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 on Form 10-K 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 on Form 10-K. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this Annual Report on Form 10-K. 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 on Form 10-K. 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, as follows, collectively referred to as “we”, “us” or the "Company". Subsidiaries include NRG Assets Management, LLC, BSPE Texas LLC, and Copano Bay Holdings, LLC.
Overview and History
We are an oil and natural gas exploration and development company currently focused on the acquisition and development of conventional and unconventional oil and gas fields in North America. Our operations are conducting through our subsidiaries, including our wholly-owned subsidiary Blacksands Petroleum Texas LLC (“BSPE Texas”) and Access Energy Inc. (“Access”), of which we own 19.88%. Access is a private company, 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 Energy Management LLC was formed under the laws of Texas in October 2009, and Copano Bay Holdings, LLC was formed under the laws of Texas in December 2010.
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.
Our Competitive Strengths
We believe that we have the following business strengths that will enable us to achieve our business objectives:
•
our management team has direct conventional and unconventional resource industry experience, including operations, exploration and production experience in the United States;
•
We purchased the J.E. Pettus Gas Unit located in Goliad County, Texas which includes four (4) active gas wells and 24 non producing gas wells located on 3,688.77 acres in Goliad County, Texas;
•
We purchased working interests in four additional producing wells in two other fields and have begun drilling on a fifth well; and
•
We acquired a 50% working interest in 147,000 acres of land in New Mexico.
Our Operations
J.E. Pettus Gas Unit (known as “Cabeza Creek Field”)
In November 2009, we purchased, for approximately US$430,000 including legal and other costs, through BSPE Texas, the J.E. Pettus Gas Unit located in Goliad County, Texas, previously owned by Pioneer Natural Resources USA, Inc. The Gas Unit includes five (5) active gas wells and 20 non producing gas wells located on 3688.77 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 a 8.66% interest. We are operator of all depth rights. The gas and oil production is from conventional Gulf Coast sand-stone formations.
The Gas Unit was purchased with the objective of providing us cash flow in the near and long term, to enhance our stockholder value, with the intent to increase production through (i) reworking and recompleting existing oil and gas wells, (ii) utilization of industry technology such as compression and artificial lift, and (iii) further exploration in order to define additional reserves.
The lease operating expenses included several non-recurring costs associated with the unsuccessful attempt to recomplete the Pettus No. 4 well and the Pettus No. 27 well, and plugging and abandoning the No. 15 well as required by the Texas Railroad Commission. The No. 4 and No. 27 wells are currently shut in and temporarily abandoned.
We purchased 6.5 squares of 3-D seismic over the Cabeza Creek Field from Western Geophysical for approximately $98,000. This seismic data is being utilized to help identify potential proven developed non-producing and proven undeveloped reserves on the property.
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 are not operated by us or any of our affiliates.
Pedregosa Basin Field
On June 18, 2010, BSPE Texas acquired a 50% undivided leasehold working interest (with a contributing 40% net revenue interest) in and to approximately 147,262 acres of land, located in the Pedregosa Basin (SW New Mexico) from Dan A. Hughes Company (“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. A two well drilling program is contemplated following the seismic acquisition. The first well would potentially be drilled to the north with the objective to fully test and evaluate the Percha Shale, a 350 foot thick shale unit that is the age equivalent of the Woodford shale in West Texas and Oklahoma. The second contemplated well would be proposed to test the Hueco, South Unit structure by drilling thick depositional sequences of carbonates and sandstones of early Cretaceous age rocks through deeper Paleozoics.
The Pedregosa Basin offers the combined potential of 1) conventional oil and gas plays targeting porous sandstones and carbonate reefs, carbonate sequences with potential for hydraulic fracturing and shallow gas pays already identified and 2) an unconventional shale play targeting the Percha Shale. With a conservative strategy of first acquiring six 2D seismic lines and potentially drilling two test wells, our goal is to explore the potential hydrocarbons of one of the few remaining large, under-explored lower 48 basins.
We have contracted with Hughes to drill a test well on the property. According to our operating agreement with Hughes, we are responsible for the first $1.2 million in costs associated with this test well. We are also responsible for acquiring approximately 37 linear miles of 2-D seismic. We are currently awaiting the results of the seismic work and expect the work to commence on the test well in February 2011.
West Texas Field
On August 13, 2010, we acquired a (i) 25% working interest (18.75% of net revenue interest) in two producing wells for $325,000 and an 18.75% of leasehold working interest (14.0625% of net revenue interest) in 1,257 acres of land located in West Texas for $135,000 from an undisclosed Party (“the Party”). Pursuant to the agreement, the Party will be carried by BSPE Texas for a 2.5% of working interest (1.875% net revenue interest) until sales point (capped at $1.5M) on the first well drilled on the 1,257 acres. Additionally, the Party will receive a 3.75% working interest (2.8125% net revenue interest) back-in at 100% payout in the first well drilled on the 1,257 acres. Therefore, on the first well drilled, BSPE Texas will be responsible for 25% of the costs, expenses and liabilities until either (i) the cumulative total well costs reach 1.5M or (ii) the well is completed as a producer or plugged and abandoned as a dry hole. At such time, the interests of the Parties shall be (i) the Party 2.5% of working interest (1.875% of net revenue interest) and BSPE-Texas 22.5% of working interest (16.875% of net revenue interest). In the event the first well is completed as a commercial completion and the cumulative net revenue generated from production from the well equals the cumulative well costs associated with the well, than the Party will back-in for an additional 3.75% of working interest (2.8125% of net revenue interest). At payout of the first well, the Parties interests shall be the Party 6.25% of working interest (4.6875% of net revenue interest) and BSPE-Texas 18.75% of working interest (14.0625% of net revenue interest). The interest of the parties in all subsequent wells drilled on the 1,257 acres is: the Party 6.25% leasehold working interest (4.6875% net revenue interest) and BSPE-Texas 18.75% leasehold working interest (14.0625% net revenue interest).
Access Energy
On August 3, 2007, we purchased 600 newly issued shares of common stock of Access, representing 75.0% of its common stock for an aggregate sum of Cdn$3,427,935.23 (approximately US$3,213,000), and common stock purchase warrants to acquire 1,500,000 of our shares of common stock.
Access is an exploration stage company that was formed in August 2005 for the purpose of acquiring rights for conventional and unconventional oil and gas exploration and development on lands in Western Canada and the United States, including the traditional lands of the Buffalo River Dene Nation in Northern Saskatchewan. Access has a right to exploration and development until March 2028. In connection with our agreements with Access, we were committed to make certain contributions for capacity and infrastructure building and for reimbursement of costs for traditional lands staffing and to support training and development
On April 30, 2010, we sold 441 of the 600 shares we held of Access to the other stockholder of Access. Following the transfer, we hold 19.9% of the outstanding Access shares and the other shareholder holds 80.1%. As consideration for the transfer, we paid the other shareholder $75,000 cash and we were relieved of our contractual obligation to fund Access’ annual plan and budget. In addition, we were released of any rights and obligations related to any joint venture agreements between Access and other counterparties. In connection with the sale, warrants held by the other shareholder to purchase shares of our common stock were cancelled.
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:
·
Cabeza Creek Field: Dewbre Petroleum Corporation;
·
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.
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 Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiations between buyers and sellers. Natural gas exported from Canada is subject to regulation by the National Energy Board of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the National Energy Board of Canada. Natural gas (other than propane, butanes and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an order of the National Energy Board, or the NEB. Natural gas may be exported for a term of no more than one year in respect to propane and butane, and no more than two years in respect to ethane, with all exports requiring an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the issue of such a license requires the approval of the Lieutenant Governor in Council. The export of natural gas pursuant to an order or license shall be subject to the terms and conditions included by the National Energy Board of Canada in such order or license.
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 Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding two years in the case of heavy crude and not exceeding one year in the case of oil other than heavy crude, provided that an order approving any such export has been obtained from the National Energy Board of Canada. Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the National Energy Board of Canada and the issue of such a license requires a public hearing and obtaining the approval of the Lieutenant Governor in Council. The export of oil pursuant to an order or license shall be subject to the terms and conditions included by the National Energy Board of Canada in such order or license.
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.
In Canada, royalties payable on production from non-Crown lands (i.e. non-government lands) are determined by negotiations between the mineral owner and the lessee. However, crown royalties (i.e. government land royalties) are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. From time to time the governments of Canada and Saskatchewan have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects.
Land Tenure
In Canada, oil and natural gas deposits located in Saskatchewan are predominantly owned by the provincial government. The Provincial government grants rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms and on conditions set forth in provincial legislation including specific work commitments or obligations to make rental, royalty or other payments. Where oil and natural gas deposits are privately owned, such as in the U.S., rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.
The North American Free Trade Agreement
On January 1, 1994, the North American Free Trade Agreement, or NAFTA, became effective among the governments of Canada, the U.S. and Mexico. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36-month period), (ii) impose an export price higher than the domestic price and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.
NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.
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 our natural resources and the environment. The recent trend in environmental legislation and regulation 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, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting 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, injunctions or both. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act, or the CERCLA, and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the 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. The Resource Conservation and Recovery Act, or the RCRA, and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.
Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990, or the OPA, contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations. We are required to maintain such permits or meet general permit requirements. The EPA and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and natural gas exploration and production operations. A number of agencies including but not limited to the EPA, the Bureau of Land Management, the Texas Commission of Environmental Quality, the Louisiana Department of Natural Resources, the North Dakota Industrial Commission, the Oklahoma Conservation Commission, the Wyoming Oil and Gas Conservation Commission, the Montana Board of Oil and Gas Conservation and similar commissions within these states and of other states in which we do business have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit pollutants. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.
The EPA amended the UIC provisions of the SDWA to exclude hydraulic fracturing from the definition of “underground injection.” However, the U.S. Senate and House of Representatives are currently considering the FRAC Act, which will amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, which could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.
On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Consequently, the EPA proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.
Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce United States emissions of greenhouse gases including carbon dioxide and methane that may contribute to the warming of the Earth’s atmosphere and other climatic changes. If it becomes law, ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system.
Canada
The oil and natural gas industry is governed by environmental regulation under Canadian federal and provincial laws, rules and regulations, which restrict and prohibit the release or emission and regulate the storage and transportation of various substances produced or utilized in association with oil and natural gas industry operations. In addition, applicable environmental laws require that well and facility sites be abandoned and reclaimed, to the satisfaction of provincial authorities, in order to remediate these sites to near natural conditions. Also, environmental laws may impose upon “responsible persons” remediation obligations on property designated as a contaminated site. Responsible persons include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any present or past owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures. A breach of environmental laws may result in the imposition of fines and penalties and suspension of production, in addition to the costs of abandonment and reclamation.
In Saskatchewan, environmental laws are set out in a number of acts and regulations, including The Oil and Gas Conservation Act. Under these acts and regulations, environmental standards and requirements applicable to compliance, cleanup and reporting are contained and administered by the Energy and Resources Ministry.
In December 2002, the Government of Canada ratified the Kyoto Protocol, or the Protocol. The Protocol calls for Canada to reduce its emissions of GHGs to 6% below 1990 “business as usual” levels between 2008 and 2012. It remains uncertain whether the Kyoto target of 6% below 1990 GHG emission levels will be enforced in Canada. On April 26, 2007, the Canadian government released “Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution,” or the Action Plan, which set forth a plan for regulations to address both GHG and air pollution. On March 10, 2008, the Canadian government released an update to the Action Plan, “Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions,” or the Updated Action Plan. Regulations for the implementation of the Updated Action Plan were originally intended to be in force by January 1, 2010. To date, no such regulations have been proposed. Further, representatives of the Canadian government have recently indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. Since it is presently unclear what approach will be adopted by the United States, the provisions of the Updated Action Plan, described below are expected to be significantly modified.
The proposed compliance mechanisms under the Updated Action Plan include an emissions credit trading system for GHGs and certain industrial air pollutants, and several options for companies to choose among to meet GHG emission intensity reduction targets and encourage the development of new emission reduction technologies, including the option of making payments into a technology fund, an emissions and offset trading system, limited credits for emission reductions created between 1992 and 2006, and international emission credits under the clean development mechanism under the Kyoto Protocol for up to 10% of each company’s regulatory obligation.
Climate Change
Climate change has emerged as an important topic in public policy debate regarding our environment. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in GHGs, which may ultimately pose a risk to society and the environment. Products produced by the oil and natural gas exploration and production industry are a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.
Employees
As of January 1, 2011, we have five employees, including the chief executive officer, chief financial officer, vice president in charge of land and acquisitions and two managers in charge of development and production. We believe our relationships with our employees are good. None of our employees are represented by labor unions and we are not a party to any collective bargaining agreement.
ITEM 1A
ITEM 1A - RISK FACTORS
RISKS RELATED TO OUR BUSINESS AND OPERATIONS
A substantial or extended decline in oil and natural gas prices or demand for oil and gas products may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital, and future rate of growth. Recent extremely high prices have affected the demand for oil and gas products, and that demand has declined on a worldwide basis. If the decline in demand continues, the ability of the Company to command higher prices for its oil and gas products will be endangered. Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, and the revenue we will receive, depend on numerous factors beyond our control. These factors include the following:
§
changes in global supply and demand for oil and natural gas;
§
the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other organizations and government entities;
§
the price and quantity of imports of foreign oil and natural gas;
§
political conditions and events worldwide, including rules concerning production and environmental protection, and political instability in countries with significant oil production such as the Congo and Venezuela, all affecting oil-producing activity;
§
the level of global oil and natural gas exploration and production activity;
§
the short and long term levels of global oil and natural gas inventories;
§
weather conditions;
§
technological advances affecting the exploitation for oil and gas, and related advances for energy consumption; and
§
the price and availability of alternative fuels.
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but may also reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices is likely to materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
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 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
We Will Need Additional External Capital.
We will need substantial additional capital for acquisitions or for development in order to implement any proposed capital expenditure program. We may attempt to obtain sufficient funds, including through borrowing against the reserves of the Company to further implement our business plan. 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.
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, while our revenues increase if oil and gas prices increase significantly, 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, while costs of drilling remain high. There can be no assurance that we will replace reserves or replace our reserves economically.
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 canceled 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.
The Unavailability Or High Cost Of Drilling Rigs, Equipment, Supplies, Personnel And Oil Field Services Could Adversely Affect Our Ability To Execute Our Exploration And Exploitation Plans On A Timely Basis And Within Our Budget.
Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations. If the unavailability or high cost of rigs, equipment, supplies or personnel were particularly severe in Texas, especially as a result of an active hurricane season, we could be materially and adversely affected because our operations and properties are concentrated in that area.
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 affect 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 Affect 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 affect 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.
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.
The Producing Life Of Company 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 wholly owned subsidiary, BSPE Texas LLC, currently focuses on the conventional oil and gas industry. BSPE Texas LLC currently only owns a single property and has an interest in several additional properties. 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.
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.
Because Management Has Other Business Interests, He May Not Be Able To Devote A Sufficient Amount Of Time To Our Business Operation, Causing Our Business To Fail.
Mr. Giannattasio is involved with other business interests and unable to devote all of his business time and effort to us. He presently possesses 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.
Because Our Officers And Directors Are Involved Or Affiliated With Other Oil and Gas Exploration Companies, They May Have Conflicts Of Interest With Us.
Mr. Holcombe and Mr. Wilson are involved or affiliated with one or more other oil and gas resource exploration companies. As a result of this relationship, they 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 has become increasingly intense as the price of oil on the commodities markets has risen 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.
Our success depends on the ability of our management and employees 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.
We have a history of losses which may continue, which may negatively impact our ability to achieve our business objectives.
We incurred net losses of $781,602 for the year ended October 31, 2010 and $5,302,960 for the year ended October 31, 2009. In addition, at October 31, 2010, we had an accumulated deficit of $10,922,740. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Subsequent to year end, our cash flows generated from operations exceeds our day-to-day operating costs, excluding new development or acquisitions. 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.
We Will Require Additional Financing In Order To Continue Exploration and New Development Activities.
The Company had $1,609,961 as of October 31, 2010, and $2,886,243 as of October 31, 2009 in cash and cash equivalents, cash in the Company’s attorney’s trust account, and short-term investments on hand. Costs of exploration and new development programs will require additional financing.
We will be dependent on raising capital, debt or equity, from outside sources to pay for further expansion, exploration and development of our business. 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 will be unable to undertake any further exploration or new development. 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.
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 Could Reduce Profitability, Growth and the Value of Our Proposed Business.
Our revenues and earnings, if any, will be 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 Canadian, 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. For example, market fluctuations of oil prices may render uneconomic the mining, extraction and upgrading of tar sands reserves containing relatively lower grades of bitumen.
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.
Existing Environmental Regulations Impose Substantial Operating Costs Which Could Adversely Effect 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.
Amendments To Current Laws and Regulations Governing Our Proposed Operations Could Have a Material Adverse Impact On Our Proposed Business.
Our business will be subject to substantial regulation under state and federal laws relating to the exploration for, and the development, upgrading, marketing, pricing, taxation, and transportation of unconventional oil and related products and other matters. Amendments to current laws and regulations governing operations and activities of unconventional oil extraction operations could have a material adverse impact on our proposed business. In addition, there can be no assurance that income tax laws, royalty regulations and government incentive programs related to the unconventional oil industry generally will not be changed in a manner which may adversely affect us and cause delays, inability to complete or abandonment of properties.
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.
We Are Subject To Technology Risks In All Of Our Proposed Conventional and Unconventional Oil and Gas Operations.
We currently plan to 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 which 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.
Operational Hazards
Our production, exploration and development activities are subject to the customary hazards of operation in remote areas. A casualty occurrence might result in the loss of equipment or life, as well as injury, property damage or other liability. While we maintain limited insurance to cover current operations, our property and liability insurance may not be sufficient to cover any such casualty occurrences or disruptions. Equipment failures could result in damage to our facilities and liability to third parties against which we may not be able to fully insure or may elect not to insure because of high premium costs or for other reasons. Our operations could be interrupted by natural disasters or other events beyond our control. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on the business, our financial condition and results of our operations.
Competitive Risks
The North American and international petroleum and natural gas industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of oil and gas interests, and the distribution and marketing of petroleum and gas products. A number of companies other than our company are engaged in the oil and gas businesses and are actively exploring for and delineating their resource bases.
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.
It is anticipated that there will be a limited trading market for the Common Stock on the NASD’s Over-the-Counter Bulletin Board. 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 NASD Over-the-Counter Bulletin Board 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 expect to make in the Offering and 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 the investors following the expiration of the required holding period for the shares of Common Stock issued in this Offering and/or future investors in future offerings we expect to make to raise additional capital.
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 in the foreseeable future.
We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their Common Stock, and stockholders may be unable to sell their shares on favorable terms or at all. Investors cannot be assured of a positive return on investment or that they will not lose the entire amount of their investment in the Common Stock.
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 “Over-the-Counter Bulletin Board”, 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.
Shareholders 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.
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. Such attestation requirement by our independent registered public accounting firm would not be applicable to us until the report for the year ended October 31, 2011 at the earliest, if at all. 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.
FINRA sales practice requirements may also limit a shareholder’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
ITEM 1B - UNRESOLVED STAFF COMMENTS
None.
ITEM 2
ITEM 2 - PROPERTIES
We maintain our principal offices at 25025 I-45 N., Ste. 410, The Woodlands, Texas 77380 and 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 on these spaces is on a month to month basis and totals $2,800 per month.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on our business, financial condition or operating results.
ITEM 4
ITEM 4 - (REMOVED AND RESERVED)
PART II
ITEM 5
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 traded on the Over-the-Counter Bulletin Board under the symbol “BSPE.” For the period from November 1, 2008 through October 31, 2010, the following table sets forth the high and low sale prices of our common stock as reported by the Over-the-Counter Bulletin Board.
On January 28, 2011, the closing sale price of our common stock, as reported by the Over-the-Counter Bulletin Board, was $3.75 per share. On January 28, 2011, there were 36 holders of record of our common stock. On January 5, 2011, a one-for-three reverse stock split was effective for our common stock. All share prices herein reflect this reverse stock split.
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.
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA
Not required under Regulation S-K for “smaller reporting companies.”
ITEM 7
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 our oil and natural gas exploration, exploitation and development operations on projects located in Colorado, New Mexico and Texas. The higher potential impact projects (“Core Focus Areas”) are concentrated on (i) Spraberry, Wolfberry, Strawn and Mississippian formations in the Midland Basin in W. Texas, (ii) conventional reef structures and unconventional shale (Percha Shale) in the Pedregosa Basin in S.W. New Mexico and (iii) conventional structure and stratigraphic formations and unconventional resource formations in Southern Colorado. In addition to the Core Focus Areas, our management team is pursuing conventional properties (“Non-Core Properties”) which we anticipate will provide the company with immediate cash flow and additional upside through recompletion potential and new drilling opportunities.
As of October 31, 2010, we owned interests in (i) approximately 7,340 gross (3,200 net) acres in the Midland Basin, (ii) approximately 147,262 gross (73,631 net) acres in the Pedregosa Basin and (iii) approximately 3,300 gross (1,650 net) acres in Colorado. Approximately, 125,115 gross acres (2,720 gross acres in Midland Basin, 118,607 gross acres in the Pedregosa Basin, and approximately 3,788 gross acres in the Non-Core Properties) are held by production or drilling operations.
We began oil and gas operations in the United States on November 1, 2009, with the purchase of a producing conventional oil and gas field, located in the Gulf Coast region of Texas, from Pioneer Natural Resources. Additionally, we acquired interests in one Non-Core Property located in the Gulf Coast region of Texas and one Core Focus Area property located in West Texas.
Subsequent to Oct 31, 2010, we have (i) acquired one operated, producing Non-Core Property in the Gulf Coast, (ii) drilled and set casing in the Everett Well No. 3 to 9,200’ (total depth), (iii) surveyed and acquired 37 linear miles of 2-D seismic data on the southern part of the Pedregosa Basin project, and (iv) built location on the northern part of the Pedregosa Basin project for the initial vertical test well to be drill to 7,000’ (total depth) in the first calendar quarter of 2011. In addition, we have acquired term leasehold in our Core Focus Areas.
The Core Focus Areas provide us with the opportunity to grow reserves and cash flow by drilling and developing the properties. Our Non-Core Properties currently provide cash flow for overhead and administrative costs, while we develop our Core Focus Areas.
We continue to pursue avenues to reduce or eliminate our financial exposure in the initial development stage on a case by case basis for each project. Joint venture arrangements may be considered for others to participate for a disproportionate share of the initial leasing and/or drilling costs, further reducing our exposure.
2011 Projects, subject to raising the capital requirements:
Subject to obtaining additional financing, the following drilling, recompletion/work-over and leasing activity may be pursued. The projects and our share of the estimated costs are listed below:
Estimated cost based on expected participating working interest.
Project
Current WI%
No. Wells
Procedure
Est. Cost
Midland Basin
18.75-70%
New Drill
$4.0 MM
Pedregosa Basin
50%
New Drill
$5.5 MM
Colorado
50%
New Drill
$1.8 MM
Non Core
100%
Recompletions
$0.4 MM
Non Core
30%
New Drill
$0.5 MM
All Properties
various
New Leases
$3.0 MM
Total
$15.2 MM
While our base case drilling, recompletion/workover and leasing activity would result in estimated costs of $15.2 MM, we may expand drilling, recompletion/workover and leasing activity to as much as $22 MM, if project economics and general economic conditions support the more aggressive drilling program. If we elect to expand drilling activities, we will need to access additional capital. We have no third-party commitments to provide additional capital and there is no assurance such capital will be available to us, or if available, that the terms will be favorable to us. We may access capital from equity and/or debt offerings.
We have not entered into any commodity derivative arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. We have no off-balance sheet arrangements.
In order to retain a strong balance sheet, we have sold equity and used joint venture agreements with other industry companies to limit or eliminate our financial exposure in early drilling.
Consolidated Results of Operations for the Year Ended October 31, 2010 Compared to the Year Ended October 31, 2009
Prior to our acquisition of the J.E. Pettus Gas Unit in November 2009, we had no revenues. Revenues for the year ended October 31, 2010 totaled $1,260,507. We are expecting a significant increase in revenues in Fiscal 2011 as a result of having a full year of revenue on the Beech Creek and AP Clark leases. In addition, we acquired additional leases on eight operating wells in November 2010.
Management and directors’ fees increased $1,236,577, to $1,429,081 in the fiscal year ended October 31, 2010 as compared to $192,504 during the year ended October 31, 2009. Included in the management and directors’ fees during the year ended October 31, 2010 was $979,835 in stock based compensation related to stock options granted to officers and directors during 2010. In addition, we hired several consultants to assist with operating the company.
Depreciation, depletion and accretion totaled $573,398 for the year ended October 31, 2010. In addition, we incurred lease operating expenses totaling $756,920 during the year ended October 31, 2010. There was no expense recorded in the previous year as there was no production. We expect lease operating expenses to remain significant as many of our properties have older wells and will incur repairs and other age related costs.
During the year ended October 31, 2009, we incurred exploration expenses of $1,119,493. The exploration expenses for the year ended October 31, 2009 include costs associated with maintaining our interest in the A10 Project as well as costs to investigate the acquisition of additional projects which are not expected to yield us a new acquisition project. There were no exploration costs during the year ended October 31, 2010. As we commence drilling in some of our unproved properties, we expect to incur exploration costs in 2011.
The gain on the sale of Assess totaling $2,341,452 resulted from our sale of 441 of the 600 shares we held in Access Energy to the other stockholder of Access Energy. As consideration for the transfer, we paid the other Access shareholder $75,000 cash and we were relieved of our contractual obligation to fund Access’ annual plan, budget and any joint venture agreements between Access and other counterparties.
In connection with the exchange agreement on October 29, 2010, we recorded a loss on the extinguishment of the convertible notes included in the exchange. There was no similar charge in the comparable period.
We earned total interest income of $160,714 for the year ended October 31, 2009, as compared to total interest income of $113,316 for the year ended October 31, 2010. The interest for the years ended October 31, 2010 and October 31, 2009 was earned from the investment of proceeds of a private placement of our common stock and common stock purchase warrants on August 9, 2006, which remained in interest bearing instruments during the above periods, and which balance has diminished over the course of 2009 and 2010 with the purchase of Access and with ongoing operations. We were able to obtain improved returns on investments starting in May 2009 compared to prior returns by investing in different investment projects with higher rates of return, but increased foreign exchange risk.
The minority interest amount of $540,935 for the year ended October 31, 2009 represents 25% share of minority stockholders of Access of the losses incurred by Access from November 1, 2008 to October 31, 2009 (excluding capital contribution to subsidiary on behalf of minority shareholder of $55,932 that is not recoverable from the minority shareholder).
The loss from foreign currency exchange of $203,342 and $166,735 at October 31, 2010 and 2009, respectively, arose as a result of fluctuations in the exchange rate on US-denominated transactions, including investments.
We incurred a net loss for the year ended October 31, 2010 of $781,602, compared to a net loss of $5,302,960 for the year ended October 31, 2009. Of this loss for the year ended October 31, 2009, $3,831,190 is attributable to our write off of our oil and gas property costs on April 30, 2009.
Liquidity and Capital Resources
As of October 31, 2010, we had cash and cash equivalents on hand of $1,609,961. We believe this amount is sufficient to fund our general and administrative costs for the next twelve months. We do not have sufficient funds on hand in order to fund any capital expenditures for the drilling of new wells or the recompletion of existing wells. We expect to rely on external sources of capital in order to fund our capital expenditures. We do not have any firm commitments to raise additional capital nor is there any assurance sufficient capital will be available at acceptable terms.
Net Cash Used In Operating Activities
Cash used in operating activities in the year ended October 31, 2010 was $506,452, compared to $932,790 used for the comparative period. The difference is due to significant exploration costs incurred on Access related projects for the year ended October 31, 2009.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the year ended October 31, 2010 was $3,364,278 compared to net cash provided by investing activities of $776,559 for the comparative period. The majority of the net cash used in investing activities for the year ended October 31, 2010 related to the purchase of oil and gas properties. In the comparable period, the cash flows provided by investing activities related to the redemption of short-term investments totaling $778,653.
Cash Flows from Financing Activities
Cash provided by financing activities for the nine months ended July 31, 2010 was $2,560,000, compared to $Nil for the comparative period. On June 18, 2010, we entered into a bridge loan agreement (the “Bridge Loan Agreement”) with Talras Overseas S.A. as investor (“Talras”). On such date, Talras made a bridge loan to us in the amount of $1,000,000 (the “Bridge Loan”). Under the Bridge Loan Agreement, the principal face amount of $1,000,000 was provided in the first tranche and subsequent tranches of $500,000 or more were permitted up to $2,500,000 in the aggregate to be funded by June 30, 2010. During the fiscal year ended October 31, 2010, we borrowed the total amount under the agreement of $2,500,000.
The Bridge Loan bears interest at a rate of 6.0% per annum which amount shall, at our option, be payable either in cash or by adding such interest to the outstanding principal amount. The Bridge loan is due on the earliest of June 30, 2011 or the closing date of an investment or series of related investments in equity securities in an aggregate amount of at least $10 million.
On October 29, 2010, the Company and Talrus entered into a exchange agreement, whereby the amount then outstanding on the Bridge Loan Agreement were exchanged for 250,000 shares of the Company’s Series A preferred stock and warrants to purchase 333,333 shares of the Company’s common stock. The warrants are exercisable at an exercise price of $6.00 per share through October 29, 2013. The convertible preferred shares provide for dividends at the rate of 8% per annum of the stated value of the shares. The dividends are cumulative and payable in cash or in additional Series A Convertible Preferred shares. The shares are convertible at any time at the option of the holder into common stock at a conversion price of $3.75 per common share. If not previously converted, all outstanding shares of the Series A preferred stock, including any unpaid dividends, convert to shares of common stock on October 29, 2013.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Contractual Obligations
Critical Accounting Policies
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the mere chance that future market conditions will improve or new technologies will be found that would make the project’s development economically profitable. Often, the ability to move the project into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.
Proved Reserves
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s E&P operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineers have policies and procedures in place consistent with these authoritative guidelines.
Proved reserve estimates are adjusted annually and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and year-end costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.
Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in prices of crude oil, natural gas and natural gas liquids; recoverable operating expenses; and capital costs. The estimation of proved developed reserves also is important to the statement of operations because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that asset.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group and annually following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets-generally on a field-by-field basis for exploration and production assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, commodity prices, operating costs, refining margins and capital project decisions, considering all available information at the date of review.
Asset Retirement Obligations
Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and plug wells at the end of operations at operational sites. The fair values of obligations for dismantling and removing these facilities are accrued at the installation of the asset based on estimated discounted costs. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.
New Accounting Pronouncements Adopted
In January 2010, the FASB issued guidance related to fair value measurements requiring new disclosures regarding transfers in and out of Level 1 and 2 and requiring the gross presentation of activity within Level 3. The guidance also clarifies existing disclosures of inputs and valuation techniques for Level 2 and 3 fair value measurements. Additionally, the guidance includes conforming amendments to employers’ disclosures about postretirement benefit plan assets. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009 (except for the disclosure of activity within Level 3 fair value measurements which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years). The impact of adopting this guidance has not resulted in additional disclosures in the Consolidated Financial Statements.
In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted ASU 2010-03 effective October 31, 2010.
On March 1, 2010, the Company adopted ASU 2010-06, Improving Disclosure about Fair Value Measurements. ASU 2010-06, issued January 2010, requires additional disclosures regarding fair value measurements, amends disclosures about postretirement benefit plan assets, and provides clarification regarding the level of disaggregation of fair value disclosures by investment class. The ASU is effective for interim and annual reporting periods beginning after December 15, 2009, except for certain Level 3 activity disclosure requirements that will be effective for reporting periods beginning after December 15, 2010.
The Company has implemented all new accounting pronouncements above that are in effect and that may impact its financial statements and does not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on its financial position or results of operations.
ITEM 7A
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not required under Regulation S-K for “smaller reporting companies.”
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Blacksands Petroleum, Inc.
The Woodlands, Texas
We have audited the accompanying consolidated balance sheet of Blacksands Petroleum, Inc. (the “Company”) as of October 31, 2010, and the related consolidated statement of operations and comprehensive loss, stockholders’ equity, and cash flows for the year 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 audit.
We conducted our audit 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 audit 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 audit provides 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 the Company as of October 31, 2010 and the results of its operations and cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ MaloneBailey, LLP
www.malonebailey.com
Houston, Texas
February 1, 2011
Report of Independent Registered Public Accounting Firm
To the Directors and Stockholders of
Blacksands Petroleum, Inc.
We have audited the accompanying consolidated balance sheet of Blacksands Petroleum, Inc. as of October 31, 2009, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity, and cash flows for the year ended October 31, 2009. 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 audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, based on our audit, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Blacksands Petroleum, Inc. as of October 31, 2009 and the consolidated results of its operations and its cash flows for the year ended October 31, 2009, in conformity with U.S. generally accepted accounting principles.
Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Balance Sheets
October 31, 2010 and 2009
The accompanying notes are an integral part of these consolidated financial statements.
Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Statements of Operations and Comprehensive Loss
Years Ended October 31, 2010 and 2009
The accompanying notes are an integral part of these consolidated financial statements.
Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Statement of Stockholders’ Equity
Years Ended October 31, 2010 and 2009
The accompanying notes are an integral part of these consolidated financial statements.
BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the Years Ended October 31, 2010 and 2009
Supplemental Disclosures
The accompanying notes are an integral part of these consolidated financial statements
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 as Lam Liang Corp. The Company changed its name to Blacksands Petroleum, Inc. on June 9, 2006. Since August 2007, the Company has been engaged in the exploration, development, exploitation and production of oil and natural gas. Until November 9, 2009 when the Company acquired its interest in the J.E. Pettus Gas Unit, the Company was considered an exploration stage company in accordance with Accounting Standards Codification (“ASC”) No. 915. The Company sells its oil and gas products primarily to domestic pipelines and refineries. Its operations are presently focused in the States of Texas and New Mexico.
Principles of consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, NRG Asset Management LLC and BSPE Texas, LLC. Access Energy Inc., which was 75% owned by the Company, is included from the date of acquisition of August 3, 2007 until the date of disposal, April 30, 2010. The Company had been required to fund the operations of Access until Access was self-sustaining. Funding on behalf of the minority shareholder is expensed as incurred in the statement of operations. 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. Unproved oil and gas properties are periodically assessed to determine whether they have been impaired, and any impairment in value 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.
During the year ended October 31, 2009, the Company impaired its oil and gas properties by $3,831,190, which is reflected in the consolidated statement of operations. Management assessed the impact of the April 30, 2009 announcement regarding the sale of its investment in Access on the Company’s financial position and results of operation, and determined that the Company’s oil and gas property costs capitalized had been impaired requiring a write-down to the fair value of the asset ($nil) and accordingly, these capitalized costs were written down to $nil during the second quarter ended April 30, 2009. The fair value of the asset was determined with reference to the value of the monetary consideration for the proposed transaction for two-thirds of its 75% interest in Access as $1. To the extent that any costs incurred for Access projects would otherwise be capitalized as oil and gas property costs when they are incurred, such costs were expensed by the Company.
During the year ended October 31, 2010, the Company impaired its oil and gas properties by $163,576, which is reflected in the consolidated statement of operations. At October 31, 2010, the Company compared the expected undiscounted future cash flows on a field by field basis to the capitalized cost of the asset. The Company determined that based on its analysis, capitalized costs for one of its fields exceeded its fair value.
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, short term investments, and accounts receivable. During much of the fiscal year ended October 31, 2010, the Company maintained substantially all of its cash balances in a limited number of financial institutions in the United States. The balances are each insured by the Federal Deposit Insurance Corporation up to $250,000 through December 31, 2013, at which time they are scheduled to revert to the prior limit of $100,000. The Company had balances in excess of this limit at October 31, 2010 totaling $1,141,577. During the fiscal year ended October 31, 2009 and a portion of the fiscal year ended October 31, 2010, some of the Company’s cash and cash equivalents and short-term investments accounts were held with reputable Canadian financial institutions which are insured by the Canada Deposit Insurance Corporation (“CDIC”) up to Cdn$100,000. During year ended October 31, 2009, the Company has maintained balances exceeding the CDIC insurance limits. Cash and cash equivalents held outside of Canada are not insured (see also note 8). To reduce its risk associated with the failure of such financial institutions, the Company periodically evaluates the credit quality of the financial institutions in which it holds deposits. The Company has determined that there are no issues regarding the credit quality of the financial institutions in which it holds deposits, and any risk of loss to be remote. The Company does not have investments in asset-backed commercial paper.
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, 2010, our aggregate production imbalances were no material.
Stock-based compensation
The Company follows the provisions of 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 2006 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 1,727,778 and 500,000 for the years ended October 31, 2010 and 2009, respectively.
Foreign Currency Translation
The functional currency of the Company until April 30, 2010 was the Canadian Dollar, at which time the functional currency became the United States Dollar. The Company uses the United States Dollar as its reporting currency for consistency with registrants of the Securities and Exchange Commission (the “SEC”).
Transactions denominated in foreign currencies other than the functional currency are translated into the functional currency at the rate of exchange in effect at the time of the transaction. Monetary assets and liabilities are translated into the functional currency at the year-end exchange rate. Non-monetary items are translated at historical rates. All exchange gains and losses are included in earnings.
The functional currency financial statements are translated to the Company’s US dollars reporting currency. Accordingly, assets and liabilities are translated at the year-end exchange rate, and revenues and expenses are translated at the average exchange rate for the year. The unrealized foreign exchange impact of these translations is included in the accumulated comprehensive income in stockholders’ equity.
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, 2010 and October 31, 2009 because of the short period to maturity of these instruments. The Company’s derivative liabilities result from the issuance of equity instruments with embedded derivatives which the Company reports at their fair value.
New Accounting Pronouncements Adopted
In January 2010, the FASB issued guidance related to fair value measurements requiring new disclosures regarding transfers in and out of Level 1 and 2 and requiring the gross presentation of activity within Level 3. The guidance also clarifies existing disclosures of inputs and valuation techniques for Level 2 and 3 fair value measurements. Additionally, the guidance includes conforming amendments to employers’ disclosures about postretirement benefit plan assets. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009 (except for the disclosure of activity within Level 3 fair value measurements which is effective for fiscal years beginning after December 15, 2010 and for interim periods within those years). The impact of adopting this guidance has not resulted in additional disclosures in the Consolidated Financial Statements.
In January 2010, the FASB issued FASB Accounting Standards Update (ASU) No. 2010-03 Oil and Gas Estimations and Disclosures (ASU 2010-03). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule ASC 2010-3, as discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. We adopted ASU 2010-03 effective October 31, 2010.
On March 1, 2010, the Company adopted ASU 2010-06, Improving Disclosure about Fair Value Measurements. ASU 2010-06, issued January 2010, requires additional disclosures regarding fair value measurements, amends disclosures about postretirement benefit plan assets, and provides clarification regarding the level of disaggregation of fair value disclosures by investment class. The ASU is effective for interim and annual reporting periods beginning after December 15, 2009, except for certain Level 3 activity disclosure requirements that will be effective for reporting periods beginning after December 15, 2010.
The Company has implemented all new accounting pronouncements above that are in effect and that may impact its financial statements and does not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on its financial position or results of operations.
2.
Short-term Investment
The Company’s short-term investment, a redeemable short-term investment certificate, was classified as available-for-sale. The fair value of this investment approximated its carrying value which was its cost plus accrued interest. The certificate principal and contracted interest were guaranteed, and accordingly there was no gain or loss recorded. Until the short-term investment matured, the Company recorded an accrual for interest earned, with a credit to interest income in the consolidated statements of operations. During the year ended October 31, 2010, the Company discontinued its investments into these short-term investments. All short term investments had matured prior to April 30, 2010. Short term investments at October 31, 2010 and 2009 totaled $nil and $88,553, respectively.
3.
Oil and Gas Property Costs
In the years ended October 31, 2010 and October 31, 2009, the Company incurred property acquisition costs as follows:
During the year ended October 31, 2010, the Company incurred costs totaling $1,786,997 for the acquisition of oil and gas properties considered unproven. All other costs incurred in the year ended October 31, 2010 were from the acquisition and operation of proven properties. Costs incurred during the year ended October 31, 2009 were for the exploration costs.
Blacksands Texas projects
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. NRG Assets Management LLC, a Texas LLC and Texas registered operating company owned by the Company is the operator at all depths.
Beech Creek Oil Wells (known as “Beech Creek Field”) Acquisition in April 2010
On April 5, 2010, the Company purchased different leasehold working interests in the Beech Creek Wells No. 1 and No A-2 located in Hardin County, Texas for $740,798 in cash. These property interests were previously owned by a group of five different working interest owners. A 30.0587% working interest (21.942851% net revenue interest) was acquired in the Beech Creek #1 well. A 24.4337% (18.3253% Net Revenue Interest) working interest was acquired in the Beech Creek A-2 well.
The unaudited pro forma results presented below for the years ended October 31, 2010 and 2009 have been prepared to give effect to the acquistion of the Beech Creek on the Company’s results of operations under the purchase method of accounting as if it had been consummated at the beginning of each of the periods presented. The unaudited pro forma results do not purport to represent the results of operations that actually would have occurred on such date or to project the Company’s results of operations for any future date or period.
AP Clark Wells (known as “Jo-Mill Field”) Acquisition in August 2010
On August 10, 2010 the Company purchased the interest of Bonanza Oil & Gas, Inc’s 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. In addition, the Company agreed to carry Bonanza for a 2.5% gross leasehold working interest (1.875% net revenue interest) for the next well drilled on the property to the sales point.
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. This remaining $500 thousand is reflected in the financial statements at October 31, 2010 as accounts payable. The property has no production and was accounted for as an acquisition of unproved property. In addition, Blacksands is responsible for paying all costs associated with 37 linear miles of 2-D seismic data, which is estimated at $400,000. As a result of this acquisition, the Company recorded $1.5 million in unproved properties. 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.
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.
Access Projects
A10 Project
On November 3, 2006, the Company entered into a joint venture agreement (“JV Agreement”), which was amended on May 18, 2007, and further amended on March 17, 2008, and on May 24, 2007, the Company entered into an Impact/Benefit Agreement with the Buffalo River Dene Nation (“BRDN”) to explore and develop its traditional lands in northern Saskatchewan and Alberta.
Pursuant to the terms of the JV Agreement, the Company was responsible for 100% of the costs to explore and develop any project within the traditional lands.
As at October 31, 2009, the Company had paid or accrued a total of approximately Cdn$3,098,500 (approximately US$2,864,000) to the BRDN pursuant to the Impact/Benefit Agreement. During the year ended October 31, 2009, the Company spent funds to evaluate and to acquire properties with oil and gas potential in northern Saskatchewan and northern Alberta. As a result of the Company’s sale of the majority of its Access shares on April 30, 2010 (note 4), the Company no longer controls this project including the Impact/Benefit Agreement with the BRDN.
La Loche Project
On October 15, 2008, Access signed a Joint Venture Agreement and an Impact Benefit Agreement (the “Agreements”) with La Loche Clearwater Development Authority. The Agreements were subject to the ratification by the aboriginal residents of the area (the La Loche “Community”) before they were effective. On February 14, 2009, the Community ratified the Joint Venture Agreement and the Impact Benefit Agreement signed by Access and the La Loche Clearwater Development Authority (“LLCDA”) on October 15, 2008. With the ratification of the Joint Venture Agreement and Impact Benefit Agreement between Access and LLCDA in February 2009, Access is considered to have secured another project and the 500,000 “Access Warrants” referred to in note 7 vested with their value capitalized to oil and gas property costs.
The Agreements allowed Access to exclusively participate in the acquisition, exploration and development of certain surface and subsurface rights in and to approximately 3,000,000 hectares of La Loche Traditional Lands in northwestern Saskatchewan, north and west of the town of La Loche, Saskatchewan.
The terms of the Agreements are for twenty years from the date of signing (October 15, 2008), and automatically renew for consecutive terms of twenty years if Access provides notice of renewal to LLCDA before the expiration of the Agreements. Pursuant to the terms of the Agreements, Access paid Cdn$15,000 (approximately $13,920) on the signing of the Agreements, and is obligated to pay to the LLCDA Cdn$75,000 (approximately US$69,300) at the start of each three-month period upon ratification of the Agreements (or Cdn$300,000 annually - approximately US$277,300). As well, Access was obligated to pay a 5% gross overriding royalty to LLCDA from the production of any products. During the year ended October 31, 2009, the Company expensed Cdn$300,000 (approximately US$277,300) representing amounts payable to LLCDA after ratification. The Company incurred expenses totaling Cdn$150,000 (approx $149,000) from November 1, 2009 to April 30, 2010. As a result of the Company’s sale of the majority of its Access shares on April 30, 2010 (note 4), the Company no longer controls this project.
Impairment of Oil and Gas Property Costs
On April 30, 2009, the Company announced that the Board of Directors had approved an agreement in principle to sell two-thirds of its interest in Access Energy to the other stockholder of Access Energy. Following the transfer, Blacksands would hold 25% of the outstanding Access shares and the other Access shareholder would hold 75%. As consideration for the transfer, the Company would be relieved of its contractual obligation to fund Access’ annual plan and budget including Access’ commitments to First Nations’ communities, the other Access shareholder would pay Blacksands nominal consideration, and warrants to purchase the Access shares held by the other Access shareholder would be cancelled.
Management assessed the impact of the April 30, 2009 announcement on the Company’s financial position and results of operation, and determined that the Company’s oil and gas property costs capitalized had been impaired requiring a write-down to the fair value of the asset ($nil) and accordingly, these capitalized costs were written down to $nil during the second quarter ended April 30, 2009. The fair value of the asset was determined with reference to the value of the monetary consideration for the proposed transaction for two-thirds of its 75% interest in Access as $1. To the extent that any costs incurred for Access projects would otherwise be capitalized as oil and gas property costs when they are incurred, such costs will be expensed by the Company.
At October 31, 2010, 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 one of its fields exceeded its fair value. As a result the Company recorded an impairment totaling $163,576.
4.
Gain on Sale of Access Shares
On April 30, 2010, the Company sold 441 of the 600 shares it held in Access Energy to the other stockholder of Access Energy. Following the transfer, Blacksands holds 19.9% of the outstanding Access shares. As consideration for the transfer, the Company paid the other Access shareholder $75,000 cash and the Company is relieved of its contractual obligation to fund Access’ annual plan and budget including Access’ commitments to First Nations’ communities. In addition, the Company is released of any rights and obligations related to any joint venture agreements between Access and other counterparties. In connection with the sale, warrants held by the other Access shareholder to purchase additional shares of the Company were cancelled. The fair value of the warrants on April 30, 2010 was $1,120,263, which was included in the gain calculation for the sale of the Access shares. The weighted variables used in the Black-Scholes option-pricing model, include (1) 1.3% risk-free interest rate (2) 2.27 years expected term, (3) expected volatility of 176%, and (4) zero expected dividends.
Access had no assets and liabilities of $1,637,104 (including an offset for accumulated currency fluctuation of $302,556). Because the Company continues to own 19.9% of the outstanding shares of Access, the transaction does not result in discontinued operations. As a result of this sale, the Company recorded a gain of $2,341,452, which primarily represents the release from liabilities associated with Access.
5.
Debt
On June 18, 2010, the Company entered into a bridge loan agreement (the “Bridge Loan Agreement”) with Talras Overseas S.A. (“Talras”). On such date, Talras made a bridge loan to the Company in the amount of $1,000,000 (the “Bridge Loan”). Under the Bridge Loan Agreement, the principal face amount of $1,000,000 was provided in the first tranche and subsequent tranches of $500,000 or more were permitted up to $2,500,000 in the aggregate to be funded by June 30, 2010. The Company had borrowed the total amount under the agreement of $2,500,000. This Bridge Loan was unsecured.
The Bridge Loan bears interest at a rate of 6.0% per annum which amount shall, at the option of the Company, be payable either (i) in cash or (ii) by adding such interest to the accreted principal amount which is the outstanding principal amount including all PIK amounts (the “Accreted Principal Amount”).
Under the original terms, the Company must pay the Accreted Principal Amount together with all interest accrued and unpaid at the earliest of (i) June 30, 2011 or (ii) the closing date of an investment or series of related investments in equity securities of the Company in an aggregate amount of at least $10 million including the Accreted Principal Amount and interest outstanding under the Bridge Loan Agreement and any other bridge loan agreements. Should an aggregate $10 million investment or series of related investments in equity securities of the Company occur prior to June 30, 2011, then all of the obligations due under this note will be converted automatically into equity shares of the Company. The Company evaluated the conversion feature under ASC 815 and determined that is was not a derivative.
On October 29, 2010, the Company and Talrus entered into a exchange agreement, whereby the amount then outstanding on the Bridge Loan Agreement 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 convertible preferred shares provide for dividends at the rate of 8% per annum of the stated value of the shares. The dividends are cumulative and payable in cash or in additional Series A Convertible Preferred shares. The shares are convertible at any time at the option of the holder into common stock at a conversion price of $3.75 per common share. If not previously converted, all outstanding shares of the Series A preferred stock, including any unpaid dividends, convert to shares of common stock on October 29, 2013. The warrants are exercisable at an exercise price of $6 per share through October 29, 2013.
As a result of the significant change in the terms of the agreements involved in the exchange agreement, the Company recorded a loss on the extinguishment of the original loan totaling $823,756.
The Company evaluated the warrants under ASC 815 and determined that due to a “reset” or “ratchet” provision causing variability in the exercise price of the warrant, the instrument was not indexed in the Company’s own stock. As a result, the day one fair value of the warrants, which was $923,756, was recorded as a derivative liability on the consolidated balance sheet. The fair value of the warrant grant was estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 154%, risk free interest rate of .51%; and expected lives of three years. The Company recognized a beneficial conversion feature in connection with the issuance of the preferred shares and warrants of $923,756, which has been reflected as a deemed dividend in the statement of operations and comprehensive loss.
In November 2009, the Company received an interest-free advance from an unrelated third party totaling $60,000. In January 2011, the interest-free advances were converted into a note payable. The note payable is due January 11, 2012 and incurs interest at the rate of 6%.
6. Asset Retirement Obligation
The following table summarizes the change in the asset retirement obligation for the years ended October 31,
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.
7. Stockholders Equity
Preferred Stock
In June 2006, the Company amended its certificate of incorporation to authorize 10,000,000 shares of preferred stock at a par value of $.001.
In October 2010, the Board of Directors designated 310,000 shares of the Company’s preferred stock as Series A Convertible Preferred Stock (“Series A Preferred”). The Series A Preferred are convertible into shares of common stock at a conversion price of $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 will mandatorily convert into common shares on October 29, 2013. As of October 31, 2010, 250,000 shares of the Series A Preferred were issued and outstanding.
1-For-3 Reverse Stock Split
On January 11, 2011, the Company effectuated a 1 for 3 split. On the date of the 1 for 3 split, the Company amended its certificate of incorporation to reduce the number of authorized common shares from 300,000,000 to 100,000,000. The effect of the split has been reflective retroactively for all periods presented.
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, 2010, stock options were granted to certain directors, officers and consultants to the Company for options representing 1,033,333 common shares. The exercise price of the options is $3, with a ten year term, with vesting occurring at varying rates over the first three years. The fair value of the option grants were estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 188% to 158%, risk free interest rate of 1.76% to 2.74%; and expected lives of five to six years. During the year ended October, 31, 2010, the Company recorded stock based compensation totaling $979,835 as a result of these stock option grants.
A summary of the Company’s stock option activity and related information is as follows:
The intrinsic value of the exercisable options at October 31, 2010 totaled $140,000. At October 31, 2010, the weighted average remaining life of the stock options is 9.64 years. At October 31, 2010, there was $1,534,100 of total unrecognized compensation cost related to the stock options granted under the plan. This cost is expected to be recognized over a weighted average period of 1.09 years.
Warrants
A summary of the Company’s stock warrant activity and related information for the years ended October 31, 2010 and 2009 is as follows:
There is no intrinsic value for the outstanding warrants at October 31, 2010. There remaining term of the warrants is 3 years and the 333,333 warrants are accounted for as derivative liabilities.
The 500,000 Warrants outstanding at October 31, 2009, were issued as part of the consideration for the purchase of the subsidiary, Access Energy. Referred to as the “Access Warrants”, each of these 500,000 Access Warrants was exercisable for five years commencing August 3, 2007 and entitled the holder to purchase one share of Common Stock at $6.00 per share. The Access Warrants were granted in consideration for the future acquisition of an additional project other than the A10 Project, which, at the time of the acquisition of Access had not been secured. The Access Warrants did not vest until Access secured an additional project. The Access Warrants vested with the ratification of the Agreements with LLCDA on February 14, 2009, and the fair value of the Access Warrants was calculated on the date of vesting (February 14, 2009) using the Black-Scholes method with the following assumptions:
The fair value of the Access Warrants of $108,000 was capitalized to oil and gas property costs with a credit to Additional Paid-In Capital in the quarter ended April 30, 2009. The warrants were cancelled as a result of the sale of Access shares.
8 Derivative Instruments
In June 2008, the FASB ratified ASC 815-15, “ Derivatives and Hedging - Embedded Derivatives” (“ASC 815-15”). ASC 815-15, specifies that a contract that would otherwise meet the definition of a derivative, but is both (a) indexed to its own stock and (b) classified in stockholders’ equity in the statement of financial position would not be considered a derivative financial instrument. ASC815-15 provides a new two-step model to be applied in determining whether a financial instrument or an embedded feature is indexed to an issuer’s own stock, including evaluating the instrument’s contingent exercise and settlement provisions, and thus able to qualify for the ASC 815-15 scope exception. It also clarifies the impact of foreign currency denominated strike prices and market-based employee stock option valuation instruments on the evaluation.
The Company evaluated all of its financial instruments and determined that 333,333 warrants associated with an October 2010 exchange agreement qualified for treatment under ASC 815-15. The fair value of these warrants was classified on the date of their issuance in the amount of $923,756 as derivative liability. There was no change in the value of the warrants from October 29, 2010 (date of issuance) to October 31, 2010.
The fair values of the warrants were estimated using the following assumptions:
9.
Related Party Transactions
As of October 31, 2009, there are no significant related party transactions between the Company and any of its officers or directors other than a consulting agreement between Access and a company controlled by a director of the Company as described below.
On November 1, 2005, Access entered into an agreement with Coniston Investment Corp. (“Coniston”), to provide management, consulting and advisory services to Access (the “Services”). These services include assisting Access in negotiating joint venture agreements, assisting in the formation of a team of technical experts, and other consulting and advisory services as required by Access from time to time. The agreement automatically renews for consecutive one-year terms unless terminated by either party in writing, and was set to expire on October 31, 2010. Effective April 30, 2010, the Company was no longer a party to this agreement as a result of its sale of the Access shares (note 4).
Coniston’s sole shareholder, President and CEO is the President and CEO of Access, a director of the Company since August 2007, and, from November 1, 2007 to July 31, 2009, also the President and CEO of the Company. Pursuant to the agreement: (i) Access shall pay Coniston a fee of: (i) Cdn$260,000 per annum, payable monthly (paid); (ii) Cdn$1,000,000 (the “Dene Fee”) in the event Access entered into an agreement with the BRDN and/or its associates or affiliates to develop hydrocarbon opportunities in a defined area within Treaty 10 lands which includes the traditional and historically occupied and used lands of the BRDN (paid); and (iii) Coniston will also be entitled to receive a 1.25% non-convertible overriding royalty based on 100% production (“GORR”) from any and all projects that Coniston brings to Access (the “Royalty Fee”). Amounts are due on demand by Access, are non-interest bearing, and are unsecured. Effective January 1, 2009, the agreement was revised to reflect a reduced fee of Cdn$160,000 per annum, payable monthly. The revised agreement was set to expire on October 31, 2010, but automatically renews for consecutive one-year terms unless terminated by either party in writing. Effective April 30, 2010, the Company was no longer a party to this agreement as a result of its sale of the Access shares (note 4).
During the year ended October 31, 2009, Coniston charged Access management fees of Cdn$176,667 which are included in the consolidated statement of operations. Amounts payable to Coniston of Cdn$40,000 (US$36,972) were recorded to the end of October 31, 2009. These amounts payable are due on demand, are non-interest bearing, and are unsecured.
Additionally, $7,500 and $6,667 was owed to directors for director fees at October 31, 2010 and 2009, respectively, and paid subsequent to year end. It was payable on demand, non-interest bearing and unsecured.
During the year ended October 31, 2010, the Company made payments for management consulting services to Holcombe Ventures LLC, a firm controlled by the Company’s chief financial officer (through September 1, 2010) and director. Payments for these services during the year ended October 31, 2010 totaled $91,649.
10.
Financial Instruments and Fair Value Measurement
ASC 825 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. ASC 825 establishes three levels of inputs that may be used to measure fair value.
Level 1 applies to assets and liabilities for which there are quoted prices in active markets for identical assets or liabilities. Valuations are based on quoted prices that are readily and regularly available in an active market and do not entail a significant degree of judgment.
Level 2 applies to assets and liabilities for which there are other than Level 1 observable inputs such as quoted prices for similar assets or liabilities in active markets, quoted prices for identical assets or liabilities in markets with insufficient volume or infrequent transactions (less active markets) or model-derived valuations in which significant inputs are observable or can be derived principally from, or corroborated by, observable market data. Level 2 instruments require more management judgement and subjectivity as compared to Level 1 instruments.
Level 3 applies to assets and liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities. The determination of fair value for Level 3 instruments requires the most management judgment and subjectivity.
The Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities, accounts payable with related parties and derivative liabilities. The estimated fair values of the financial instruments have been determined based on the Company’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction. The fair values of financial instruments generally approximate their book amounts due to the short-term maturity of these instruments at October 31, 2010 and 2009 except as disclosed below:..
Assets and liabilities measured at fair value on a recurring basis were presented on the Company’s consolidated balance sheet as of October 31, 2010 as follows:
Cash equivalents
The Company’s cash equivalents as at October 31, 2009 were three deposits held at the EFG Bank & Trust (Bahamas) Ltd. The Company has elected to record these deposits using the fair value option. These deposits are denominated in U.S. dollars, however on maturity, the Company may receive the deposit in either U.S. or Canadian dollars, depending on the exchange rate in relation to a set strike conversion rate. If the exchange rate is in excess of the strike price 2 days prior to maturity, the deposit and interest will be repaid by the bank in Canadian dollars using the strike price to determine such amount. If the exchange rate is below the strike price 2 days prior to maturity, the deposit and interest will be repaid in U.S. dollars. There were no such deposits at October 31, 2010. The significant terms of the deposits as at October 31, 2009 are as follows:
The fair value option elected for these deposits represents the most appropriate expected amount to be received. The fair value of these deposits has been determined using Level 2, significant other observable inputs. The input used to calculate the fair value was the U.S. /Canadian forward exchange rate for the maturities of the deposits. This rate as of October 31, 2009 was 1.0844 for each maturity date noted above.
Interest income related to these deposits is recorded using the stated coupon rate and included in the “interest income”. Other fair value adjustments are recorded as “loss (gain) from foreign currency exchange” as any change in value is a result of changes in currency exchange rates.
11.
Commitments and Contingencies
The Company’s contractual obligations not included in its Balance Sheet as of October 31, 2010 (except Long-term debt and Abandonment obligations) are as follows:
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, 2010, 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.
Operating leases
The Company leases its offices Texas on a month to month basis. Rent expense for the years ended October 31, 2010 and 2009 was $16,101 and $29,471, respectively.
12. 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:
The composition of deferred tax assets/liability is as follows:
The valuation allowance for the year ended October 31, 2009, included $2,394,595 pertaining to Access. The valuation allowance (excluding Access) increased by $327,326 during the year ended October 2010. 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 $4,854,433 at October 31, 2010. These losses expire as follows:
13. Subsequent Events
Promissory note
On November 19, 2010, the Company entered into a loan agreement with Silver Bullet Property Holdings for a promissory note totaling $1,500,000. The note bears interest at the rate of 10% per annum and is due on the earlier of the date the Company closes on an offering with gross proceeds of at least $5 million or November 19, 2011.
AP Clark II Prospect
On November 29, 2010, the Company entered into a leasehold acquisition and participation agreement (the “LAPA”) with Westerly Exploration, Inc. (“Westerly”) pursuant to which (i) the Company acquired the leasehold interests and rights thereto in the AP Clark II Prospect (as defined in the LAPA) located in Borden County, Texas from Westerly for $260,000 (ii) the Company paid Westerly $119,000 as advance payment towards 70% of the actual third party costs that will be required to receive an extension of certain leasehold properties included in the AP Clark II Prospect (as defined in the LAPA) (the “Extension Monies”) and (iii) the Company and Westerly agreed to drill the W.D. Everett Well No. 3 located within the AP Clark II Prospect (as defined in the LAPA) whereby all costs of such drilling operation shall be borne 30% by Westerly and 70% by the Company.
Upon execution of the LAPA, the Company paid Westerly $163,590 for the sole purpose of acquisition of casing for the W.D. Everett Well No. 3. If the cost of the casing exceeds $233,700, the Company is required to pay 70% of the excess.
On or before 10 days from the expected date the rig will move in or 2 days prior to Westerly’s date of execution of a W.D. Everett Well No. 3 drilling contract (whichever is earlier but not before December 15, 2010), the Company shall pay the sum of $556,990 to Westerly for the sole purpose of defraying all costs of drilling the W.D. Everett Well No. 3 to casing point. The $556,990 was paid by the Company in December 2010. If the cost of drilling to the casing point exceeds $795,700, the Company is required to pay 70% of the excess.
Upon achieving casing point in the W.D. Everett Well No. 3, completion operations shall proceed on W.D. Everett Well No. 3 provided the Company shall pay Westerly the sum of $609,500 (the estimated 70% share of completion costs) for the sole purpose of defraying all costs of completing the W.D. Everett Well No. 3.
Copano Bay
Effective November 1, 2010, the Company 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 are currently four active wells on the property.
14. Supplemental Oil and Gas Disclosures
The following supplemental information regarding the oil and gas activities of the Company for 2010 and 2009 is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and ASC No. 932 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
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, AND DEVELOPMENT ACTIVITIES
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 CREST Engineering Services, Inc. The oil and natural gas price as of October 31, 2010 is based on the 12-month unweighted average of the first of the month prices of the West Texas Intermediate posted price. Oil and natural gas prices as of October 31, 2009 are based on the respective year-end 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, 2010 is based on the 12-month unweighted average of the first of the month prices of the Henry Hub spot price. Gas prices as of October 31, 2009 are based on the year-end Henry Hub spot market 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.
CHANGES IN ESTIMATED RESERVE QUANTITIES
The net interest in estimated quantities of proved developed and undeveloped reserves of crude oil and natural gas at October 31, 2010 and 2009, and changes to such quantities during each of the years then ended were as follows:
The Company's proved developed reserves are as follows:
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 CREST Engineering Services, Inc. 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, 2010 and 2009 the future cash inflows were estimated by applying year-end oil and natural gas prices 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, 2010, 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.
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, 2010:
ITEM 9
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
On February 10, 2010, Blacksands Petroleum, Inc. terminated its relationship with Ernst & Young LLP (“E&Y”), their independent accountants. Blacksands dismissed E&Y as approved by the Board of Directors. E&Y’s auditors’ report for Blacksands’ financial statements for the fiscal years ended October 31, 2009 and October 31, 2008 and for the period October 12, 2004 (inception) through October 31, 2009 did not contain an adverse opinion, or a disclaimer of opinion, nor qualification or modification as to uncertainty, audit scope, or accounting principles. There were not any disagreements between Blacksands and E&Y, and none of the events described in Item 304(a)(1)(v) of Regulation S-K occurred.
On February 10, 2010, Blacksands engaged Malone Bailey LLP (“Malone”) to serve as its independent accountants. During the two most recent fiscal years and through February 10, 2010, the Company did not consult with Malone with regard to the application of accounting principles to a specified transaction, completed or proposed, the type of audit opinion that might be rendered on the Company’s financial statements, or any matter that was either the subject of a disagreement or a reportable event.
ITEM 9A
ITEM 9A - CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the 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 chief executive officer and chief financial officer concluded that, as a result of the material weaknesses described below, as of October 31, 2010, our disclosure controls and procedures are not designed at a reasonable assurance level and are 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 chief executive officer 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)
We did not have sufficient personnel in our accounting and financial reporting functions. As a result we were not able to achieve adequate separation 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)
We did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of U.S. GAAP commensurate with out complexity and our financial accounting and reporting requirements. This control deficiency is pervasive in nature. Further, there is a reasonable possibility that material misstatements of the financial statements including disclosures will not be prevented or detected on a timely basis as a result.
We are committed to improving our accounting and financial reporting functions. As part of this commitment, we will create a segregation of duties consistent with control objectives and will look to increase our personnel resources and technical accounting expertise within the accounting function by the end of fiscal 2011 to appropriately address non-routine or complex accounting matters. In addition, we have engaged an outside accounting firm and a new Chief Financial Officer to provide additional knowledgeable personnel with technical accounting expertise to further support the current accounting personnel at the Company.
Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the following material weaknesses: (A) lack of sufficient personnel in our accounting and financial reporting functions to achieve adequate segregation of duties; and (B) insufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of US GAAP commensurate with our complexity and our financial accounting and reporting requirements.
Management believes that the hiring of additional personnel who have the technical expertise and knowledge with the non-routine or technical issues we have encountered in the past will result in both proper recording of these transactions and a much more knowledgeable finance department as a whole. Due to the fact that our accounting staff consists of a Chief Financial Officer and an accounting clerk, 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 turnover issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.
We will continue to monitor and evaluate the effectiveness of our disclosure controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.
(b) Changes in internal control over financial reporting.
We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.
On September 1, 2010, Mark Holcolmbe resigned as our Chief Financial Officer. On October 22, 2010, Donald Giannattasio was appointed as our Chief Financial Officer. Other than such resignation and appointment, there were no changes in our internal control over financial reporting that occurred during the quarter ended October 31, 2010 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, 2010. The effectiveness of our internal control over financial reporting as of October 31, 2010 has not been audited by Malone Bailey LLP, our independent registered public accounting firm. Pursuant to the recently passed Dodd-Frank Wall Street Reform and Consumer Protection Act, smaller reporting companies, like us, are exempt from the requirement that management’s report be subject to an audit by an independent registered public accounting firm.
ITEM 9B
ITEM 9B - OTHER INFORMATION
None.
PART III
ITEM 10
ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The names of our directors and executive officers and their ages, titles, and biographies as of October 31, 2010 are set forth below:
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.
David DeMarco has been our President, Chief Executive Officer and a Director since May 2010. Between 2004 and April 2010, Mr. DeMarco was the Vice President of Business Development, Gaither Petroleum Corporation. Mr. DeMarco is a Certified Petroleum Landman (No. 30164) and has extensive experience in all aspects of the oil and gas exploration and production business. Mr. DeMarco has extensive experience with start up oil and gas companies and has managed all aspects of 3-D seismic acquisition and exploration activities onshore in the United States. Mr. DeMarco received his undergraduate degree in Economics with minors in Petroleum Land Management and Petroleum Engineering from the University of Texas at Austin in 1990.
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.
Mark Holcombe has been a Director since November 2007. Mr. Holcombe was our President and Chief Executive Officer between August 2009 and May 2010 and our Chief Financial Officer between September 2009 and September 2010. Mr. Holcombe has been a partner and managing director of Stirling Partners Limited since he founded it in 2006. Between 2004 and 2006, Mr. Holcombe was the Head of Corporate Development and Private Equity and Chief Compliance Officer at GEM Global Equities Management, S.A., an emerging market hedge fund. Mr. Holcombe was previously an investment banker at DLJ and ING Capital in New York. Since 2007, Mr. Holcombe has served on the board of Sandfield Ventures Corporation, PNG LNG Ltd. and Pacific LNG Operations LTD. Mr. Holcombe holds a B.A. from Colgate University.
Bruno Mosimann has been a Director since May 2006. Since July 1985, he has been the President and Managing Director of Romofin AG, a firm that supplies investment management services to its customers.
Eric Urban has been a Director since March 2010. Mr. Urban has also served as the Director of Operations of Blacksands Petroleum Texas LLC. For the past 5 years, Mr. Urban has worked as a Landman and Land Manager for Gaither Petroleum Corporation, an independent oil and gas company. Mr. Urban holds a BBA in International Business from the University of Houston, and is an active member of various professional oil and gas organizations.
Rick Wilson has been a Director since February 2007. 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.
Meetings and Committees of the Board of Directors
During the fiscal year ended October 31, 2010, our board of directors held 16 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.
Audit Committee
Our Audit Committee currently consists of Bruno Mosimann., Our Board of Directors has determined that Mr. Mosimann is “independent” as that term is defined under applicable SEC rules and under the current listing standards of the NASDAQ Stock Market. Mr. Mosimann is our audit committee financial expert.
The Audit Committee meets with management and Blacksands’ external auditors to review matters affecting financial reporting, the system of internal accounting and financial controls and procedures, and the audit procedures and audit plans. The Audit Committee reviews Blacksands’ significant financial risks, will be involved in the appointment of senior financial executives, and will annually review Blacksands’ insurance coverage and any off-balance sheet transactions.
The Audit Committee is mandated to monitor Blacksands’ audit and the preparation of financial statements and to review and recommend to the Board of Directors all financial disclosure contained in Blacksands’ public documents. The Audit Committee is also mandated to appoint external auditors, monitor their qualifications and independence and determine the appropriate level of their remuneration. The external auditors report directly to the Audit Committee and to the board of directors. The Audit Committee and Board of Directors each have the authority to terminate the external auditor’s engagement. The Audit Committee will also approve in advance any services to be provided by the external auditors which are not related to the audit.
Compensation Committee
Our Compensation Committee currently consists of Bruno Mosimann and David DeMarco with Mr. Mosimann elected as Chairman of the Committee. Our Board of Directors has determined that only Mr. Mosimann is “independent” under the current listing standards of the NASDAQ Stock Market. Our Board of Directors has adopted a written charter setting forth the authority and responsibilities of the Compensation Committee.
Our Compensation Committee has responsibility for assisting the Board of Directors in, among other things, evaluating and making recommendations regarding the compensation of our executive officers and directors, assuring that the executive officers are compensated effectively in a manner consistent with our stated compensation strategy, producing an annual report on executive compensation in accordance with the rules and regulations promulgated by the SEC, periodically evaluating the terms and administration of our incentive plans and benefit programs and monitoring of compliance with the legal prohibition on loans to our directors and executive officers.
Corporate Governance Committee
Our Corporate Governance Committee currently consists of Bruno Mosimann and Mark Holcombe, with Mr. Mosimann elected as Chairman of the Committee. Our Board of Directors has determined that only Mr. Mosimann is “independent” under the current listing standards of the NASDAQ Stock Market.
The Corporate Governance Committee is charged with the responsibility of assisting the Board in fulfilling its oversight responsibilities in relation to the corporate governance practices and policies of the Company, and assessing the functioning and effectiveness of the Board, its committees, and its individual members.
Director Nomination Process
We do not have a nominating committee. The Board seeks qualified candidates to serve on the Board when needed, and all Board members participate in all director nominating and approval. The Board, at its discretion, could ask the Corporate Governance Committee to seek and nominate qualified candidates on the Board’s behalf. The Board may employ a variety of methods for identifying and evaluating nominees for director. The Board regularly assesses the size of the Board, the need for particular expertise on the Board, and whether any vacancies on the Board are expected due to retirement or otherwise. In the event that vacancies are anticipated, or otherwise arise, the Committee considers various potential candidates for director which may come to the Committee’s attention through current Board members, shareholders, or other persons. These candidates are evaluated at regular or special meetings of the Board, and may be considered at any point during the year.
The Board will consider candidates recommended by shareholders at its discretion. If any materials are provided by a shareholder in connection with the nomination of a director candidate, such materials are forwarded to the Board as part of its review. A potential candidate nominated by a shareholder is treated like any other potential candidate during the review process by the Board.
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. Except as disclosed below, we believe that, during fiscal 2010, our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements.
·
A late Form 4 was filed by Bruno Mosimann relating to the acquisition on June 15, 2010 of 200,000 stock options granted. The options vest 125,000 on June 15, 2010; 25,000 options vest on July 31, 2010; 25,000 options vest on October 31, 2010 and 25,000 options vest on January 31, 2011 at an exercise price of $3.00 per share.
·
A late Form 4 was filed by Mark Holcombe relating to the acquisition on June 15, 2010 of 400,000 stock options granted. The options vest 250,000 on June 15, 2010; 50,000 options vest on July 31, 2010; 50,000 options vest on October 31, 2010 and 50,000 options vest on January 31, 2011 at an exercise price of $3.00 per share.
·
A late Form 4 was filed by Eric Urban relating to the acquisition on June 15, 2010 of 600,000 stock options granted. The options vest 150,000 on June 1, 2011; 200,000 options vest on June 1, 2012 and 250,000 options vest on June 1, 2013 at an exercise price of $3.00 per share.
·
A late Form 4 was filed by David DeMarco relating to the acquisition on June 15, 2010 of 1,000,000 stock options granted. The options vest 300,000 on June 1, 2011; 300,000 options vest on June 1, 2012 and 400,000 options vest on June 1, 2013 at an exercise price of $3.00 per share.
·
A late Form 3 was filed by David DeMarco relating to the ownership of 132,470 shares.
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.
ITEM 11
ITEM 11 - EXECUTIVE COMPENSATION
Under the rules of the SEC, this Compensation Discussion and Analysis Report is not deemed to be incorporated by reference by any general statement incorporating this Annual Report by reference into any filings with the SEC.
The Compensation Committee has reviewed and discussed the following Compensation Discussion and Analysis with management. Based on this review and these discussions, the Compensation Committee recommended to the Board of Directors that the following Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
Submitted by the Compensation Committee
Bruno Mosimann, Chairman
David DeMarco
COMPENSATION DISCUSSION AND ANALYSIS (CD&A)
The following discussion and analysis of compensation arrangements of our named executive officers for the fiscal year ended October 31, 2010 should be read together with the compensation tables and related disclosures set forth below.
Compensation Philosophy and Objectives
We believe our success depends on the continued contributions of our named executive officers. Our named executive officers are primarily responsible for our growth and operations strategy, and the management of the day-to-day operations of our subsidiaries. Therefore, it is important to our success that we retain the services of these individuals to ensure our future success and prevent them from competing with us should their employment with us terminate.
Our overall compensation philosophy is to provide an executive compensation package that enables us to attract, retain and motivate executive officers to achieve our short-term and long-term business goals. We strive to apply a uniform philosophy regarding compensation of all employees, including members of senior management. This philosophy is based upon the premise that our achievements result from the combined and coordinated efforts of all employees working toward common goals and objectives in a competitive, evolving market place. The goals of our compensation program are to align remuneration with business objectives and performance and to enable us to retain and competitively reward executive officers and employees who contribute to our long-term success. In making executive compensation and other employment compensation decisions, the Compensation Committee considers achievement of certain criteria, some of which relate to our performance and others of which relate to the performance of the individual employee. Awards to executive officers are based on our achievement and individual performance criteria.
The Compensation Committee will evaluate our compensation policies on an ongoing basis to determine whether they enable us to attract, retain and motivate key personnel. To meet these objectives, the Compensation Committee may from time to time increase salaries, award additional stock options or provide other short and long-term incentive compensation to executive officers and other employees.
Compensation Program & Forms of Compensation
We provide our executive officers with a compensation package consisting of base salary and participation in benefit plans generally available to other employees. In setting total compensation, the Compensation Committee considers individual and company performance, as well as market information regarding compensation paid by other companies in our industry.
In order to achieve the above goals, our total compensation packages include base salary, annual bonus, as well as long-term compensation in the form of stock options.
Base Salary. Salaries for our executive officers are initially set based on negotiation with individual executive officers at the time of recruitment and with reference to salaries for comparable positions in the industry for individuals of similar education and background to the executive officers being recruited. We also consider the individual’s experience, and expected contributions to our company. Base salary is continuously evaluated by competitive pay and individual job performance. Base salaries for executives are reviewed annually or more frequently should there be significant changes in responsibilities. In each case, we take into account the results achieved by the executive, his or her future potential, scope of responsibilities and experience, and competitive salary practices.
Bonuses. Our executive officers are entitled to an annual bonus, to be determined at the discretion of the Compensation Committee, based on our financial performance and the achievement of the officer’s individual performance objectives.
Long-Term Incentives. Longer-term incentives are provided through stock options, which reward executives and other employees through the growth in value of our stock. The Compensation Committee believes that employee equity ownership provides a major incentive for employees to build stockholder value and serves to align the interests of employees with those of our stockholders. Grants of stock options to executive officers are based upon each officer’s relative position, responsibilities and contributions, with primary weight given to the executive officers’ relative rank and responsibilities. Initial stock option grants designed to recruit an executive officer may be based on negotiations with the officer and with reference to historical option grants to existing officers. Stock options are generally granted at an exercise price equal to the market price of our common stock on the date of grant and will provide value to the executive officers only when the price of our common stock increases over the exercise price. Although the expenses of stock options affect our financial statements negatively, we continue to believe that this is a strong element of compensation that focuses the employees on financial and operational performance to create value for the long-term.
With regard to our option grant practice, the Compensation Committee has the responsibility of approving all stock option grants to employees. Stock option grants for plan participants are generally determined within ranges established for each job level. These ranges are established based on our desired pay positioning relative to the competitive market. Specific recruitment needs are taken into account for establishing the levels of initial option grants. Annual option grants take into consideration a number of factors, including performance of the individual, job level, prior grants and competitive external levels. The goals of option grant guidelines are to ensure future grants remain competitive from a grant value perspective and to ensure option usage consistent with option pool forecasts. Based on the definition of fair market value in our stock option plan, options are granted at 100% of the closing sales price of our stock on the last market trading date prior to the grant date. We do not time the granting of our options with any favorable or unfavorable news released by us. Proximity of any awards to an earnings announcement or other market events is coincidental.
Executive Equity Ownership
We encourage our executives to hold an equity interest in our company. However, we do not have specific share retention and ownership guidelines for our executives.
Performance-Based Compensation and Financial Restatement
We have not considered or implemented a policy regarding retroactive adjustments to any cash or equity-based incentive compensation paid to our executives and other employees where such payments were predicated upon the achievement of certain financial results that were subsequently the subject of a financial restatement.
Tax and Accounting Considerations
Compliance with Internal Revenue Code Section 162(m). Section 162(m) of the Internal Revenue Code of 1986, as amended, restricts deductibility of executive compensation paid to our Chief Executive Officer and each of the four other most highly compensated executive officers holding office at the end of any year to the extent such compensation exceeds $1,000,000 for any of such officers in any year and does not qualify for an exception under Section 162(m) or related regulations. The Compensation Committee’s policy is to qualify its executive compensation for deductibility under applicable tax laws to the extent practicable. Income related to stock options granted under our stock option plans generally qualify for an exemption from these restrictions imposed by Section 162(m). In the future, the Compensation Committee will continue to evaluate the advisability of qualifying its executive compensation for full deductibility.
Accounting for Stock-Based Compensation. We record compensation expense for the fair value of stock-based 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 whose total annual salary and bonus exceeded $100,000 for fiscal years 2010 and 2009.
(1)
Mr. DeMarco has served as Chief Executive Officer since May 6, 2010.
(2)
Mr. DeMarco receives $12,500 per month for his services as Chief Executive Officer.
(3)
Mr. Holcombe served as Chief Executive Officer from August 1, 2009 until May 6, 2010 and Chief Financial Officer from September 1, 2009 until September 1, 2010.
(4)
Mr. Holcombe received $10,000 per month for his services as Chief Executive Officer until May 6, 2010 and Chief Financial Officer until September 1, 2010.
(5)
Mr. Holcombe received $10,000 per month for his services as Chief Executive Officer effective August 1, 2009 and Chief Financial Officer effective September 1, 2009.
(6)
Mr. Parisotto served as Chief Executive Officer from November 1, 2007 until July 31, 2009.
(7)
Access paid Coniston (a Company controlled by Mr.Parisotto) CDN $176,667 (US $163,293)(excluding goods and services (tax) for the year ended October 31, 2009 for management services performed for Access.
Employment Contracts and Termination of Employment and Change-In-Control Arrangements
None.
GRANTS OF PLAN-BASED AWARDS
The following table sets forth information regarding the number of stock options granted to named executive officers during fiscal 2010.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table sets forth information for the named executive officers regarding the number of shares subject to both exercisable and unexercisable stock options, as well as the exercise prices and expiration dates thereof, as of October 31, 2010.
Director Compensation
The following table sets forth summary information concerning the total compensation paid to our non-employee directors in 2010 for services to our company.
ITEM 12
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 January 28, 2011:
•
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.
(1)
The address for each of our officers and directors is 25025 I-45 N., Ste. 410, The Woodlands, Texas 77380.
(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 January 28, 2011 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 14,951,881 shares of common stock outstanding.
(4)
Includes the following number of shares of common stock which may be acquired by certain officers and directors through the exercise of stock options which were exercisable as of January 28, 2011 or become exercisable within 60 days of that date: Mark Holcombe (133,333 shares), Bruno Mosimann (66,667 shares) and Rick Wilson (66,667 shares); and all officers and directors as a group, (266,667 shares).
EQUITY COMPENSATION PLAN INFORMATION
On June 26, 2006, our Board of Directors and the holders of a majority of our then outstanding common stock approved our 2006 Stock Option Plan (the “2006 Plan”). The purpose of the 2006 Plan is to provide an incentive to attract and retain directors, officers, consultants, advisors and employees whose services are considered valuable, to encourage a sense of proprietorship and to stimulate an active interest of such persons into our development and financial success. Under the 2006 Plan, we are authorized to issue incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, nonqualified stock options and restricted stock. The 2006 Plan is administered by our Board of Directors. The 2006 Plan authorized up to 2,000,000 shares of common stock for issuance thereunder.
On April 21, 2010, our Board of Directors approved our amended and restated 2008 Stock Option Plan (the “2008 Plan”), which was approved by our stockholders in June 2010. The purpose of the 2008 Plan is to provide an incentive to attract and retain directors, officers, consultants, advisors and employees whose services are considered valuable, to encourage a sense of proprietorship and to stimulate an active interest of such persons into our development and financial success. Under the 2008 Plan, we are authorized to issue incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, nonqualified stock options and restricted stock. The 2008 Plan is administered by our Board of Directors. The number of shares of common stock authorized for issuance pursuant to our 2008 Plan is determined by the Board of Directors from time to time, but cannot exceed 10% of the number of shares of our common stock issued and outstanding. However, the aggregate number of shares available for “Incentive Stock Options,” is 1,495,156.
The following table sets forth information about the shares of our common stock that may be issued upon the exercise of options granted to employees under the 2006 and 2008 Plans approved by the Board of Directors and shareholders,.
(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, 2010, 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, 2010, 1,033,333 shares were issuable upon exercise of options granted to employees and directors.
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Other than as disclosed below, 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 10% of the outstanding Common Stock, 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.
Mr. Holcombe, the President and CEO of the Company between August 1, 2009 and May 6, 2010, for his services as President and CEO (with no additional compensation for his role as CFO) was paid on a month-to-month basis under a board-approved agreement with Mr. Holcombe in the amount of US$10,000 per month.
Mr. Parisotto is the President and sole Director and stockholder of Coniston which provides consulting services to Access. From November 1, 2007 to July 31, 2009, Mr. Parisotto was the President of Blacksands.
Coniston is entitled to a 1.25% nonconvertible overriding royalty based on 100% production when and if the A10 Project commences production. Coniston is also entitled to receive this royalty and other success fees as it may negotiate with Access for future projects where it is fundamental to the consummation of a similar project with us or Access. It is impossible to quantify the present dollar value of Coniston’s royalty interest since a great deal of additional exploration will be required for us to begin preparing a plan for production and the uncertainty associated with any petroleum development.
Until we sold 441 of the 600 shares we held in Access Energy to the other stockholder of Access Energy, Mr. Reg Burden, we were required to provide the necessary capital for Access’ operations until it has sufficient cash flow to do so itself. As consideration for the transfer, we are relieved of our contractual obligation to fund Access’ annual plan and budget including Access’ commitments to First Nations’ communities, and Mr. Burden’s warrants to purchase the Access Warrants were cancelled.
ITEM 14
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, 2010 and 2009, and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years were approximately $85,000 and $92,430, respectively.
Audit Related Fees. We incurred fees to our independent auditors of $nil and $20,000, respectively, for audit related fees during the fiscal years ended October 31, 2010 and 2009.
Tax and Other Fees. We incurred fees to our independent auditors of $nil and $19,318, respectively, for tax and fees during the fiscal years ended October 31, 2010 and 2009.
Consistent with SEC policies and guidelines regarding audit independence, the Audit Committee is responsible for the pre-approval of all audit and permissible non-audit services provided by our principal accountants on a case-by-case basis. Our Audit Committee has established a policy regarding approval of all audit and permissible non-audit services provided by our principal accountants. Our Audit Committee pre-approves these services by category and service. Our Audit Committee has pre-approved all of the services provided by our principal accountants.
PART IV
ITEM 15
ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Exhibits:
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 2, 2011
By: /s/ DAVID DEMARCO
David DeMarco
Chief Executive Officer (Principal Executive Officer)
Date: February 2, 2011
By: /s/ DONALD GIANNATTASIO
Donald Giannattasio
Chief Financial Officer (Principal 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/ DAVID DEMARCO
David DeMarco
Director
February 2, 2011
/s/ MARK HOLCOMBE
Mark Holcombe
Director
February 2, 2011
Bruno Mosimann
Director
February 2, 2011
/s/ ERIC URBAN
Eric Urban
Director
February 2, 2011
/s/ RICK WILSON
Rick Wilson
Director
February 2, 2011