10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended October 31, 2014

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.)

800 Bering, Suite 250 Houston, Texas	77057	(713) 554-4491
(Address of principal executive office)	(Zip Code)	(Registrant’s telephone number, Including area code)

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

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.001 par value

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

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

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

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 (§ 229.405 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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

The aggregate market value of the voting common equity held by non-affiliates as of April 30, 2014, based on the closing sales price of the common stock as quoted on the OTC QB was $32,927,087.10. For purposes of this computation, all officers, directors, and 5 percent beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or 5 percent beneficial owners are, in fact, affiliates of the registrant.

As of February 5, 2015, there were 18,872,832 shares of registrant’s common stock outstanding.

TABLE OF CONTENTS

		PAGE
PART I
Item 1.	Business		3
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		26
Item 2.	Properties		26
Item 3.	Legal Proceedings		29
Item 4.	Mine Safety Disclosures		29
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		30
Item 6.	Selected Financial Data		30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		37
Item 8.	Financial Statements and Supplementary Data		F-1 - F-22
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		40
Item 9A.	Controls and Procedures		40
Item 9B.	Other Information		41
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		42
Item 11.	Executive Compensation		45
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		46
Item 13.	Certain Relationships and Related Transactions, and Director Independence		48
Item 14.	Principal Accounting Fees and Services		48
PART IV
Item 15.	Exhibits, Financial Statement Schedules		49
	Signatures		52

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PART I

ITEM 1 - BUSINESS

This Annual Report on Form 10-K (including the section regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations) contains forward-looking statements regarding our business, financial condition, results of operations and prospects. Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements, but are not deemed to represent an all-inclusive means of identifying forward-looking statements as denoted in this Annual Report on Form 10-K. Additionally, statements concerning future matters are forward-looking statements.

Although forward-looking statements in this Annual Report reflect the good faith judgment of our Management, such statements can only be based on facts and factors currently known by us. Consequently, forward-looking statements are inherently subject to risks and uncertainties and actual results and outcomes may differ materially from the results and outcomes discussed in or anticipated by the forward-looking statements. Factors that could cause or contribute to such differences in results and outcomes include, without limitation, those specifically addressed under the heading “Risks Factors” below, as well as those discussed elsewhere in this Annual Report. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this Annual Report. We file reports with the Securities and Exchange Commission (“SEC”). You can read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You can obtain additional information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

We undertake no obligation to revise or update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this Annual Report. Readers are urged to carefully review and consider the various disclosures made throughout the entirety of this Annual Report, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operations and prospects.

This Annual Report on Form 10-K includes the accounts of Blacksands Petroleum, Inc. and its wholly-owned subsidiaries, collectively referred to as “we,” “us” or the “Company.”

Overview and History

We are an oil and natural gas company engaged in the exploration for, and the acquisition, development and production of, oil and natural gas reserves in the U.S. The Company pursues exploration, development and exploitation drilling, complimented with property or corporate acquisitions exhibiting synergy in lands, facilities, production and operating efficiencies. Our operations are conducted through our subsidiaries, including our wholly-owned subsidiaries, Blacksands Petroleum Texas LLC (“BSPE Texas”), NRG Assets Management LLC (“NRG Assets”) and Copano Bay Holdings, LLC (“Copano Bay”) as well as ApClark LLC (“ApClark”) and Access Energy Inc. (“Access,” and collectively, the “Subsidiaries”), of which we own 100% of the voting interests and 19.88%, respectively.

We were incorporated under the laws of the State of Nevada on October 12, 2004 as Lam Liang Corp. In June 2006, we changed our name to Blacksands Petroleum, Inc., which was in line with our new business of oil and gas exploration and development. Access was formed under the laws of Ontario, Canada on August 26, 2005, BSPE Texas was formed under the laws of Texas on November 9, 2009, NRG Assets was formed under the laws of Texas in October 29, 2009, ApClark was formed under the laws of Delaware on July 18, 2012 and Copano Bay was formed under the laws of Nevada on December 14, 2010.

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Our Competitive Strengths

We believe that we have the following business strengths that will enable us to achieve our business objectives:

· We operate one producing field in Texas;

· We have an outside operating interest in seven additional wells in Texas;

· We have in-depth experience in acquiring producing properties;

· We have third party expertise engaged to handle accounting, engineering, land and geotechnical personnel; and

· We have been actively developing a Permian basin field (our “AP Clark Field”).

Our Operations

West Texas Field (also referred to herein as “AP Clark Field,” “Jo-Mill Field,” “Midland basin,” and “Permian basin”)

On August 10, 2010, we acquired a 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”).

On November 29, 2010, the Company acquired the leasehold interests and rights in the AP Clark Field from Westerly Exploration, Inc. (“Westerly”) for $260,000. The Company paid Westerly $119,000 as an advance payment towards 70% of the actual third party costs that was required to receive an extension of certain leasehold properties included in the AP Clark Field. The Company and Westerly also agreed to drill the W.D. Everett Well No. 3 located within the AP Clark Field whereby all costs of such drilling operation were borne 30% by Westerly and 70% by the Company.

As of January 15, 2015, we owned interest in approximately 8,703 gross (5,057 net) acres in Borden Co., Texas, with an undivided interest ranging from 25% gross working interest (18.75% net revenue interest) to 85% gross working interest (63.75% net revenue interest). In 2011, we drilled, set casing, perforated and fracture stimulated two vertical wells in Borden Co., Texas, the Westerly Everett #3 and the Beaver Valley Ranch #6-1. During 2012, we drilled, set casing, perforated and fracture stimulated two vertical wells in Borden Co., Texas, the Livestock 7-1 and Livestock 18-1 wells. All four wells are currently producing and are operated by NRG Assets.

BSPE Texas participated in and NRG Assets operated the Everett #3 for a 70% gross working interest. The well was drilled to 9,140’ true vertical depth (“TVD”) tested the lower Spraberry, Wolfcamp, Strawn and Mississippian formation. The well was completed and fracture stimulated in the Mississippian and subsequently perforated and fracture stimulated in the lower Spraberry and Wolfcamp using a 4-stage fracture stimulation design. The well is currently producing five (5) barrels of oil per day and has produced 10,700 barrels of oil since March 2011.

BSPE Texas participated and NRG Assets operated the Beaver Valley Ranch 6-1 Well for a 60% gross working interest. The well was drilled to a 7,950’ TVD tested the Wolfcamp, lower Spraberry and Jo-Mill formation. The well was completed and fracture stimulated in the Wolfcamp, lower Spraberry and Jo-Mill formations using a 6-stage fracture stimulation design. The well is currently producing eleven (11) barrels of oil a day and has produced 16,800 barrels of oil since November 2011.

Our share of the costs to drill these two wells totaled $2,508,764.

BSPE Texas participated and NRG Assets operated the Livestock 7-1 Well for a 62.8% gross working interest. The well was drilled to a 8,224’ TVD tested the Cline, Wolfcamp, lower Spraberry and JO-Mill formation. The well was completed and fracture stimulated in the Wolfcamp, Dean, lower Spraberry and Jo-Mill formations using a 4-stage fracture stimulation design. The well is currently producing sixteen (16) barrels of oil a day and has produced 19,900 barrels of oil since November 2012.

BSPE Texas participated and NRG Assets operated the Livestock 18-1 Well for a 65.65% gross working interest. The well was drilled to a 8,260’ TVD tested the Cline, Wolfcamp, lower Spraberry and JO-Mill formation. The well was completed and fracture stimulated in the Cline, Wolfcamp, Dean, lower Spraberry and Jo-Mill formations using a 5-stage fracture stimulation design. The well is currently producing five (5) barrels of oil a day and has produced 8,400 barrels of oil since October 2012. Our share of the costs to drill these two wells totaled $2,499,234.

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During the fiscal year 2014, the Company participated in the drilling of three wells, the Livestock 7-2, Livestock 18-2 and the BVR 5-1 for a total cost of $1,015,980, $1,024,117 and $1,009,284, respectively. The Company owned 100% of the working interest in the wells during the drilling operations. The Company reported an impairment of $2,219,813 of these costs during the quarter ended January 31, 2014. Subsequent to the drilling of these wells, the Company transferred approximately 59% in working interests to third parties and recorded a gain of $1,639,394. The Company has a working interest in these well of 41.46%. These wells began production in June 2014.

In February 2014, the Company amended its development agreement with Adwar Drilling Fund II, LP. (“Adwar II”). Pursuant to the amendment, Adwar II agreed to purchase up to a 37.5% working interest in the three wells drilled in November 2013 in the AP Clark Field, and up to a 18.75% working interest in a well to be drilled in the future. In February 2014, Adwar II delivered $300,000 toward the purchase of a working interest in the three wells, along with $30,000 of upfront monies.

On March 17, 2014, ApClark entered into a Partial Assignment of Oil, Gas and Mineral Leases and Bill of Sale of Wells (“PIE Assignment I”) with PIE Holdings, LP (“PIE Holdings”) whereby ApClark sold working interests in wells and related oil, gas and mineral leasehold interests as follows:

Well	Assigned Leasehold Interest(%)		Assigned Net Revenue Interest(%)
Beaver Valley Ranch Well No. 5-1		25.00		18.75
Livestock Well No. 7-2		13.60		10.20
Livestock Well No. 18-2		16.45		12.3375

Pursuant to PIE Assignment I, PIE Holdings paid ApClark a purchase price of $10.00 and assumed obligations of $560,805.91, which related to expense obligations incurred in relation to the wells and related interests. In conjunction with PIE Assignment I, ApClark and PIE Holdings amended an Operating Agreement dated August 1, 2007, by and between Westerly, and Lucas Energy, Inc., as previously amended (the “Operating Agreement”) to which ApClark and PIE Holdings are successors in interest. The amended Operating Agreement provided that PIE Operating, LLC replace the operator of record, NRG Assets, with respect to certain wells and related leases.

ApClark and PIE Holdings entered into an additional Partial Assignment of Oil, Gas and Mineral Leases and Bill of Sale of Wells (“PIE Assignment II”) on March 28, 2014, pursuant to which ApClark sold additional working interests in wells and related oil, gas and mineral leasehold interests as follows:

Well	Assigned Leasehold Interest (%)		Assigned Net Revenue Interest(%)
Beaver Valley Ranch Well No. 5-1		25.00		18.75
Livestock Well No. 7-2		25.00		18.75
Livestock Well No. 18-2		25.00		18.75

Pursuant to PIE Assignment II, PIE Holdings paid ApClark a purchase price of $10.00 and assumed obligations equal to $755,302.05, which related to expense obligations incurred in relation to the wells and related interests.

On March 31, 2014, ApClark and PIE Holdings further amended the Operating Agreement to reflect the current working interests and associated net revenue interests in wells and leasehold interests covered by the Operating Agreement. As a result of PIE Assignment I and II, ApClark and PIE Holdings each hold a 50% working interest and 37.5% net revenue interest in the wells and oil, gas and mineral leasehold interests described above.

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Our ability to secure liquidity in the form of additional financing or otherwise remains crucial for the execution of our business plans and our ability to continue as a going concern. Our current cash balance, together with cash anticipated to be provided by operations, will not be sufficient to satisfy our anticipated cash requirements for normal operations, accounts payable, accrued expenses, interest expense and capital expenditures for the foreseeable future. Obligations that may exert further pressure on our liquidity situation include: (i) the obligation to repay principal and interest on approximately $3.2 million of secured notes due to Silver Bullet Property Holdings SDN BHD (“Silver Bullet”) during 2015; (ii) the obligation to repay equity interests of approximately $2.6 million, as of October 31, 2014, to KP-RAHR Ventures III, LLC (“KP Ventures”); and (iii) approximately $2.3 million of accrued expenses and $129,000 of accounts payable owed as of October 31, 2014. We may determine that it is in our best interests to seek relief through a pre-packaged, pre-negotiated or other type of filing under Chapter 11 of the U.S. Bankruptcy Code.

Our ability to develop our interests in the AP Clark Field is dependent on our ability to obtain adequate capital to fund those projects as well as our ongoing operations and existing obligations. In view of these capital requirements, our current cash resources, nondiscretionary expenses, debt and near term accounts payable and accrued expenses obligations, we intend to explore all strategic alternatives to maintain our business as a going concern, including, but not limited to, a sale of assets of our Company, or one or more other transactions that may include a comprehensive financial reorganization of our Company.

Hydraulic fracturing is the process required to stimulate oil and natural gas flow from hydrocarbon bearing formations into the well bore. As part of the fracturing process, companies typically inject water and sand or other items into rock formations to create “fractures” or conduits through which the oil and natural gas can flow into the wellbore. The selection of individual ingredients to use in the fracturing process involves complex technical decisions, including an assessment and analysis of the scientific data regarding the petrophysics and the geology of the specific formations to be fracture stimulated and an understanding and assessment of the pressures and fracturing efficiency of the various materials that may be used in the process for each specific geological formation. Decisions on whether to employ fracturing techniques, the individual ingredients to use, and how to conduct the fracturing activities are a part of the Company’s day-to-day, ordinary business operations.

Registration in Canada and Listing on the Canadian Securities Exchange

On January 19, 2015, we filed a non-offering preliminary prospectus (the “Canadian Prospectus”) with the securities regulatory authorities in British Columbia, Canada, to enable us to become a reporting issuer under applicable securities legislation in British Columbia. As no securities are being offered through the Canadian Prospectus, no proceeds will be raised and all expenses in connection with the preparation and filing of the Canadian Prospectus will be paid by the Company. The Company intends to submit an application to list its shares of common stock on the Canadian Securities Exchange (the “CSE”). Listing will be subject to the Company fulfilling all of the requirements of the CSE, including meeting all minimum listing requirements.

J.E. Pettus Gas Unit (known as “Cabeza Creek Field”)

In November 2009, we purchased, for approximately $430,000 including legal and other costs, through BSPE Texas, the J.E. Pettus Gas Unit located in Goliad County, Texas (the “Gas Unit”), previously owned by Pioneer Natural Resources USA, Inc. The Gas Unit included five active gas wells and 20 non-producing gas wells located on approximately 3,700 acres in Goliad County, Texas. The interest acquired by BSPE Texas is 100% with all rights, title and interest from the surface to 8,500 feet below the surface and 10.67% below 8,500 feet. The other interest owners with rights below 8,500 feet beneath the surface are: XTO Energy Inc. with a 35% interest, ConocoPhillips Company with a 45.67% interest, and Anadarko Petroleum Corp. with an 8.66% interest. The gas and oil production is from conventional Gulf Coast sand-stone formations.

In January 2014, we sold our interest in all the wells in the Cabeza Creek Field for all depths from the ground to 8,500 feet below the surface in exchange for $50,000 and the assumption by the buyer of all outstanding and future liabilities related to the Cabeza Creek Field. The gain realized by the Company on the sale of its Cabeza Creek Field interest was $645,323.

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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 held by production 44 acres for a total of 88 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, which are currently producing, are not operated by us or any of our affiliates and the Company’s interest is for sale.

Copano Bay

Effective November 1, 2010, we acquired a 50% working interest (37.5% net revenue interest) in certain operating oil and gas leases in and around Aransas County, Texas for $100,000. There were four active wells on the property. In connection with the acquisition, we recorded an asset retirement obligation totaling $126,040.

Effective July 1, 2012, we disposed of our interest in the property in exchange for $25,000. We reported a gain of $10,277 on the sale of this field.

Del Norte

On September 9, 2010, we acquired a 50% undivided leasehold working interest in and to approximately 3,200 acres of land located in Rio Grande County in Colorado from Dan A. Hughes Company (“Hughes”) for an initial acquisition cost of $200,000. The property has no production and was accounted for as an acquisition of unproved property. Pursuant to the agreement, we have the option to participate in the drilling of a test well. If we participate in the drilling of this test well, all costs associated with the well will be borne equally. As a result of this acquisition, we recorded $200,000 in unproved properties. In August 2012, leases covering approximately 1,240 of these acres expired. As a result, we reported an impairment charge of $77,703 for the expired leases for the year ended October 31, 2012. The Company continues to focus its resources on developing the AP Clark Field and, as such, does not currently have sufficient capital for the development of the Del Norte prospect. Accordingly, an impairment charge totaling $138,381 was recorded during the year ended October 31, 2013.

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 (73,631 net acres) of land, located in the Pedregosa Basin (SW New Mexico) from Hughes 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. In December 2010, 37 linear miles of 2-D seismic data were surveyed and acquired on the southern part of the Pedregosa Basin project. The data was processed and interpreted with final interpretations reviewed with Hughes in October 2011. The primary southern prospect, a four way structural closure, was confirmed. A drilling location for the southern prospect area was evaluated.

A two well drilling program was contemplated following the seismic acquisition. The first well was 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. 

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In May 2011, the first test well, the Hughes #1 Big Hatchet North Unit 14 State, was drilled to a depth of 5,630’ TVD in the north area of the Pedregosa Project to test the Percha Shale. Pursuant to an agreement, the Company is obligated to carry the drilling costs for a test well up to $1.2 million. Costs in excess of $1.2 million are to be split based upon the parties working interest. The Company incurred $1,665,142 in capitalized exploration costs. During the quarter ended October 31, 2011, the Company determined that there were not economically feasible hydrocarbons at the test well site and expensed the costs of the well as exploration costs. The Company determined that it owed an additional $952,320 in 2012 and $171,790 in 2013 for the drilling of this test well based on cost over runs reported to the Company by the operator of the well. This amount is reported in the statement of operations as exploration costs. The well was logged, plugged and abandoned.

Competition

The petroleum industry is highly competitive. Many of the oil and gas exploration companies with whom we compete have greater financial and technical resources than we do. Accordingly, these competitors may be able to spend greater amounts on acquisitions of properties of merit and on exploration of their properties. In addition, they may be able to afford greater geological expertise in the targeting and exploration of resource properties. This competition could result in our competitors having resource properties of greater quality and interest to prospective investors who may finance additional exploration, and to senior exploration companies that may purchase resource properties or enter into joint venture agreements with junior exploration companies. This competition could adversely impact our ability to finance property acquisitions and further exploration.

We compete with other exploration and early stage operating companies for financing from a limited number of investors prepared to make investments in junior companies exploring for conventional and unconventional oil and gas resources. The presence of competing oil and gas exploration companies, both major and independent, may impact our ability to raise additional capital in order to fund our exploration program if investors are of the view that investments in competitors are more attractive based on the merit of the properties under investigation, and the price of the investment offered to investors.

We compete with a number of larger public and private companies and smaller, independent exploration companies in our various fields, including:

· Beech Creek Field: Cico Oil & Gas Company;

· Pedregosa Basin Field: Yates Petroleum; and

· West Texas Field: Apache Corporation and Chesapeake Energy Corporation.

All of these companies have significantly more personnel and experience and greater access to capital than we do.

Governmental Regulation

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil and natural gas industry. We have developed internal procedures and policies to ensure that our operations are conducted in full and substantial environmental regulatory compliance.

Failure to comply with any laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

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We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on our operations than on other similar companies in the oil and natural gas industry. Our future expenditures to comply with environmental requirements have been estimated in the consolidated financial statements included in this prospectus, under the caption of asset retirement obligations.

Pricing and Marketing of Natural Gas

In the U.S., historically, the sale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, or the FERC. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, or the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993 and sales by producers of natural gas are uncontrolled and can be made at market prices. The natural gas industry historically has been heavily regulated and from time to time proposals are introduced by Congress and the FERC and judicial decisions are rendered that impact the conduct of business in the natural gas industry. We cannot assure you that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Pricing and Marketing of Oil

In the U.S., sales of crude oil, condensate and natural gas liquids are not regulated and are made at negotiated prices. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser.

Royalties and Incentives

The royalty regime is a significant factor in the profitability of oil, natural gas and natural gas liquids production. In the U.S., all royalties are determined by negotiations between the mineral owner and the lessee.

Environmental

United States

Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment. The recent trend in environmental legislation and regulation in the oil and natural gas industry is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, especially in wilderness areas with endangered or threatened plant or animal species; impose restrictions on construction, drilling and other exploration and production activities; regulate air emissions, wastewater and other production and waste streams from our operations; impose substantial liabilities for pollution that may result from our operations; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, compliance orders, and other enforcement actions. We are not aware of any material noncompliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements, however, given the complex regulatory requirements applicable to our operations, and the rapidly changing nature of environmental laws in our industry, we cannot predict our future exposure concerning such matters, and our future costs to achieve compliance, or remedy potential violations, could be significant. Our operations require permits and are regulated under environmental laws, and current or future noncompliance with such laws, as well as changes to existing laws or interpretations thereof, could have a significant impact on us, as well as the oil and natural gas industry in general.

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Hazardous Substances

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

Waste Handling

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency (the “EPA”) or state agencies as solid wastes. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

Water Regulation

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws and regulations impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water from our operations and may be required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil, including refined petroleum products. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills. OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.

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Air Emissions

The Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits or utilize specific emission control technologies to limit emissions. For example, in August 2012, the EPA adopted new rules that impose additional air emission control standards on well completion activities and certain production equipment, such as glycol dehydrators and storage vessels. Some of these new rules, such as a requirement for flaring of gas not sent to a gathering line, became effective in October 2012, but the most significant new rule, requiring the use of “green completions” emission control technology to reduce air emissions during well completions, became effective January 1, 2015. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and potentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

Global Warming and Climate Change

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted rules regulating greenhouse gas emissions under the Clean Air Act, including emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis. We believe that we are in compliance with all greenhouse gas emissions reporting requirements applicable to our operations.

In addition, from time to time Congress has considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emission control systems, to acquire emission allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisitions, chemical mixing, well injection, flowback and produced water, and wastewater treatment and waste disposal. The EPA was rescheduled to release its study report in late 2014 and now is expected to release the report sometime this year. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

To our knowledge, there have been no citations, suits or contamination of potable drinking water arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Employees

As of February 5, 2015, the Company has one employee, its Chief Financial Officer, and three consultants, of which one is the Company’s interim President and two special advisors that work on the oil and gas ventures. We believe our relationship with our employee is good. Our employee is not represented by labor unions and we are not a party to any collective bargaining agreement.

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ITEM 1A - RISK FACTORS

RISKS RELATED TO OUR BUSINESS AND OPERATIONS

We will need to secure additional funds and if we are unable to secure adequate funds on terms acceptable to us, we will be unable to support our business requirements, build our business or continue as a going concern.

The Company had cash and cash equivalents of $678,940 as of October 31, 2014 and $1,335,237 as of October 31, 2013. Although we currently have sufficient cash to maintain the production of the new wells, we may not have sufficient cash to engage in any further drilling or exploration activities. In addition, our cash balances are not sufficient to satisfy our anticipated cash requirements for accrued expenses and obligations regarding our indebtedness or capital expenditures for the foreseeable future.

We have incurred substantial losses since inception and our cash balance at year end is not sufficient to fully fund our business plan or to meet our other obligations regarding our indebtedness or our anticipated development activities over the next twelve months. In view of our capital requirements, current cash resources, nondiscretionary expenses, debt and near term accounts payable and accrued expenses obligations, we may explore all strategic alternatives to maintain our business as a going concern including, but not limited to, a sale of assets of our Company, or one or more other transactions that may include a comprehensive financial reorganization of our Company.

In order to continue operations and engage in development of our properties, we will be dependent on raising capital, debt or equity, from outside sources to pay for further expansion, exploration and development of our business, and to meet current obligations. Such capital may not be available to us when we need it on terms acceptable to us if at all, particularly in the current global economic conditions. The issuance of additional equity securities by us will result in a dilution to our current stockholders which could depress the trading price of our common stock. Obtaining debt financing will increase our liabilities and future cash commitments. If we are unable to obtain financing in the amounts and on terms deemed acceptable to us, we may be unable to continue our business and may be required to scale back or cease our operations. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which may adversely impact our financial condition. However, there is no assurance that we will be able to obtain sufficient funds on terms acceptable to us or at all. If adequate additional funding is not available, we may be forced to limit our activities.

If we are unable to obtain substantial additional capital, we may need to seek protection under Chapter 11 of the U.S. Bankruptcy Code, which could result in a loss of your entire investment.

We are experiencing significant liquidity constraints. If we are not able to obtain sufficient capital either from the sale of assets or external sources of investment to fund our immediate operating requirements, we may determine that it is in the Company’s best interests to seek relief through a pre-packaged, pre-negotiated or other type of filing under Chapter 11 of the U.S. Bankruptcy Code.

In the event we seek protection under Chapter 11 of the U.S. Bankruptcy Code, it may be necessary, in order to obtain the approval of our creditors and the Bankruptcy Court to a plan of reorganization for the Company, to eliminate and cancel all existing equity of the Company, including common stock, options, warrants and other securities that are linked to our equity, which will result in a loss of the entire investment of the holders of such securities, including our stockholders. Further, if we were unable to implement a plan of reorganization or if sufficient debtor-in-possession financing were not available, we could be forced to liquidate under Chapter 7 of the U.S. Bankruptcy Code, which would result in a loss of your entire investment.

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We have a history of losses, which may continue and may negatively impact our ability to achieve our business objectives.

We incurred net losses of $6,216,251 for the year ended October 31, 2014 and $8,393,974 for the year ended October 31, 2013. In addition, at October 31, 2014, we had an accumulated deficit of $34,924,061. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in early stage oil and gas exploration companies. There can be no assurance that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether production from our operating wells continues at their current rates. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.

Our independent registered public accounting firm’s report on our financial statements questions our ability to continue as a going concern.

Our independent registered public accounting firm’s report on our financial statement as of October 31, 2014 expresses doubt about our ability to continue as a going concern. Their report includes an explanatory paragraph stating that there is substantial doubt about our ability to continue as a going concern due to a working capital deficit of $1,149,885 and an accumulated deficit of $34,924,061 through October 31, 2014.

We will need to secure additional capital in the future and if we are unable to secure adequate funds on terms acceptable to us, we will be unable to support our business requirements, build our business or continue as a going concern. Accordingly, we can offer no assurance that the actions we plan to take to address these conditions will be successful. Inclusion of a “going concern qualification” in the report of our independent accountants or any future report may have a negative impact on our ability to obtain financing and may adversely impact our stock price.

We have substantial capital requirements that, if not met, may hinder our operations.

If we are successful in raising additional capital, we anticipate that we will make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and for future drilling programs. We have insufficient revenues or available cash, which currently prohibits us from undertaking or completing any drilling programs. We cannot assure you that debt or equity financing, or cash generated by operations, will be available or sufficient to meet these requirements or for other corporate purposes, or if debt or equity financing is available, that it will be on terms acceptable to us. Moreover, future activities may require us to alter our capitalization significantly. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations or prospects.

We plan to conduct exploration, exploitation and production operations, which present additional unique operating risks.

There are additional risks associated with oil and gas investment which involve production and well operations and drilling. These risks include, among others, substantial cost overruns and/or unanticipated outcomes that may result in uneconomic projects or wells. Cost overruns could materially reduce the funds available to the Company, and cost overruns are common in the oil and gas industry. Moreover, drilling expense and the risk of mechanical failure can be significantly increased in wells drilled to greater depths and where one is more likely to encounter adverse conditions such as high temperature and pressure.

We are not the operator and have limited influence over the operations of our oil and natural gas properties.

We partnered with PIE Holdings and other working interest owners for a percentage of our revenue and drilling activity pursuant to certain agreements. As a result, we cannot entirely control the pace of exploration or development, major decisions affecting the drilling of wells or the plan for development and production at non-operated properties. The operator’s influence over these matters can affect the pace at which we incur capital expenditures. Additionally, we depend on the operators at non-operated properties to provide us with reliable accounting information. We also depend on operators and joint operators to maintain the financial resources to fund their share of all abandonment and reclamation costs.

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We may not be able to control operations of the wells we acquire.

We may not be able to acquire the operations for properties that we invest in. As a result, we may have limited ability to exercise influence over the operations for these properties or their associated costs. Our dependence on another operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

· the timing and amount of capital expenditures;

· the availability of suitable drilling rigs, drilling equipment, production and transportation infrastructure and qualified operating personnel;

· the operator’s expertise and financial resources;

· approval of other participants in drilling wells; and

· selection of technology.

Our reserve estimates and projections are inherently imprecise, and actual production, revenues and expenditures may differ materially from such estimates and projections.

There are numerous uncertainties inherent in estimating quantities of reserves and their values, including many factors beyond our control. Estimates of oil and gas reserves, by necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and gas prices, future operating cost, severance and excise taxes, development costs, workover and remedial costs and the costs of plugging and abandoning wells, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped, probable, or possible reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity and value of our reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

We may not be successful in identifying or developing recoverable reserves.

Our future success depends upon our ability to acquire and develop oil and gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we can replace those reserves by exploration and development activities or acquisition of properties containing proved reserves, or both. In order to increase reserves and production, we must undertake development, exploration, drilling and recompletion programs or other replacement activities. Our current strategy includes increasing our reserve base through development, exploitation, exploration and acquisition. There can be no assurance that our planned development and exploration projects or acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells at economical values in terms of their finding and development costs. Furthermore, finding costs for additional reserves have increased during the last few years. It is possible that product prices will decline while the Company is in the middle of executing its plans and while costs of drilling remain high. There can be no assurance that we will replace reserves or replace our reserves economically.

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Our future drilling activities may not be successful.

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain, and the cost associated with these activities has risen significantly during the past year. Our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond our control, including economic conditions, mechanical problems, title problems, weather conditions, governmental requirements and shortages or delays in the delivery of equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our future results of operations and financial condition.

Our operations are subject to risks associated with drilling or producing and transporting oil and gas.

Our operations are subject to hazards and risks inherent in drilling or producing and transporting oil and gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties.

A substantial decline in oil and natural gas prices for a prolonged period of time would have a material adverse effect on the Company.

The Company’s financial position, results of operations, access to capital and the quantities of oil and natural gas that may be economically produced would be negatively impacted if oil and natural gas prices decrease significantly for an extended period of time. The ways in which such price decreases could have a material negative effect include:

· cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves and maintain or increase production;

· future undiscounted and discounted net cash flows from producing properties would decrease, possibly resulting in impairment expense that may be significant;

· certain reserves may no longer be economic to produce, leading to lower proved reserves, production and cash flow; and

· access to sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable

Should the current decline in oil prices continue it is unlikely that our future oil and natural gas operating cash flows will be sufficient to fund the capital expenditure levels necessary to maintain current production and reserve levels over the long term and our results of operations as well as the Company over-all would be adversely affected.

The lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, fracture stimulation crews, equipment, supplies, key infrastructure, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified crews rise as the number of active rigs and completion fleets in service increases. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in Texas, New Mexico or Colorado, we could be materially and adversely affected because our operations and properties are concentrated in those areas.

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Compliance with government regulations may require significant expenditures.

Our business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of oil and gas, as well as safety matters. Although we will attempt to conduct due diligence concerning standard compliance issues, there is a heightened risk that our target properties are not in compliance because of lack of funding. We may be required to make significant expenditures to comply with governmental laws and regulations that may have a material adverse effect on our financial condition and results of operations. Even if the properties are in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations are frequently changed and are subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

Environmental regulations and costs of remediation could have a material adverse effect on our operations.

Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local government authorities. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on our operations. The discharge of oil, gas or other pollutants into the air, soil, or water may give rise to significant liabilities on our part to the government and third parties, and may require us to incur substantial costs of remediation. We will be required to consider and negotiate the responsibility of the Company for prior and ongoing environmental liabilities. We may be required to post or assume bonds or other financial guarantees with the parties from whom we purchase properties or with governments to provide financial assurance that we can meet potential remediation costs. There can be no assurance that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not materially adversely affect our results of operation and financial condition or that material indemnity claims will not arise against us with respect to properties acquired by us.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

Recently, there has been significant discussion among members of Congress regarding potential legislation that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:

· the repeal of the limited percentage depletion allowance for oil and natural gas production in the United States;

· the replacement of expensing intangible drilling and development costs in the year incurred with an amortization of those costs over several years;

· the elimination of the deduction for certain domestic production activities; and

· an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

We operate in a highly competitive environment.

We operate in the highly competitive areas of oil and gas exploration, development, acquisition and production with other companies. In seeking to acquire desirable producing properties or new leases for future exploration, and in marketing our oil and gas production, we face intense competition from both major and independent oil and gas companies. Many of these competitors have financial and other resources substantially in excess of those available to us. Our inability to effectively compete in this environment could materially and adversely affect our financial condition and results of operations.

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The producing life of the Company’s wells is uncertain, and production will decline.

It is not possible to predict the life and production of any well with accuracy. The actual life could differ significantly from that anticipated. Sufficient oil or natural gas may not be produced for investors to receive a profit or even to recover their initial investments. In addition, production from the Company’s oil and natural gas wells, if any, will decline over time, and current production does not necessarily indicate any consistent level of future production. A production decline may be rapid and irregular when compared to a well’s initial production.

Our lack of diversification will increase the risk of an investment in us, as our financial condition may deteriorate if we fail to diversify.

The Company, through its Subsidiaries, currently focuses on the conventional oil and gas industry. BSPE Texas currently owns a single property and has an interest in several additional properties. ApClark currently has an interest in certain wells located in the AP Clark Field. Larger companies have the ability to manage their risk by diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate. The Company has a limited number of revenue generating properties. This revenue generating property historical revenue is derived from natural gas and oil. Therefore, the price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.

Our business may suffer if we do not attract and retain talented personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting our intended business. We presently have a small management team, which we intend to expand in conjunction with our planned operations and growth. The loss of a key individual, or our inability to attract suitably qualified staff could materially adversely impact our business.

We may not be able to establish substantial oil operations or manage our growth effectively, which may harm our profitability.

Our strategy envisions establishing and expanding our oil business. If we fail to effectively establish sufficient oil operations and thereafter manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:

· meet our capital needs;

· expand our systems effectively or efficiently or in a timely manner;

· allocate our human resources optimally;

· identify and hire qualified employees or retain valued employees; or

· incorporate effectively the components of any business that we may acquire in our effort to achieve growth.

If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.

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Relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

To develop our business, it will be necessary for us to establish business relationships, which may take the form of joint ventures with private parties and contractual arrangements with other unconventional oil companies, including those that supply equipment and other resources that we expect to use in our business. We may not be able to establish these relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

An increase in royalties payable may make our operations unprofitable.

Any development project of our resource assets will be directly affected by the royalty regime applicable. The economic benefit of future capital expenditures for the project is, in many cases, dependent on a satisfactory royalty regime. There can be no assurance that governments will not adopt a new royalty regime that will make capital expenditures uneconomic or that the royalty regime currently in place will remain unchanged.

Hydraulic fracturing, the process used for releasing oil and natural gas from shale rock, is facing increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is an important and common practice that is used to stimulate production of gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

On August 16, 2012, the EPA adopted final regulations under the Clean Air Act that, among other things, require additional emission controls for gas production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allowed operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could increase our costs of development and production.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA did not meet its scheduled release date in late 2014 for the study report, and the report is expected to be released this year. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These efforts could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms, ultimately make it more difficult or costly for us to perform hydraulic fracturing and increase our costs of compliance and doing business.

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Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, and/or state levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay or curtail the development of unconventional oil and natural gas resources from shale formations which are not commercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.

Members of management have other business interests, and they may not be able to devote a sufficient amount of time to our business operation, which may cause our business to fail.

Ms. Rosen and Mr. Giannattasio, our interim President and Chief Financial Officer, respectively, are involved with other business interests and are unable to devote all of their business time and effort to us. They presently possess adequate time to attend to our interests. In the future, our management will use their best efforts to devote sufficient time to the management of our business and affairs and, provided additional staff may be retained on acceptable terms, our management will engage additional officers and other staff should additional personnel be required. However, it is possible that our demands on management’s time could increase to such an extent that they come to exceed their available time, or that additional qualified personnel cannot be located and retained on commercially reasonable terms. This could negatively impact our business development.

Our directors are involved or affiliated with other oil and gas exploration companies, and they may have conflicts of interest with us.

Messrs. Harold Hodgson, Rick Wilson and Conrad Kerr are involved or affiliated with one or more other oil and gas resource exploration companies. As a result of their relationships, one or all of them may have or may develop a conflict of interest with us.

Competition in obtaining rights to acquire and develop conventional and unconventional oil and gas reserves and to market our production may impair our business.

The conventional and unconventional oil and gas industry is highly competitive. Other conventional and unconventional oil and gas companies may seek to acquire property leases and other properties and services we will need to operate our business in the areas in which we expect to operate. This competition became increasingly intense as the price of oil on the commodities markets rose in recent years. A number of other companies have entered or have indicated they are planning to enter the oil sands business and begin production of bitumen and synthetic crude oil or expand their existing operations, although the impact on their plans in the current global economic climate including the current reduced price of oil is not yet known. It is difficult to assess the number, level of production and ultimate timing of all of the potential new producers or where existing production levels may increase.

Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.

The oil and gas industry competes with other industries in the supply of energy, fuel and related products to consumers. A number of other ventures have announced plans to enter the conventional and unconventional oil and gas development business or expand existing operations (although the impact on their plans in the current global economic climate is uncertain). Development of new projects or expansion of existing operations could materially increase the supply of synthetic crude oil in the marketplace. Depending upon the levels of future demand, increased supplies could negatively impact the prices obtained for oil.

20

Our success depends on the ability of our management, employees and partners to interpret market and geological data correctly, and to interpret and respond to economic, market and other conditions in order to locate and adopt appropriate investment opportunities, monitor such investments, and ultimately, if required, to successfully divest such investments. Our future success also depends on our ability to identify, attract, hire, train, retain and motivate other highly skilled technical, managerial, and marketing personnel. Competition for such personnel is intense, and there can be no assurance that we will be able to successfully attract, integrate or retain sufficiently qualified personnel.

RISKS RELATED TO OUR INDUSTRY

Exploration for petroleum and gas products is inherently speculative. There can be no assurance that we will ever establish commercial discoveries.

Exploration for economic reserves of oil and gas is subject to a number of risk factors. Few properties that are explored are ultimately developed into producing oil or gas wells. Some of our properties are in the exploration stage only and are without proven reserves of oil and gas. We may not establish commercial discoveries on any of our properties.

There are numerous uncertainties inherent in estimating quantities of conventional and unconventional oil and gas resources, including many factors beyond our control, and no assurance can be given that expected levels of resources or recovery of oil and gas will be realized. In general, estimates of recoverable oil and gas resources are based upon a number of factors and assumptions made as of the date on which resource estimates are determined, such as geological and engineering estimates which have inherent uncertainties and the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain, and classifications of resources are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the recoverable unconventional oil, the classification of such resources based on risk of recovery, prepared by different engineers or by the same engineers at different times, may vary substantially.

Prices and markets for oil and gas are unpredictable and tend to fluctuate significantly, which reduce profitability, growth and the value of our business and could affect our results of operations and financial condition.

Our revenues and earnings, if any, are highly sensitive to the price of oil and gas. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include, without limitation, weather conditions, the condition of the U.S. and global economies, the actions of the Organization of Petroleum Exporting Countries, governmental regulations, political stability in the Middle East and elsewhere, war, or the threat of war, in oil producing regions, the foreign supply of oil, the price of foreign imports and the availability of alternate fuel sources. Significant changes in long-term price outlooks for crude oil and natural gas could have a material adverse effect on us.

All of these factors are beyond our control and can result in a high degree of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials between heavy and light grades of crude oil, which can impact prices for our crude oil and bitumen. Oil and natural gas prices have fluctuated widely in recent years, and we expect continued volatility and uncertainty in crude oil and natural gas prices. A prolonged period of low crude oil and natural gas prices could affect the value of our crude oil and gas properties and the level of spending on growth projects, and could result in curtailment of production on some properties. Accordingly, low crude oil prices in particular could have an adverse impact on our financial condition and liquidity and results of operations. Moreover, a decline in oil or natural gas prices, particularly a substantial or extended decline, may have a material adverse effect on our operations, financial condition, cash flows, borrowing ability, reserves, and the amount of capital that we are able to allocate for financial commitments as well as the development of oil and natural gas reserves and future growth.

21

Existing environmental regulations impose substantial operating costs, which could adversely affect our business.

Environmental regulation affects nearly all aspects of our operations. These regulatory regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in the energy industry. Unconventional oil sand extraction operations present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and municipal laws and regulations.

Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil operations. The legislation also requires that facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material.

We expect future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gases that will impose further requirements on companies operating in the energy industry. Changes in environmental regulation could have an adverse effect on us from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs, and financial results. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on us. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations.

Abandonment and reclamation costs are unknown and may be substantial.

Certain environmental regulations govern the abandonment of project properties and reclamation of lands at the end of their economic life, the costs of which may be substantial. A breach of such regulations may result in the issuance of remedial orders, the suspension of approvals, or the imposition of fines and penalties, including an order for cessation of operations at the site until satisfactory remedies are made. It is not possible to estimate with certainty abandonment and reclamation costs since they will be a function of regulatory requirements at the time.

Changes in the granting of governmental approvals could raise our costs and adversely affect our business.

Permits, leases, licenses and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of our activities or, if granted, will not be cancelled or will be renewed upon expiration. There is no assurance that such permits, leases, licenses and approvals will not contain terms and provisions which may adversely affect our exploration and development activities.

Our inability to obtain necessary facilities could hamper our operations.

Conventional and unconventional oil and gas extraction and development activities are dependent on the availability of equipment, transportation, power and technical support in the particular areas where these activities will be conducted, and our access to these facilities may be limited. To the extent that we conduct our activities in remote areas, needed facilities may not be proximate to our operations, which will increase our expenses. Demand for such limited equipment and other facilities or access restrictions may affect the availability of such equipment to us, and may delay exploration and development activities. The quality and reliability of necessary facilities may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or otherwise.

22

We are subject to technology risks in all of our conventional and unconventional oil and gas operations.

We employ commercially proven technologies in all of our conventional and unconventional oil and gas operations. Our intent is to employ these commercially proven technologies in concert but tied together in a fashion that is innovative to the resource with which we are operating. Arranging these technologies as conceptualized may result in unforeseen issues and challenges that may require engineering remediation. There is no assurance that capital and operating cost performance as anticipated from the use of these proven technologies will be realized.

Challenges to title to our properties may impact our financial condition.

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense. While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.

RISKS RELATED TO OUR COMMON STOCK

There has been a limited trading market for our common stock.

There is a limited trading market for the common stock on the OTCQB Market. The lack of an active market may impair your ability to sell your shares at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the fair market value of your shares. An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or technologies by using common stock as consideration.

You may have difficulty trading and obtaining quotations for our common stock.

The common stock may not be actively traded, and the bid and asked prices for our common stock on the OTCQB may fluctuate widely. As a result, investors may find it difficult to dispose of, or to obtain accurate quotations of the price of, our securities. This severely limits the liquidity of the common stock, and would likely reduce the market price of our common stock and hamper our ability to raise additional capital.

The market price of our common stock may, and is likely to continue to be, highly volatile and subject to wide fluctuations.

The market price of our common stock is likely to be highly volatile and could be subject to wide fluctuations in response to a number of factors that are beyond our control, including:

· dilution caused by our issuance of additional shares of common stock and other forms of equity securities, which we may make in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;

· quarterly variations in our revenues and operating expenses;

· changes in the valuation of similarly situated companies, both in our industry and in other industries;

· changes in analysts’ estimates affecting our Company, our competitors and/or our industry;

· changes in the accounting methods used in or otherwise affecting our industry;

· additions and departures of key personnel;

· announcements of technological innovations or new reserves available;

· fluctuations in interest rates and the availability of capital in the capital markets; and

· significant sales of our common stock, including sales by our investors.

23

These and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our common stock and/or our results of operations and financial condition.

We do not expect to pay dividends on our common stock in the foreseeable future.

We do not intend to declare dividends on our common stock for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. You should not rely on an investment in our Company if you require dividend income from your investment in our Company. The success of your investment will likely depend entirely upon any future appreciation of the market price of our common stock, which is uncertain and unpredictable. There is no guarantee that our common stock will appreciate in value.

Our common stock is not currently traded at high volume, and you may be unable to sell at or near ask prices or at all if you need to sell or liquidate a substantial number of shares at one time.

Our common stock is currently traded, but with very low, if any, volume, based on quotations on the OTCQB Market, meaning that the number of persons interested in purchasing our common stock at or near bid prices at any given time may be relatively small or non-existent. This situation is attributable to a number of factors, including the fact that we are a small company which is still relatively unknown to stock analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales volume, and that even if we came to the attention of such persons, they tend to be risk-averse and would be reluctant to follow an unproven company such as ours or purchase or recommend the purchase of our shares until such time as we became more seasoned and viable. As a consequence, there may be periods of several days or more when trading activity in our shares is minimal or non-existent, as compared to a seasoned issuer which has a large and steady volume of trading activity that will generally support continuous sales without an adverse effect on share price. We cannot give you any assurance that a broader or more active public trading market for our common stock will develop or be sustained, or that trading levels will be sustained.

Stockholders should be aware that, according to Commission Release No. 34-29093, the market for “penny stocks” has suffered in recent years from patterns of fraud and abuse. Such patterns include (1) control of the market for the security by one or a few broker-dealers that are often related to the promoter or issuer; (2) manipulation of prices through prearranged matching of purchases and sales and false and misleading press releases; (3) boiler room practices involving high-pressure sales tactics and unrealistic price projections by inexperienced sales persons; (4) excessive and undisclosed bid-ask differential and markups by selling broker-dealers; and (5) the wholesale dumping of the same securities by promoters and broker-dealers after prices have been manipulated to a desired level, along with the resulting inevitable collapse of those prices and with consequent investor losses. Our management is aware of the abuses that have occurred historically in the penny stock market. Although we do not expect to be in a position to dictate the behavior of the market or of broker-dealers who participate in the market, management will strive within the confines of practical limitations to prevent the described patterns from being established with respect to our securities. The occurrence of these patterns or practices could increase the future volatility of our share price.

Legislative actions, higher insurance costs and potential new accounting pronouncements may impact our future financial position and results of operations.

There have been regulatory changes, including the Sarbanes-Oxley Act of 2002, and there may potentially be new accounting pronouncements or additional regulatory rulings that will have an impact on our future financial position and results of operations. The Sarbanes-Oxley Act of 2002 and other rule changes as well as proposed legislative initiatives following the Enron bankruptcy are likely to increase general and administrative costs and expenses. In addition, insurers are likely to increase premiums as a result of high claims rates over the past several years, which we expect will increase our premiums for insurance policies. Further, there could be changes in certain accounting rules. These and other potential changes could materially increase the expenses we report under generally accepted accounting principles, and adversely affect our operating results.

24

Efforts to comply with recently enacted changes in securities laws and regulations will increase our costs and require additional management resources.

As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the SEC adopted rules requiring public companies to include a report of management on their internal controls over financial reporting in their annual reports on Form 10-K. In addition, in the event we are no longer a smaller reporting company, the independent registered public accounting firm auditing our financial statements would be required to attest to the effectiveness of our internal controls over financial reporting. If we are unable to conclude that we have effective internal controls over financial reporting or if our independent registered public accounting firm is required to, but is unable to provide us with a report as to the effectiveness of our internal controls over financial reporting, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our securities.

Our common stock is subject to the “penny stock” rules of the SEC and the trading market in our securities is limited, which makes transactions in our stock cumbersome and may reduce the value of an investment in our stock.

The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

· that a broker or dealer approve a person’s account for transactions in penny stocks; and

· the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

· obtain financial information and investment experience objectives of the person; and

· make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

· sets forth the basis on which the broker or dealer made the suitability determination; and

· that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

25

FINRA sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

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

ITEM 1B – UNRESOLVED STAFF COMMENTS

None.

ITEM 2 – PROPERTIES

We maintain our principal executive offices at 800 Bering, Suite 250, Houston, Texas 77057. Our telephone number at that office is (713) 554-4491 and our facsimile number is (713) 583-1617. Our rent is on a month to month basis and approximately $4,000 per month.

Reserve Estimation Procedures and Audits

The information included in this Report about the Company’s proved reserves as of October 31, 2014 and 2013, which were located in the United States, is based on evaluations prepared by the Company’s engineers and audited by Hite & Associates (“Hite” or the “Independent Petroleum Engineers”). The Company has no oil and gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure of probable or possible reserves.

Reserve estimation procedures. The Company has established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and GAAP requirements. These controls include the annual external audits of substantial portions of the Company’s proved reserves by the Independent Petroleum Engineers.

Proved reserves audits. The reserve audits performed by the Independent Petroleum Engineers in the aggregate represented 100% of the Company’s 2014 and 2013 proved reserves.

The Independent Petroleum Engineers follow the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers (“SPE”). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE’s definition of a reserve audit includes the following concepts:

· A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the SPE.

· The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.

 · The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties.

26

To further clarify, in conjunction with the audit of the Company’s proved reserves and associated pre-tax present value discounted at ten percent, the Company provided to the Independent Petroleum Engineers its engineering and geoscience technical data and analyses. Following the Independent Petroleum Engineers’ review of that data, they had the option of honoring the Company’s interpretation, or making their own interpretation. No data was withheld from the Independent Petroleum Engineers. The Independent Petroleum Engineers accepted without independent verification the accuracy and completeness of the historical information and data furnished by the Company with respect to ownership interest, oil and gas production, well test data, commodity prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluation something came to their attention that brought into question the validity or sufficiency of any such information or data, the Independent Petroleum Engineers did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data.

In the course of their evaluations, the Independent Petroleum Engineers prepared, for all of the properties, their own estimates of the Company’s proved reserves and the pre-tax present value of such reserves discounted at ten percent. At the conclusion of the audit process, it was the Independent Petroleum Engineers’ opinions, as set forth in their audit letters, which are included as exhibits to this Report, that the Company’s estimates of the Company’s proved oil and gas reserves and associated pre-tax present value discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering standards promulgated by the SPE.

Qualifications of reserves preparers and auditors. The Independent Petroleum Engineers provide petroleum property analysis services for energy clients, financial organizations and government agencies.

George Hite, Texas Board of Professional Engineers Registration number 57184, was primarily responsible for auditing the Company’s reserves estimates for Hite & Associates Inc. at October 31, 2014 and 2013. Mr. Hite has been a practicing consulting petroleum engineer and has over 49 years of practical experience in petroleum engineering, including the estimation and evaluation of proved reserves. He graduated with a Bachelor of Science degree in Mechanical Engineering in 1964 and meets or exceeds the education, training and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the board of directors of the SPE.

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for the report and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates is Eric Urban, Special Advisor to Blacksands Petroleum, Inc. Mr. Urban has ten (10) years’ experience in the oil and gas exploration industry and has assisted in overseeing the preparation of the reserve estimates for the past five years. He is the sole person in the Company that reviews and approves the reserve estimates.

Technologies used in reserves estimates. The Company uses reliable technologies to establish additions to reserve estimates, including seismic data and interpretation, wireline formation tests, geophysical logs and core data.

Description of Properties

Net Reserves of Crude Oil and Natural Gas at October 31,

	2014		2013
Proved developed oil reserves (MBbls)		28.84		58.36
Proved developed gas reserves (Mcf)		17.40		195.56
Proved undeveloped oil reserves (MBbls)		--		--
Proved undeveloped gas reserves (Mcf)		--		--
Total proved oil reserves (MBbls)		28.84		58.36
Proved gas reserves (Mcf)		17.40		195.56

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Developed and Undeveloped Acreage

	Developed Acreage				Undeveloped Acreage
Geographic Area:	Gross		Net		Gross		Net
Year ended October 31, 2014
Cabeza Creek		--		--		--		--
Beech Creek		88		24		--		--
AP Clark		400		127		8,300		4,923
Year ended October 31, 2013
Cabeza Creek		3,689		3,689		--		--
Beech Creek		88		24		--		--
AP Clark		400		127		8,300		4,923

The following table summarizes our oil and gas production revenue and costs, our productive wells and acreage, undeveloped acreage and drilling activities for each of the last two (2) years ended October 31.

	2014		2013
Production
Net oil production (Bbls)		11,108		16,139
Net gas production (Mcf)		19,396		18,145
Total production (Mboe) (1)		14,341		19,163
Average sales price per Bbl of oil	$	90.48	$	91.85
Average sales price per Mcf of gas	$	4.49	$	4.06
Average sales price per Boe	$	85.68	$	82.15
Average production cost per Mboe	$	29.97	$	39.44

(1)  Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil.

The following tables summarize the Company’s United States development and exploration/extension drilling activities during 2014:

	Development Drilling
	Beginning Wells In Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells In Progress
Cabeza Creek		--		--		--		--		--
Beech Creek		--		--		--		--		--
AP Clark		1		2		3		--		--
Total United States		1		2		3		--		--

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Exploration/Extension Drilling

Beginning Wells In Progress

Wells Spud

Successful Wells

Unsuccessful Wells

Sold Wells

Ending Wells In Progress

Cabeza Creek

--

--

--

--

--

--

Beech Creek

--

--

--

--

--

--

AP Clark

--

--

--

--

--

--

Pedregosa

--

--

--

--

--

--

Total United States

--

--

--

--

--

--

The following table summarizes the Company’s average daily oil, gas and total production by asset area during 2014:

	Oil (Bbls)		Gas (Mcf)			Total (BOE)
Cabeza Creek		--		--			--
Beech Creek		2		19			5
AP Clark		28		14			30
Pedregosa		--			--		--
Del Norte		--			--		--
Total		30		33			35

The following table summarizes the Company’s costs incurred by geographic area during 2014:

	Property Acquisition Costs				Exploration Costs		Development Costs		Asset Retirement Obligations		Total
	Proved		Unproved
Cabeza Creek	$	--		--		--		--		--		--
Beech Creek		--		--		--		74,516		916		75,432
AP Clark		--		--		--		3,607,107		43,041		3,650,148
Pedregosa		--		--		--		--		--		--
Del Norte		--		--		--		--		--		--
Total	$	--		--		--		3,681,623		43,957		3,725,580

ITEM 3 - LEGAL PROCEEDINGS

On January 26, 2015, David DeMarco, a former Chief Executive Officer and director of the Company, filed a complaint against the Company in the District Court of Harris County, Texas, alleging that pursuant to a contract for work performed and/or services rendered, Mr. DeMarco is due $151,000 in deferred compensation that accrued during his tenure as Chief Executive Officer of the Company. The Company believes that Mr. DeMarco is currently an officer of an affiliate of PIE Operating  LLC, the operator of five of the Company's wells. Mr. DeMarco is seeking between $200,000 and $1 million in damages. As of the date of this filing, service of process has not been effected.

ITEM 4 – MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Price Range of Common Stock

Our common stock is currently quoted on the OTCQB Market under the symbol “BSPE.” Prior to September 23, 2013, our common stock was quoted on the OTC QB under the symbol “BSPE.” For the period from November 1, 2012 through October 31, 2014, the following table sets forth the high and low sale prices of our common stock as reported by NASDAQ.

Period	High		Low
Fiscal Year Ended October 31, 2013:
First Quarter	$	1.70	$	0.91
Second Quarter		2.65		1.01
Third Quarter		3.50		2.00
Fourth Quarter		2.90		1.01
Fiscal Year Ended October 31, 2014:
First Quarter	$	2.02	$	0.90
Second Quarter		1.95		1.02
Third Quarter		2.05		1.45
Fourth Quarter		1.80		0.90

On February 5, 2015, the closing sale price of our common stock, as reported by the OTCQB Market, was $0.50 per share. On February 5, 2015, there were 21 holders of record of our common stock.

Dividend Policy

We have never paid any cash dividends on our capital stock and do not anticipate paying any cash dividends on our common stock in the foreseeable future. We intend to retain future earnings to fund ongoing operations and future capital requirements of our business. Any future determination to pay cash dividends will be at the discretion of the Board and will be dependent upon our financial condition, results of operations, capital requirements and such other factors as the Board deems relevant.

Recent Sales of Unregistered Securities

On November 12, 2014, we issued 21,875 shares of common stock to a former director of the Company as compensation for his service.

On December 18, 2014, we issued Silver Bullet an aggregate of 94,758 shares of common stock with 20,183 shares of common stock at a cost base of $1.62 per share and 74,575 shares of common stock at a cost base of $1.31 per share in exchange for interest due on the notes pursuant to the Exchange Agreement.

ITEM 6 – SELECTED FINANCIAL DATA

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

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

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 on 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, Cline, Strawn and Mississippian formations in the Permian Basin (Midland Basin) in W. Texas. We also have interests in (i) conventional reef structures in the Pedregosa Basin in S.W. New Mexico, (ii) conventional structure and stratigraphic formations and unconventional resource formations in Southern Colorado and (iii) Beech Creek Field in Hardin County, Texas (“Non-core Properties”).

As of October 31, 2014, we owned interests in approximately (i) 7,700 gross (4,000 net) acres in the Midland Basin, (ii) 108,715 gross (54,357 net) acres in the Pedregosa Basin, and (iii) 3,300 gross (1,650 net) acres in Colorado.

We have approximately 112,793 gross acres (56,100 net acres) held by production and continuous drilling operations. This includes approximately 3,100 gross acres (1,150 net acres) in Midland Basin, 108,715 gross acres (54,357 net acres) in the Pedregosa Basin. We also own between a 24% and 30% working interest in two wells in the Beech Creek Field, which are operated by Gaither Petroleum Corp. The Corporation has no production in Colorado.

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 two (2) properties located in the Gulf Coast region of Texas and one property in our Core Focus Area located in the Midland Basin in West Texas.

The Core Focus Areas provide us with the opportunity to grow reserves and cash flow by drilling and developing the properties. The Core Focus Areas we currently plan to concentrate on developing are in the AP Clark Field. The three wells that we commenced drilling on in the AP Clark Field in November 2013 were completed and have been producing. During the twelve months ended October 31, 2014, the Corporation’s portion of the production amounted to approximately 697 barrels of oil. These wells came online in the month of May 2014 with the Corporation’s portion of the production averaging approximately 18 barrels of oil per day. During August 2014, the wells were shut in for completion and fracking. The Corporation is still testing zones on the wells and is waiting for the formations to come back in. The Corporation will need to raise additional capital in order to drill any potential future wells.

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We continue to pursue avenues to reduce or eliminate our financial exposure on a case by case basis for each project, including joint venture arrangements where others may participate in the well revenue, in exchange for a disproportionate share of the initial leasing and/or drilling costs, thus further reducing its economic exposure. In order to maintain our financial position, we have sold equity and used joint venture agreements with other industry companies to limit or eliminate its financial exposure in early drilling.

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.

Consolidated Results of Operations for the Year Ended October 31, 2014 Compared to the Year Ended October 31, 2013

Revenues for the year ended October 31, 2014 totaled $1,228,868 as compared to $1,690,249 for the year ended October 31, 2013. The decrease, totaling $461,381, resulted primarily from a decrease in oil production of approximately $462,097, a decrease in revenues due to a drop in the average price of oil of $15,218 and partially offset by an increase in gas production of $5,079 and an increase in the average price of gas of $8,340. During the fiscal year ended October 31, 2013, the Cabeza Creek Field accounted for oil revenues of $89,345 and gas revenues of $51,759. The Company reflected no production from this field in the fiscal year ended October 31, 2014 prior to its sale in January 2014. We anticipate that the production for the older wells will continue at low levels and expect that as the three wells completed during the fiscal year ended October 31, 2014 test additional formations, production from those wells may increase during 2015.

Selling general and administrative expenses decreased by $177,984 from $1,443,223 in the fiscal year ended October 31, 2013 to $1,265,239 in the fiscal year ended October 31, 2014. The decrease is primarily related to a decrease of $290,919 in the stock based compensation recorded in the year ended October 31, 2014 from reduced vesting of previously granted stock options, which was partially offset by additional legal fees of $127,832. There were no options granted during the year ended October 31, 2014.

Depreciation, depletion and accretion totaled $1,423,350 in the year ended October 31, 2014 as compared to $1,009,242 for the year ended October 31, 2013. The increase in the depreciation, depletion and accretion was a result of the decrease in the estimated amount of proved reserves as determined by the independent petroleum engineer.

Lease operating expenses decreased to $429,810 in the year ended October 31, 2014 as compared to $765,643 in the year ended October 31, 2013. Approximately $169,268 of the decrease relates to costs eliminated as a result of the sale of the Cabeza property in January 2014. The balance of the decrease relates to the utilization of one of the wells in the AP Clark Field for salt water disposal. As a result of utilizing an existing nonproducing well for salt water disposal purposes, the Company reduced its costs for salt water disposal by $89,371 and the Company billed out $93,506 to others for salt water disposal.

During the year ended October 31, 2013, we incurred exploration expenses of $699,335. These costs related primarily to lease extension payments for several AP Clark Field leases. There were no such costs in the fiscal year ended October 31, 2014.

During the years ended October 31, 2014 and 2013, we reported impairment costs on our oil and gas properties totaling $3,630,194 and $4,820,770, respectively. These impairment charges resulted from the carrying costs of the AP Clark Field, including the costs of the three new wells exceeding the estimated fair value of the field based on estimated future cash flows.

The gain on the sale of oil and gas properties of $645,323 in the year ended October 31, 2014 was the result of selling the Company’s rights in the Cabeza Creek Field. In January 2014, the Company sold its interest in all of the wells in the Cabeza Creek Field for all depths from the surface to 8,500 feet below the surface in exchange for $50,000 and the assumption by the purchaser of $617,189 in current liabilities and all future liabilities associated with the plugging and abandoning of all wells in the Cabeza Creek Field.

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The gain on sale of interest to PIE Holdings of $1,639,394 for the year ended October 31, 2014 is the result of the partial transfer of the Company’s interest in three wells in the AP Clark Field, ranging from between 38.6% and 50.0%, to PIE Holdings. In connection with these transfers, PIE Holdings paid a purchase price of $20.00 and assumed aggregate obligations of approximately $1.3 million, which related to expense obligations incurred in relation to the wells and related interests.

During the years ended October 31, 2014 and 2013, we incurred interest expenses totaling $2,139,317 and $1,401,611, respectively. The increase in interest expense of $737,706 was primarily related to the $651,028 increase in the amortization of the discount on the amounts due to KP Ventures, which represents the balance of the discount on the amounts due KP Ventures using the effective interest method of amortization. In addition, we incurred amortization totaling $37,127 on the discount of the Pacific LNG convertible debenture, and interest of $45,411 from the Pacific LNG convertible debenture.

During the year ended October 31, 2014, we incurred a loss on the extinguishment of debt totaling $841,926. As a result of the issuance of the shares for the accrued interest due Silver Bullet through June 30, 2014, the Company recorded a loss on the extinguishment of debt of $841,926, which is the amount the value of the shares issued exceeded the amount of the accrued interest. There was no such extinguishment in the year ended October 31, 2013.

We incurred a net loss for the year ended October 31, 2014 of $6,216,251, compared to a net loss of $8,393,974 for the year ended October 31, 2013.

Liquidity and Capital Resources

The Company had cash and cash equivalents of $678,940 as of October 31, 2014. We currently do not have sufficient cash to engage in any further drilling or exploration activities. In addition, our cash balances are not sufficient to satisfy our anticipated cash requirements for normal operations, to meet our immediate accounts payable and other obligations regarding our indebtedness or capital expenditures for the foreseeable future. We believe that our current cash will allow us to continue basic operations for the next two months.

The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business. As reflected in the accompanying consolidated financial statements, as of October 31, 2014, we had approximately $678,940 in cash and cash equivalents on hand, a working capital deficiency of approximately $1,149,885 million and an accumulated deficit of approximately $34,924,061 through October 31, 2014.

We have incurred substantial losses since inception and our cash balance at year end is not sufficient to fully fund our business plan or to meet our other obligations regarding our indebtedness or our anticipated development activities over the next twelve (12) months. In view of our capital requirements, current cash resources, nondiscretionary expenses, debt and near term accounts payable and accrued expenses obligations, we may explore all strategic alternatives to maintain our business as a going concern including, but not limited to, a sale of assets of our Company, or one or more other transactions that may include a comprehensive financial reorganization of our Company.

In order to continue operations and engage in development of our properties, we will be dependent on raising capital, debt or equity, from outside sources to pay for further expansion, exploration and development of our business, and to meet current obligations. Such capital may not be available to us when we need it on terms acceptable to us if at all, particularly in the current global economic conditions. The issuance of additional equity securities by us will result in a dilution to our current stockholders, which could depress the trading price of our common stock. Obtaining debt financing will increase our liabilities and future cash commitments. If we are unable to obtain financing in the amounts and on terms deemed acceptable to us, we may be unable to continue our business and may be required to scale back, sell a portion of or cease our operations. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

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We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which may adversely impact our financial condition. However, there is no assurance that we will be able to obtain sufficient funds on terms acceptable to us or at all. If adequate additional funding is not available, we may be forced to limit our activities.

If we are not able to obtain sufficient capital either from the sale of assets or external sources of capital to fund our immediate operating requirements, we may determine that it is in the Company’s best interests to seek relief through a pre-packaged, pre-negotiated or other type of filing under Chapter 11 of the U.S. Bankruptcy Code.

In the event we seek protection under Chapter 11 of the U.S. Bankruptcy Code, it may be necessary, in order to obtain the approval of our creditors and the Bankruptcy Court to a plan of reorganization for the Company, to eliminate and cancel all existing equity of the Company, including common stock, options, warrants and other securities that are linked to our equity, which will result in a loss of the entire investment of the holders of such securities, including our stockholders. Further, if we were unable to implement a plan of reorganization or if sufficient debtor-in-possession financing were not available, we could be forced to liquidate under Chapter 7 of the U.S. Bankruptcy Code, which would result in a loss of your entire investment.

Net Cash Provided By (Used In) Operating Activities

Cash used by operating activities in the year ended October 31, 2014 was $1,664,068, compared to $397,182 in the year ended October 31, 2013. The increase in cash used by operating activities was primarily a result of a $1,190,576 decrease in the impairment costs for oil and gas properties, a non-cash gain of $645,323 on the sale of the Cabeza Creek Field and $1,639,394 from the sale of an interest in certain wells to PIE Holdings, a $1,153,357 decrease in accounts payable and a $290,919 decrease in equity compensation expense, which was partially offset by a $2,177,723 decrease in the net loss and a $688,155 increase in the amortization of debt discounts.

Cash Flows Used In Investing Activities

Net cash used in investing activities for the year ended October 31, 2014 was $1,992,229 compared to $647,901 for the year ended October 31, 2013. Investing activities for both periods relate to our oil and gas acquisitions and development activity. The costs for the year ended October 31, 2014 represented $3,681,623 paid primarily to drill the three new wells in the AP Clark Field, offset in part by $50,000 of cash received from the sale of Cabeza Creek and $1,639,394 in cash received for the same of interest in wells in the AP Clark Field. There were no acquisitions of additional leaseholds incurred in either period.

Cash Flows from Financing Activities

Cash provided by financing activities for the year ended October 31, 2014 was $3,000,000, compared to $1,220,000 for the year ended October 31, 2013. The financing for both periods was obtained in furtherance of our drilling programs. On June 6, 2014, we entered into a subscription agreement with Pacific LNG, whereby, in exchange for the $2 million previously received, we issued to Pacific LNG a (i) $1,500,000 Debenture and (ii) 500,000 shares of Series B Preferred Stock. On October 16, 2014, the Company entered into the Series C Subscription Agreement with Silver Bullet whereby the Company issued to Silver Bullet 1,000,000 shares of Series C Preferred Stock at a purchase price of $1.00 per share.

Cabeza Creek Field

In January 2014, the Company sold its interest in all the wells in the Cabeza Creek Field for all depths from the ground to 8,500 feet below the surface in exchange for $50,000 and the assumption by the buyer of all outstanding and future liabilities related to the Cabeza Creek Field.

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Issuance of Common Stock to Silver Bullet

In October 2013, the Company issued 500,000 shares of its common stock to Silver Bullet in exchange for $1,000,000. The base price paid by Silver Bullet will be reduced and additional shares issued if there is an issuance of securities or repricing of an existing right to a price less than the base share price paid by Silver Bullet within one year from the original issuance. As a result of a stock issuance to Pacific LNG (defined below) on June 6, 2014 at a price of $1 per share, an additional 500,000 shares were issued to Silver Bullet pursuant to the price protection clause. The Company reported the issuance of these additional shares as an equity transaction as the shares were issued in relation to a prior equity issuance, there was no derivative reporting on the original equity transaction and there were no additional services or goods provided.

June 2014 Financing

On June 6, 2014, the Company entered into a subscription agreement with Pacific LNG Operations Ltd., a company incorporated in the British Virgin Islands (“Pacific LNG”), whereby the Company issued to Pacific LNG a (i) $1,500,000 principal face amount 5% Convertible Debenture (“Debenture”) convertible into shares of Series B Preferred Stock (as hereinafter defined) at a conversion price of $1.00 per share and (ii) 500,000 shares of Series B Convertible Preferred Stock (“Series B Preferred Stock”) at a price of $1.00 per share.

The Debenture accrues interest at the rate of 5% per annum, payable semi-annually in arrears, and matures on June 6, 2017. Pacific LNG has the right, at any time prior to June 6, 2015, to convert the outstanding principal and interest, if any, of the Debenture into shares of Series B Preferred Stock at a price of $1.00 per share of Series B Preferred Stock.

Each share of Series B Preferred Stock has a stated value of $1.00 (“Series B Stated Value”) and accrues a dividend of 3% of the Series B Stated Value per annum, which is payable in additional shares of Series B Preferred Stock annually on December 31 in arrears. Each share of Series B Preferred Stock may be converted at any time on or prior to May 30, 2017 into such number of shares of the Company’s common stock equal to the Series B Stated Value divided by $1.00 per share. The Company has the right, at any time after May 30, 2017, to redeem the Series B Preferred Stock at a price of $1.00 per share.

Under the terms set forth in the Series B Certificate of Designation, the holders of Series B Preferred Stock have the exclusive right, voting separately as a class, to elect one director of the Board (“Series B Director”), who must be reasonably acceptable to the Company. The Series B Director must be appointed by the holders of a majority of the issued and outstanding Series B Preferred Stock.

The Company has also recorded a discount on this Debenture relating to the beneficial conversion feature contained in the Debenture. This discount reduced the original carrying value debenture by $1,350,000. The carrying value of the discounts totaled $1,312,873 at October 31, 2014. The discount is being amortized over a three year period using the effective interest rate method. The Company amortized $37,127 as additional interest expense in the fiscal year ended October 31, 2014.

Amendment to Silver Bullet Notes Payable

On August 26, 2014, the Company entered into an Amendment and Exchange Agreement (the “Exchange Agreement”) with Silver Bullet, pursuant to which the Company issued 1,052,407 shares (the “Exchange Shares”) of common stock to Silver Bullet in exchange for accrued interest on an aggregate amount of $3,220,000 of promissory notes held by Silver Bullet dated November 19, 2010, September 27, 2011, November 1, 2011, December 1, 2011, June 12, 2012 and August 28, 2013 (collectively, the “Notes”). Also pursuant to the Exchange Agreement, the Notes were amended such that (i) all interest accruing after June 30, 2014 shall be exchanged for shares of common stock on a quarterly basis in arrears and (ii) the maturity date of each of the Notes was extended to December 31, 2015. As a result of the issuance of the shares for the accrued interest due Silver Bullet through June 30, 2014, the Company recorded a loss on the extinguishment of debt of $841,926, which is the amount the value of the shares issued exceeded the amount of the accrued interest.

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October 2014 Financing

On October 16, 2014, the Company entered into a subscription agreement (the “Series C Subscription Agreement”) with Silver Bullet whereby the Company issued to Silver Bullet 1,000,000 shares of Series C Preferred Stock at a purchase price of $1.00 per share. Each share of Series C Preferred Stock has a stated value of $1.00 (“Series C Stated Value”) and accrues a dividend of 3% of the Series C Stated Value per annum, which is payable in additional shares of Series C Preferred Stock annually on December 31, in arrears, and beginning on December 31, 2014. Each share of Series C Preferred Stock may be converted at any time on or before June 30, 2017, into such number of shares of the Company’s common stock equal to the Series C Stated Value divided by $1.00 per share. The Company has the right, at any time after June 30, 2017, to redeem the shares of Series C Preferred Stock, either in whole or in part, at the price of $1.00 per share. There are no voting rights underlying the Series C Preferred Stock.

KP Energy Joint Venture Agreement

On July 20, 2012, the Company entered into a Contribution Agreement (the “Contribution Agreement”), between ApClark and KP Ventures. Pursuant to the Contribution Agreement (i) the Company contributed $1,000 and certain of the Company’s oil and gas assets to ApClark in exchange for 1,000 shares of Class A Membership Units of ApClark (the “Class A Membership Units”) and (ii) KP Ventures contributed approximately $2,600,000 (the “KP Ventures Cash Consideration”) to ApClark in consideration of 1,000 shares of Class B Non-Voting Convertible Preferred Membership Units of ApClark (the “Class B Membership Units” and the transaction, the “Asset Transaction”). KP Ventures has the option to contribute additional funds to ApClark, up to an aggregate of $7,600,000, for no further equity consideration.

In connection with the Contribution Agreement, the Company entered into a Company Agreement (the “Operating Agreement”) governing the operations of ApClark and defining various rights of the Company and KP Ventures.

Pursuant to the Operating Agreement, KP Ventures shall receive a preferred return of 12% per annum (the “Preferred Return”) on the unrecovered KP Ventures Cash Consideration until such time as the KP Ventures Cash Consideration is repaid. In addition, KP Ventures receives a 1% overriding royalty from the production of the ApClark oil and gas properties. Once the KP Ventures Cash Consideration is repaid, including all accrued Preferred Returns, the Class B Membership Units will automatically convert into Class C Non-Voting Net Profit Membership Units (the “Class C Membership Units”), which represent percentages of non-dilutable outstanding membership units in ApClark (“ApClark Ownership”) and non-dilutable “Net Profits” interest (“NPI”) in ApClark and the assets owned by ApClark. The amount of ApClark Ownership and NPI granted depends on when the KP Ventures Cash Consideration and Preferred Return are paid, as follows:

Date of Repayment in Full	Percentage of ApClark Ownership and NPI
After July 20, 2014 but on or prior to July 20, 2015		20	%
After July 20, 2015		50	%

The Company will be responsible for the operations of ApClark and has the sole right to appoint the director(s) of ApClark. The consent of KP Ventures is required in certain situations, including, but not limited to: expanding the scope of the business; admitting additional members or transfer of membership units; approve annual budget; any merger or sale of all or substantially all of the assets of ApClark; voluntary liquidation, dissolution or winding up of ApClark; and to make any cash distributions.

In addition, the Company entered into a Pledge Agreement (the “Pledge Agreement”) pursuant to which it pledged the Class A Membership Units to KP Ventures to secure the Company’s obligations and performance thereunder and under the Contribution Agreement and Operating Agreement, which such Class A Membership Units shall be held pursuant to an escrow agreement.

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Previously, the Company entered into a security agreement, dated as of September 27, 2011, whereby the Company granted Silver Bullet a security interest in certain of the assets of the Company that were contributed to ApClark pursuant to the Contribution Agreement (the “Pledged Assets”). In connection with the Asset Transaction, the Company, ApClark, Silver Bullet and KP Ventures entered into a subordination agreement (the “Subordination Agreement”), pursuant to which Silver Bullet subordinated its security interest to KP Ventures, so that KP Ventures would have a first priority interest in the Pledged Assets until KP Ventures is repaid the KP Ventures Cash Consideration and Preferred Return. In addition, the Company previously granted Silver Bullet a “net proceeds” interest of 9% on the Pledged Assets (the “Silver Bullet NPI”), which Silver Bullet NPI was capped at 25% of the outstanding principal and accrued interest owed under the Notes (the “Silver Bullet NPI Limitation”).

As consideration for Silver Bullet entering into the Subordination Agreement, the Company agreed to increase the interest on the Notes to 12% per annum and remove the Silver Bullet NPI Limitation so that there is no cap on the maximum amount of Silver Bullet NPI that Silver Bullet can receive.

As a result of the required repayment of the equity to KP Ventures, the amount of the contribution has been reflected as a liability on the balance sheet. The Company has also recorded a discount on this liability relating to the relative fair value of the overriding royalties totaling $163,786 and net profits interest totaling $1,915,231. These discounts reduced the carrying value of the proved oil and gas costs. The carrying value of the discounts totaled $0 at October 31, 2014. The Company amortized $1,329,581 and $678,553 as additional interest expense in the fiscal years ended October 31, 2014 and 2013, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

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.

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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.

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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.

During the years ended October 31, 2014 and 2013, we recorded impairments on the oil and gas properties of $3,630,194 and $4,820,770, respectively.

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 7A – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of October 31, 2014 and 2013		F-3
Consolidated Statements of Operations and Comprehensive Loss for the years ended October 31, 2014 and 2013		F-4
Consolidated Statement of Stockholders’ Equity for the years ended October 31, 2014 and 2013		F-5
Consolidated Statements of Cash Flows for the years ended October 31, 2014 and 2013		F-6
Notes to Consolidated Financial Statements		F-7 - F-22

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Blacksands Petroleum, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Blacksands Petroleum, Inc. and its subsidiaries (collectively, the “Company”) as of October 31, 2014 and 2013 and the related consolidated statement of operations, stockholders’ deficit, and cash flows for each of the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Blacksands Petroleum, Inc. and its subsidiaries as of October 31, 2014 and 2013 and the results of their operations and their cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that Blacksands Petroleum, Inc. and its subsidiaries will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has incurred cumulative losses since inception and has negative working capital, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters also are described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ MaloneBailey, LLP

www.malonebailey.com

Houston, Texas

February 11, 2015

F-2

BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

Consolidated Balance Sheets

October 31, 2014 and 2013

	October 31, 2014			October 31, 2013
ASSETS
Current Assets:
Cash and cash equivalents	$	678,940		$	1,335,237
Accounts receivable		210,577			417,597
Prepaid expenses		522,073			-
Total Current Assets		1,411,590			1,752,834
Oil and gas property costs (successful efforts method of accounting)
Proved		735,756			2,077,872
Other assets		50,000			50,312
TOTAL ASSETS	$	2,197,346		$	3,881,018
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current Liabilities:
Note payable	$	60,000		$	280,000
Accounts payable		129,400			523,365
Accrued expenses		2,372,075			3,121,900
Total Current Liabilities		2,561,475			3,925,265
Notes payable, net of discounts of $1,312,873 and $1,329,581		2,787,127			1,050,419
Notes payable to related party		3,220,000			3,220,000
Asset retirement obligation		91,707			649,233
Total Liabilities		8,660,309			8,844,917
Stockholders’ Equity:
Preferred stock - $0.001 par value; 10,000,000 shares authorized:					--
Series A - $0.001 par value, 310,000 shares authorized, nil and nil shares issued and outstanding		--			--
Series B - $0.001 par value; 2,217,281 shares authorized, 500,000 and nil shares issued and outstanding, respectively		500			--
Series C - $0.001 par value; 1,750,000 shares authorized, 1,000,000 and nil shares issued and outstanding, respectively		1,000			--
Common stock - $0.001 par value; 100,000,000 shares authorized; 19,278,017 and 17,719,360 shares issued and outstanding at October 31, 2014 and October 31, 2013, respectively		19,278			17,720
Additional paid-in capital		28,440,320			23,726,191
Accumulated deficit		(34,924,061	)		(28,707,810	)
Total Stockholders’ Deficit		(6,462,963	)		(4,963,899	)
TOTAL LIABILITIES AND STOCKHOLDERS’ Deficit	$	2,197,346		$	3,881,018

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

F-3

BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

Years Ended October 31, 2014 and 2013

		October 31
		2014			2013
Revenue:
Oil and Gas Revenue		$	1,228,868		$	1,690,249
Expenses:
	Selling, general and administrative		1,265,239			1,443,223
	Depreciation and depletion		1,407,644			969,511
	Accretion		15,706			39,731
	Lease operating expenses		429,810			765,643
	Impairment of oil and gas property interest		3,630,194			4,820,770
	Gain on sale of assets		(645,323	)		--
	Gain on sale of working interests		(1,639,394	)		--
	Oil and gas exploration		--			699,335
	Total expenses		4,463,876			8,738,213
Loss from Operations			(3,235,008	)		(7,047,964	)
Other income and expense:
	Interest expense		(2,139,317	)		(1,401,611	)
	Other income		-			55,601
	Loss on extinguishment of debt		(841,926	)		--
	Total Other Income (Expense)		(2,981,243	)		(1,346,010	)
Loss before provision for income taxes			(6,216,251	)		(8,393,974	)
Provision for income taxes			--			--
Net Loss			(6,216,251	)		(8,393,974	)
Preferred stock Dividends			(7,583	)		(200,000	)
Deemed dividend – beneficial conversion feature
Series B Preferred Stock			(450,000	)		--
Deemed dividend – beneficial conversion feature
Series C Preferred Stock			(390,000	)		--
Net loss attributable to common shareholders		$	(7,063,834	)	$	(8,593,974	)
Loss Per Share attributable to common shareholders
Basic and diluted		$	(0.39	)	$	(0.52	)
Weighted Average Shares Outstanding
Basic and diluted			18,094,055			16,405,142

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

F-4

BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Deficit

Years Ended October 31, 2014 and 2013

	Preferred Stock						Common Stock				Additional Paid-in			Retained			Total Stockholders’
	Shares			Amount			Shares		Amount		Capital			Deficit			Deficit
Balance, October 31, 2012		250,000			250			16,386,443		16,387		22,463,501			(20,313,836	)		2,166,302
Stock issued to director for services		--			--			6,250		6		24,787			--			24,793
Stock based compensation		--			--			--		--		238,980			--			238,980
Shares issued in private placement		--			--			500,000		500		999,500			--			1,000,000
Conversion of preferred shares		(250,000	)		(250	)		826,667		827		(577	)		--			--
Net loss		--			--			--		--		--			(8,393,974	)		(8,393,974	)
Balance, October 31, 2013		--			--			17,719,360		17,720		23,726,191			(28,707,810	)		(4,963,899	)
Stock based compensation		--			--			--		--		33,146			--			33,146
Unvested portion of forfeited options		--			--			--		--		(68,730	)		--			(68,730	)
Stock issued to director for services		--			--			6,250		6		8,432			--			8,438
Payment of interest with common stock		--			--			1,052,407		1,052		1,893,281			--			1,894,333
Stock issuance costs		--			--			500,000		500		(500	)		--			--
Discount on convertible debt		--			--			--		--		1,350,000			--			1,350,000
Issuance of Preferred B shares		500,000			500			--		--		499,500			--			500,000
Beneficial conversion feature
on Preferred B Shares		--			--			--		--		450,000			--			450,000
Deemed dividend on Preferred B shares		--			--			--		--		(450,000	)		--			(450,000	)
Issuance of Preferred C shares		1,000,000			1,000			--		--		999,000			--			1,000,000
Beneficial conversion feature
discount on Preferred C shares		--			--			--		--		390,000			--			390,000
Deemed dividend on Preferred C shares		--			--			--		--		(390,000	)		--			(390,000	)
Net loss		--			--			--		--		--			(6,216,251	)		(6,216,251	)
Balance, October 31, 2014		1,500,000		$	1,500			19,278,017	$	19,278	$	28,440,320		$	(34,924,061	)	$	(6,462,963	)

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

F-5

BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For the Years Ended October 31, 2014 and 2013

	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(6,216,251	)	$	(8,393,974	)
Adjustments to reconcile net loss to net cash used in operating activities:
Impairment of oil and gas property costs		3,630,194			4,820,770
Share-based compensation expense		(27,146	)		263,773
Depreciation and depletion		1,407,644			969,511
Accretion		15,706			39,731
Amortization of debt discount		1,366,708			678,553
Loss on extinguishment		841,926			--
Gain on sale of working interest		(1,639,394	)		--
Gain on sale of assets		(645,323	)		--
Changes in operating assets and liabilities:
Accounts receivable		207,020			(15,435	)
Prepaid expense and other current assets		(522,073	)		169,611
Accounts payable and accrued expenses		(83,079	)		1,070,278
Net cash flows from operating activities		(1,664,068	)		(397,182	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties		(3,681,623	)		(647,901	)
Proceeds from sale of Cabeza Creek property		50,000			--
Cash received from the sale of oil and gas properties		1,639,394			--
Net cash flows from investing activities		(1,992,229	)		(647,901	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable		1,500,000			220,000
Proceeds from sale of preferred stock		1,500,000			--
Proceeds from sale of common stock		--			1,000,000
Net cash flows from financing activities		3,000,000			1,220,000
NET INCREASE IN CASH AND CASH EQUIVALENTS		(656,297	)		174,917
CASH AND CASH EQUIVALENTS - Beginning of period		1,335,237			1,160,320
CASH AND CASH EQUIVALENTS - End of period	$	678,940		$	1,335,237
Supplemental Disclosures
Cash paid for interest	$	337,246		$	223,599
Cash paid for income taxes	$	--		$	--
Supplemental non-cash activities
Discount on debt	$	1,350,000		$	--
Payment of accrued interest through issuance of common stock	$	1,052,407		$	--
Revision of asset retirement obligation		43,957			--
Conversion of Preferred Stock to Common Stock	$	--			827

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

F-6

BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

October 31, 2014

1. The Company and Summary of Significant Accounting Policies

Description of business and history

Blacksands Petroleum, Inc. (hereinafter referred to as the “Company”) was incorporated in the State of Nevada on October 12, 2004. Since August 2007, the Company has been engaged in the exploration, development, exploitation and production of oil and natural gas. The Company sells its oil and gas products primarily to domestic pipelines and refineries. Its operations are presently focused in the States of Colorado, Texas and New Mexico.

Principles of consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, including the wholly-owned subsidiaries Blacksands Petroleum Texas LLC, NRG Asset Management LLC, Copano Bay Holdings LLC and APClark LLC, of which we own 100% of the voting interests. All significant inter-company transactions and balances have been eliminated.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties. Oil and gas properties are periodically assessed to determine whether they have been impaired. Any impairment in value of unproved properties is charged to exploration expense. The costs of unproved properties, which are determined to be productive, are transferred to proved oil and gas properties and amortized on an equivalent unit-of-production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and gas reserves. In accordance with ASC No. 935, exploratory drilling costs are evaluated within a one-year period after the completion of drilling. For proved properties, we compare expected undiscounted future cash flows at a producing filed level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant date, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

During the years ended October 31, 2014 and 2013, the Company impaired its oil and gas properties by $3,630,194 and $4,820,770, which is reflected in the consolidated statement of operations (see Note 2).

The Company had advanced toward future drilling activities at October 31, 2014 totaling $516,976. These advances are reported as prepaid expenses in the Company’s balance sheet.

Asset Retirement Obligation

The Company follows ASC 410—Asset Retirement and Environmental Obligations which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs excluding salvage values. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

F-7

Accounting for Derivative Instruments

ASC 815-24 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”), requires all derivatives to be recorded on the balance sheet at fair value. The Company’s derivatives are separately valued and accounted for on the balance sheet. Fair values for securities traded in the open market and derivatives are based on quoted market prices. Where market prices are not readily available, fair values are determined using market based pricing models incorporating readily observable market data and requiring judgment and estimates.

The pricing model the Company used for determining fair values of its derivatives is the Black-Scholes option-pricing model. Valuations derived from this model are subject to ongoing internal and external verification and review. The model uses market-sourced inputs such as interest rates, exchange rates and option volatilities. Selection of these inputs involves management’s judgment and may impact net income.

Cash and cash equivalents and short term investments

Cash and cash equivalents include cash on account and all highly liquid investments with original maturities of three months or less on the date of acquisition. Investments with original maturities of greater than three months but less than one year are considered short-term investments.

Use of estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

The most critical estimate is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion and amortization of the oil and gas properties and the estimate of the impairment of the oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future cash flows.

Concentration of credit risks

The Company’s consolidated financial assets that are exposed to credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company maintained substantially all of its cash balances in a limited number of financial institutions. The balances are insured by the Federal Deposit Insurance Corporation up to $250,000. The Company had $162,986 in excess of this limit at October 31, 2014.

Property and equipment

Property and equipment are stated at cost less accumulated depreciation. Depreciation is provided principally on the straight-line method over the estimated useful lives of the assets, which are generally 3 to 27 years. The amounts of depreciation provided are sufficient to charge the cost of the related assets to operations over their estimated useful lives. Upon sale or other disposition of a depreciable property, cost and accumulated depreciation are removed from the accounts and any gain or loss is reflected in the statement of operations.

The Company periodically evaluates whether events and circumstances have occurred that may warrant revision of the estimated useful life of fixed assets or whether the remaining balance of fixed assets should be evaluated for possible impairment. The Company uses an estimate of the related undiscounted cash flows over the remaining life of the fixed assets in measuring their recoverability.

F-8

Revenue recognition

Revenue is recognized when title to the products transfer to the purchaser. The Company uses the “sales method” to account for production revenue, whereby revenue is recognized on all oil, natural gas or other related products sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that there is an imbalance on a specific property greater than the expected remaining proved reserves. As of October 31, 2014, our aggregate production imbalances were not material.

Stock-based compensation

The Company follows the provisions of FASB ASC 718—Stock Compensation. The statement requires all stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values on the date of grant.

Income taxes

The Company accounts for its income taxes in accordance with ASC 740 Income Taxes, which requires recognition of deferred tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date. A valuation allowance is provided for the amount of deferred tax assets that would otherwise be recorded for income tax benefits primarily relating to operating loss carryforwards as realization cannot be determined to be more likely than not.

The statement establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, the statement implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns and the adoption of the statement had no material impact to the Company’s consolidated financial statements. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2010 remain open to examination by U.S. federal and state tax jurisdictions.

Net loss per common share

The Company computes net income or loss per share in accordance with ASC 260 Earnings Per Share. Under the provisions of the Earnings per Share Topic ASC, basic net loss per share is computed by dividing the net loss available to common stockholders for the period by the weighted average number of shares of common stock outstanding during the period. The calculation of diluted net loss per share gives effect to common stock equivalents; however, potential common shares are excluded if their effect is anti-dilutive. The weighted average number of potentially dilutive common shares excluded from the calculation of diluted net income (loss) per share totaled 3,066,667 and 3,103,601 for the years ended October 31, 2014 and 2013, respectively.

Fair Value of Financial Instruments

The carrying amounts of financial instruments, including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value at October 31, 2014 and October 31, 2013 because of the short period to maturity of these instruments.

Going Concern

As shown in the accompanying consolidated financial statements, the Company has incurred an accumulated deficit of $34,924,061 through October 31, 2014. In addition, the Company had a working capital deficit of 1,149,885 and cash and cash equivalents of $678,940 at October 31, 2014. The Company’s plan is to raise additional capital for the drilling of new oil wells until such time that the Company generates sufficient revenues from its wells to cover its cash flow needs. However, the Company cannot assure that it will accomplish this task and there are many factors that may prevent the Company from reaching its goal of profitability.

F-9

The current rate of cash usage raises substantial doubt about the Company’s ability to continue as a going concern, absent additional significant revenues from new oil production. The Company’s financial statements do not include any adjustments relating to the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be necessary in the event that the Company cannot continue in existence.

2.  Oil and Gas Property Costs

In the years ended October 31, 2014 and October 31, 2013, the Company incurred property acquisition costs as follows: 

Proved Properties

	2014			2013
Balance, beginning of year	$	2,077,872		$	5,284,597
Costs incurred during the year		3,681,623			647,901
Asset retirement obligation revision		43,957			--
Depletion		(1,407,331	)		(968,451	)
Impairment of oil and gas property costs		(3,630,194	)		(2,886,175	)
Cost of property sold		(30,171	)		(--	)
Balance, end of year	$	735,756		$	2,077,872

Unproved Properties

	2014		2013
Balance, beginning of year	$	--	$	1,934,595
Costs incurred during the year		--		--
Impairment of oil and gas property costs		--		(1,934,595	)
Balance, end of year	$	--	$	--

Blacksands Projects

Proved Properties

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. The Company also incurred approximately $25,000 in fees associated with the acquisition, which were expensed when incurred. 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 Texas 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.

At October 31, 2013 and 2012, the Company compared the expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. The Company determined that based on its analysis, capitalized costs for the field exceeded its fair value. As a result the Company recorded an impairment totaling $4,359 and $147,370, respectively.

In January 2014, the Company sold its interest in all of the wells in the Cabeza Creek Field for all depths from the surface to 8,500 feet below the surface in exchange for $50,000 and the assumption by the buyer of all future liabilities associated with the plugging and abandoning of all wells in the Cabeza Creek Field ($617,189). The Company retained its working interest for depths greater than 8,500 feet. The Company recorded a gain on the sale of $645,323 during the year ended October 31, 2014.

F-10

The following is a summary of the pro forma information for the years ended October 31, 2014 and 2013 assuming the sale of the Cabeza Creek field had occurred as of the beginning of each fiscal year presented:

	2014			2013
Oil and gas revenue	$	1,228,868		$	1,549,145
Expenses
Selling, general and administrative		1,265,239			1,443,223
Depreciation and depletion		1,407,644			912,948
Accretion		15,706			3,474
Lease operating expense		429,810			701,726
Impairment of oil and gas property interest		3,630,194			4,820,770
Gain on sale of working interest		(1,639,394	)		--
Oil and gas exploration costs		--			699,335
Total expenses		5,109,199			8,581,476
Loss from operations		(3,880,331	)		(7,032,331	)
Other income (expense)		(2,981,243	)		(1,346,010	)
Net loss	$	(6,861,574	)	$	(8,378,341	)

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. Both of these wells are currently producing. The costs related to these wells have been fully depleted.

AP Clark Wells (known as “Jo-Mill Field”) Acquisition in August 2010

On August 10, 2010 the Company purchased an interest in two operating wells and its leasehold interest in 1,257 acres for $460,000. As a result of the acquisition, the Company has a 25% gross working interest (18.75% net revenue interest) in the two operating wells. The Company also has an 18.875% gross working interest (14.15625% net revenue interest) on the leasehold interests acquired on the 1,257 acres.

On November 29, 2010, the Company acquired additional leasehold interests and rights in the AP Clark Field from Westerly for $260,000. In addition, the Company paid Westerly $119,000 as advance payment towards 70% of the actual third party costs that was required to receive an extension of certain leasehold properties included in the AP Clark Field (the “Extension Monies”) The Company and Westerly also agreed to drill the W.D. Everett Well No. 3 located within the AP Clark Field whereby all costs of such drilling operation were borne 30% by Westerly and 70% by the Company.

The Company incurred $1,342,539 in drilling costs related to the drilling and completion of the W.D. Everett Well No. 3. In addition, during the quarter ended October 31, 2011, the Company drilled the Beaver Valley Ranch 6-1 well. Westerly elected to not participate for its full working interest in this well and has a working interest on this well of 15%. The Company was able to arrange for two unrelated parties to participate for an additional 20%. As a result, the Company has a working interest in this well of 65%. The Company incurred costs relating to the well totaling $1,166,225. These wells are currently producing and are operated by NRG.

F-11

During the fiscal year 2012, the Company drilled two wells, the Livestock 7-1 and Livestock 18-1 for a total cost of $1,223,535 and $1,275,699, respectively. Westerly elected to not participate for its full working interest in these wells and has a working interest of 11.4% and 8.55%, respectively. The Company was able to arrange for four unrelated parties to participate in each of these wells for an additional 26%. As a result, the Company has a working interest in these well of 62.8% and 65.65%. These wells began production in November 2012. These wells are currently producing and are operated by NRG.

During the fiscal year 2014, the Company participated in the drilling of three wells, the Livestock 7-2, Livestock 18-2 and the BVR 5-1 for a total cost of $1,015,980, $1,024,117 and $1,009,284, respectively. The Company owned 100% of the working interest in the wells during drilling operations. The Company reported an impairment of $2,219,813 of these costs during the quarter ended January 31, 2014. Subsequent to the drilling of these wells, the Company transferred approximately 59% in working interests to third parties and recorded a gain of $1,639,394. The Company has a working interest in these well of 41.46%. These wells are operated by a third party and began production in June 2014.

Unproved Properties

Pedregosa Basin Field Acquisition in June 2010

On June 18, 2010, the Company 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) for an initial acquisition cost of $1.5 million (the “Exploration Agreement”). Pursuant to the agreement, $1 million was paid at purchase and the remaining $500 thousand was due and subsequently paid on November 1, 2010. The property has no production and was accounted for as an acquisition of unproved property. Pursuant to an agreement, the Company was obligated to carry the drilling costs for a test well up to $1.2 million. Costs in excess of $1.2 million are to be split based upon the parties working interest. During the quarter ended April 30, 2011, the Company began drilling on a test well. The Company incurred $1,665,142 in capitalized exploration costs. During the quarter ended October 31, 2011, the Company determined that there were not economically feasible hydrocarbons at the test well site and expensed the costs of the well as exploration costs. During 2012, the Company determined that it owed an additional $952,320 for the drilling of this test well based on cost over runs reported to the Company by the operator of the well. During 2013, the Company was informed that an additional $171,790 was due on the drilling of the test well. This amount is reported in the statement of operations as exploration costs. At October 31, 2014, the Company owes the entire balance of $1,124,110, which is reflected in accrued expenses. The current leases are being held by production by other wells in the area the Company did not participate in which are operated by the other working interest owner. In October 2013, the Company recorded an impairment charge for the remaining leasehold costs totaling $1,781,214.

Del Norte Acquisition in September 2010

On September 9, 2010, the Company acquired a 50% undivided leasehold working interest in and to approximately 3,200 acres of land located in Rio Grande County in Colorado from Dan A. Hughes Company for an initial acquisition cost of $200,000. The property has no production and was accounted for as an acquisition of unproved property. Pursuant to the agreement, the Company has the option to participate in the drilling of a test well. If the Company participates in the drilling of this test well, all costs associated with the well will be borne equally. As a result of this acquisition, the Company recorded $200,000 in unproved properties. In August 2011, leases covering approximately 1,240 of these acres expired. As a result, the Company reported an impairment charge of $77,703 for the year ended October 31, 2012 for the expired leases. In October 2013, the Company recorded an impairment charge for the remaining leasehold costs totaling $138,381.

F-12

3.  Debt

The following is a summary of the debt outstanding at October 31,

	2014		2013
Silver Bullet Properties	$	3,220,000	$	3,220,000
PIE Energy		60,000		60,000
KP-RAHR Ventures III, LLC, net of discount of $0 and $1,329,581		2,600,000		1,270,419
Pacific LNG Operations LTD net of discount of $1,312,873 and $0		187,127		--
Total		6,067,127		4,550,419
Less current maturities		60,000		280,000
Long-term debt	$	6,007,127	$	4,270,419

Silver Bullet Properties

The Company entered into a series of loan agreements with Silver Bullet Property Holdings SDN BHD (the “Investor”) for promissory notes totaling of $1,500,000, $1,000,000, $500,000 and $220,000 on November 19, 2010, September 27, 2011, June 12, 2012 and August 28, 2013, respectively. The notes bear interest at the rate of 10% per annum until July 20, 2013, after which the notes bear interest at the rate of 12% per annum. The notes as amended are due December 31, 2015. Pursuant to a security agreement, dated September 27, 2011, the Company granted the Investor a first priority lien on the Company’s oil and gas mineral leases in the ApClark Field. The Investor subordinated it’s liens to KP Rahr in July 2013 (see joint venture agreement below).In April 2012, the Company granted a net proceeds interest totaling 9%. The net proceeds interest represents the amount remaining from the proceeds of the sale of the property after deducting the related costs.

In August 2014, the Company and the Investor entered into an Amendment and Exchange Agreement (the “August 2014 Amendment”). Pursuant to the August 2014 Amendment, all accrued and unpaid interest through June 30, 2014 on the outstanding notes issued to the Investor, totaling $1,052,407, was exchanged for 1,052,407 shares of the Company’s common stock. In addition, interest accrued on the notes is to be paid quarterly in arrears in shares of the Company’s common stock based upon the average common stock price for the last five trading days of the quarter. As a result of the issuance of the shares for the accrued interest due the Investor through June 30, 2014, the company recorded a loss on the extinguishment of debt of $841,926, which is the amount the value of the shares issued exceeded the amount of the accrued interest. As a result of these issuings, Silver Bullet controls in excess of 10% of the Company’s issued and outstanding stock and the outstanding balance on these notes is reflected on the balance sheet as notes payable from a related party.

In December 2014, 20,183 and 74,574 shares were issued for interest accruing for the month of July 2014 and for the quarter ended October 31, 2014.

Pacific LNG Operations LTD.

On June 6, 2014, the Company entered into a subscription agreement with Pacific LNG Operations Ltd., a company incorporated in the British Virgin Islands (“Pacific LNG”), whereby the Company issued to Pacific LNG, in exchange for $2,000,000, a (i) $1,500,000 principal face amount 5% Convertible Debenture (“Debenture”) convertible into shares of Series B Preferred (Note 5) at a conversion price of $1.00 per share, and (ii) $500,000 in exchange for 500,000 shares of Series B Preferred.

The Debenture accrues interest at the rate of 5% per annum, payable semi-annually in arrears, and matures on June 6, 2017. Pacific LNG has the right, at any time prior to June 6, 2015, to convert the outstanding principal and interest, if any, of the Debenture into shares of Series B Preferred at a price of $1.00 per share of Series B Preferred.

F-13

Each share of Series B Preferred has a stated value of $1.00 (“Stated Value”) and accrues a dividend of 3% of the Stated Value per annum, which is payable in additional shares of Series B Preferred annually on December 31 in arrears. Each share of Series B Preferred may be converted at any time on or prior to May 30, 2017 into such number of shares of the Company’s common stock equal to the Stated Value divided by $1.00 per share. The Company has the right, at any time after May 30, 2017, to redeem the Series B Preferred at a price of $1.00 per share. Management has evaluated the Series B Preferred and its related terms and determined there are no embedded derivatives.

In connection with the issuance of the Debenture, the Company has reported a beneficial conversion feature for the difference between the conversion price pursuant to the Debenture and the quoted price of the Company’s common stock on the date of the agreement. On the date of the agreement, a discount totaling $1,350,000 was recorded. The unamortized discount which at October 31, 2014 was $1,312,873, will be amortized over the remaining term of the Debenture using the effective interest method. In addition, a deemed dividend totaling $450,000 was recorded in connection with the beneficial conversion feature associated with the conversion features in the Series B Preferred.

PIE Energy

In November 2009, the Company received an interest-free advance from an unrelated third party totaling $60,000. In January 2011, the interest-free advances were converted into a note payable, which was due on January 11, 2012 and has a stated annual interest rate of 6%. In January 2012, the parties amended the agreement to extend the due date to January 11, 2013. All other terms and conditions remained unchanged. The note has not been extended further nor has the Company received a notice of default.

Joint Venture Agreement

On July 20, 2012, Blacksands Petroleum, Inc. (the “Company”) entered into a Contribution Agreement (the “Contribution Agreement”), between APClark, LLC, a subsidiary of the Company (“APClark”) and KP-RAHR Ventures III, LLC (“KP Ventures”). Pursuant to the Contribution Agreement (i) the Company contributed $1,000 and certain of the Company’s oil and gas assets to APClark in exchange for 1,000 shares of Class A Membership Units of ApClark (the “Class A Membership Units”) and (ii) KP Ventures contributed approximately $2,600,000 (the “KP Ventures Cash Consideration”) to APClark in consideration of 1,000 shares of Class B Non-Voting Convertible Preferred Membership Units of APClark (the “Class B Membership Units” and the transaction, the “Asset Transaction”). KP Ventures has the option to contribute additional funds to APClark, up to an aggregate of $7,600,000, for no further equity consideration.

In connection with the Contribution Agreement, the Company entered into a Company Agreement (the “Company Agreement”) governing the operations of APClark and defining various rights of the Company and KP Ventures.

Pursuant to the Company Agreement, KP Ventures shall receive a preferred return of 12% per annum (the “Preferred Return”) on the unrecovered KP Ventures Cash Consideration until such time as the KP Ventures Cash Consideration is repaid. In addition, KP Ventures receives a 1% overriding royalty from the production of the APClark oil and gas properties. Once the KP Ventures Cash Consideration is repaid, including all accrued Preferred Returns, the Class B Membership Units shall automatically convert into Class C Non-Voting Net Profit Membership Units (the “Class C Membership Units”), which represent a non-dilutable “Net Profits” interest (“NPI”) in APClark and the assets owned by APClark and a percentage of all outstanding membership units of APClark initially equal to the NPI. The amount of the NPI granted depends on when the KP Ventures Cash Consideration and Preferred Return is paid, as follows:

Date of Repayment in Full	NPI %
On or prior to six month anniversary		7.5	%
After six months but on or prior to two year anniversary		15	%
After two years but on or prior to three year anniversary		20	%
After three years		50	%

F-14

The Company will be responsible for the operations of APClark and has the right to appoint the sole director of APClark, The consent of KP Ventures is required in certain situations, including, but not limited to: expanding the scope of the business; admitting additional members or transfer of membership units; approve annual budget; any merger or sale of all or substantially all of the assets of APClark; voluntary liquidation, dissolution or winding up of APClark; and to make any cash distributions.

In addition, the Company entered into a Pledge Agreement (the “Pledge Agreement”) pursuant to which it pledged the Class A Membership Units to KP Ventures to secure the Company’s obligations and performance thereunder and under the Contribution Agreement and Operating Agreement, which such Class A Membership Units shall be held pursuant to an escrow agreement.

Previously, the Company entered into a security agreement, dated as of September 27, 2011, pursuant to which, as security for the repayment of promissory notes in the principal face amount of $3,000,000 (the “Notes”), issued to Silver Bullet Property Holdings SDN BHD (“Silver Bullet”) a first priority security interest (the “Security Interest”) in certain of the assets of the Company that were contributed to APClark pursuant to the Contribution Agreement (the “Pledged Assets”). In connection with the Asset Transaction, the Company, APClark, Silver Bullet and KP Ventures entered into a subordination agreement (the “Subordination Agreement”), pursuant to which Silver Bullet subordinated its Security Interest to KP Ventures, so that KP Ventures would have a first priority interest in the Pledged Assets until KP Ventures is repaid the KP Ventures Cash Consideration and Preferred Return. In addition, the Company previously granted Silver Bullet a “net proceeds” interest of 9% on the Pledged Assets (the “Silver Bullet NPI”), which Silver Bullet NPI was capped at 25% of the outstanding principal and accrued interest owed under the Notes (the “Silver Bullet NPI Limitation”).

As a result of the required repayment of the equity to KP Ventures, the amount of the contribution has been reflected as a liability on the balance sheet. The Company has also recorded a discount on this liability relating to the relative fair value of the overriding royalties totaling $163,786 and net profits interest totaling $1,915,231. These discounts reduced the carrying value of the proved oil and gas costs. The discounts were fully amortized at October 31, 2014. The Company amortized $1,329,581 and $678,553 as additional interest expense in the fiscal years ended October 31, 2014 and 2013, respectively.

4. Asset Retirement Obligation

The following table summarizes the change in the asset retirement obligation (“ARO”) for the years ended October 31,

	2014			2013
Beginning balance at November 1	$	649,233		$	609,502
Liabilities settled		--			--
Liabilities incurred through acquisition of assets		--			--
Liabilities transferred through sale of assets		(617,189	)		--
Change in estimate of well life		43,957			--
Accretion expense		15,706			39,731
Ending balance at October 31	$	91,707		$	649,233

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.

F-15

5. Stockholders Equity 

Preferred Stock

The Company is authorized to issue 10,000,000 shares of preferred stock at a par value of $.001.

Series A Preferred Stock

In October 2010, the Board of Directors (“Board”) designated 310,000 shares of the Company’s preferred stock as Series A Convertible Preferred Stock (“Series A Preferred”). The Series A Preferred are convertible into shares of common stock at a conversion price of $3.75. The shares are entitled to dividends at a rate of 8% of the stated value per share per annum. The dividends are payable annually on December 31 in cash or additional shares of the Series A Preferred, at the option of the Company. The Series A Preferred and any accrued and unpaid dividends mandatorily convert into common shares on October 29, 2013. The outstanding Series A Preferred and accumulated unpaid dividends were converted into 826,667 shares of the Company’s common stock on October 29, 2013.

On October 29, 2010, the Company and Talras Overseas S.A. (“Talras”) entered into an exchange agreement, whereby $2,500,000 in notes payable were exchanged for 250,000 shares of the Company’s Series A convertible preferred stock and warrants to purchase 333,333 shares of the Company’s common stock. The warrants were exercisable at an exercise price of $6 per share through October 29, 2013. The preferred shares and accumulated dividends were converted into 826,667 shares of common stock on October 29, 2013. The warrants expired unexercised.

Series B Preferred Stock

On May 30, 2014, the Board of the Company approved the filing of a Certificate of Designation of Preferences, Rights and Limitations of Series B Convertible Preferred Stock (the “Certificate of Designation”), which was filed with and accepted by the Secretary of State of Nevada on June 6, 2014. Pursuant to the Certificate of Designation, the Company established a new series of 2,217,281 shares of the Series B Convertible Preferred Stock (“Series B Preferred Stock”).

Each share of Series B Preferred Stock has a stated value of $1.00 (“Stated Value”) and accrues a dividend of 3% of the Stated Value per annum, which is payable in additional shares of Series B Preferred Stock annually on December 31, in arrears. Each share of Series B Preferred Stock may be converted at any time on or prior to May 30, 2017 into such number of shares of the Company’s common stock equal to the Stated Value divided by $1.00 per share. The Company has the right, at any time after May 30, 2017, to redeem the Series B Preferred Stock at a price of $1.00 per share. In June 2014, the Company issued 500,000 shares of the Series B Preferred Stockin exchange for $500,000 pursuant to a subscription agreement with Pacific LNG (see note 3). At October 31, 2014, there were 500,000 shares of the Series B Preferred Stock outstanding. A deemed dividend totaling $450,000 was recorded in connection with the beneficial conversion feature associated with the conversion features of the Series B Preferred Shares.

Series C Preferred Stock

On October 15, 2014, the Board the Company approved the filing of a Certificate of Designation of Preferences, Rights and Privileges of Series C Convertible Preferred Stock (“Certificate of Designation”), which was filed with and accepted by the Secretary of State of the State of Nevada on October 16, 2014. Pursuant to the Certificate of Designation, the Company established a new series of 1,750,000 shares of the Series C Convertible Preferred Stock (“Series C Preferred Stock”).

F-16

Each share of Series C Preferred Stock has a stated value of $1.00 (“Stated Value”) and accrues a dividend of 3% of the Stated Value per annum, which is payable in additional shares of Series C Preferred Stock annually on December 31, in arrears, and beginning on December 31, 2014. Each share of Series C Preferred Stock may be converted at any time on or before June 30, 2017, into such number of shares of the Company’s common stock equal to the Stated Value divided by $1.00 per share. The Company has the right, at any time after June 30, 2017, to redeem the shares of Series C Preferred Stock, either in whole or in part, at the price of $1.00 per share. There are no voting rights underlying the Series C Preferred Stock. In October 2014, the Company issued 1,000,000 shares of the Series C Preferred Stock in exchange for $1,000,000. At October 31, 2014, there were 1,000,000 shares of Series C Preferred Stock outstanding. A deemed dividend totaling $390,000 was recorded in connection with the beneficial conversion feature associated with the conversion features of the Series C Preferred Shares.

Issuances of Common Stock

In October 2013, the Company issued 500,000 shares of its common stock to Silver Bullet in exchange for $1,000,000. The base price paid by Silver Bullet will be reduced and additional shares issued if there is an issuance of securities or repricing of an existing right to a price less than the base share price paid by Silver Bullet prior to October 23, 2014. As a result of the issuance of the debenture and Series B Preferred stock which had a conversion price of $1 per share, an additional 500,000 shares were required to be issued to Silver Bullet pursuant to the price protection clause. The Company reported the issuance of these shares as an equity transaction as the shares were issued in relation to the prior equity issuance, there were no derivative reporting on the original equity tranasaction and there were no additional services or goods provided.

During 2014, the Company recorded the vesting of 6,250 restricted shares of the Company’s common stock that were granted to a director. The Company recorded a stock based compensation expense for the vesting of the shares totaling $8,438.

Stock Options

As of June 26, 2006, the Company’s Board of Directors approved, and a majority of the Company’s stockholders ratified, the adoption of the Company’s 2006 Stock Option Plan (the “Plan”), pursuant to which the Board of Directors has the ability to provide incentives through the issuance of options, stock, restricted stock, and other stock-based awards, representing up to 2,000,000 shares of the Company’s common stock, to certain employees, outside directors, officers, consultants and advisors. The 2006 Stock Option Plan allows the term of options granted to be determined by the Board of Directors not to exceed ten years. The Board of Directors is authorized to determine the vesting requirements of the options granted.

During the Fiscal year ended October 31, 2012, stock options were granted to a director of the Company for options representing 88,000 common shares. The exercise price of the option is $4.50, with a ten year term, vesting equally over four years. The fair value of the option grants were estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 134%, risk free interest rate of 0.77%; and expected lives of 3.7 years. During the years ended October, 31, 2014 and 2013, the Company recorded stock based compensation totaling $(35,584) and $238,980 as a result of the stock option grants. Included in stock based compensation for the fiscal year ended October 31, 2014 is a reduction of $68,730 that was previously recognized on unvested options which were forfeited.

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

	Number of Shares		Weighted Average Exercise Price
Outstanding at November 1, 2012		1,046,333		3.13
Granted		--	$	--
Exercised		-		-
Cancelled		--		--
Outstanding at October 31, 2013		1,046,333	$	3.13
Granted		--		--
Exercised		-		-
Cancelled		979,666		4.50
Outstanding at October 31, 2014		66,667	$	3.00
Exercisable at October 31, 2014		66,667	$	3.00

The intrinsic value of the exercisable options at October 31, 2014 totaled $0. At October 31, 2014, the weighted average remaining life of the stock options is 5.44 years. At October 31, 2014, there was $0 of total unrecognized compensation cost related to the stock options granted under the plan.

F-17

Warrants

A summary of the Company’s stock warrant activity and related information for the years ended October 31, 2014 and 2013 is as follows:

	Warrants			Weighted Average Exercise Price
Outstanding at November 1, 2012		2,390,601		$	4.71
Granted		--			--
Cancelled		(333,333	)		6.00
Outstanding at October 31, 2013		2,057,268		$	4.50
Granted		--		$	--
Cancelled		(2,057,268	)	$	4.50
Outstanding at October 31, 2014		--		$	--

6. Commitments and Contingencies

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of October 31, 2014, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past noncompliance with environmental laws will not be discovered on the Company’s properties.

On January 26, 2015, David DeMarco, a former Chief Executive Officer and director of the Company, filed a complaint against the Company in the District Court of Harris County, Texas, alleging that pursuant to a contract for work performed and/or services rendered, Mr. DeMarco is due $151,000 in deferred compensation that accrued during his tenure as Chief Executive Officer of the Company. The Company believes that Mr. DeMarco is currently an officer of an affiliate of PIE Holding LLC, the operator of five of the Company's wells. Mr. DeMarco is seeking between $200,000 and $1 million in damages. As of the date of this filing, service of process has not been effected. The Company has reported $151,000 in accrued expenses.

Operating leases

The Company leases its offices Texas on a month to month basis. Rent expense for the years ended October 31, 2014 and 2013 was $40,494 and $47,832, respectively.

F-18

7. Income Taxes

The reconciliation between the expected income tax benefit, computed using the statutory federal rate of 34%, and the actual income tax benefit is as follows:

	October 31,
	2014			2013
Expected tax benefit at 34%	$	2,113,525		$	2,853,951
Stock option expenses		(14,139	)		(89,672	)
Miscellaneous		(312,681	)		1,762
Loss on extinguishment		(286,256	)		--
Amortization of debt discount		(464,681	)		(230,708	)
Change in valuation allowance		(1,035,768	)		(2,535,333	)
Actual tax benefit	$	--		$	-

The composition of deferred tax assets/liability is as follows:

	October 31,
	2014			2013
Deferred Tax Asset
Net operating loss	$	7,037,058		$	5,234,969
Oil and gas property interests		630,168			1,211,160
Other		196,982			382,311
Total deferred tax assets	$	7,864,208		$	6,828,440
Valuation allowance		(7,864,208	)		(6,828,440	)
Net	$	--		$	--

The valuation allowance increased by $1,035,768 during the year ended October 2014. The Company established a valuation allowance to fully offset the net deferred income tax assets due to the uncertainty of the Company's ability to generate future taxable income necessary to realize these net deferred income tax assets, considering the Company's history of significant operating losses. In addition, future utilization of the available net operating loss carryforwards may be limited under Internal Revenue Code Section 382 as a result of any future changes in ownership.

For federal income tax purposes, the Company has net operating losses of approximately $20,597,272 at October 31, 2014. These losses expire as follows:

2026	$	291,662
2027		1,739,955
2028		1,265,101
2029		769,546
2030		588,394
2031		5,153,072
2032		3,748,939
2033		1,438,676
2034		5,601,927
	$	20,597,272

8. Supplemental Oil and Gas Disclosures (Unaudited)

The following supplemental information regarding the oil and gas activities of the Company for 2014 and 2013 is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and ASC 932, "Disclosures About Oil and Gas Producing Activities." Capitalized costs relating to oil and gas activities and costs incurred in oil and gas property acquisition, exploration and development activities for each year are shown below.

F-19

CAPITALIZED COST OF OIL AND GAS PRODUCING ACTIVITIES

	2014			2013
As of October 31	United States			United States
Unproved properties not being amortized	$	--		$	--
Proved property being amortized		10,515,204			8,387,479
Accumulated depreciation, depletion amortization and impairment		(9,779,448	)		(6,309,607	)
Net capitalized costs	$	735,756		$	2,077,872

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES

As of October 31	2014		2013
Property acquisition costs—proved and unproved properties	$	--	$	--
Exploration costs	$	--	$	699,335
Development costs	$	3,681,623	$	649,003

OIL AND GAS RESERVES

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

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

F-20

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Hite & Associates for the years ended October 31, 2014 and 2013, respectively. The oil and natural gas price as of October 31, 2014 and 2013 is based on the 12-month unweighted average of the first of the month prices of the West Texas Intermediate posted price. The oil and natural gas prices were adjusted by lease for quality, transportation fees, and regional price differentials. The gas price as of October 31, 2014 and 2013 is based on the 12-month unweighted average of the first of the month prices of the Henry Hub spot price. All prices are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.

	Oil BBls			Gas Mcf
October 31, 2012		586,300			510,090
Revisions of previous estimates		(511,801	)		(296,245	)
Acquisition of minerals in place		--			--
Sales of minerals in place		--			--
Production		(16,139	)		(18,285	)
October 31, 2013		58,360			195,560
Revisions of previous estimates		(17,503	)		(154,195	)
Acquisition of minerals in place		--			--
Sales of minerals in place		(910	)		(4,570	)
Production		(11,107	)		(19,395	)
October 31, 2014		28,840			17,400

The Company's proved developed reserves are as follows:

	Developed				Undeveloped
	Oil BBls		Gas Mcf		Oil BBls		Gas Mcf
October 31, 2014		28,840		17,400		--		--
October 31, 2013		58,360		195,560		--		--
October 31, 2012		76,000		234,526		510,300		275,564

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOW

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

The Company believes that the following factors should be taken into account when reviewing the following information:

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

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

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

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

F-21

Under the Standardized Measure, for the years ended October 31, 2014 and 2013 the future cash inflows were estimated by applying the 12 month average of the oil and natural gas prices on the first day of the month ($98.13 and $92.60 for oil and $4.29 and $2.34 for natural gas for the years ended October 31, 2014 and 2013, respectively) to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices were required. At October 31, 2014 and 2013, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month (12-month unweighted average) cash price quotes, except for volumes subject to fixed price contracts.

	2014			2013
Future cash inflows	$	2,623,080		$	6,077,480
Future development costs		(136,170	)		(321,400	)
Future production costs		(1,215,530	)		(2,940,800	)
Future income tax expenses		-			-
Future net cash flows before 10% discount		1,271,380			2,815,280
10%Annual discount for estimated timing of cash flows		(262,700	)		(713,950	)
Standardized measure discounted future net cash flows	$	1,008,680		$	2,101,330

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Company’s proved oil and natural gas reserves during each of the years in the two year period ended October 31, 2014:

	2014			2013
Beginning of the year	$	2,101,330		$	7,682,610
Sales and transfers of oil and gas produced, net of production costs		(799,057	)		(924,607	)
Net changes in prices and production costs		306,123			(6,104,363	)
Net changes in income taxes		-			-
Production costs incurred		61,626			647,901
Changes in estimated future development costs, net of current development costs		(166,349	)		16,571,027
Acquisition of minerals in place		--			--
Revision of previous estimates		(519,601	)		(12,918,359	)
Change of discount		210,833			768,261
Change in production rate and other		(186,225	)		(3,621,140	)
End of year	$	1,008,680		$	2,101,330

F-22

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

None.

ITEM 9A – CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures.

Our management, with the participation of our Interim President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act. 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 management’s evaluation, our Interim President and Chief Financial Officer concluded that, as of October 31, 2014, our disclosure controls and procedures were not designed at a reasonable assurance level and were ineffective 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 SEC rules and forms, and that such information is accumulated and communicated to our management, including our interim president and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. The material weaknesses, which relate to internal control over financial reporting, that were identified are: 

a)

Due to our small size, we did not have sufficient personnel in our accounting and financial reporting functions nor do we have a proper segregation of duties. During the year ended October 31, 2014, we had limited staff that performed nearly all aspects of our financial reporting process, including, but not limited to, access to the underlying accounting records and systems, the ability to post and record journal entries and responsibility for the preparation of the financial statements. This creates certain incompatible duties and a lack of review over the financial reporting process that would likely result in a failure to detect errors in spreadsheets, calculations, or assumptions used to compile the financial statements and related disclosures as filed with the Securities and Exchange Commission. In addition, we have had an overreliance on consultants involved in our financial statement closing process. As a result we were not able to achieve adequate segregation of duties and were not able to provide for adequate reviewing of the financial statements. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the financial statements will not be prevented or detected on a timely basis; and

b)

Our executive officers only work for the Company on a part-time basis, have outside interests and are unable to devote all of their business time and effort to the Company. As a result, they may be unable to provide the level of oversight required.

We are committed to improving our financial organization. We will look to increase our personnel resources and technical accounting expertise within the accounting function to resolve non-routine or complex accounting matters. In addition, when funds are available, 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. As our operations are relatively small and we continue to have net cash losses each quarter, we do not anticipate being able to hire additional internal personnel until such time as our operations are profitable on a cash basis or until our operations are large enough to justify the hiring of additional accounting personnel. As necessary, we will engage consultants in the future 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.

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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. Due to the fact that our internal accounting staff consists of a Chief Financial Officer and a bookkeeper, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. Additional personnel will also provide the cross training needed to support us if personnel turn over issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.

In addition to the accounting personnel to be hired in the future, we are actively searching for a full time Chief Executive Officer to oversee our operations.

(b) Changes in internal control over financial reporting.

There were no changes in our internal control over financial reporting that occurred during the quarter ended October 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

(c) Management’s report on internal control over financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of October 31, 2014.

This annual report does not include an attestation report by Malone Bailey LLP, our independent registered public accounting firm, regarding internal control over financial reporting. As a smaller reporting company, our management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

ITEM 9B – OTHER INFORMATION

None.

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PART III

ITEM 10 – DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The names of our directors and executive officers and their ages, titles, and biographies as of February 5, 2015 are set forth below:

NAME	AGE	OFFICE HELD
Rhonda Rosen	58	Interim President
Donald Giannattasio	58	Chief Financial Officer
Rick Wilson	57	Director
Harold Hodgson	55	Director
Al Conrad Kerr, Jr.	58	Director

Directors are elected annually and hold office until the next annual meeting of the stockholders of the Company and until their successors are elected. Officers are elected annually and serve at the discretion of the Board of Directors. There is no family relationship between any of our executive officers or directors.

Rhonda Rosen has been our Interim President since December 30, 2013. Between October and December 2013, Ms. Rosen has served as a consultant to the board of directors of the Company. She also serves as part time Chief Financial Officer of RenovaCare, Inc. Between June and September 2013, Ms. Rosen served as the interim President and Chief Executive Officer of RenovaCare, Inc. From May 2012 through March 2013, Ms. Rosen served as the Chief Financial Officer of Armada Oil, Inc. From August 2010 through February 2012, Ms. Rosen was the Treasurer, Chief Financial Officer and Chief Administrative Officer of Tonix Pharmaceuticals Holding Corp. and its wholly owned subsidiaries. Ms. Rosen has also been a partner at Tatum since March 2010, where she provides executive level financial consulting services. Between July 2007 and February 2010, Ms. Rosen served as the Treasurer and Chief Financial Officer of Validus Pharmaceuticals LLC and its predecessor companies. Between November 2006 and July 2007, Ms. Rosen was the Senior Vice President of Wood Creek Capital Management, the founding sponsor of Validus Pharmaceuticals LLC. Previously, Ms. Rosen was the Director of Sales at Liability Solutions Inc. (2004 to 2005); Managing Director of Insurance and Alternative Asset Management Investment Banking at Putnam Lovell NBF (1999 to 2003); and Managing Director of Insurance Investment Banking at CIBC World Markets (formerly Oppenheimer & Co.) (1992-1999). Ms. Rosen earned her MBA in Finance & Accounting and her BS in Economics from The Wharton School of Business and her MS in Taxation from the Fox School of Business. Ms. Rosen started her career with PricewaterhouseCoopers LLP and is a Certified Public Accountant in the State of Pennsylvania.

Donald Giannattasio has been our Chief Financial Officer since October 2010. Since 1983, Mr. Giannattasio has been a partner in Seligson & Giannattasio, LLP, an accounting firm based in White Plains, New York. He has been a certified public accountant since 1980. Mr. Giannattasio graduated from Herbert H. Lehman College with a Bachelor of Science degree in Accounting in 1976.

Rick Wilson has been a Director since February 2007. Since April 2010, Mr. Wilson has been the President of Lions Bay Capital, Inc., a Toronto Venture Exchange listed company. Since December 2011, Mr. Wilson has been the President and a Director of Baroyeca Gold and Silver Inc., a Toronto Venture Exchange listed company. Since 2006, Mr. Wilson has been the President of Regent Ventures Ltd., a company engaged in the acquisition, exploration and development of mineral resource properties. Prior to serving as its President, Mr. Wilson was a director of Regent Ventures from 1993 to 2006. Mr. Wilson also served as the President of Emerson Explorations/GBS Gold International Inc. from 1998 to 2006. Mr. Wilson was selected to serve as a director due to his deep familiarity with our business, his extensive entrepreneurial background and his substantial financial and accounting experience.

Harold Hodgson has been a Director since June 2014. Mr. Hodgson was a financial advisor at Haywood Securities Inc. for over 30 years until May 2014. Mr. Hodgson has been the President and a Director of Langley International Speedway since 2003. Mr. Hodgson has also been a Director and Secretary of 4224973 Canada Inc., a closely held real estate company, since February 2013. Mr. Hodgson was a registered investment advisor in Canada until his retirement from Haywood Securities Inc. in May 2014. Mr. Hodgson was elected as the board representative for the holders of the Series B Preferred Stock. Mr. Hodgson was selected to serve as a director due to his familiarity with the Company’s business and the oil and gas industry.

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Al Conrad Kerr, Jr. has been a Director since December 2014. Mr. Kerr is a senior energy professional with over thirty (30) years of diversified experience in the natural gas, LNG, power generation, exploration and production industries in Africa, Asia, the Middle East and North America. His experience includes international business development, project execution and marketing as well as strategy planning. Since January 2011, Mr. Kerr has served as the Vice President of Pacific LNG Operations Ltd. in Singapore, a natural gas exploration company. Between June 2009 through January 2011, Mr. Kerr was a Principal of Caribbean LNG (Jamaica) Limited, a company working to develop natural gas distribution in Jamaica. Previously, Mr. Kerr was a Managing Director – Head of Global LNG at Merrill Lynch Commodities Inc. (2007 – 2009). Mr. Kerr previously worked for Mobil and ExxonMobil (1996 – 2007), Tenneco Gas Company (1994 – 1996), TransAlta Utility Corp. (1992 – 1994), Stewart and Stevenson Corporation (1986 – 1992) and Koomey Incorporated (1980 – 1985). Mr. Kerr has a Bachelor’s Degree in Business Administration from the University of Texas. Mr. Kerr was previously an Officer in the U.S. Merchant Marines with a Captain’s License from the United States Coast Guard. Mr. Kerr was selected to serve as a director due to his familiarity with the oil and gas industry.

Family Relationships

None.

Board Independence

We are not required to have any independent members of the Board of Directors. The board of directors has determined that Rick Wilson is an independent director as defined in the Marketplace Rules of The NASDAQ Stock Market.

Meetings and Committees of the Board of Directors

During the fiscal year ended October 31, 2014, our board of directors held two meetings and approved certain actions by unanimous written consent. We expect our directors to attend all board and committee meetings and to spend the time needed and meet as frequently as necessary to properly discharge their responsibilities. Due to the limited size of our board of directors, we have determined to suspend the use of board committees. As a result, the board as a whole carries out the functions of audit, nominating and compensation committees.

Involvement in Certain Legal Proceedings

Our Directors and Executive Officers have not been involved in any of the following events during the past ten years:

1.	any bankruptcy petition filed by or against such person or any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;
2.	any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
3.	being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from or otherwise limiting his involvement in any type of business, securities or banking activities or to be associated with any person practicing in banking or securities activities;
4.	being found by a court of competent jurisdiction in a civil action, the Securities and Exchange Commission or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;

43

5.

being subject of, or a party to, any federal or state judicial or administrative order, judgment decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of any federal or state securities or commodities law or regulation, any law or regulation respecting financial institutions or insurance companies, or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

6.

being subject of or party to any sanction or order, not subsequently reversed, suspended, or vacated, of any self-regulatory organization, any registered entity or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers and holders of more than 10% of our common stock to file with the SEC reports regarding their ownership and changes in ownership of our securities.

During fiscal 2014, we believe that our directors and executive officers complied with all Section 16(a) filing requirements. With respect to Silver Bullet, a holder of more than 10% of our common stock, Silver Bullet did not timely file an Initial Statement of Beneficial Ownership on Form 3 and a Statement of Changes in Beneficial Ownership on Form 4 regarding a transaction that should have been reported during fiscal 2014. The Company has informed Silver Bullet about the obligation to file the forms.

The table below accounts for the Form 3 and Form 4 reporting Silver Bullet’s holdings.

Name	# of Late Reports	Transactions Not Timely Reported	Known Failures to File a Required Form
Silver Bullet Property Holdings SDN BHD	2	2	2

Code of Business Conduct and Ethics/Business Conduct Policy

We adopted a Code of Business Conduct and Ethics in October 2007 that applies to all of our directors, officers, employees and consultants. The Code of Business Conduct and Ethics summarizes the legal, ethical and regulatory standards that we must follow and serves as a reminder to our directors, officers, employees, and contractors, of the seriousness of that commitment. Compliance with this code and high standards of business conduct is mandatory for each of our contractors.

Whistleblower Policy

As a public company, the integrity, transparency and accountability of the financial, administrative and management practices of the Company are critical. Accordingly in October 2008, we adopted a Whistleblower Policy.

44

ITEM 11 – EXECUTIVE COMPENSATION

Summary Compensation Table

The following table provides certain summary information concerning compensation awarded to, earned by or paid to our Chief Executive Officer and the highest paid executive officer and one other highest paid individual whose total annual salary and bonus exceeded $100,000 for fiscal years 2014 and 2013. In accordance with the rules of the SEC, this table omits columns that are not relevant.

Name and Principal Position	Year	Salary ($)		Option Awards ($)		All Other Compensation ($) (1)		Total ($)
Rhonda Rosen	2014		60,000		-		-		60,000
Interim President
Bruno Mosimann	2014		--		--		--		--
Interim Chief Executive Officer (2)	2013		--		--		--		--
David DeMarco	2014		157,636		--		--		157,636
Special Advisor and	2013		204,000		--		--		204,000
Former Chief Executive Officer (3)
Donald Giannattasio	2014		120,000		--		--		120,000
Chief Financial Officer	2013		120,000		--		--		120,000
Eric Urban	-		-		--		--		-
Special Advisor	2013		120,000		--		--		120,000
Henry Overstreet	2014		106,636		--		--		106,636
Manager of Operations	2013		138,000		--		--		138,000

______________

(1)	Other compensation represents consulting fees paid to or earned by the officers.
(2)	Mr. Mosimann served as interim chief executive officer between October 3, 2013 and December 24, 2013. He did not receive salary in addition to his fees as a member of the Board of Directors.
(3)	Mr. DeMarco served as chief executive officer until his resignation on October 3, 2013, then continued serving the Company as a Special Advisor until August 12, 2014.

Employment Contracts and Termination of Employment and Change-In-Control Arrangements

None.

Option/SAR Grants in Fiscal Year Ended October 31, 2014

None.

Outstanding Equity Awards at Fiscal Year-End

None.

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Equity Compensation Plan Information

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights		(b) Weighted-average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans excluding securities reflected in column (a) (1)
Equity compensation plan approved by security holders (1)		--	$	--		2,000,000
Equity compensation plan approved by security holders (2)		66,667	$	3.00		1,811,135
Total		66,667	$	3.00		3,811,135

(1)	We established the 2006 Plan, under which 2,000,000 shares of common stock were reserved for issuance upon the exercise of stock options, stock awards or restricted stock. As of October 31, 2014, no shares were issuable upon exercise of options granted to employees and directors.
(2)	We established the 2008 Plan, under which no more than 10% of the total number of shares of common stock issued and outstanding may be reserved for issuance upon the exercise of stock options, stock awards or restricted stock. As of October 31, 2014, 1,018,833 shares were issuable upon exercise of options granted to employees and directors.

Director Compensation

The following table summarizes the compensation for our non-employee board of directors for the fiscal year ended October 31, 2014. All compensation paid to our employee directors is included under the summary compensation table above.

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)		Option Awards ($)		All Other Compensation ($)		Total ($)
Rick Wilson		10,000		--		--		--		10,000
Bruno Mosimann (1)		10,000		--		--		--		10,000
Richard Hunter (2)		20,000		--		--		--		20,000
Harold Hodgson		--		--		--		--		--

____________

(1)	Mr. Mosimann resigned as a director on December 24, 2013.
(2)	Mr. Hunter resigned as a director effective August 1, 2014.

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

The following table sets forth certain information regarding beneficial ownership of our common stock as of February 5, 2015:

· by each person who is known by us to beneficially own more than 5% of our common stock;

· by each of our officers and directors; and

· by all of our officers and directors as a group.

Name And Address Of Beneficial Owner (1)	Number of  Shares Owned (2)			Percentage of Class (3)
Executive Officers and Directors
Rhonda Rosen		0			*
Donald Giannattasio		1,000			*
Rick Wilson		66,667	(4)		*
Harold Hodgson		1,092,922			5.79	%
Al Conrad Kerr, Jr.		0			*
All Officers and Directors as a Group (6 persons)		1,160,589			6.15	%
Silver Bullet Property Holdings SDN BHD		2,147,165			11.38	%

____________

* Denotes less than 1%.

(1)	The address for each of our officers and directors is 800 Bering, Suite 250, Houston, Texas 77057.
(2)	Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and generally includes voting or investment power with respect to securities. Shares of common stock subject to options or warrants currently exercisable or convertible, or exercisable or convertible within 60 days of February 5, 2015 are deemed outstanding for computing the percentage of the person holding such option or warrant but are not deemed outstanding for computing the percentage of any other person.
(3)	Percentage based on 18,872,832 shares of common stock outstanding as of February 5, 2015.
(4)	Represents 66,667 shares of common stock issuable to Rick Wilson, which may be acquired upon the exercise of stock options that were exercisable as of February 5, 2015.

47

ITEM 13 – CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Other than as disclosed below, during the last two fiscal years, there have been no transactions, or proposed transactions, which have materially affected or will materially affect us in which any director, executive officer or beneficial holder of more than 5% of the outstanding common, or any of their respective relatives, spouses, associates or affiliates, has had or will have any direct or material indirect interest. We have no policy regarding entering into transactions with affiliated parties.

On October 23, 2013, the Company issued 500,000 shares of common stock at a purchase price of $2.00 per share (the “Per Share Purchase Price”) to Silver Bullet pursuant to a common stock purchase agreement (the “Common Stock Purchase Agreement.”). The Common Stock Purchase Agreement contains an anti-dilution provision whereby the Company would be required to issue to Silver Bullet additional stock in the event the Company sold or granted equity or debt securities below the Per Share Purchase Price at any time until October 24, 2014. As a result of the issuance of the Debenture and Series B Preferred Stock on June 6, 2014, an additional 500,000 shares were issuable to Silver Bullet.

Subsequently on June 6, 2014, the Company entered into a subscription agreement with Pacific LNG whereby the Company issued a Debenture and Series B Preferred Stock at a purchase price of $1.00 per share. As a result of the transaction with Pacific LNG, the Company issued 500,000 shares of common stock to Silver Bullet pursuant to the aforementioned anti-dilution provision. Accordingly, as of June 6, 2014, Silver Bullet beneficially owned more than 5% of the Company’s outstanding common stock.

On August 26, 2014, the Company entered into a Exchange Agreement with Silver Bullet, which amended an aggregate amount of $3,220,000 of promissory notes held by Silver Bullet dated November 19, 2010, September 27, 2011, November 1, 2011, December 1, 2011, June 12, 2012 and August 28, 2013 such that (i) all interest accruing after June 30, 2014 shall be exchanged for shares of common stock on a quarterly basis in arrears and (ii) the maturity date of each of the promissory notes was extended to December 31, 2015. Pursuant to the Exchange Agreement, the Company issued 1,052,407 shares of common stock to Silver Bullet on September 2, 2014 in exchange for all accrued and unpaid interest on the promissory notes through June 30, 2014. Subsequently on December 18, 2014, we issued Silver Bullet an aggregate of 94,758 shares of common stock with 20,183 shares of common stock at a cost base of $1.62 per share and 74,575 shares of common stock at a cost base of $1.31 per share in exchange for interest due on the notes for the quarters ended July 31, 2014 and October 31, 2014 pursuant to the Exchange Agreement. The interest due on the notes for the quarter ended January 31, 2015 is $97,216.

On October 16, 2014, the Company entered into a subscription agreement with Silver Bullet whereby the Company issued to Silver Bullet 1,000,000 shares of Series C Preferred Stock at a purchase price of $1.00 per share.

ITEM 14 – PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit Fees. The aggregate fees billed by our independent auditors, for professional services rendered for the audit of our annual financial statements for the years ended October 31, 2014 and 2013, and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years were approximately $86,000 and $105,000, respectively.

Audit Related Fees. We incurred fees to our independent auditors of $nil for audit related fees during the fiscal years ended October 31, 2014 and 2013.

Tax and Other Fees. We did not incur fees to our independent auditors for tax and fees during the fiscal years ended October 31, 2014 and 2013.

The Board of Directors has considered whether the provision of non-audit services is compatible with maintaining the principal accountant’s independence.

48

PART IV

ITEM 15 – EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibits:

3.01	Articles of Incorporation, filed as an exhibit to the registration statement on Form SB-2, filed with the Securities Exchange Commission on December 10, 2004 and incorporated herein by reference.
3.02	Certificate of Amendment to the Articles of Incorporation, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on June 15, 2006 and incorporated herein by reference.
3.03	Certificate of Designation of the Series A Convertible Preferred Stock, filed as an exhibit to the annual report on Form 10-K, filed with the Securities Exchange Commission on February 2, 2011 and incorporated herein by reference.
3.04	Certificate of Amendment to the Articles of Incorporation, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on January 10, 2011 and incorporated herein by reference.
3.05	Bylaws, filed as an exhibit to the registration statement on Form SB-2, filed with the Securities Exchange Commission on December 10, 2004 and incorporated herein by reference.
3.06	Amendment to the Bylaws, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on April 30, 2009 and incorporated herein by reference.
3.07	Certificate of Designation of the Series B Convertible Preferred Stock, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on June 13, 2014 and incorporated herein by reference.
3.08	Certificate of Designation of the Series C Convertible Preferred Stock, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on October 21, 2014 and incorporated herein by reference.
10.01	2008 Stock Option Plan, filed as an exhibit to the definitive proxy statement on Schedule 14A, filed with the Securities Exchange Commission on June 9, 2010 and incorporated herein by reference.
10.02	Exploration Agreement dated as of June 18, 2010 among Blacksands Petroleum Texas, LLC and Dan A. Hughes Company, L.P., filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on June 22, 2010 and incorporated herein by reference.
10.03	Loan Agreement, dated as of November 19, 2010, by and between Blacksands Petroleum, Inc. and Silver Bullet Property Holdings SDN BHD, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on November 24, 2010 and incorporated herein by reference.
10.04	Form of Promissory Note, issued November 19, 2010, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on November 24, 2010 and incorporated herein by reference.
10.05	Form of Warrant, issued February 2, 2011, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on February 8, 2011 and incorporated herein by reference.

49

10.06	Form of Warrant, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on March 23, 2011 and incorporated herein by reference.
10.07	Allonge to Promissory Note, dated as of September 27, 2011, by and between Blacksands Petroleum, Inc. and Silver Bullet Property Holdings SDN BHD, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on October 19, 2011 and incorporated herein by reference.
10.08	Security Agreement, dated as of September 27, 2011, by and between Blacksands Petroleum, Inc. and Silver Bullet Property Holdings SDN BHD, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on October 19, 2011 and incorporated herein by reference.
10.09	Allonge to Promissory Note, dated as of April 9, 2012, by and between Blacksands Petroleum, Inc. and Silver Bullet Property Holdings SDN BHD, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on May 1, 2012 and incorporated herein by reference.
10.10	Contribution Agreement, dated as of July 20, 2012, by and among Blacksands Petroleum, Inc., ApClark, LLC and KP-RAHR Ventures III, LLC, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on July 26, 2012 and incorporated herein by reference.
10.11	Company Agreement of ApClark, LLC, dated as of July 20, 2012, by and between Blacksands Petroleum, Inc. and KP-RAHR Ventures III, LLC, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on July 26, 2012 and incorporated herein by reference.
10.12	Pledge Agreement, dated as of July 20, 2012, by and between Blacksands Petroleum, Inc. and KP-RAHR Ventures III, LLC, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on July 26, 2012 and incorporated herein by reference.
10.13	Escrow Agreement for Pledge of Membership Interest, dated as of July 20, 2012, by and among Blacksands Petroleum, Inc., KP-RAHR Ventures III, LLC and The Strong Firm P.C., filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on July 26, 2012 and incorporated herein by reference.
10.14	Subordination Agreement, dated as of July 20, 2012, by and among KP-RAHR Ventures III, LLC, Silver Bullet Property Holdings SDN BHD, Blacksands Petroleum, Inc. and ApClark, LLC., filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on July 26, 2012 and incorporated herein by reference.
10.15	Common Stock Purchase Agreement, by and between Blacksands Petroleum, Inc. and Silver Bullet Property Holdings SDN BHD, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on October 29, 2013 and incorporated herein by reference.
10.16	Partial Assignment of Oil, Gas and Mineral Leases and Bill of Sale of Wells, dated as of March 17, 2014, by and between ApClark, LLC and PIE Holdings, LP, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on June 13, 2014 and incorporated herein by reference.
10.17	Partial Assignment of Oil, Gas and Mineral Leases and Bill of Sale of Wells, dated as of March 31, 2014, by and between ApClark, LLC and PIE Holdings, LP, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on June 13, 2014 and incorporated herein by reference.
10.18	Subscription Agreement by and between Blacksands Petroleum, Inc. and Pacific LNG Operations Ltd., dated June 6, 2014, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on June 13, 2014 and incorporated herein by reference.

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10.19	Form of Debenture, dated June 6, 2014, issued to Pacific LNG Operations Ltd., filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on June 13, 2014 and incorporated herein by reference.
10.20	Amendment and Exchange Agreement, by and between Blacksands Petroleum, Inc. and Silver Bullet Property Holdings SDN BHD, dated August 26, 2014, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on August 29, 2014 and incorporated herein by reference.
10.21	Amendment 2 to Development Agreement, dated July 9, 2014, by and among ApClark, LLC, Blacksands Petroleum Texas, LLC, NRG Assets Management, LLC and Adwar Drilling Fund II, LP, filed as an exhibit to the quarterly report on Form 10-Q, filed with the Securities Exchange Commission on September 15, 2014 and incorporated herein by reference.
10.22	Participation and Development Agreement, dated August 9, 2014, by and between ApClark, LLC and Adwar Drilling Fund III, L.P., filed as an exhibit to the quarterly report on Form 10-Q, filed with the Securities Exchange Commission on September 15, 2014 and incorporated herein by reference.
10.23	Subscription Agreement by and between Blacksands Petroleum, Inc. and Silver BF Ventures SDN BHD, dated October 16, 2014, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on October 21, 2014 and incorporated herein by reference.
14.01	Code of Ethics, included in Business Conduct Policy, dated October 27, 2008, filed as an exhibit to the current report on Form 8-K, filed with the Securities Exchange Commission on October 28, 2008 and incorporated herein by reference.
21.01	Subsidiaries of the registrant+
23.01	Consent of Hite & Associates, Independent Petroleum Engineers+
31.01	Certification of Principal Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Certification of Principal Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certifications of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Report of Hite & Associates, Independent Petroleum Engineers+
101 INS	XBRL Instance Document
101 SCH	XBRL Taxonomy Extension Schema Document
101 CAL	XBRL Taxonomy Calculation Linkbase Document
101 LAB	XBRL Taxonomy Labels Linkbase Document
101 PRE	XBRL Taxonomy Presentation Linkbase Document
101 DEF	XBRL Taxonomy Extension Definition Linkbase Document

___________ 

 + filed herewith

51

SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BLACKSANDS PETROLEUM, INC.
Date: February 11, 2015	By:	/s/ Rhonda Rosen
		Rhonda Rosen
		Interim President (Principal Executive Officer)
Date: February 11, 2015	By:	/s/ Donald Giannattasio
		Donald Giannattasio
		Chief Financial Officer (Principal Financial Officer and Accounting Officer)

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

Name	Position	Date
/s/ Rick Wilson	Director	February 11, 2015
Rick Wilson
/s/ Harold Hodgson	Director	February 11, 2015
Harold Hodgson
/s/ Al Conrad Kerr, Jr.	Director	February 11, 2015
Al Conrad Kerr, Jr.

52

EX-21.01

EXHIBIT 21.01

SUBSIDIARIES OF THE COMPANY

Subsidiary Name	State of Incorporation/Formation
NRG Assets Management, LLC	Texas
Blacksands Petroleum Texas, LLC	Texas
Copano Bay Holdings, Inc.	Nevada
ApClark, LLC	Delaware

EX-23.01

EXHIBIT 23.01

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Hite & Associates, Inc. hereby consents to the reference to our firm and to its having audited certain estimates of oil and natural gas reserves as prepared by Blacksands Petroleum Inc. (the “Company”). The reserves are attributable to certain interest ownership positions held by the Company for the fiscal year ended October 31, 2014. We hereby further consent to the use of the reserve volumes as reviewed and certified and our report dated December 10, 2014 appearing in the Company’s Form 10-K for the year ended October 31, 2014 and in all current and future registration statements of the Company that incorporate by reference such Form 10-K.

Hite & Associates, Inc.

By: /s/ George C. Hite, P.E.

Dated: February 9, 2015

EX-31.01

EXHIBIT 31.01

CERTIFICATION

I, Rhonda Rosen, certify that:

1.	I have reviewed this annual report on Form 10-K of Blacksands Petroleum, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonable likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: February 11, 2015	By	/s/ RHONDA ROSEN
		Rhonda Rosen
		Interim President (Principal Executive Officer)

EX-31.02

EXHIBIT 31.02

CERTIFICATION

I, Donald Giannattasio, certify that:

1.	I have reviewed this annual report on Form 10-K of Blacksands Petroleum, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonable likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: February 11, 2015	By:	/s/ DONALD GIANNATTASIO
		Donald Giannattasio
		Chief Financial Officer

EX-32.01

EXHIBIT 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

I, Rhonda Rosen, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Blacksands Petroleum, Inc. on Form 10-K for the fiscal year ended October 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in this Annual Report on Form 10-K fairly presents in all material respects the financial condition and results of operations of Blacksands Petroleum, Inc.

	By:	/s/ RHONDA ROSEN
Date: February 11, 2015	Name:	Rhonda Rosen
	Title:	Interim President (Principal Executive Officer)

I, Donald Giannattasio, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Blacksands Petroleum, Inc. on Form 10-K for the fiscal year ended October 31, 2014 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in this Annual Report on Form 10-K fairly presents in all material respects the financial condition and results of operations of Blacksands Petroleum, Inc.

	By:	/s/ DONALD GIANNATTASIO
Date: February 11, 2015	Name:	Donald Giannattasio
	Title:	Chief Financial Officer

EX-99.01

EXHIBIT 99.01

Hite & Associates, Inc.

Petroleum Engineers / Business Advisors

712 Main Street · Suite 1701 · Houston, Texas 77002

Phone: 713.654.4141 · Fax: 713.654.4404 · www.hiteinc.com

December 10, 2014

Mr. Eric Urban

Blacksands Petroleum Inc.

800 Bering, Suite 250

Houston, TX 77057

Dear Mr. Urban:

At your request, we have estimated the proved reserves and future net cash flow attributable to certain interests owned by Blacksands Petroleum Inc. (Blacksands) as of October 31, 2014. This report has been prepared using operating costs obtained from Blacksands’ revenue and expense statements. The estimates of reserves and future net cash flow in this report have been prepared in accordance with Securities & Exchange Commission (SEC) definitions and the guidelines set forth in the Petroleum Resources Management System approved by the Society of Petroleum Engineers. The definitions are presented immediately following this letter.

As summarized in the following table, we estimate the net reserves and future net cash flow to Blacksands’ interest in these properties, as of October 31, 2014, to be:

	Net Reserves				Future Net Cash Flow (M$)
Category	Oil (MB)		Gas (MMCF)		Total		NPV @ 10%
Total Proved Producing*		28.84		17.40		1,271.4		1,008.7

* Includes Everett SWD well

The detailed cash flow projections and a one-line summary are attached to the report.

The oil reserves shown include crude oil and condensate. Liquid volumes are expressed in thousands of barrels (MB) with a barrel being equivalent to 42 US gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Mr. Eric Urban-Blacksands Petroleum, Inc. 

December 10, 2014

Page 2 of 4

The future net cash flow is after the deduction of production taxes, the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs and abandonment costs. The future net cash flow is before the deduction of state and federal income taxes and general administrative overhead and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. No attempt has been made to quantify or otherwise account for any accumulated gas production imbalances that may exist.

Estimates of Reserves

The reserves included herein were estimated by decline curve analysis. This method is based on the extrapolation of historical production data. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

Future Production Rates

Initial production rates were based on the current producing rates for the wells now on production.

The future production rates may be more or less than estimated because of changes in well performance, market demand or allowables set by regulatory bodies.

Hydrocarbon Prices

Historical hydrocarbon prices were provided by Blacksands. The oil and condensate index price forecast used was a flat WTI Cushing, OK spot price of $98.13 per barrel which represents the average first day of the month price for the previous 12 month period. The oil price in the field was calculated using historical field price differentials derived from Blacksands’ revenue and expense statements. The natural gas price was based on a flat $4.29 per MMBTU and represents the Henry Hub average for the first day of the month price for the months of November 2013 through October 2014. The gas price in the field was estimated using historical gas sales differentials.

Mr. Eric Urban-Blacksands Petroleum, Inc.

December 10, 2014

Page 3 of 4

Costs

Operating costs for the wells in this report were calculated using Blacksands’ revenue and expense statements. The costs included were only those costs directly applicable to the leases or wells. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses and exploration and development prepayments that are not charged directly to the leases or wells.

The estimated unescalated net cost of abandonment was included for each well and was provided by Blacksands. We make no warranty, expressed or implied as to the accuracy or completeness of this information.

General

This report presents our estimated projections of production and net cash flow by year after October 31, 2014. The estimates of reserves presented herein were based on a study of the certain properties in which Blacksands owns an interest; however, we have not made any field examination of the properties nor conducted any well tests. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Blacksands has informed us that they have provided us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices and other factual data provided by Blacksands were accepted without independent verification.

The estimates of reserves and future revenue included herein have not been adjusted for risk. We believe that Blacksands understands the uncertainties inherent in the interpretation of engineering, geological, geophysical and petrophysical data. The reserves and economic calculations contained in this report represent our informed professional judgment based on the data provided by Blacksands and information obtained by us. Due to political and economic forces, there is significant uncertainty regarding the forecasting of the future hydrocarbon prices. The recoverable reserves and the income attributable thereto are directly affected by the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Mr. Eric Urban-Blacksands Petroleum, Inc.

December 10, 2014

Page 4 of 4

Neither we, nor any of our employees have any interest in the subject properties and neither our employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.

This report was prepared for the exclusive use of Blacksands. The data, work papers and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Sincerely,

HITE & ASSOCIATES, INC.

TBPE FIRM REGISTRATION NO. F-1245

George C. Hite, P.E.

TPBE License No. 57184

President

GCH/cc

Attachments

Blacksands.EricUrban.12.10.2014

The work performed in this report for properties located in the State of Texas has been reviewed and approved by a licensed Texas Professional Engineer according to the rules of the Texas Board of Professional Engineers (TBPE).

XML

Supplemental Oil and Gas Disclosures (Unaudited) (Details 1) (USD $)	Oct. 31, 2014	Oct. 31, 2013
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES
Property acquisition costs proved and unproved properties
Exploration costs		699,335
Development costs	$ 3,681,623	$ 649,003

XML

Commitments and Contingencies (Details Narrative) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Commitments And Contingencies Details Narrative
Rent expense	$ 40,494	$ 47,832

XML

Oil and Gas Property Costs (Details Narrative) (USD $)	12 Months Ended
	Oct. 30, 2014	Oct. 31, 2014	Oct. 31, 2013	Oct. 31, 2012
Livestock 7-2 [Member]
Drilled wells cost	$ 1,015,980
Livestock 18-2 [Member]
Drilled wells cost	1,024,117
BVR 5-1 [Member]
Drilled wells cost		1,009,284
Unproved Properties [Member]
Impairment			1,934,595
Drilled wells cost		171,790
Unproved Properties [Member] | Del Norte Acquisition [Member]
Impairment			153,381
Unproved Properties [Member] | Pedregosa Basin [Member]
Impairment		1,781,214
Proved Properties [Member]
Impairment		3,630,194	2,886,175
Proved Properties [Member] | Cabeza Creek Field [Member]
Impairment			4,359	147,370
Gain on sale		645,323
Pedregosa Basin [Member] | Unproved Properties [Member]
Amount due		$ 1,124,110

XML

Supplemental Oil and Gas Disclosures (Unaudited) (Details 4) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Notes to Financial Statements
Future cash inflows	$ 2,623,080	$ 6,077,480
Future development costs	(136,170)	(321,400)
Future production costs	(1,215,530)	(2,940,800)
Future income tax expenses
Future net cash flows before 10% discount	1,271,380	2,815,280
10%Annual discount for estimated timing of cash flows	(262,700)	(713,950)
Standardized measure discounted future net cash flows	$ 1,008,680	$ 2,101,330

XML

Income Taxes (Details Narrative) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Income Taxes Details Narrative
Statutory federal rate	34.00%
Change in valuation allowance	$ (1,035,768)	$ (2,535,333)
Operating Loss Carry forwards	$ 20,597,272

XML

Debt

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 3. Debt

The following is a summary of the debt outstanding at October 31,

	2014		2013
Silver Bullet Properties	$	3,220,000	$	3,220,000
PIE Energy		60,000		60,000
KP-RAHR Ventures III, LLC, net of discount of $0 and $1,329,581		2,600,000		1,270,419
Pacific LNG Operations LTD net of discount of $1,312,873 and $0		187,127		--
Total		6,067,127		4,550,419
Less current maturities		60,000		280,000
Long-term debt	$	6,007,127	$	4,270,419

Silver Bullet Properties

The Company entered into a series of loan agreements with Silver Bullet Property Holdings SDN BHD (the “Investor”) for promissory notes totaling of $1,500,000, $1,000,000, $500,000 and $220,000 on November 19, 2010, September 27, 2011, June 12, 2012 and August 28, 2013, respectively. The notes bear interest at the rate of 10% per annum until July 20, 2013, after which the notes bear interest at the rate of 12% per annum. The notes as amended are due December 31, 2015. Pursuant to a security agreement, dated September 27, 2011, the Company granted the Investor a first priority lien on the Company’s oil and gas mineral leases in the ApClark Field. The Investor subordinated it’s liens to KP Rahr in July 2013 (see joint venture agreement below).In April 2012, the Company granted a net proceeds interest totaling 9%. The net proceeds interest represents the amount remaining from the proceeds of the sale of the property after deducting the related costs.

In August 2014, the Company and the Investor entered into an Amendment and Exchange Agreement (the “August 2014 Amendment”). Pursuant to the August 2014 Amendment, all accrued and unpaid interest through June 30, 2014 on the outstanding notes issued to the Investor, totaling $1,052,407, was exchanged for 1,052,407 shares of the Company’s common stock. In addition, interest accrued on the notes is to be paid quarterly in arrears in shares of the Company’s common stock based upon the average common stock price for the last five trading days of the quarter. As a result of the issuance of the shares for the accrued interest due the Investor through June 30, 2014, the company recorded a loss on the extinguishment of debt of $841,926, which is the amount the value of the shares issued exceeded the amount of the accrued interest. As a result of these issuings, Silver Bullet controls in excess of 10% of the Company’s issued and outstanding stock and the outstanding balance on these notes is reflected on the balance sheet as notes payable from a related party.

In December 2014, 20,183 and 74,574 shares were issued for interest accruing for the month of July 2014 and for the quarter ended October 31, 2014.

Pacific LNG Operations LTD.

On June 6, 2014, the Company entered into a subscription agreement with Pacific LNG Operations Ltd., a company incorporated in the British Virgin Islands (“Pacific LNG”), whereby the Company issued to Pacific LNG, in exchange for $2,000,000, a (i) $1,500,000 principal face amount 5% Convertible Debenture (“Debenture”) convertible into shares of Series B Preferred (Note 5) at a conversion price of $1.00 per share, and (ii) $500,000 in exchange for 500,000 shares of Series B Preferred.

The Debenture accrues interest at the rate of 5% per annum, payable semi-annually in arrears, and matures on June 6, 2017. Pacific LNG has the right, at any time prior to June 6, 2015, to convert the outstanding principal and interest, if any, of the Debenture into shares of Series B Preferred at a price of $1.00 per share of Series B Preferred.

Each share of Series B Preferred has a stated value of $1.00 (“Stated Value”) and accrues a dividend of 3% of the Stated Value per annum, which is payable in additional shares of Series B Preferred annually on December 31 in arrears. Each share of Series B Preferred may be converted at any time on or prior to May 30, 2017 into such number of shares of the Company’s common stock equal to the Stated Value divided by $1.00 per share. The Company has the right, at any time after May 30, 2017, to redeem the Series B Preferred at a price of $1.00 per share. Management has evaluated the Series B Preferred and its related terms and determined there are no embedded derivatives.

In connection with the issuance of the Debenture, the Company has reported a beneficial conversion feature for the difference between the conversion price pursuant to the Debenture and the quoted price of the Company’s common stock on the date of the agreement. On the date of the agreement, a discount totaling $1,350,000 was recorded. The unamortized discount which at October 31, 2014 was $1,312,873, will be amortized over the remaining term of the Debenture using the effective interest method. In addition, a deemed dividend totaling $450,000 was recorded in connection with the beneficial conversion feature associated with the conversion features in the Series B Preferred.

PIE Energy

In November 2009, the Company received an interest-free advance from an unrelated third party totaling $60,000. In January 2011, the interest-free advances were converted into a note payable, which was due on January 11, 2012 and has a stated annual interest rate of 6%. In January 2012, the parties amended the agreement to extend the due date to January 11, 2013. All other terms and conditions remained unchanged. The note has not been extended further nor has the Company received a notice of default.

Joint Venture Agreement

On July 20, 2012, Blacksands Petroleum, Inc. (the “Company”) entered into a Contribution Agreement (the “Contribution Agreement”), between APClark, LLC, a subsidiary of the Company (“APClark”) and KP-RAHR Ventures III, LLC (“KP Ventures”). Pursuant to the Contribution Agreement (i) the Company contributed $1,000 and certain of the Company’s oil and gas assets to APClark in exchange for 1,000 shares of Class A Membership Units of ApClark (the “Class A Membership Units”) and (ii) KP Ventures contributed approximately $2,600,000 (the “KP Ventures Cash Consideration”) to APClark in consideration of 1,000 shares of Class B Non-Voting Convertible Preferred Membership Units of APClark (the “Class B Membership Units” and the transaction, the “Asset Transaction”). KP Ventures has the option to contribute additional funds to APClark, up to an aggregate of $7,600,000, for no further equity consideration.

In connection with the Contribution Agreement, the Company entered into a Company Agreement (the “Company Agreement”) governing the operations of APClark and defining various rights of the Company and KP Ventures.

Pursuant to the Company Agreement, KP Ventures shall receive a preferred return of 12% per annum (the “Preferred Return”) on the unrecovered KP Ventures Cash Consideration until such time as the KP Ventures Cash Consideration is repaid. In addition, KP Ventures receives a 1% overriding royalty from the production of the APClark oil and gas properties. Once the KP Ventures Cash Consideration is repaid, including all accrued Preferred Returns, the Class B Membership Units shall automatically convert into Class C Non-Voting Net Profit Membership Units (the “Class C Membership Units”), which represent a non-dilutable “Net Profits” interest (“NPI”) in APClark and the assets owned by APClark and a percentage of all outstanding membership units of APClark initially equal to the NPI. The amount of the NPI granted depends on when the KP Ventures Cash Consideration and Preferred Return is paid, as follows:

Date of Repayment in Full	NPI %
On or prior to six month anniversary		7.5	%
After six months but on or prior to two year anniversary		15	%
After two years but on or prior to three year anniversary		20	%
After three years		50	%

The Company will be responsible for the operations of APClark and has the right to appoint the sole director of APClark, The consent of KP Ventures is required in certain situations, including, but not limited to: expanding the scope of the business; admitting additional members or transfer of membership units; approve annual budget; any merger or sale of all or substantially all of the assets of APClark; voluntary liquidation, dissolution or winding up of APClark; and to make any cash distributions.

In addition, the Company entered into a Pledge Agreement (the “Pledge Agreement”) pursuant to which it pledged the Class A Membership Units to KP Ventures to secure the Company’s obligations and performance thereunder and under the Contribution Agreement and Operating Agreement, which such Class A Membership Units shall be held pursuant to an escrow agreement.

Previously, the Company entered into a security agreement, dated as of September 27, 2011, pursuant to which, as security for the repayment of promissory notes in the principal face amount of $3,000,000 (the “Notes”), issued to Silver Bullet Property Holdings SDN BHD (“Silver Bullet”) a first priority security interest (the “Security Interest”) in certain of the assets of the Company that were contributed to APClark pursuant to the Contribution Agreement (the “Pledged Assets”). In connection with the Asset Transaction, the Company, APClark, Silver Bullet and KP Ventures entered into a subordination agreement (the “Subordination Agreement”), pursuant to which Silver Bullet subordinated its Security Interest to KP Ventures, so that KP Ventures would have a first priority interest in the Pledged Assets until KP Ventures is repaid the KP Ventures Cash Consideration and Preferred Return. In addition, the Company previously granted Silver Bullet a “net proceeds” interest of 9% on the Pledged Assets (the “Silver Bullet NPI”), which Silver Bullet NPI was capped at 25% of the outstanding principal and accrued interest owed under the Notes (the “Silver Bullet NPI Limitation”).

As a result of the required repayment of the equity to KP Ventures, the amount of the contribution has been reflected as a liability on the balance sheet. The Company has also recorded a discount on this liability relating to the relative fair value of the overriding royalties totaling $163,786 and net profits interest totaling $1,915,231. These discounts reduced the carrying value of the proved oil and gas costs. The discounts were fully amortized at October 31, 2014. The Company amortized $1,329,581 and $678,553 as additional interest expense in the fiscal years ended October 31, 2014 and 2013, respectively.

XML

Supplemental Oil and Gas Disclosures (Unaudited) (Details 5) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Supplemental Oil And Gas Disclosures Details 5
Beginning of the year	$ 2,101,330	$ 7,682,610
Sales and transfers of oil and gas produced, net of production costs	(799,057)	(924,607)
Net changes in prices and production costs	306,123	(6,104,363)
Net changes in income taxes
Production costs incurred	61,626	647,901
Changes in estimated future development costs, net of current development costs	(166,349)	16,571,027
Acquisition of minerals in place
Revision of previous estimates	(519,601)	(12,918,359)
Change of discount	210,833	768,261
Change in production rate and other	(186,225)	(3,621,140)
End of year	$ 1,008,680	$ 2,101,330

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Asset Retirement Obligation (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Asset Retirement Obligation Details
Beginning balance	$ 649,233	$ 609,502
Liabilities settled
Liabilities incurred through acquisition of assets
Liabilities transferred through sale of assets	(617,189)
Change in estimate of well life	43,957
Accretion expense	15,706	39,731
Ending balance	$ 91,707	$ 649,233

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Debt (Details Narrative) (USD $)	12 Months Ended
	Oct. 31, 2014
Debt Details Narrative
Carrying value of the discounts	$ 1,329,581
Amortization of interest expense	678,553
Unamortized discount	$ 1,312,873

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Stockholders Equity (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Number of Shares
Beginning Balance	1,046,333	1,046,333
Granted
Exercised
Cancelled	979,666
Ending Balance	66,667	1,046,333
Exercisable at October 31, 2014	66,667
Weighted Average Exercise Price
Beginning Balance	$ 3.13	$ 3.13
Granted
Exercised
Cancelled	$ 4.50
Ending Balance	$ 3.00	$ 3.13
Exercisable at October 31, 2014	$ 3.00

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Stockholders' Equity (Details 1) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Number of Shares
Beginning Balance	1,046,333	1,046,333
Granted
Cancelled	979,666
Ending Balance	66,667	1,046,333
Weighted Average Exercise Price
Beginning Balance	$ 3.13	$ 3.13
Granted
Cancelled	$ 4.50
Ending Balance	$ 3.00	$ 3.13
Warrant [Member]
Number of Shares
Beginning Balance	2,057,268	2,390,601
Granted
Cancelled	(2,057,268)	(333,333)
Ending Balance		2,057,268
Weighted Average Exercise Price
Beginning Balance	$ 4.50	$ 4.71
Granted
Cancelled	$ 4.50	$ 6.00
Ending Balance		$ 4.50

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Oil and Gas Property Costs

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 2. Oil and Gas Property Costs

In the years ended October 31, 2014 and October 31, 2013, the Company incurred property acquisition costs as follows: 

Proved Properties

	2014			2013
Balance, beginning of year	$	2,077,872		$	5,284,597
Costs incurred during the year		3,681,623			647,901
Asset retirement obligation revision		43,957			--
Depletion		(1,407,331	)		(968,451	)
Impairment of oil and gas property costs		(3,630,194	)		(2,886,175	)
Cost of property sold		(30,171	)		(--	)
Balance, end of year	$	735,756		$	2,077,872

Unproved Properties

	2014		2013
Balance, beginning of year	$	--	$	1,934,595
Costs incurred during the year		--		--
Impairment of oil and gas property costs		--		(1,934,595	)
Balance, end of year	$	--	$	--

Blacksands Projects

Proved Properties

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. The Company also incurred approximately $25,000 in fees associated with the acquisition, which were expensed when incurred. 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 Texas 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.

At October 31, 2013 and 2012, the Company compared the expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. The Company determined that based on its analysis, capitalized costs for the field exceeded its fair value. As a result the Company recorded an impairment totaling $4,359 and $147,370, respectively.

In January 2014, the Company sold its interest in all of the wells in the Cabeza Creek Field for all depths from the surface to 8,500 feet below the surface in exchange for $50,000 and the assumption by the buyer of all future liabilities associated with the plugging and abandoning of all wells in the Cabeza Creek Field ($617,189). The Company retained its working interest for depths greater than 8,500 feet. The Company recorded a gain on the sale of $645,323 during the year ended October 31, 2014.

The following is a summary of the pro forma information for the years ended October 31, 2014 and 2013 assuming the sale of the Cabeza Creek field had occurred as of the beginning of each fiscal year presented:

	2014			2013
Oil and gas revenue	$	1,228,868		$	1,549,145
Expenses
Selling, general and administrative		1,265,239			1,443,223
Depreciation and depletion		1,407,644			912,948
Accretion		15,706			3,474
Lease operating expense		429,810			701,726
Impairment of oil and gas property interest		3,630,194			4,820,770
Gain on sale of working interest		(1,639,394	)		--
Oil and gas exploration costs		--			699,335
Total expenses		5,109,199			8,581,476
Loss from operations		(3,880,331	)		(7,032,331	)
Other income (expense)		(2,981,243	)		(1,346,010	)
Net loss	$	(6,861,574	)	$	(8,378,341	)

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. Both of these wells are currently producing. The costs related to these wells have been fully depleted.

AP Clark Wells (known as “Jo-Mill Field”) Acquisition in August 2010

On August 10, 2010 the Company purchased an interest in two operating wells and its leasehold interest in 1,257 acres for $460,000. As a result of the acquisition, the Company has a 25% gross working interest (18.75% net revenue interest) in the two operating wells. The Company also has an 18.875% gross working interest (14.15625% net revenue interest) on the leasehold interests acquired on the 1,257 acres.

On November 29, 2010, the Company acquired additional leasehold interests and rights in the AP Clark Field from Westerly for $260,000. In addition, the Company paid Westerly $119,000 as advance payment towards 70% of the actual third party costs that was required to receive an extension of certain leasehold properties included in the AP Clark Field (the “Extension Monies”) The Company and Westerly also agreed to drill the W.D. Everett Well No. 3 located within the AP Clark Field whereby all costs of such drilling operation were borne 30% by Westerly and 70% by the Company.

The Company incurred $1,342,539 in drilling costs related to the drilling and completion of the W.D. Everett Well No. 3. In addition, during the quarter ended October 31, 2011, the Company drilled the Beaver Valley Ranch 6-1 well. Westerly elected to not participate for its full working interest in this well and has a working interest on this well of 15%. The Company was able to arrange for two unrelated parties to participate for an additional 20%. As a result, the Company has a working interest in this well of 65%. The Company incurred costs relating to the well totaling $1,166,225. These wells are currently producing and are operated by NRG.

During the fiscal year 2012, the Company drilled two wells, the Livestock 7-1 and Livestock 18-1 for a total cost of $1,223,535 and $1,275,699, respectively. Westerly elected to not participate for its full working interest in these wells and has a working interest of 11.4% and 8.55%, respectively. The Company was able to arrange for four unrelated parties to participate in each of these wells for an additional 26%. As a result, the Company has a working interest in these well of 62.8% and 65.65%. These wells began production in November 2012. These wells are currently producing and are operated by NRG.

During the fiscal year 2014, the Company participated in the drilling of three wells, the Livestock 7-2, Livestock 18-2 and the BVR 5-1 for a total cost of $1,015,980, $1,024,117 and $1,009,284, respectively. The Company owned 100% of the working interest in the wells during drilling operations. The Company reported an impairment of $2,219,813 of these costs during the quarter ended January 31, 2014. Subsequent to the drilling of these wells, the Company transferred approximately 59% in working interests to third parties and recorded a gain of $1,639,394. The Company has a working interest in these well of 41.46%. These wells are operated by a third party and began production in June 2014.

Unproved Properties

Pedregosa Basin Field Acquisition in June 2010

On June 18, 2010, the Company 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) for an initial acquisition cost of $1.5 million (the “Exploration Agreement”). Pursuant to the agreement, $1 million was paid at purchase and the remaining $500 thousand was due and subsequently paid on November 1, 2010. The property has no production and was accounted for as an acquisition of unproved property. Pursuant to an agreement, the Company was obligated to carry the drilling costs for a test well up to $1.2 million. Costs in excess of $1.2 million are to be split based upon the parties working interest. During the quarter ended April 30, 2011, the Company began drilling on a test well. The Company incurred $1,665,142 in capitalized exploration costs. During the quarter ended October 31, 2011, the Company determined that there were not economically feasible hydrocarbons at the test well site and expensed the costs of the well as exploration costs. During 2012, the Company determined that it owed an additional $952,320 for the drilling of this test well based on cost over runs reported to the Company by the operator of the well. During 2013, the Company was informed that an additional $171,790 was due on the drilling of the test well. This amount is reported in the statement of operations as exploration costs. At October 31, 2014, the Company owes the entire balance of $1,124,110, which is reflected in accrued expenses. The current leases are being held by production by other wells in the area the Company did not participate in which are operated by the other working interest owner. In October 2013, the Company recorded an impairment charge for the remaining leasehold costs totaling $1,781,214.

Del Norte Acquisition in September 2010

On September 9, 2010, the Company acquired a 50% undivided leasehold working interest in and to approximately 3,200 acres of land located in Rio Grande County in Colorado from Dan A. Hughes Company for an initial acquisition cost of $200,000. The property has no production and was accounted for as an acquisition of unproved property. Pursuant to the agreement, the Company has the option to participate in the drilling of a test well. If the Company participates in the drilling of this test well, all costs associated with the well will be borne equally. As a result of this acquisition, the Company recorded $200,000 in unproved properties. In August 2011, leases covering approximately 1,240 of these acres expired. As a result, the Company reported an impairment charge of $77,703 for the year ended October 31, 2012 for the expired leases. In October 2013, the Company recorded an impairment charge for the remaining leasehold costs totaling $138,381.

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Stockholders Equity (Details Narrative) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, authorized shares	10,000,000	10,000,000
Deemed dividend - beneficial conversion feature Series B Preferred Stock	$ 450,000
Deemed dividend - beneficial conversion feature Series C Preferred Stock	390,000
Restricted stock granted to a director	6,250
Stock based compensation expense for vested shares	8,438
Stock-based compensation expenses	(35,584)	238,980
Intrinsic value of the exercisable options	0
Weighted average remaining life of the stock options	5 years 5 months 9 days
Unrecognized compensation cost	$ 0

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Supplemental Oil and Gas Disclosures (Unaudited) (Details 2)	12 Months Ended
	Oct. 31, 2014 bbl	Oct. 31, 2013 bbl
Oil BBls Member
Begnning Balance	58,360	586,300
Revisions of previous estimates	(17,503)	(511,801)
Acquisition of minerals in place
Sales of minerals in place	(910)
Production	(11,107)	(16,139)
Ending Balance	28,840	58,360
Gas Mcf Member
Begnning Balance	195,560	510,090
Revisions of previous estimates	(154,195)	(296,245)
Acquisition of minerals in place
Sales of minerals in place	(4,570)
Production	(19,395)	(18,285)
Ending Balance	17,400	195,560

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Consolidated Balance Sheets (USD $)	Oct. 31, 2014	Oct. 31, 2013
Current Assets:
Cash and cash equivalents	$ 678,940	$ 1,335,237
Accounts receivable	210,577	417,597
Prepaid expenses	522,073
Total Current Assets	1,411,590	1,752,834
Oil and gas property costs (successful efforts method of accounting)
Proved	735,756	2,077,872
Other assets	50,000	50,312
TOTAL ASSETS	2,197,346	3,881,018
Current Liabilities:
Note payable	60,000	280,000
Accounts payable	129,400	523,365
Accrued expenses	2,372,075	3,121,900
Total Current Liabilities	2,561,475	3,925,265
Notes payable, net of discounts of $1,312,873 and $1,329,581	2,787,127	1,050,419
Notes payable to related party	3,220,000	3,220,000
Asset Retirement obligation	91,707	649,233
Total Liabilities	8,660,309	8,844,917
Stockholders' Equity:
Preferred stock - $0.001 par value; 10,000,000 shares authorized:
Series A - $0.001 par value, 310,000 shares authorized, nil and nil shares issued and outstanding
Series B - $0.001 par value; 2,217,281 shares authorized, 500,000 and nil shares issued and outstanding, respectively	500
Series C - $0.001 par value; 1,750,000 shares authorized, 1,000,000 and nil shares issued and outstanding, respectively	1,000
Common stock - $0.001 par value; 100,000,000 shares authorized; 19,278,017 and 17,719,360 shares issued and outstanding at October 31, 2014 and October 31, 2013, respectively	19,278	17,720
Additional paid-in capital	28,440,320	23,726,191
Accumulated deficit	(34,924,061)	(28,707,810)
Total Stockholders' Equity	(6,462,963)	(4,963,899)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 2,197,346	$ 3,881,018

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Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (6,216,251)	$ (8,393,974)
Adjustments to reconcile net loss to net cash used in operating activities:
Impairment of oil and gas property costs	3,630,194	4,820,770
Share-based compensation expense	(27,146)	263,773
Depreciation and depletion	1,407,644	969,511
Accretion	15,706	39,731
Amortization of debt discount	1,366,708	678,553
Loss on extinguishment	841,926
Gain on sale of working interests	(1,639,394)
Gain on sale of assets	(645,323)
Changes in operating assets and liabilities:
Accounts receivable	207,020	(15,435)
Prepaid expense and other current assets	(522,073)	169,611
Accounts payable and accrued expenses	(83,079)	1,070,278
Net cash flows provided by (used in) operating activities	(1,664,068)	(397,182)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties	(3,681,623)	(647,901)
Proceeds from sale of Cabeza Creek property	50,000
Cash received from the sale of oil and gas properties	1,639,394
Net cash flows used in investing activities	(1,992,229)	(647,901)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable	1,500,000	220,000
Proceeds from sale of preferred stock	1,500,000
Proceeds from sale of common stock		1,000,000
Net cash flows from financing activities	3,000,000	1,220,000
NET INCREASE IN CASH AND CASH EQUIVALENTS	(656,297)	174,917
CASH AND CASH EQUIVALENTS - Beginning of period	1,335,237	1,160,320
CASH AND CASH EQUIVALENTS - End of period	678,940	1,335,237
Supplemental Disclosures
Cash paid for interest	337,246	223,599
Cash paid for income taxes
Supplemental non-cash activities
Discount on debt	1,350,000
Payment of accrued interest through issuance of common stock	1,052,407
Revision of asset retirement obligation	43,957
Conversion of Preferred Stock to Common Stock		$ 827

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Income Taxes (Details 1) (USD $)	Oct. 31, 2014	Oct. 31, 2013
Deferred Tax Asset
Net operating loss	$ 7,037,058	$ 5,234,969
Oil and gas property interests	630,168	1,211,160
Other	196,982	382,311
Total deferred tax assets	7,864,208	6,828,440
Valuation allowance	(7,864,208)	(6,828,440)
Net

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The Company and Summary of Significant Accounting Policies (Details Narrative) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Company And Summary Of Significant Accounting Policies Details Narrative
Impairment of oil and gas property interest	$ 3,630,194	$ 4,820,770
Advanced from future drilling acitivities	516,976
Potentially dilutive common shares excluded from the calculation of diluted net income (loss)	3,066,667	3,103,601
Accumulated deficit	(34,924,061)	(28,707,810)
Working capital deficit	1,149,885
Cash and cash equivalents	678,940	1,335,237
Insurance Deposit	$ 162,986

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Income Taxes (Details 2) (USD $)	Oct. 31, 2014
Operating Loss Carry forwards	$ 20,597,272
2026
Operating Loss Carry forwards	291,662
2027
Operating Loss Carry forwards	1,739,955
2028
Operating Loss Carry forwards	1,265,101
2029
Operating Loss Carry forwards	769,546
2030
Operating Loss Carry forwards	588,394
2031
Operating Loss Carry forwards	5,153,072
2032
Operating Loss Carry forwards	3,748,939
2033
Operating Loss Carry forwards	1,438,676
2034
Operating Loss Carry forwards	$ 5,601,927

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Oil and Gas Property Costs (Details 1) (Copano Bay [Member], USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Copano Bay [Member]
Oil and gas revenues	$ 1,228,868	$ 1,549,145
Expenses
Selling, general and administrative	1,265,239	1,443,223
Depreciation and depletion	1,407,644	912,948
Accretion	15,706	3,474
Lease operating expense	429,810	701,726
Impairment of oil and gas properties	3,630,194	4,820,770
Gain on sale of working interest	(1,639,394)
Oil and gas exploration costs		699,335
Total expenses	5,109,199	8,581,476
Loss from operations	(3,880,331)	(7,032,331)
Other income (expense)	(2,981,243)	(1,346,010)
Net income	$ (6,861,574)	$ (8,378,341)

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The Company and Summary of Significant Accounting Policies

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 1. The Company and Summary of Significant Accounting Policies

Description of business and history

Blacksands Petroleum, Inc. (hereinafter referred to as the “Company”) was incorporated in the State of Nevada on October 12, 2004. Since August 2007, the Company has been engaged in the exploration, development, exploitation and production of oil and natural gas. The Company sells its oil and gas products primarily to domestic pipelines and refineries. Its operations are presently focused in the States of Colorado, Texas and New Mexico.

Principles of consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, including the wholly-owned subsidiaries Blacksands Petroleum Texas LLC, NRG Asset Management LLC, Copano Bay Holdings LLC and APClark LLC, of which we own 100% of the voting interests. All significant inter-company transactions and balances have been eliminated.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties. Oil and gas properties are periodically assessed to determine whether they have been impaired. Any impairment in value of unproved properties is charged to exploration expense. The costs of unproved properties, which are determined to be productive, are transferred to proved oil and gas properties and amortized on an equivalent unit-of-production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and gas reserves. In accordance with ASC No. 935, exploratory drilling costs are evaluated within a one-year period after the completion of drilling. For proved properties, we compare expected undiscounted future cash flows at a producing filed level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant date, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

During the years ended October 31, 2014 and 2013, the Company impaired its oil and gas properties by $3,630,194 and $4,820,770, which is reflected in the consolidated statement of operations (see Note 2).

The Company had advanced toward future drilling activities at October 31, 2014 totaling $516,976. These advances are reported as prepaid expenses in the Company’s balance sheet.

Asset Retirement Obligation

The Company follows ASC 410—Asset Retirement and Environmental Obligations which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs excluding salvage values. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

Accounting for Derivative Instruments

ASC 815-24 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”), requires all derivatives to be recorded on the balance sheet at fair value. The Company’s derivatives are separately valued and accounted for on the balance sheet. Fair values for securities traded in the open market and derivatives are based on quoted market prices. Where market prices are not readily available, fair values are determined using market based pricing models incorporating readily observable market data and requiring judgment and estimates.

The pricing model the Company used for determining fair values of its derivatives is the Black-Scholes option-pricing model. Valuations derived from this model are subject to ongoing internal and external verification and review. The model uses market-sourced inputs such as interest rates, exchange rates and option volatilities. Selection of these inputs involves management’s judgment and may impact net income.

Cash and cash equivalents and short term investments

Cash and cash equivalents include cash on account and all highly liquid investments with original maturities of three months or less on the date of acquisition. Investments with original maturities of greater than three months but less than one year are considered short-term investments.

Use of estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

The most critical estimate is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion and amortization of the oil and gas properties and the estimate of the impairment of the oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future cash flows.

Concentration of credit risks

The Company’s consolidated financial assets that are exposed to credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company maintained substantially all of its cash balances in a limited number of financial institutions. The balances are insured by the Federal Deposit Insurance Corporation up to $250,000. The Company had $162,986 in excess of this limit at October 31, 2014.

Property and equipment

Property and equipment are stated at cost less accumulated depreciation. Depreciation is provided principally on the straight-line method over the estimated useful lives of the assets, which are generally 3 to 27 years. The amounts of depreciation provided are sufficient to charge the cost of the related assets to operations over their estimated useful lives. Upon sale or other disposition of a depreciable property, cost and accumulated depreciation are removed from the accounts and any gain or loss is reflected in the statement of operations.

The Company periodically evaluates whether events and circumstances have occurred that may warrant revision of the estimated useful life of fixed assets or whether the remaining balance of fixed assets should be evaluated for possible impairment. The Company uses an estimate of the related undiscounted cash flows over the remaining life of the fixed assets in measuring their recoverability.

Revenue recognition

Revenue is recognized when title to the products transfer to the purchaser. The Company uses the “sales method” to account for production revenue, whereby revenue is recognized on all oil, natural gas or other related products sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that there is an imbalance on a specific property greater than the expected remaining proved reserves. As of October 31, 2014, our aggregate production imbalances were not material.

Stock-based compensation

The Company follows the provisions of FASB ASC 718—Stock Compensation. The statement requires all stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values on the date of grant.

Income taxes

The Company accounts for its income taxes in accordance with ASC 740 Income Taxes, which requires recognition of deferred tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date. A valuation allowance is provided for the amount of deferred tax assets that would otherwise be recorded for income tax benefits primarily relating to operating loss carryforwards as realization cannot be determined to be more likely than not.

The statement establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, the statement implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns and the adoption of the statement had no material impact to the Company’s consolidated financial statements. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2010 remain open to examination by U.S. federal and state tax jurisdictions.

Net loss per common share

The Company computes net income or loss per share in accordance with ASC 260 Earnings Per Share. Under the provisions of the Earnings per Share Topic ASC, basic net loss per share is computed by dividing the net loss available to common stockholders for the period by the weighted average number of shares of common stock outstanding during the period. The calculation of diluted net loss per share gives effect to common stock equivalents; however, potential common shares are excluded if their effect is anti-dilutive. The weighted average number of potentially dilutive common shares excluded from the calculation of diluted net income (loss) per share totaled 3,066,667 and 3,103,601 for the years ended October 31, 2014 and 2013, respectively.

Fair Value of Financial Instruments

The carrying amounts of financial instruments, including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value at October 31, 2014 and October 31, 2013 because of the short period to maturity of these instruments.

Going Concern

As shown in the accompanying consolidated financial statements, the Company has incurred an accumulated deficit of $34,924,061 through October 31, 2014. In addition, the Company had a working capital deficit of 1,149,885 and cash and cash equivalents of $678,940 at October 31, 2014. The Company’s plan is to raise additional capital for the drilling of new oil wells until such time that the Company generates sufficient revenues from its wells to cover its cash flow needs. However, the Company cannot assure that it will accomplish this task and there are many factors that may prevent the Company from reaching its goal of profitability.

The current rate of cash usage raises substantial doubt about the Company’s ability to continue as a going concern, absent additional significant revenues from new oil production. The Company’s financial statements do not include any adjustments relating to the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be necessary in the event that the Company cannot continue in existence.

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Consolidated Balance Sheets (Parenthetical) (USD $)	Oct. 31, 2014	Oct. 31, 2013
Stockholders' Equity:
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, authorized shares	10,000,000	10,000,000
Preferred stock Series A, par value	$ 0.001	$ 0.001
Preferred stock Series A, authorized shares	310,000	310,000
Preferred stock Series A, issued shares	0	0
Preferred stock Series A, outstanding shares	0	0
Preferred stock Series B, par value	$ 0.001	$ 0.001
Preferred stock Series B, authorized shares	2,217,281	2,217,281
Preferred stock Series B, issued shares	500,000	0
Preferred stock Series B, outstanding shares	500,000	0
Preferred stock Series C, par value	$ 0.001	$ 0.001
Preferred stock Series C, authorized shares	1,750,000	1,750,000
Preferred stock Series C, issued shares	1,000,000	0
Preferred stock Series C, outstanding shares	1,000,000	0
Common stock par value	$ 0.001	$ 0.001
Common stock shares authorized	100,000,000	100,000,000
Common stock shares issued	19,278,017	17,719,360
Common stock shares outstanding	19,278,017	17,719,360

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Debt (Tables)

12 Months Ended

Oct. 31, 2014

Debt Tables

Debt outstanding

	2014		2013
Silver Bullet Properties	$	3,220,000	$	3,220,000
PIE Energy		60,000		60,000
KP-RAHR Ventures III, LLC, net of discount of $0 and $1,329,581		2,600,000		1,270,419
Pacific LNG Operations LTD net of discount of $1,312,873 and $0		187,127		--
Total		6,067,127		4,550,419
Less current maturities		60,000		280,000
Long-term debt	$	6,007,127	$	4,270,419

Date of Repayment

Date of Repayment in Full	NPI %
On or prior to six month anniversary		7.5	%
After six months but on or prior to two year anniversary		15	%
After two years but on or prior to three year anniversary		20	%
After three years		50	%

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Document and Entity Information (USD $)	12 Months Ended
	Oct. 31, 2014	Feb. 05, 2015	Apr. 30, 2014
Document And Entity Information
Entity Registrant Name	BLACKSANDS PETROLEUM, INC.
Entity Central Index Key	0001308137
Document Type	10-K
Document Period End Date	Oct. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--10-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		18,872,832
Entity Public Float			$ 32,927,087
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014

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Asset Retirement Obligation (Tables)

12 Months Ended

Oct. 31, 2014

Asset Retirement Obligation Tables

Change in the asset retirement obligation

	2014			2013
Beginning balance at November 1	$	649,233		$	609,502
Liabilities settled		--			--
Liabilities incurred through acquisition of assets		--			--
Liabilities transferred through sale of assets		(617,189	)		--
Change in estimate of well life		43,957			--
Accretion expense		15,706			39,731
Ending balance at October 31	$	91,707		$	649,233

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Consolidated Statements of Operations (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Revenue:
Oil and gas revenue	$ 1,228,868	$ 1,690,249
Expenses:
Selling, general and administrative	1,265,239	1,443,223
Depreciation and depletion	1,407,644	969,511
Accretion	15,706	39,731
Lease operating expenses	429,810	765,643
Impairment of oil and gas property interest	3,630,194	4,820,770
Gain on sale of assets	(645,323)
Gain on sale of working interests	(1,639,394)
Oil and gas exploration costs		699,335
Total expenses	4,463,876	8,738,213
Loss from Operations	(3,235,008)	(7,047,964)
Other income and expense:
Interest expense	(2,139,317)	(1,401,611)
Other income		55,601
Loss on extinguishment of debt	(841,926)
Total Other Income (Expense)	(2,981,243)	(1,346,010)
Loss before provision for income taxes	(6,216,251)	(8,393,974)
Provision for income taxes
Net Loss	(6,216,251)	(8,393,974)
Preferred stock Dividends	(7,583)	(200,000)
Deemed dividend - beneficial conversion feature Series B Preferred Stock	(450,000)
Deemed dividend - beneficial conversion feature Series C Preferred Stock	(390,000)
Net loss attributable to common shareholders	(7,063,834)	(8,593,974)
Loss Per Share attributable to common shareholders Basic and diluted	$ (0.39)	$ (0.52)
Weighted Average Shares Outstanding Basic and diluted	$ 18,094,055	$ 16,405,142

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Commitments and Contingencies

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 6. Commitments and Contingencies

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of October 31, 2014, which have not been provided for, covered by insurance or otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past noncompliance with environmental laws will not be discovered on the Company’s properties.

On January 26, 2015, David DeMarco, a former Chief Executive Officer and director of the Company, filed a complaint against the Company in the District Court of Harris County, Texas, alleging that pursuant to a contract for work performed and/or services rendered, Mr. DeMarco is due $151,000 in deferred compensation that accrued during his tenure as Chief Executive Officer of the Company. The Company believes that Mr. DeMarco is currently an officer of an affiliate of PIE Holding LLC, the operator of five of the Company's wells. Mr. DeMarco is seeking between $200,000 and $1 million in damages. As of the date of this filing, service of process has not been effected. The Company has reported $151,000 in accrued expenses.

Operating leases

The Company leases its offices Texas on a month to month basis. Rent expense for the years ended October 31, 2014 and 2013 was $40,494 and $47,832, respectively.

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Stockholders' Equity

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 5. Stockholders' Equity

Preferred Stock

The Company is authorized to issue 10,000,000 shares of preferred stock at a par value of $.001.

Series A Preferred Stock

In October 2010, the Board of Directors (“Board”) designated 310,000 shares of the Company’s preferred stock as Series A Convertible Preferred Stock (“Series A Preferred”). The Series A Preferred are convertible into shares of common stock at a conversion price of $3.75. The shares are entitled to dividends at a rate of 8% of the stated value per share per annum. The dividends are payable annually on December 31 in cash or additional shares of the Series A Preferred, at the option of the Company. The Series A Preferred and any accrued and unpaid dividends mandatorily convert into common shares on October 29, 2013. The outstanding Series A Preferred and accumulated unpaid dividends were converted into 826,667 shares of the Company’s common stock on October 29, 2013.

On October 29, 2010, the Company and Talras Overseas S.A. (“Talras”) entered into an exchange agreement, whereby $2,500,000 in notes payable were exchanged for 250,000 shares of the Company’s Series A convertible preferred stock and warrants to purchase 333,333 shares of the Company’s common stock. The warrants were exercisable at an exercise price of $6 per share through October 29, 2013. The preferred shares and accumulated dividends were converted into 826,667 shares of common stock on October 29, 2013. The warrants expired unexercised.

Series B Preferred Stock

On May 30, 2014, the Board of the Company approved the filing of a Certificate of Designation of Preferences, Rights and Limitations of Series B Convertible Preferred Stock (the “Certificate of Designation”), which was filed with and accepted by the Secretary of State of Nevada on June 6, 2014. Pursuant to the Certificate of Designation, the Company established a new series of 2,217,281 shares of the Series B Convertible Preferred Stock (“Series B Preferred Stock”).

Each share of Series B Preferred Stock has a stated value of $1.00 (“Stated Value”) and accrues a dividend of 3% of the Stated Value per annum, which is payable in additional shares of Series B Preferred Stock annually on December 31, in arrears. Each share of Series B Preferred Stock may be converted at any time on or prior to May 30, 2017 into such number of shares of the Company’s common stock equal to the Stated Value divided by $1.00 per share. The Company has the right, at any time after May 30, 2017, to redeem the Series B Preferred Stock at a price of $1.00 per share. In June 2014, the Company issued 500,000 shares of the Series B Preferred Stockin exchange for $500,000 pursuant to a subscription agreement with Pacific LNG (see note 3). At October 31, 2014, there were 500,000 shares of the Series B Preferred Stock outstanding. A deemed dividend totaling $450,000 was recorded in connection with the beneficial conversion feature associated with the conversion features of the Series B Preferred Shares.

Series C Preferred Stock

On October 15, 2014, the Board the Company approved the filing of a Certificate of Designation of Preferences, Rights and Privileges of Series C Convertible Preferred Stock (“Certificate of Designation”), which was filed with and accepted by the Secretary of State of the State of Nevada on October 16, 2014. Pursuant to the Certificate of Designation, the Company established a new series of 1,750,000 shares of the Series C Convertible Preferred Stock (“Series C Preferred Stock”).

Each share of Series C Preferred Stock has a stated value of $1.00 (“Stated Value”) and accrues a dividend of 3% of the Stated Value per annum, which is payable in additional shares of Series C Preferred Stock annually on December 31, in arrears, and beginning on December 31, 2014. Each share of Series C Preferred Stock may be converted at any time on or before June 30, 2017, into such number of shares of the Company’s common stock equal to the Stated Value divided by $1.00 per share. The Company has the right, at any time after June 30, 2017, to redeem the shares of Series C Preferred Stock, either in whole or in part, at the price of $1.00 per share. There are no voting rights underlying the Series C Preferred Stock. In October 2014, the Company issued 1,000,000 shares of the Series C Preferred Stock in exchange for $1,000,000. At October 31, 2014, there were 1,000,000 shares of Series C Preferred Stock outstanding. A deemed dividend totaling $390,000 was recorded in connection with the beneficial conversion feature associated with the conversion features of the Series C Preferred Shares.

Issuances of Common Stock

In October 2013, the Company issued 500,000 shares of its common stock to Silver Bullet in exchange for $1,000,000. The base price paid by Silver Bullet will be reduced and additional shares issued if there is an issuance of securities or repricing of an existing right to a price less than the base share price paid by Silver Bullet prior to October 23, 2014. As a result of the issuance of the debenture and Series B Preferred stock which had a conversion price of $1 per share, an additional 500,000 shares were required to be issued to Silver Bullet pursuant to the price protection clause. The Company reported the issuance of these shares as an equity transaction as the shares were issued in relation to the prior equity issuance, there were no derivative reporting on the original equity tranasaction and there were no additional services or goods provided.

During 2014, the Company recorded the vesting of 6,250 restricted shares of the Company’s common stock that were granted to a director. The Company recorded a stock based compensation expense for the vesting of the shares totaling $8,438.

Stock Options

As of June 26, 2006, the Company’s Board of Directors approved, and a majority of the Company’s stockholders ratified, the adoption of the Company’s 2006 Stock Option Plan (the “Plan”), pursuant to which the Board of Directors has the ability to provide incentives through the issuance of options, stock, restricted stock, and other stock-based awards, representing up to 2,000,000 shares of the Company’s common stock, to certain employees, outside directors, officers, consultants and advisors. The 2006 Stock Option Plan allows the term of options granted to be determined by the Board of Directors not to exceed ten years. The Board of Directors is authorized to determine the vesting requirements of the options granted.

During the Fiscal year ended October 31, 2012, stock options were granted to a director of the Company for options representing 88,000 common shares. The exercise price of the option is $4.50, with a ten year term, vesting equally over four years. The fair value of the option grants were estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 134%, risk free interest rate of 0.77%; and expected lives of 3.7 years. During the years ended October, 31, 2014 and 2013, the Company recorded stock based compensation totaling $(35,584) and $238,980 as a result of the stock option grants. Included in stock based compensation for the fiscal year ended October 31, 2014 is a reduction of $68,730 that was previously recognized on unvested options which were forfeited.

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

	Number of Shares		Weighted Average Exercise Price
Outstanding at November 1, 2012		1,046,333		3.13
Granted		--	$	--
Exercised		-		-
Cancelled		--		--
Outstanding at October 31, 2013		1,046,333	$	3.13
Granted		--		--
Exercised		-		-
Cancelled		979,666		4.50
Outstanding at October 31, 2014		66,667	$	3.00
Exercisable at October 31, 2014		66,667	$	3.00

The intrinsic value of the exercisable options at October 31, 2014 totaled $0. At October 31, 2014, the weighted average remaining life of the stock options is 5.44 years. At October 31, 2014, there was $0 of total unrecognized compensation cost related to the stock options granted under the plan.

Warrants

A summary of the Company’s stock warrant activity and related information for the years ended October 31, 2014 and 2013 is as follows:

	Warrants			Weighted Average Exercise Price
Outstanding at November 1, 2012		2,390,601		$	4.71
Granted		--			--
Cancelled		(333,333	)		6.00
Outstanding at October 31, 2013		2,057,268		$	4.50
Granted		--		$	--
Cancelled		(2,057,268	)	$	4.50
Outstanding at October 31, 2014		--		$	--

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Oil and Gas Property Costs (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Proved Properties [Member]
Balance, beginning of year	$ 2,077,872	$ 5,284,597
Costs incurred during the year	3,681,623	647,901
Asset retirement obligation acquired	43,957
Depletion	(1,407,331)	(968,451)
Impairment of oil and gas property costs	(3,630,194)	(2,886,175)
Cost of property sold	(30,171)
Balance, end of year	735,756	2,077,872
Unproved Properties [Member]
Balance, beginning of year		1,934,595
Costs incurred during the year
Impairment of oil and gas property costs		(1,934,595)
Balance, end of year

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Stockholders Equity (Tables)

12 Months Ended

Oct. 31, 2014

Stockholders Equity Tables

Stock Options Activity

	Number of Shares		Weighted Average Exercise Price
Outstanding at November 1, 2012		1,046,333		3.13
Granted		--	$	--
Exercised		-		-
Cancelled		--		--
Outstanding at October 31, 2013		1,046,333	$	3.13
Granted		--		--
Exercised		-		-
Cancelled		979,666		4.50
Outstanding at October 31, 2014		66,667	$	3.00
Exercisable at October 31, 2014		66,667	$	3.00

Stock Warrant Activity

	Warrants			Weighted Average Exercise Price
Outstanding at November 1, 2012		2,390,601		$	4.71
Granted		--			--
Cancelled		(333,333	)		6.00
Outstanding at October 31, 2013		2,057,268		$	4.50
Granted		--		$	--
Cancelled		(2,057,268	)	$	4.50
Outstanding at October 31, 2014		--		$	--

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The Company and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Oct. 31, 2014

Company And Summary Of Significant Accounting Policies Policies

Description of business and history

Blacksands Petroleum, Inc. (hereinafter referred to as the “Company”) was incorporated in the State of Nevada on October 12, 2004. Since August 2007, the Company has been engaged in the exploration, development, exploitation and production of oil and natural gas. The Company sells its oil and gas products primarily to domestic pipelines and refineries. Its operations are presently focused in the States of Colorado, Texas and New Mexico.

Principles of consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries, including the wholly-owned subsidiaries Blacksands Petroleum Texas LLC, NRG Asset Management LLC, Copano Bay Holdings LLC and APClark LLC, of which we own 100% of the voting interests. All significant inter-company transactions and balances have been eliminated.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas properties. Oil and gas properties are periodically assessed to determine whether they have been impaired. Any impairment in value of unproved properties is charged to exploration expense. The costs of unproved properties, which are determined to be productive, are transferred to proved oil and gas properties and amortized on an equivalent unit-of-production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and gas reserves. In accordance with ASC No. 935, exploratory drilling costs are evaluated within a one-year period after the completion of drilling. For proved properties, we compare expected undiscounted future cash flows at a producing filed level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant date, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

During the years ended October 31, 2014 and 2013, the Company impaired its oil and gas properties by $3,630,194 and $4,820,770, which is reflected in the consolidated statement of operations (see Note 2).

The Company had advanced toward future drilling activities at October 31, 2014 totaling $516,976. These advances are reported as prepaid expenses in the Company’s balance sheet.

Asset Retirement Obligation

The Company follows ASC 410—Asset Retirement and Environmental Obligations which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs excluding salvage values. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

Accounting for Derivative Instruments

ASC 815-24 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”), requires all derivatives to be recorded on the balance sheet at fair value. The Company’s derivatives are separately valued and accounted for on the balance sheet. Fair values for securities traded in the open market and derivatives are based on quoted market prices. Where market prices are not readily available, fair values are determined using market based pricing models incorporating readily observable market data and requiring judgment and estimates.

The pricing model the Company used for determining fair values of its derivatives is the Black-Scholes option-pricing model. Valuations derived from this model are subject to ongoing internal and external verification and review. The model uses market-sourced inputs such as interest rates, exchange rates and option volatilities. Selection of these inputs involves management’s judgment and may impact net income.

Cash and cash equivalents and short term investments

Cash and cash equivalents include cash on account and all highly liquid investments with original maturities of three months or less on the date of acquisition. Investments with original maturities of greater than three months but less than one year are considered short-term investments.

Use of estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

The most critical estimate is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion and amortization of the oil and gas properties and the estimate of the impairment of the oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future cash flows.

Concentration of credit risks

The Company’s consolidated financial assets that are exposed to credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company maintained substantially all of its cash balances in a limited number of financial institutions. The balances are insured by the Federal Deposit Insurance Corporation up to $250,000. The Company had $162,986 in excess of this limit at October 31, 2014.

Property and equipment

Property and equipment are stated at cost less accumulated depreciation. Depreciation is provided principally on the straight-line method over the estimated useful lives of the assets, which are generally 3 to 27 years. The amounts of depreciation provided are sufficient to charge the cost of the related assets to operations over their estimated useful lives. Upon sale or other disposition of a depreciable property, cost and accumulated depreciation are removed from the accounts and any gain or loss is reflected in the statement of operations.

The Company periodically evaluates whether events and circumstances have occurred that may warrant revision of the estimated useful life of fixed assets or whether the remaining balance of fixed assets should be evaluated for possible impairment. The Company uses an estimate of the related undiscounted cash flows over the remaining life of the fixed assets in measuring their recoverability.

Revenue recognition

Revenue is recognized when title to the products transfer to the purchaser. The Company uses the “sales method” to account for production revenue, whereby revenue is recognized on all oil, natural gas or other related products sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that there is an imbalance on a specific property greater than the expected remaining proved reserves. As of October 31, 2014, our aggregate production imbalances were not material.

Stock-based compensation

The Company follows the provisions of FASB ASC 718—Stock Compensation. The statement requires all stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values on the date of grant.

Income taxes

The Company accounts for its income taxes in accordance with ASC 740 Income Taxes, which requires recognition of deferred tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date. A valuation allowance is provided for the amount of deferred tax assets that would otherwise be recorded for income tax benefits primarily relating to operating loss carryforwards as realization cannot be determined to be more likely than not.

The statement establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, the statement implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns and the adoption of the statement had no material impact to the Company’s consolidated financial statements. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2010 remain open to examination by U.S. federal and state tax jurisdictions.

Net loss per common share

The Company computes net income or loss per share in accordance with ASC 260 Earnings Per Share. Under the provisions of the Earnings per Share Topic ASC, basic net loss per share is computed by dividing the net loss available to common stockholders for the period by the weighted average number of shares of common stock outstanding during the period. The calculation of diluted net loss per share gives effect to common stock equivalents; however, potential common shares are excluded if their effect is anti-dilutive. The weighted average number of potentially dilutive common shares excluded from the calculation of diluted net income (loss) per share totaled 3,066,667 and 3,103,601 for the years ended October 31, 2014 and 2013, respectively.

Fair Value of Financial Instruments

The carrying amounts of financial instruments, including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value at October 31, 2014 and October 31, 2013 because of the short period to maturity of these instruments.

Going Concern

As shown in the accompanying consolidated financial statements, the Company has incurred an accumulated deficit of $34,924,061 through October 31, 2014. In addition, the Company had a working capital deficit of 1,149,885 and cash and cash equivalents of $678,940 at October 31, 2014. The Company’s plan is to raise additional capital for the drilling of new oil wells until such time that the Company generates sufficient revenues from its wells to cover its cash flow needs. However, the Company cannot assure that it will accomplish this task and there are many factors that may prevent the Company from reaching its goal of profitability.

The current rate of cash usage raises substantial doubt about the Company’s ability to continue as a going concern, absent additional significant revenues from new oil production. The Company’s financial statements do not include any adjustments relating to the recoverability and classification of recorded assets, or the amounts and classification of liabilities that might be necessary in the event that the Company cannot continue in existence.

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Income Taxes

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 7. Income Taxes

The reconciliation between the expected income tax benefit, computed using the statutory federal rate of 34%, and the actual income tax benefit is as follows:

	October 31,
	2014			2013
Expected tax benefit at 34%	$	2,113,525		$	2,853,951
Stock option expenses		(14,139	)		(89,672	)
Miscellaneous		(312,681	)		1,762
Loss on extinguishment		(286,256	)		-
Amortization of debt discount		(464,681	)		(230,708	)
Change in valuation allowance		(1,035,768	)		(2,535,333	)
Actual tax benefit	$	-		$	-

The composition of deferred tax assets/liability is as follows:

	October 31,
	2014			2013
Deferred Tax Asset
Net operating loss	$	7,037,058		$	5,234,969
Oil and gas property interests		630,168			1,211,160
Other		196,982			382,311
Total deferred tax assets	$	7,864,208		$	6,828,440
Valuation allowance		(7,864,208	)		(6,828,440	)
Net	$	-		$	-

The valuation allowance increased by $1,035,768 during the year ended October 2014. The Company established a valuation allowance to fully offset the net deferred income tax assets due to the uncertainty of the Company's ability to generate future taxable income necessary to realize these net deferred income tax assets, considering the Company's history of significant operating losses. In addition, future utilization of the available net operating loss carryforwards may be limited under Internal Revenue Code Section 382 as a result of any future changes in ownership.

For federal income tax purposes, the Company has net operating losses of approximately $20,597,272 at October 31, 2014. These losses expire as follows:

2026	$	291,662
2027		1,739,955
2028		1,265,101
2029		769,546
2030		588,394
2031		5,153,072
2032		3,748,939
2033		1,438,676
2034		5,601,927
	$	20,597,272

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Supplemental Oil and Gas Disclosures

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 8. Supplemental Oil and Gas Disclosures (Unaudited)

The following supplemental information regarding the oil and gas activities of the Company for 2014 and 2013 is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and ASC 932, "Disclosures About Oil and Gas Producing Activities." Capitalized costs relating to oil and gas activities and costs incurred in oil and gas property acquisition, exploration and development activities for each year are shown below.

CAPITALIZED COST OF OIL AND GAS PRODUCING ACTIVITIES

	2014			2013
As of October 31	United States			United States
Unproved properties not being amortized	$	--		$	--
Proved property being amortized		10,515,204			8,387,479
Accumulated depreciation, depletion amortization and impairment		(9,779,448	)		(6,309,607	)
Net capitalized costs	$	735,756		$	2,077,872

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES

As of October 31	2014		2013
Property acquisition costs—proved and unproved properties	$	--	$	--
Exploration costs	$	--	$	699,335
Development costs	$	3,681,623	$	649,003

OIL AND GAS RESERVES

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

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

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Hite & Associates for the years ended October 31, 2014 and 2013, respectively. The oil and natural gas price as of October 31, 2014 and 2013 is based on the 12-month unweighted average of the first of the month prices of the West Texas Intermediate posted price. The oil and natural gas prices were adjusted by lease for quality, transportation fees, and regional price differentials. The gas price as of October 31, 2014 and 2013 is based on the 12-month unweighted average of the first of the month prices of the Henry Hub spot price. All prices are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.

	Oil BBls			Gas Mcf
October 31, 2012		586,300			510,090
Revisions of previous estimates		(511,801	)		(296,245	)
Acquisition of minerals in place		--			--
Sales of minerals in place		--			--
Production		(16,139	)		(18,285	)
October 31, 2013		58,360			195,560
Revisions of previous estimates		(17,503	)		(154,195	)
Acquisition of minerals in place		--			--
Sales of minerals in place		(910	)		(4,570	)
Production		(11,107	)		(19,395	)
October 31, 2014		28,840			17,400

The Company's proved developed reserves are as follows:

	Developed				Undeveloped
	Oil BBls		Gas Mcf		Oil BBls		Gas Mcf
October 31, 2014		28,840		17,400		--		--
October 31, 2013		58,360		195,560		--		--
October 31, 2012		76,000		234,526		510,300		275,564

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOW

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

The Company believes that the following factors should be taken into account when reviewing the following information:

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

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

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

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

Under the Standardized Measure, for the years ended October 31, 2014 and 2013 the future cash inflows were estimated by applying the 12 month average of the oil and natural gas prices on the first day of the month ($98.13 and $92.60 for oil and $4.29 and $2.34 for natural gas for the years ended October 31, 2014 and 2013, respectively) to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year-end prices were required. At October 31, 2014 and 2013, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month (12-month unweighted average) cash price quotes, except for volumes subject to fixed price contracts.

	2014			2013
Future cash inflows	$	2,623,080		$	6,077,480
Future development costs		(136,170	)		(321,400	)
Future production costs		(1,215,530	)		(2,940,800	)
Future income tax expenses		-			-
Future net cash flows before 10% discount		1,271,380			2,815,280
10%Annual discount for estimated timing of cash flows		(262,700	)		(713,950	)
Standardized measure discounted future net cash flows	$	1,008,680		$	2,101,330

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Company’s proved oil and natural gas reserves during each of the years in the two year period ended October 31, 2014:

	2014			2013
Beginning of the year	$	2,101,330		$	7,682,610
Sales and transfers of oil and gas produced, net of production costs		(799,057	)		(924,607	)
Net changes in prices and production costs		306,123			(6,104,363	)
Net changes in income taxes		-			-
Production costs incurred		61,626			647,901
Changes in estimated future development costs, net of current development costs		(166,349	)		16,571,027
Acquisition of minerals in place		--			--
Revision of previous estimates		(519,601	)		(12,918,359	)
Change of discount		210,833			768,261
Change in production rate and other		(186,225	)		(3,621,140	)
End of year	$	1,008,680		$	2,101,330

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Oil and Gas Property Costs (Tables)

12 Months Ended

Oct. 31, 2014

Oil And Gas Property Costs Tables

Property acquisition costs

Proved Properties

	2014			2013
Balance, beginning of year	$	2,077,872		$	5,284,597
Costs incurred during the year		3,681,623			647,901
Asset retirement obligation revision		43,957			--
Depletion		(1,407,331	)		(968,451	)
Impairment of oil and gas property costs		(3,630,194	)		(2,886,175	)
Cost of property sold		(30,171	)		(--	)
Balance, end of year	$	735,756		$	2,077,872

Unproved Properties

	2014		2013
Balance, beginning of year	$	--	$	1,934,595
Costs incurred during the year		--		--
Impairment of oil and gas property costs		--		(1,934,595	)
Balance, end of year	$	--	$	--

Proforma information

	2014			2013
Oil and gas revenue	$	1,228,868		$	1,549,145
Expenses
Selling, general and administrative		1,265,239			1,443,223
Depreciation and depletion		1,407,644			912,948
Accretion		15,706			3,474
Lease operating expense		429,810			701,726
Impairment of oil and gas property interest		3,630,194			4,820,770
Gain on sale of working interest		(1,639,394	)		--
Oil and gas exploration costs		--			699,335
Total expenses		5,109,199			8,581,476
Loss from operations		(3,880,331	)		(7,032,331	)
Other income (expense)		(2,981,243	)		(1,346,010	)
Net loss	$	(6,861,574	)	$	(8,378,341	)

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Income Taxes (Details) (USD $)	12 Months Ended
	Oct. 31, 2014	Oct. 31, 2013
Income Taxes Details
Expected tax benefit at 34%	$ 2,113,525	$ 2,853,951
Stock option expenses	(14,139)	(89,672)
Miscellaneous	(312,681)	1,762
Loss on extinguishment	(286,256)
Amortization of debt discount	(464,681)	(230,708)
Change in valuation allowance	(1,035,768)	(2,535,333)
Actual tax benefit

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Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Oct. 31, 2014

Supplemental Oil And Gas Disclosures Tables

Capitalized Cost Of Oil And Gas Producing Activities

	2014			2013
As of October 31	United States			United States
Unproved properties not being amortized	$	--		$	--
Proved property being amortized		10,515,204			8,387,479
Accumulated depreciation, depletion amortization and impairment		(9,779,448	)		(6,309,607	)
Net capitalized costs	$	735,756		$	2,077,872

Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities

As of October 31	2014		2013
Property acquisition costs—proved and unproved properties	$	--	$	--
Exploration costs	$	--	$	699,335
Development costs	$	3,681,623	$	649,003

Oil And Gas Reserves

	Oil BBls			Gas Mcf
October 31, 2012		586,300			510,090
Revisions of previous estimates		(511,801	)		(296,245	)
Acquisition of minerals in place		--			--
Sales of minerals in place		--			--
Production		(16,139	)		(18,285	)
October 31, 2013		58,360			195,560
Revisions of previous estimates		(17,503	)		(154,195	)
Acquisition of minerals in place		--			--
Sales of minerals in place		(910	)		(4,570	)
Production		(11,107	)		(19,395	)
October 31, 2014		28,840			17,400

Proved developed reserves

	Developed				Undeveloped
	Oil BBls		Gas Mcf		Oil BBls		Gas Mcf
October 31, 2014		28,840		17,400		--		--
October 31, 2013		58,360		195,560		--		--
October 31, 2012		76,000		234,526		510,300		275,564

Standardized Measure Of Discounted Future Net Cash Flow

	2014			2013
Future cash inflows	$	2,623,080		$	6,077,480
Future development costs		(136,170	)		(321,400	)
Future production costs		(1,215,530	)		(2,940,800	)
Future income tax expenses		-			-
Future net cash flows before 10% discount		1,271,380			2,815,280
10%Annual discount for estimated timing of cash flows		(262,700	)		(713,950	)
Standardized measure discounted future net cash flows	$	1,008,680		$	2,101,330

Changes In Standardized Measure Of Discounted Future Net Cash Flows

	2014			2013
Beginning of the year	$	2,101,330		$	7,682,610
Sales and transfers of oil and gas produced, net of production costs		(799,057	)		(924,607	)
Net changes in prices and production costs		306,123			(6,104,363	)
Net changes in income taxes		-			-
Production costs incurred		61,626			647,901
Changes in estimated future development costs, net of current development costs		(166,349	)		16,571,027
Acquisition of minerals in place		--			--
Revision of previous estimates		(519,601	)		(12,918,359	)
Change of discount		210,833			768,261
Change in production rate and other		(186,225	)		(3,621,140	)
End of year	$	1,008,680		$	2,101,330

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Debt (Details) (USD $)	Oct. 31, 2014	Oct. 31, 2013
Total	$ 6,067,127	$ 4,270,419
Less current maturities	60,000	280,000
Long-term debt	6,007,127	4,550,419
KP-RAHR Ventures III, LLC
Total	2,600,000	1,270,419
Silver Bullet Properties [Member]
Total	3,220,000	3,220,000
PIE Energy [Member]
Total	60,000	60,000
Pacific LNG [Member]
Total	$ 187,127

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Supplemental Oil and Gas Disclosures (Unaudited) (Details 3)	Oct. 31, 2014 bbl	Oct. 31, 2013 bbl	Oct. 31, 2012 bbl
Oil BBls Member
Developed Reserves	28,840	58,360	76,000
Undeveloped Reserves			510,300
Gas Mcf Member
Developed Reserves	17,400	195,560	234,526
Undeveloped Reserves			275,564

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Consolidated Statement of Stockholder's Equity (USD $)	Preferred Stock	Common Stock	Additional Paid-In Capital	Retained Deficit	Total
Beginning Balance, Amount at Oct. 31, 2012	$ 250	$ 16,387	$ 22,463,501	$ (20,313,836)	$ 2,166,302
Beginning Balance, Shares at Oct. 31, 2012	250,000	16,386,443
Stock issued to director for services, Shares		6,250
Stock issued to director for services, Amount		6	24,787		24,793
Stock based compensation			238,980		238,980
Shares issued in private placement, Shares		500,000
Shares issued in private placement, Amount		500	999,500		1,000,000
Conversion of preferred shares, Shares	(250,000)	826,667
Conversion of preferred shares, Amount	(250)	827	(577)
Net loss				(8,393,974)	(8,393,974)
Ending Balance, Amount at Oct. 31, 2013		17,720	23,726,191	(28,707,810)	(4,963,899)
Ending Balance, Shares at Oct. 31, 2013		17,719,360
Stock issued to director for services, Shares		6,250			6,250
Stock issued to director for services, Amount		6	8,432		8,438
Stock based compensation			33,146		33,146
Unvested portion of forfeited options			(68,730)		(68,730)
Payment of interest with common stock, Shares		1,052,407
Payment of interest with common stock, Amount		1,052	1,893,281		1,894,333
Stock issuance costs, Shares		500,000
Stock issuance costs, Amount		500	(500)
Discount on convertible debt			1,350,000		1,350,000
Issuance of Preferred B shares, Shares	500,000
Issuance of Preferred B shares, Amount	500		499,500		500,000
Beneficial conversion feature On Preferred B Shares			450,000		450,000
Deemed dividend on Preferred B shares			(450,000)		(450,000)
Issuance of Preferred C shares, Shares	1,000,000
Issuance of Preferred C shares, Amount	1,000		999,000		1,000,000
Beneficial conversion feature discount on Preferred C shares			390,000		390,000
Deemed dividend on Preferred C shares			(390,000)		(390,000)
Net loss				(6,216,251)	(6,216,251)
Ending Balance, Amount at Oct. 31, 2014	$ 1,500	$ 19,278	$ 28,440,320	$ (34,924,061)	$ (6,462,963)
Ending Balance, Shares at Oct. 31, 2014	1,500,000	19,278,017

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Asset Retirement Obligation

12 Months Ended

Oct. 31, 2014

Notes to Financial Statements

Note 4. Asset Retirement Obligation

The following table summarizes the change in the asset retirement obligation (“ARO”) for the years ended October 31,

	2014			2013
Beginning balance at November 1	$	649,233		$	609,502
Liabilities settled		--			--
Liabilities incurred through acquisition of assets		--			--
Liabilities transferred through sale of assets		(617,189	)		--
Change in estimate of well life		43,957			--
Accretion expense		15,706			39,731
Ending balance at October 31	$	91,707		$	649,233

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.

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Debt (Details 1)	12 Months Ended
	Oct. 31, 2014
Date of Repayment in Full
On or prior to six month anniversary	7.50%
After six months but on or prior to two year anniversary	15.00%
After two years but on or prior to three year anniversary	20.00%
After three years	50.00%

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Supplemental Oil and Gas Disclosures (Unaudited) (Details) (United States, USD $)	Oct. 31, 2014	Oct. 31, 2013
United States
CAPITALIZED COST OF OIL AND GAS PRODUCING ACTIVITIES
Unproved properties not being amortized
Proved property being amortized	10,515,204	8,387,479
Accumulated depreciation, depletion amortization and impairment	(9,779,448)	(6,309,607)
Net capitalized costs	$ 735,756	$ 2,077,872

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Income Taxes (Tables)

12 Months Ended

Oct. 31, 2014

Income Taxes Tables

Reconciliation between the expected income tax benefit and statutory federal rate

	October 31,
	2014			2013
Expected tax benefit at 34%	$	2,113,525		$	2,853,951
Stock option expenses		(14,139	)		(89,672	)
Miscellaneous		(312,681	)		1,762
Loss on extinguishment		(286,256	)		-
Amortization of debt discount		(464,681	)		(230,708	)
Change in valuation allowance		(1,035,768	)		(2,535,333	)
Actual tax benefit	$	-		$	-

Deferred tax assets/liability

	October 31,
	2014			2013
Deferred Tax Asset
Net operating loss	$	7,037,058		$	5,234,969
Oil and gas property interests		630,168			1,211,160
Other		196,982			382,311
Total deferred tax assets	$	7,864,208		$	6,828,440
Valuation allowance		(7,864,208	)		(6,828,440	)
Net	$	-		$	-

Net operating losses

2026	$	291,662
2027		1,739,955
2028		1,265,101
2029		769,546
2030		588,394
2031		5,153,072
2032		3,748,939
2033		1,438,676
2034		5,601,927
	$	20,597,272