structurally more complex, the Permian Basin has similar depositional systems of equivalent age to the West Texas basins as well as petroleum source units such as the Devonian Percha (Woodford equivalent) shale. Two early test wells in the late 1950’s encountered and tested gas from different reservoirs.

The project strategy is to acquire 2D seismic data over select areas to 1) delineate structural features with focus on reef carbonate rocks, 2) attempt to define sandstone depositional sequences, and 3) map the Percha shale unit. A two well drilling program is contemplated following the seismic acquisition. The first well would potentially be drilled to the north with the objective to fully test and evaluate the Percha Shale, a 350 foot thick shale unit that is the age equivalent of the Woodford shale in West Texas and Oklahoma. The second contemplated well would be proposed to test the Hueco, South Unit structure by drilling thick depositional sequences of carbonates and sandstones of early Cretaceous age rocks through deeper Paleozoics.

The Pedregosa Basin offers the combined potential of 1) conventional oil and gas plays targeting porous sandstones and carbonate reefs, carbonate sequences with potential for hydraulic fracturing and shallow gas pays already identified and 2) an unconventional shale play targeting the Percha Shale. With a conservative strategy of first acquiring six 2D seismic lines and potentially drilling two test wells, our goal is to explore the potential hydrocarbons of one of the few remaining large, under-explored lower 48 basins.

Blacksands has received bids to acquire approximately 37 linear miles of 2-D seismic. We anticipate commencing operations in the fourth quarter of 2010.

West Texas Field

Access Energy

Results of Operations for the Nine Months Ended July 31, 2010 Compared to the Nine Months Ended July 31, 2009

For the nine months ended July 31, 2010, we generated revenue of $851,371 compared to $nil revenue for the nine months ended July 31, 2009. The increase is a result of the acquisition of producing gas wells since the end of our last fiscal year.

We generated net income of $1,434,781for the nine months ended July 31, 2010 compared to a net loss of $5,453,142 for nine months ended July 31, 2009.The net income for the nine months ended July 31, 2010 is attributable to the sale of Access shares and release of related contractual obligations. The net loss for the nine months ended July 31, 2009 is attributable to exploration costs and impairment of oil and gas properties.

We incurred total operating expenses of $1,956,819 for the nine months ended July 31, 2010, as compared to total operating expenses of $1,635,669 for the nine months ended July 31, 2009. These expenses consisted of general operating expenses incurred in connection with the day-to-day operations of our business, the preparation and filing of our periodic reports, costs associated with exploration activities for our subsidiary, Access Energy Inc. and costs associated with the operation of the gas wells.

The significant operating expenses include professional fees of $296,543 for the nine months ended July 31, 2010 incurred in connection with filing of periodic reports, SEC compliance filings, legal, audit and accounting fees, and general corporate matters as compared with professional fees of $431,820 for the comparative period of July 31, 2009. The decrease is due primarily to the non-recurrence of costs associated with restating prior year reports incurred in the nine months ended July 31, 2009. The office and administration expenses of $109,886 for the nine months ended July 31, 2010 include rent, telephone and other office expenses, as compared to office and administration expenses of $91,028 for the nine months ended July 31, 2009. The management and directors’ fees of $853,994 for the nine months ended July 31, 2010 includes the directors’ fee and Coniston’s management fee, compared to management and directors’ fees of $148,067 for the comparative period in 2009. The increase is mostly due to the addition of new management and the stock options that were granted during the quarter ended July 31, 2010.

During the nine months ended July 31, 2010, we incurred lease operating and exploration expenses of $517,405 compared to exploration expenses of $964,754 for the nine months ended July 31, 2009. The decrease is due primarily to the sale of Access and corresponding non-recurrence of Access related exploration costs.

We earned total interest income of $113,309 for the nine months ended July 31, 2010, as compared to total interest income of $69,957 for the nine months ended July 31, 2009. The interest for the nine months ended July 31, 2010 and 2009 was earned from the investment of proceeds of a private placement of our common stock and common stock purchase warrants in 2006, which remained in interest bearing instruments during the above periods. The increase in interest income is a result of the use of investing in dual-currency investment products using the U.S and Canadian dollars. These investment products were discontinued around the beginning of the third quarter when we no longer had operations in Canada.

We recorded interest expense of $13,260 in the nine months ended July 31, 2010 as compared to $54,439 for the nine months ended July 31, 2009. The interest expense for the nine months ended July 31, 2010 was incurred on the new debt, whereas the same for the comparative period was a charge to us for 25% of capital advanced to Access in February 2008, and used by Access in the three months from November 1, 2008 to January 31, 2009.

We recorded a loss from foreign currency transactions of $203,828 for the nine months ended July 31, 2010. The loss is attributable primarily to the difference in exchange rates between the U.S. dollar and Canadian dollar beginning and ending in the second quarter. At the beginning of the second quarter (February 1, 2010) the exchange rate was 1.0693 and the value of the US denominated accounts was approximately $2,200,000. At the end of the second quarter (April 30, 2010) the exchange rate was 1.0048 and the value of the accounts was approximately $388,000. We recorded a loss from foreign currency transactions of $1,801 for the nine months ended July 31, 2009. That loss reflected foreign currency adjustments arising from having the majority of our cash and investments denominated in US dollars while our functional currency is the Canadian dollar.

Our total comprehensive income for the nine months ended July 31, 2010 was $1,557,782, compared to total comprehensive loss of $4,683,193 for the nine months ended July 31, 2009. We recorded a gain of $2,644,008 as result of the selling of 55.2% of Access Energy and being relieved of our liability for funding our operations.

Results of Operations for the Three Months Ended July 31, 2010 Compared to the Three Months Ended July 31, 2009

For the three month period ended July 31, 2010, we have generated revenue of $357,279. We did not generate any revenue for the three months ended July 31, 2009.The increase is a result of the acquisition of producing gas wells since the end of our last fiscal year.

We incurred a net loss of $940,109 for the three months ended July 31, 2010 compared to a net loss of $1,082,430 for three months ended July 31, 2009.The decrease of the loss is a result of the acquisition of producing gas wells as well as the sale of Access and the disposition of Access related contractual obligations.

We incurred total operating expenses of $1,187,727 for the three months ended July 31, 2010, as compared to total operating expenses of $1,112,561 for the three months ended July 31, 2009. These expenses consisted of general operating expenses incurred in connection with the day-to-day operations of our business, the preparation and filing of our periodic reports, costs associated with exploration activities for our subsidiary, Access Energy Inc. and costs associated with the operation of the gas wells. The increase is a result of the stock options granted to management during the quarter ended July 31, 2010.

The significant operating expenses include professional fees of $111,304 for the three months ended July 31, 2010 incurred in connection with filing of periodic reports, SEC compliance filings, legal, audit and accounting fees, and general corporate matters as compared with professional fees of $140,264 for the comparative period of July 31, 2009. The office and administration expenses of $46,029 for the three months ended July 31, 2010 include rent, telephone and other office expenses, as compared to office and administration expenses of $29,165 for the three months ended July 31, 2009. The management and directors’ fees of $767,032 for the three months ended July 31, 2010 includes the directors’ fees as compared to management and directors’ fees of $45,271 for the comparative period. The increase is mostly due to the addition of new management and the stock options granted to manager and directors during the quarter ended July 31, 2010.

During the three months ended July 31, 2010, we incurred lease operating and exploration expenses of $165,978 compared to exploration expenses of $897,861 for the three months ended July 31, 2009. The decrease is a result of the sale of Access and the disposition of Access related contractual obligations.

We earned total interest income of $nil for the three months ended July 31, 2010, as compared to total interest income of $35,278 for the three months ended July 31, 2009. The interest for the quarter ended July 31, 2009 was earned from the investment of proceeds of a private placement of our common stock and common stock purchase warrants in 2006, which remained in interest bearing instruments during the above periods, and which balance was depleted before the quarter ended July 31, 2010.

We recorded interest expense of $13,260 in the three months ended July 31, 2010 as compared to $4,676 for the three months ended July 31, 2009. The interest expense for the three months ended July 31, 2010 was incurred on the new debt, whereas the same for the comparative period was a charge to us for 25% of capital advanced to Access in February 2008, and used by Access in the three months from November 1, 2008 to January 31, 2009.

We recorded a loss from foreign currency transactions of $25,279 for the three months ended July 31, 2010. The loss is attributable to the difference in exchange rates between the U.S. dollar and Canadian dollar beginning and ending in the third quarter. The loss reflects foreign currency adjustments arising from having the majority of our cash and investments denominated in US dollars while our functional currency is the Canadian dollar.

Our total comprehensive loss for the three months ended July 31, 2010 was $940,109, compared to total comprehensive loss of $896,183 for the three months ended July 31, 2009. The decrease in the loss was a result of the increase in revenue and decrease in operating expenses, as discussed above.

Liquidity and Capital Resources

As of July 31, 2010, we had cash and cash equivalents on hand of $2,477,392. We believe this amount is sufficient to fund our general and administrative costs for the next twelve months. In the interim, we are closely monitoring our cash balances and are minimizing our use of cash as much as possible.

Net Cash Used In Operating Activities

Cash used in operating activities in the nine months ended July 31, 2010 was $344,692, compared to $748,849 used for the comparative period. The difference is due to significant exploration costs incurred on Access related projects for the nine months ended July 31, 2009.

Cash Flows Used In Investing Activities

Net cash used in investing activities for the nine months ended July 31, 2010 was $2,598,607 compared to net cash used in investing activities of $91,336 for the comparative period. The majority of the net cash used in investing activities for the nine months ended July 31, 2010 was for the purchase of oil and gas properties.

Cash Flows from Financing Activities

Cash provided by financing activities for the nine months ended July 31, 2010 was $2,500,000, compared to $Nil for the comparative period. On June 18, 2010, we entered into a bridge loan agreement (the “Bridge Loan Agreement”) with Talras Overseas S.A. as investor (“Talras”). On such date, Talras made a bridge loan to us in the amount of $1,000,000 (the “Bridge Loan”). Under the Bridge Loan Agreement, the principal face amount of $1,000,000 was provided in the first tranche and subsequent tranches of $500,000 or more were permitted up to $2,500,000 in the aggregate to be funded by June 30, 2010. As of July 31, 2010, we have borrowed the total amount under the agreement of $2,500,000. This Bridge Loan is unsecured.

The Bridge Loan bears interest at a rate of 6.0% per annum which amount shall, at our option, be payable either (i) in cash or (ii) by adding such interest to the accreted principal amount which is the outstanding principal amount including all PIK amounts (the “Accreted Principal Amount”).

We must pay the Accreted Principal Amount together with all interest accrued and unpaid at the earliest of (i) June 30, 2011 or (ii) the closing date of an investment or series of related investments in equity securities of the Company in an aggregate amount of at least $10 million including the Accreted Principal Amount and interest outstanding under the Bridge Loan Agreement and any other bridge loan agreements. Should we raise an aggregate $10 million investment or series of related investments in equity securities prior to June 30, 2011, then all of the obligations due under the Bridge Loan will be converted automatically into shares of our common stock.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Contractual Obligations

Other than the commitments related to the BSPE Texas oil and gas wells described elsewhere, there was no significant change in our commitments during the three month period ending July 31, 2010.

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.

New Accounting Pronouncements Adopted

In June and December 2009, the FASB amended the accounting guidance for transfers of financial assets. This amendment requires greater transparency and additional disclosures for transfers of financial assets and the entity’s continuing involvement with them and changes the requirements for derecognizing financial assets. In addition, this amendment eliminates the concept of a qualifying special-purpose entity. The amendment must be applied as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. Earlier application is prohibited. We are currently assessing the impact that this amendment may have on our consolidated financial statements.

In January 2010, the FASB issued new accounting guidance that requires new disclosures related to fair value measurements. The new guidance requires expanded disclosures related to transfers between Level 1 and 2 activities and a gross presentation for Level 3 activity. The new accounting guidance is effective for fiscal years and interim periods beginning after December 15, 2009, except for the new disclosures related to Level 3 activities, which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. The new guidance will be effective for us in the second quarter of fiscal year 2010, except for the new disclosures related to Level 3 activities, which will be effective for us in the first quarter of fiscal year 2012. We are currently assessing the impact that the guidance may have on our consolidated financial statements.

Management has determined that there are no other new accounting pronouncements, other than those described herein and in our Form 10-K for the year ended October 31, 2009, that will impact us.

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 July 31, 2010. 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.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes. 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 2010 to resolve non-routine or complex accounting matters. In addition, when funds are available, which we expect to occur by the end of 2010, 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 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.

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: September 17, 2010	By:	/s/ David DeMarco
		Name: David DeMarco
		Title: Chief Executive Officer