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 Report reflect the good faith judgment of our Management, such statements can only be based on facts and factors currently known by us. Consequently, forward-looking statements are inherently subject to risks and uncertainties and actual results and outcomes may differ materially from the results and outcomes discussed in or anticipated by the forward-looking statements. Factors that could cause or contribute to such differences in results and outcomes include, without limitation, those specifically addressed under the heading "Risks Factors” below, as well as those discussed elsewhere in this Report. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this Report. We file reports with the Securities and Exchange Commission ("SEC"). You can read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. You can obtain additional information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.
We undertake no obligation to revise or update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this Report. Readers are urged to carefully review and consider the various disclosures made throughout the entirety of this annual Report, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operations and prospects.
This Annual Report on Form 10-K includes the accounts of Blacksands Petroleum, Inc. and its wholly-owned subsidiaries, collectively referred to as “we”, “us” or the "Company".
Overview and History
We are an oil and natural gas 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 subsidiaries, Blacksands Petroleum Texas LLC (“BSPE Texas”), NRG Energy Management LLC (“NRG Energy”), APClark LLC (“APClark”) and Copano Bay Holdings, LLC (“Copano Bay”) and Access Energy Inc. (“Access”), of which we own 19.88%.
We were incorporated under the laws of the State of Nevada on October 12, 2004 as Lam Liang Corp. In June 2006, we changed our name to Blacksands Petroleum, Inc., which was in line with our new business of oil and gas exploration and development. Access was formed under the laws of Ontario, Canada on August 26, 2005, BSPE Texas was formed under the laws of Texas on November 9, 2009, NRG Energy was formed under the laws of Texas in October 2009, APClark was formed under the laws of Delaware in 2012 and Copano Bay Holdings was formed under the laws of Texas in December 2010.
Our Competitive Strengths
We believe that we have the following business strengths that will enable us to achieve our business objectives:
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Our management team has direct conventional and unconventional resource industry experience, including operations, exploration and production experience in the United States;
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We operate two producing fields in Texas;
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We have an outside operating interest in four additional wells in Texas;
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We have in-depth experience in acquiring producing properties;
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We have in-house accounting, engineering, land and geotechnical personnel; and
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We are actively developing a Permian basin field (our AP Clark Field).
Our Operations
West Texas Field (also referred to herein as “AP Clark Field,” “Jo-Mill Field,” “Midland basin,” and “Permian basin”)
On August 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, then 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).
As of February 7, 2013, we owned interest in approximately 8,703 gross (5,057 net) acres in Borden Co., Texas, with an undivided interest ranging from 25% gross working interest (18.75% net revenue interest) to 85% gross working interest (63.75% net revenue interest). In 2011, we drilled, set casing, perforated and fracture stimulated two vertical wells in Borden Co., Texas, the Westerly Everett #3 and the Beaver Valley Ranch #6-1. During 2012, we drilled, set casing, perforated and fracture stimulated two vertical wells in Borden Co., Texas, the Livestock 7-1 and Livestock 18-1 wells. Both wells are currently producing and are operated by NRG Energy.
BSPE Texas participated in the Everett #3 for a 70% gross working interest. The well was drilled to 9140’ true vertical depth (“TVD”) tested the lower Spraberry, Wolfcamp, Strawn and Mississippian formation. The well was completed and fracture stimulated in the Mississippian and subsequently perforated and fracture stimulated in the lower Spraberry and Wolfcamp using a 4-stage fracture stimulation design. The well is currently producing six barrels of oil per day and has produced 7,400 barrels of oil since March 2011.
BSPE Texas participated and operated the Beaver Valley Ranch 6-1 Well for a 60% gross working interest. The well was drilled to a 7950’ TVD tested the Wolfcamp, lower Spraberry and JO-Mill formation. The well was completed and fracture stimulated in the Wolfcamp, lower Spraberry and Jo-Mill formations using a 6-stage fracture stimulation design. The well is currently producing 13 barrels of oil a day and has produced 9,400 barrels of oil since November 2011.
Our share of the costs to drill these wells totalled $3,093,267.
BSPE Texas participated and operated the Livestock 7-1 Well for a 62.8% gross working interest. The well was drilled to a 8224’ TVD tested the Cline, Wolfcamp, lower Spraberry and JO-Mill formation. The well was completed and fracture stimulated in the Wolfcamp, Dean, lower Spraberry and Jo-Mill formations using a 4-stage fracture stimulation design. The well is currently producing 40 barrels of oil a day and has produced 2,100 barrels of oil since November 2012.
BSPE Texas participated and operated the Livestock 18-1 Well for a 65.65% gross working interest. The well was drilled to a 8260’ TVD tested the Cline, Wolfcamp, lower Spraberry and JO-Mill formation. The well was completed and fracture stimulated in the Cline, Wolfcamp, Dean, lower Spraberry and Jo-Mill formations using a 5-stage fracture stimulation design. The well is currently producing 22 barrels of oil a day and has produced 2500 barrels of oil since October 2012.
Our share of the costs to drill these wells totalled $2,499,234 through October 31, 2012.
Hydraulic fracturing is the process required to stimulate oil and natural gas flow from hydrocarbon bearing formations into the well bore. As part of the fracturing process, companies typically inject water and sand or other items into rock formations to create "fractures" or conduits through which the oil and natural gas can flow into the wellbore. The selection of individual ingredients to use in the fracturing process involves complex technical decisions, including an assessment and analysis of the scientific data regarding the petrophysics and the geology of the specific formations to be fracture stimulated and an understanding and assessment of the pressures and fracturing efficiency of the various materials that may be used in the process for each specific geological formation. Decisions on whether to employ fracturing techniques, the individual ingredients to use, and how to conduct the fracturing activities are a part of the Company's day-to-day, ordinary business operations.
J.E. Pettus Gas Unit (known as “Cabeza Creek Field”)
In November 2009, we purchased, for approximately $430,000 including legal and other costs, through BSPE Texas, the J.E. Pettus Gas Unit located in Goliad County, Texas, previously owned by Pioneer Natural Resources USA, Inc. The Gas Unit includes five active gas wells and 20 non-producing gas wells located on approximately 3,700 acres in Goliad County, Texas. The interest acquired by BSPE Texas is 100% with all rights, title and interest from the surface to 8,500 feet below the surface and 10.67% below 8,500 feet. The other interest owners with rights below 8,500 feet beneath the surface are: XTO Energy Inc. with a 35% interest, ConocoPhillips Company with a 45.67% interest, and Anadarko Petroleum Corp. with an 8.66% interest. We are the 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 was utilized to help identify potential proven developed non-producing and proven undeveloped reserves on the property. We have identified several sites that can be used to drill new wells and wells that are economically feasible to reopen. We have delayed action on these sites as we continue with our development program in the APClark Field.
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..
Copano Bay
Effective November 1, 2010, we acquired a 50% working interest (37.5% net revenue interest) in certain operating oil and gas leases in and around Aransas County, Texas for $100,000. There were four active wells on the property. In connection with the acquisition, we recorded an asset retirement obligation totalling $126,040.
Effective July 1, 2012, we disposed of our interest in the property in exchange for $50,000. We reported a gain of $10,277 on the sale of this field.
Del Norte
On September 9, 2010, we acquired a 50% undivided leasehold working interest in and to approximately 3,200 acres of land located in Rio Grande County in Colorado from Dan A. Hughes Company for an initial acquisition cost of $200,000. The property has no production and was accounted for as an acquisition of unproved property. Pursuant to the agreement, we have the option to participate in the drilling of a test well. If we participate in the drilling of this test well, all costs associated with the well will be borne equally. As a result of this acquisition, we recorded $200,000 in unproved properties. In August 2011, leases covering approximately 1,240 of these acres expired. As a result, we reported an impairment charge of $77,703 for the expired leases.
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.
As of February 8, 2013 we owned interest in approximately 147,262 gross acres (73,631 net) acres in the Pedregosa Basin. In December 2010, 37 linear miles of 2-D seismic data were surveyed and acquired on the southern part of the Pedregosa Basin project. The data was processed and interpreted with final interpretations reviewed with Hughes in October 2011. The primary southern prospect, a four way structural closure, was confirmed. A drilling location for the southern prospect area was evaluated. We have delayed the drilling of a well on this location while we develop our proved reserves in the AP Clark Field.
In May 2011, the Hughes #1 Big Hatchet North Unit 14 State was drilled to a depth of 5630’ TVD in the north area of the Pedregosa Project to test the Percha Shale. The well was logged, plugged and abandoned.
Competition
The petroleum industry is highly competitive. Many of the oil and gas exploration companies with whom we compete have greater financial and technical resources than we do. Accordingly, these competitors may be able to spend greater amounts on acquisitions of properties of merit and on exploration of their properties. In addition, they may be able to afford greater geological expertise in the targeting and exploration of resource properties. This competition could result in our competitors having resource properties of greater quality and interest to prospective investors who may finance additional exploration, and to senior exploration companies that may purchase resource properties or enter into joint venture agreements with junior exploration companies. This competition could adversely impact our ability to finance property acquisitions and further exploration.
We compete with other exploration and early stage operating companies for financing from a limited number of investors prepared to make investments in junior companies exploring for conventional and unconventional oil and gas resources. The presence of competing oil and gas exploration companies, both major and independent, may impact our ability to raise additional capital in order to fund our exploration program if investors are of the view that investments in competitors are more attractive based on the merit of the properties under investigation, and the price of the investment offered to investors.
We compete with a number of larger public and private companies and smaller, independent exploration companies in our various fields, including:
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Cabeza Creek Field: Dewbre Petroleum Corporation;
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Beech Creek Field: Cico Oil & Gas Company;
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Pedregosa Basin Field: Yates Petroleum; and
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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 the U.S., historically, the sale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, or the FERC. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, or the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993 and sales by producers of natural gas are uncontrolled and can be made at market prices. The natural gas industry historically has been heavily regulated and from time to time proposals are introduced by Congress and the FERC and judicial decisions are rendered that impact the conduct of business in the natural gas industry. We cannot assure you that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.
Pricing and Marketing of Oil
In the U.S., sales of crude oil, condensate and natural gas liquids are not regulated and are made at negotiated prices. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser.
Royalties and Incentives
The royalty regime is a significant factor in the profitability of oil, natural gas and natural gas liquids production. In the U.S., all royalties are determined by negotiations between the mineral owner and the lessee.
Environmental
United States
Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment. The recent trend in environmental legislation and regulation in the oil and natural gas industry is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, especially in wilderness areas with endangered or threatened plant or animal species; impose restrictions on construction, drilling and other exploration and production activities; regulate air emissions, wastewater and other production and waste streams from our operations; impose substantial liabilities for pollution that may result from our operations; and require the reclamation of certain lands.
The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, compliance orders, and other enforcement actions. We are not aware of any material noncompliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements, however, given the complex regulatory requirements applicable to our operations, and the rapidly changing nature of environmental laws in our industry, we cannot predict our future exposure concerning such matters, and our future costs to achieve compliance, or remedy potential violations, could be significant. Our operations require permits and are regulated under environmental laws, and current or future noncompliance with such laws, as well as changes to existing laws or interpretations thereof, could have a significant impact on us, as well as the oil and natural gas industry in general.
Waste Disposal and Contamination Issues
The federal Comprehensive Environmental Response, Compensation and Liability Act and comparable state laws may impose strict and joint and several liability on owners and operators of contaminated sites and on persons who disposed of or arranged for the disposal of hazardous substances found at such sites. Under these and other laws, the government, neighboring landowners and other third parties may recover the costs of responding to soil and groundwater contamination and threatened releases of hazardous substances, and seek recovery for related natural resources damages, personal injury and property damage. Some of our properties have been used for exploration and production activities for a number of years by third parties, and such properties could result in unknown cleanup liabilities for us.
The federal Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes govern the management, storage, treatment and disposal of solid waste and hazardous waste and authorize imposition of substantial fines and penalties for noncompliance. Although RCRA classifies certain of our oil field wastes as “non-hazardous” (for example, the waters produced from hydraulic fracturing operations), such wastes could be reclassified as hazardous wastes in the future, thereby making them subject to more stringent handling and disposal requirements which could have a material impact on us.
Water Regulation
The federal Clean Water Act (the “CWA”), the federal Safe Drinking Water Act (the “SWDA”) and analogous state laws restrict the discharge of wastewater and other pollutants into surface waters or underground wells and the construction of facilities in wetland areas without a permit. Federal regulations also 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. In addition, the Oil Pollution Act (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 or considered under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us.
These and similar state laws also govern the management and disposal of produced waters from our extraction process. Currently, wastewater associated with oil and natural gas production from shale formations is prohibited from being directly discharged to waterways and other waters of the U.S. While some of our wastewater is reused or re-injected, a significant amount still requires disposal. As a result, some wastewater is transported to third-party treatment plants. In October 2011, citing concerns that third-party treatment plants may not be properly equipped to handle wastewater from shale gas operations, the United States Environmental Protection Agency (the “EPA”) announced that it will consider federal pre-treatment standards for these wastewaters. We cannot predict the EPA’s future actions in this regard, but future regulation of our produced waters or other waste streams could have a material impact on us.
Air Emissions And Climate Change
The federal Clean Air Act (“CAA”) imposes permit requirements and operational restrictions on certain sources of emissions used in our operations. In July 2011, the EPA published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPs”) that would, if adopted, amend existing NSPS and NESHAP standards for oil and natural gas facilities and create new NSPS standards for oil and natural gas production, transmission and distribution facilities. Importantly, these standards would include standards for hydraulically fractured wells, which are widely used in our operations. The standards would apply to newly drilled and fractured wells as well as existing wells that are refractured. A court has directed the EPA to issue final rules by April 3, 2012. In a report issued in late 2011, the Shale Gas Production Subcommittee of the Department of Energy (the “DOE Shale Gas Subcommittee”) called on the EPA to complete the rulemaking quickly and recommended expanding the shale gas emission sources to be covered by the new rules. The DOE Shale Gas Subcommittee also encouraged states to take similar action, and included several other recommendations for studying and reducing air emissions from shale gas production activities. Because the EPA’s regulations have not yet been finalized, we cannot at this time predict the impact they may have on our financial condition or results of operation.
The issue of climate change has received increasing regulatory attention in recent years. The EPA has issued regulations governing carbon dioxide, methane and other greenhouse gas (“GHG”) emissions citing its authority under the CAA. Several of these regulations have been challenged in litigation that is currently pending before the federal D.C. Circuit Court of Appeals. In December 2011, the EPA issued amendments to a final rule issued in 2010 requiring reporting of GHG emissions from the oil and natural gas industry. Under this rule, we are obligated to report to the EPA certain GHG emissions from our operations. We do not expect that the costs of this new reporting will be material to us. In a late 2011 report, the DOE Shale Gas Subcommittee recommended that the EPA expand reporting requirements for GHG emissions from shale gas emission sources, and include methane in reporting requirements. More generally, several proposals to regulate GHG emissions have been proposed in the U.S. Congress, and various states have taken steps to regulate GHG emissions. The adoption and implementation of regulations or legislation imposing restrictions or other regulatory obligations on emissions of GHGs from oil and natural gas operations could require us to obtain permits or allowances for our GHG emissions, install new pollution controls, increase our operational costs, limit our operations or adversely affect demand for the oil and natural gas produced from our lands.
Regulation of Hydraulic Fracturing
Our industry uses hydraulic fracturing to recover oil and natural gas in deep shale and other previously inaccessible subsurface geological formations. Hydraulic fracturing (or “fracking”) is a process to significantly increase production in drilled wells by creating or expanding cracks, or fractures, in underground formations by injecting water, sand and other additives into formations at high pressures. Like others in our industry, we use this process as a means to increase the productivity of our wells. Although hydraulic fracturing has been an accepted practice in the oil and natural gas industry for many years, its use has dramatically increased in the last decade, and concerns over its potential environmental effects have received increasing attention from regulators and the public.
Under the Safe Drinking Water Act (“SDWA”), the EPA is prohibited from regulating the injection of fracking fluids through its underground injection control program, except in limited circumstances (for example, the EPA has asserted that it has authority to regulate when diesel is a component of the fluids). Waters produced from fracking operations must be disposed of in accordance with federal and state regulations. As discussed above, the EPA has announced an intention to propose pre-treatment standards for produced waters that are to be disposed of at third-party wastewater treatment plants. Separately, the EPA is studying the effects of fracking on drinking water as a result of Congressional and public concern over fracking’s potential to impact groundwater supplies, and the EPA has indicated that it expects to issue its findings later this year.
In that regard, the EPA recently issued a study indicating that contamination may have resulted from certain fracking operations in Wyoming. The operator of the wells has challenged the EPA’s findings, contending that other activities may be to blame for contaminated groundwater in the area, but the EPA’s findings can be expected to draw increased attention to potential groundwater impacts from fracking. In late 2011, the DOE Shale Gas Subcommittee recommended further study and coordination of federal, state and local efforts to determine and monitor potential groundwater impacts from fracking activities.
Other federal agencies, including the DOE and the Department of Interior, and the U.S. Congress are also investigating the potential impacts of fracking. In addition, bills have been introduced in the U.S. Congress to amend the SWDA to allow the EPA to regulate the injection of fracking fluids, which could require our and similar operations to meet federal permitting and financial assurance requirements, adhere to certain construction and testing specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. In addition, the federal Bureau of Land Management is developing draft regulations that would require companies drilling on federal land to disclose details of chemical additives, test the integrity of wells and report on water use and waste management. In November 2011, the EPA announced that it would solicit public input on possible reporting requirements for chemicals used in fracking under the authority of the federal Toxic Substances Control Act.
States, which traditionally have been the primary regulators of exploration and production wells, are also considering or have recently adopted, or may in the future adopt, additional regulations governing fracking activities. For example, North Dakota recently adopted regulations, effective April 1, 2012, to require disclosure of the chemical components of hydraulic fracturing fluids. We believe that compliance with any new reporting requirements will not have a material adverse impact on us. Nonetheless, these disclosures could make it easier for third parties who oppose fracking to initiate legal proceedings based on allegations that chemicals used in fracking could contaminate groundwater.
In addition, concerns have been raised about the potential for fracking to cause earthquakes through the disposal of produced waters into Class II underground injection control (“UIC”). The EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. Some environmentalists have asked the EPA to consider reversing an exemption that excludes such wastewaters from hazardous waste rules, which would subject the wastes to more stringent management and disposal requirements. We cannot predict the EPA’s future actions in this regard. Certain states, such as Ohio, where earthquakes have been alleged to be linked to fracking activities, have proposed regulations that would require mandatory reviews of seismic data and related testing and monitoring as part of the future permitting process for UIC wells. In addition, certain other states, including New York, New Jersey and Vermont have sought to place moratoria on fracking or subject it to more stringent permitting and well construction and testing requirements.
Employees
As of February 7, 2013, we have four employees, including the chief executive officer, chief financial officer, vice president in charge of land and acquisitions and a manager 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
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 $3,443,645 for the year ended October 31, 2012 and $6,092,933 for the year ended October 31, 2011. In addition, at October 31, 2012, we had an accumulated deficit of $20,459,318. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in early stage oil and gas exploration companies. There can be no assurance that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether production from our operating wells continues at their current rates. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.
We will require additional financing in order to continue to expand our operating and exploration activities or we will fail.
The Company had $1,160,320 as of October 31, 2012, and $240,314 as of October 31, 2011 in cash and cash equivalents. Operating costs of exploration and development programs may be greater than we anticipate, such that we may have to seek additional funds sooner than otherwise expected. We anticipate that our existing cash and cash equivalents will enable us to maintain our current operations for at least the next 12 months, and we anticipate that we will require up to an additional capital of $5 million to maintain our current drilling program for the next 12 months.
We will be dependent on raising capital, debt or equity, from outside sources to pay for further expansion, exploration and development of our business, and to meet current obligations. Such capital may not be available to us when we need it on terms acceptable to us if at all, particularly in the current global economic conditions. The issuance of additional equity securities by us will result in a dilution to our current stockholders which could depress the trading price of our common stock. Obtaining debt financing will increase our liabilities and future cash commitments. If we are unable to obtain financing in the amounts and on terms deemed acceptable to us, we may be unable to continue our business and may be required to scale back or cease our operations. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of warrants or other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.
We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes and warrants, which may adversely impact our financial condition.
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.
We have substantial capital requirements that, if not met, may hinder our operations.
We anticipate that we will make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and for future drilling programs. If we have insufficient revenues, we may have a limited ability to expend the capital necessary to undertake or complete future drilling programs. We cannot assure you that debt or equity financing, or cash generated by operations, will be available or sufficient to meet these requirements or for other corporate purposes, or if debt or equity financing is available, that it will be on terms acceptable to us. Moreover, future activities may require us to alter our capitalization significantly. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations or prospects.
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:
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changes in global supply and demand for oil and natural gas;
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the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other organizations and government entities;
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the price and quantity of imports of foreign oil and natural gas;
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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;
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the level of global oil and natural gas exploration and production activity;
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the short and long term levels of global oil and natural gas inventories;
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weather conditions;
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technological advances affecting the exploitation for oil and gas, and related advances for energy consumption; and
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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:
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the timing and amount of capital expenditures;
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the availability of suitable drilling rigs, drilling equipment, production and transportation infrastructure and qualified operating personnel;
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the operator’s expertise and financial resources;
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approval of other participants in drilling wells; and
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selection of technology.
Our reserve estimates and projections are inherently imprecise, and actual production, revenues and expenditures may differ materially from such estimates and projections.
There are numerous uncertainties inherent in estimating quantities of reserves and their values, including many factors beyond our control. Estimates of oil and gas reserves, by necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and gas prices, future operating cost, severance and excise taxes, development costs, workover and remedial costs and the costs of plugging and abandoning wells, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped, probable, or possible reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity and value of our reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
We may not be successful in identifying or developing recoverable reserves.
Our future success depends upon our ability to acquire and develop oil and gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we can replace those reserves by exploration and development activities or acquisition of properties containing proved reserves, or both. In order to increase reserves and production, we must undertake development, exploration, drilling and recompletion programs or other replacement activities. Our current strategy includes increasing our reserve base through development, exploitation, exploration and acquisition. There can be no assurance that our planned development and exploration projects or acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells at economical values in terms of their finding and development costs. Furthermore, 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 lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, fracture stimulation crews, equipment, supplies, key infrastructure, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified crews rise as the number of active rigs and completion fleets in service increases. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in Texas, New Mexico or Colorado, we could be materially and adversely affected because our operations and properties are concentrated in those areas.
Compliance with government regulations may require significant expenditures.
Our business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of oil and gas, as well as safety matters. Although we will attempt to conduct due diligence concerning standard compliance issues, there is a heightened risk that our target properties are not in compliance because of lack of funding. We may be required to make significant expenditures to comply with governmental laws and regulations that may have a material adverse effect on our financial condition and results of operations. Even if the properties are in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations are frequently changed and are subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.
Environmental regulations and costs of remediation could have a material adverse effect on our operations.
Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local government authorities. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on our operations. The discharge of oil, gas or other pollutants into the air, soil, or water may give rise to significant liabilities on our part to the government and third parties, and may require us to incur substantial costs of remediation. We will be required to consider and negotiate the responsibility of the Company for prior and ongoing environmental liabilities. We may be required to post or assume bonds or other financial guarantees with the parties from whom we purchase properties or with governments to provide financial assurance that we can meet potential remediation costs. There can be no assurance that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not materially adversely affect our results of operation and financial condition or that material indemnity claims will not arise against us with respect to properties acquired by us.
Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.
On September 12, 2011, President Obama sent to Congress a legislative package that included proposed legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:
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the repeal of the limited percentage depletion allowance for oil and natural gas production in the United States;
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the replacement of expensing intangible drilling and development costs in the year incurred with an amortization of those costs over several years;
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the elimination of the deduction for certain domestic production activities; and
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an extension of the amortization period for certain geological and geophysical expenditures.
While that package was not taken up by Congress, there has been renewed discussion regarding these and other proposals regarding reducing or eliminating tax breaks for oil and gas companies in connection with discussions on the budget and overall corporate tax reform. It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.
We operate in a highly competitive environment.
We operate in the highly competitive areas of oil and gas exploration, development, acquisition and production with other companies. In seeking to acquire desirable producing properties or new leases for future exploration, and in marketing our oil and gas production, we face intense competition from both major and independent oil and gas companies. Many of these competitors have financial and other resources substantially in excess of those available to us. Our inability to effectively compete in this environment could materially and adversely affect our financial condition and results of operations.
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 subsidiaries, BSPE Texas, APClark and Copano Bay Holdings, currently focuses on the conventional oil and gas industry. BSPE Texas currently owns a single property and has an interest in several additional properties. APClark currently has an interest in certain wells located in the AP Clark field. Larger companies have the ability to manage their risk by diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate. The Company has a limited number of revenue generating properties. This revenue generating property historical revenue is derived from Natural Gas and Oil. Therefore, the price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth
Our business may suffer if we do not attract and retain talented personnel.
Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting our intended business. We presently have a small management team which we intend to expand in conjunction with our planned operations and growth. The loss of a key individual, or our inability to attract suitably qualified staff could materially adversely impact our business.
We may not be able to establish substantial oil operations or manage our growth effectively, which may harm our profitability.
Our strategy envisions establishing and expanding our oil business. If we fail to effectively establish sufficient oil operations and thereafter manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes, and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:
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meet our capital needs;
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expand our systems effectively or efficiently or in a timely manner;
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allocate our human resources optimally;
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identify and hire qualified employees or retain valued employees; or
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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.
Hydraulic fracturing, the process used for releasing oil and natural gas from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.
Recently there has been increasing public and regulatory attention focused on the potential environmental impact of hydraulic fracturing (or “fracking”) operations. This process, which involves the injection of water, sand and certain additives deep underground to release natural gas, natural gas liquids and oil deposits, is central to our operations and future regulation of these activities could have a material adverse impact on our business, financial condition and results of operations.
Various government agencies, political representatives and public interest groups have raised concerns about the potential for fracking to lead to groundwater contamination, and various regulatory and legislative measures have been proposed or adopted at the federal, state and local level to study or monitor related concerns, to regulate well operations and related production and waste streams, or to ban fracking entirely. For example, various states and federal regulatory authorities require or are considering requiring public disclosure of the chemicals contained in fracking fluids, and testing and monitoring obligations relating to well integrity and operation. North Dakota, a state in which we conduct operations, recently amended its current regulations to require additional pollution control equipment at well sites and enhanced emergency response procedures in addition to other measures designed to reduce potential environmental impacts. In 2011, the EPA announced its intention to consider pre-treatment standards for produced waters that are sent to third party wastewater treatment plants.
In addition, bills have been proposed in the U.S. Congress to allow the EPA to regulate the injection of fracking fluids under the federal Safe Drinking Water Act, which could require hydraulic fracturing operations to meet federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The proposed legislation also would 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. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are considering additional requirements related to seismic safety. Other concerns have been raised regarding water usage, air emissions (including greenhouse gas emissions) and waste disposal, and certain jurisdictions have imposed moratoria on fracking operations while the potential impacts are studied. The EPA, Congress and other government representatives continue to investigate the impacts of fracking, and additional studies and regulatory or legislative initiatives are possible. See “Item 1 - Business Overview - Environmental Laws and Regulations” for further discussion of applicable environmental laws.
Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, and/or state levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay or curtail the development of unconventional oil and natural gas resources from shale formations which are not commercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.
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.
Messrs. Rick Wilson and Richard Hunter are involved or affiliated with one or more other oil and gas resource exploration companies. As a result of this relationship, he 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.
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.
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:
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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;
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quarterly variations in our revenues and operating expenses;
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changes in the valuation of similarly situated companies, both in our industry and in other industries;
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changes in analysts’ estimates affecting our company, our competitors and/or our industry;
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changes in the accounting methods used in or otherwise affecting our industry;
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additions and departures of key personnel;
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announcements of technological innovations or new reserves available;
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fluctuations in interest rates and the availability of capital in the capital markets; and
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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, 2013 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:
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that a broker or dealer approve a person's account for transactions in penny stocks; and
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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:
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obtain financial information and investment experience objectives of the person; and
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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:
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sets forth the basis on which the broker or dealer made the suitability determination; and
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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 executive offices at 800 Bering, Suite 250, Houston, Texas 77057. Our telephone number at that office is (713) 554-4491 and our facsimile number is (713) 583-1617. Our rent is on a month to month basis and totals $2,800 per month.
Reserve Estimation Procedures and Audits
The information included in this Report about the Company’s proved reserves as of October 31, 2012 and 2011, which were located in the United States, is based on evaluations prepared by (i) the Company’s engineers and audited by Hamilton Group (“Hamilton”) (2012) and Corridor & Associates (“Corridor”) (2011) (collectively, the “Independent Petroleum Engineers”). The Company has no oil and gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure of probable or possible reserves.
Reserve estimation procedures. The Company has established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and GAAP requirements. These controls include the annual external audits of substantial portions of the Company’s proved reserves by the Independent Petroleum Engineers.
Proved reserves audits. The reserve audits performed by the Independent Petroleum Engineers in the aggregate represented 100 % of the Company’s 2012 and 2011 proved reserves.
The Independent Petroleum Engineers follow the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers (“SPE”). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE’s definition of a reserve audit includes the following concepts:
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A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the SPE.
•
The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.
•
The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own estimates of reserve information for the audited properties.
To further clarify, in conjunction with the audit of the Company’s proved reserves and associated pre-tax present value discounted at ten percent, the Company provided to the Independent Petroleum Engineers its engineering and geoscience technical data and analyses. Following the Independent Petroleum Engineers’ review of that data, they had the option of honoring the Company’s interpretation, or making their own interpretation. No data was withheld from the Independent Petroleum Engineers. The Independent Petroleum Engineers accepted without independent verification the accuracy and completeness of the historical information and data furnished by the Company with respect to ownership interest, oil and gas production, well test data, commodity prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluation something came to their attention that brought into question the validity or sufficiency of any such information or data, the Independent Petroleum Engineers did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data.
In the course of their evaluations, the Independent Petroleum Engineers prepared, for all of the properties, their own estimates of the Company’s proved reserves and the pre-tax present value of such reserves discounted at ten percent. At the conclusion of the audit process, it was the Independent Petroleum Engineers’ opinions, as set forth in their audit letters, which are included as exhibits to this Report, that the Company’s estimates of the Company’s proved oil and gas reserves and associated pre-tax present value discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering standards promulgated by the SPE.
Qualifications of reserves preparers and auditors. The Independent Petroleum Engineers provide petroleum property analysis services for energy clients, financial organizations and government agencies. William Crenshaw, Texas Board of Professional Engineers Registration No. 7918, was primarily responsible for auditing the Company’s reserves estimates for Hamilton and Corridor. Mr. Crenshaw has been a practicing consulting petroleum engineer at Corridor has over 28 years of practical experience in petroleum engineering, including 28 years of experience in the estimation and evaluation of proved reserves. He graduated with a Bachelor of Science degree in Petroleum Engineering in 1983 and meets or exceeds the education, training and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the board of directors of the SPE.
Technologies used in reserves estimates. The Company uses reliable technologies to establish additions to reserve estimates, including seismic data and interpretation, wireline formation tests, geophysical logs and core data.
Description of Properties
Net Reserves of Crude Oil and Natural Gas at October 31,
The decrease in the proved undeveloped reserves relates to the sale of the Copano Bay Field effective July 1, 2012 and the transfer of a number of proved reserves to probable reserves. Proved reserves for the Copano Bay Field at October 31, 2011 totalled 40,140 barrels of oil. The transfer of reserves from proved to probably is the result of the Company’s scaling back its development program for the AP Clark Field. As a result of the change in the development program, approximately 2.2 million barrels of oil were transferred to the probable reserve category.
During the fiscal year ended October 31, 2012, the Company participated in the drilling and successful completion of two wells in the AP Clark field. The Company’s cost for the wells totalled approximately $2.5 million. The Company plans on drilling and completing up to an additional three wells on the AP Clark property in the next 12 months.
Developed and Undeveloped Acreage
The following table summarizes our oil and gas production revenue and costs, our productive wells and acreage, undeveloped acreage and drilling activities for each of the last two years ended October 31.
(1)
Oil and gas were combined by converting gas to a Boe equivalent on the basis of 6 Mcf of gas to 1 Bbl of oil
The following tables summarize the Company’s United States development and exploration/extension drilling activities during 2012:
The following table summarizes the Company’s average daily oil, gas and total production by asset area during 2012:
The following table summarizes the Company’s costs incurred by geographic area during 2012:
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 - MINE SAFETY DISCLOSURES
Not applicable.
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, 2010 through October 31, 2012, 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 February 11, 2013, the closing sale price of our common stock, as reported by the Over-the-Counter Bulletin Board, was $1.18 per share. On February 11, 2013, there were 33 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, Cline, Strawn and Mississippian formations in the Permian Basin (Midland Basin) in W. Texas, (ii) conventional reef structures in the Pedregosa Basin in S.W. New Mexico and (iii) conventional structure and stratigraphic formations and unconventional resource formations in Southern Colorado. We also have interest in the Beech Creek Field in Hardin County Texas and the Cabeza Creek Field in Goliad Texas, which we anticipate will provide us with immediate cash flow and additional upside through recompletion potential and new drilling opportunities (“Non-core Properties”).
As of October 31, 2012, we owned interests in (i) approximately 8,700 gross (5,050 net) acres in the Midland Basin, (ii) approximately 108,715 gross (54,357 net) acres in the Pedregosa Basin, and (iii) approximately 3,300 gross (1,650 net) acres in Colorado, and (iv) 3,800 gross acres in Non-Core Properties
We have approximately 116,515 gross acres (59,900 net acres) held by production and continuous drilling operations. This includes approximately 4,000 gross acres (1,843 net acres) in Midland Basin, 108,715 gross acres (54,357 net acres) in the Pedregosa Basin, and approximately 3,800 gross acres (3,722 net acres) in the Non-Core Properties. We have no production in Colorado.
We began oil and gas operations in the United States on November 1, 2009, with the purchase of a producing conventional oil and gas field, located in the Gulf Coast region of Texas, from Pioneer Natural Resources. Additionally, we acquired interests in two properties located in the Gulf Coast region of Texas and one property in our Core Focus Area located in West Texas.
During the twelve months ended October 31, 2012, we (i) drilled, set casing, perforated and fracture stimulated the Livestock 7-1 well and the Livestock 18-1 well, which are currently producing (ii) obtained financing for the two Livestock wells, which also provides us with the opportunity to drill additional wells in the Midland Basin.
The Core Focus Areas provide us with the opportunity to grow reserves and cash flow by drilling and developing the properties. The Core Focus Area we are currently focused primarily on developing is the APClark Field. Our other properties currently provide cash flow for overhead and administrative costs, while we develop our Core Focus Areas.
We continue to pursue avenues to reduce or eliminate our financial exposure on a case by case basis for each project. Joint venture arrangements may be considered for others to participate for a disproportionate share of the initial leasing and/or drilling costs, further reducing our exposure.
Projects in the next 12 months, 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.
While our base case drilling, recompletion/workover and leasing activity would result in estimated costs of $8.8 million, we may expand drilling, recompletion/workover and leasing activity to as much as $22 million, if project economics and general economic conditions support the more aggressive drilling program. If we elect to expand drilling activities, we will need to access additional capital. During the fiscal year ended October 31, 2012, we entered into a joint venture agreement which provided us with $2.6 million and provides our joint venture partner the option to provide an additional $5 million in financing for future wells. We utilized the $2.6 million in order to complete the two Livestock wells.
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, 2012 Compared to the Year Ended October 31, 2011
Revenues for the year ended October 31, 2012 totalled $1,588,728 as compared to $1,890,193 for the year ended October 31, 2011. The decrease totalling $301,465 resulted in part from the disposal of the Copano Bay properties and reduced production from several of our existing wells. The two recently completed Livestock wells did not begin production until November 2012. We are expecting a significant increase in revenues in Fiscal 2013 as a result of having a full year of revenue from these two new wells along with the completion of two additional wells to be drilled in the AP Clark field in mid-2013.
Selling general and administrative expenses decreased by $411,593 from $2,399,538 in the fiscal year ended October 31, 2011 to $1,987,945 in the fiscal year ended October 31, 2012. The decrease is primarily related to a decrease in the amount of stock based compensation ($224,484) and professional services ($155,388). There were approximately $125,000 in investor relation and other professional consulting services that did not recur during the year ended October 31, 2012.
Depreciation, depletion and accretion totalled $711,192 in the year ended October 31, 2012 as compared to $866,285 for the year ended October 31, 2011. The decrease in the depreciation, depletion and accretion was a result of the disposal of the Copano field and the lower overall production from our older wells.
Lease operating expenses increased $86,559 from $683,210 in the year ended October 31, 2011 to $769,769 in the year ended October 31, 2012. We had higher expenses in the Copano field through disposal as a result of the higher costs for the offshore wells and the cost of repairs on those wells. In addition, we incurred several significant repairs on several of the older wells. We expect lease operating expenses to remain significant.
During the years ended October 31, 2012 and 2011, we incurred exploration expenses of $952,320 and $1,771,536, respectively. These costs related primarily to the drilling of the test well on the Pedregosa property. This well resulted in the location of immature hydrocarbons and the well was considered a dry hole. As we continue our drilling program in some of our unproved properties, we expect to incur additional exploration costs.
We incurred a net loss for the year ended October 31, 2012 of $3,643,645, compared to a net loss of $6,292,933 for the year ended October 31, 2011.
Liquidity and Capital Resources
As of October 31, 2012, we had cash and cash equivalents on hand of $1,160,322. We believe this amount plus additional funding from our joint venture agreement with KP Energy together with production from existing wells and wells to be drilled this fiscal year is sufficient to fund our general and administrative costs for the next twelve months. Depending on the depth and formation drilled to and the frac program utilized, presuming our joint venture partner provides additional funds, we will have sufficient cash in order to fund capital expenditures for the drilling of between two and four new wells. However, if our joint venture partner does not provide additional funds, which it has no obligation to do so, we would need an additional $5 million for the next 12 months in order to fund our planned drilling program. We do not currently have the financing in order to carry out a more robust drilling program. We expect to rely on external sources of capital in order to continue to fund our capital expenditures.
Net Cash Provided By (Used In) Operating Activities
Cash provided by operating activities in the year ended October 31, 2012 was $241,434, compared to $1,358,716 used for the comparative period. The difference is due the reduction in the net loss along with the lower receivables due primarily on the drilling of new wells and inceased payables (primarily on unpaid interest due to Silver Bullet and KP-Rahr.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the year ended October 31, 2011 was $6,117,216 compared to $2,921,428 for the year ended October 31, 2012. The costs for both periods presented relate to our oil and gas acquisitions and development. During fiscal 2011, we acquired additional leasehold totalling approximately $1,350,000 and participated in the drilling of two additional wells costing a total of approximately $3,300,000. During the year ended October 31, 2012, we participated in the drilling of two additional wells.
Cash Flows from Financing Activities
Cash provided by financing activities for the year ended October 31, 2011 was $6,106,285, compared to $3,600,000 for the year ended October 31, 2012.
Silver Bullet Financing
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. On September 27, 2011, the Company entered into an amendment to the promissory note dated November 19, 2010 (the “Note”) issued by the Company to Silver Bullet Property Holdings SDN BHD (the “Investor”). Pursuant to the amendment, the maturity date of the Note was amended from November 19, 2011 to February 1, 2013. In addition, the Investor loaned the Company an additional $1 million, with $500,000 loaned prior to October 31, 2011 and the remaining $500,000 received in two installments in November and December 2011. Pursuant to a security agreement, dated September 27, 2011, as security for the repayment of the Note, the Company granted the Investor a first priority lien on the Company’s oil and gas mineral leases in the ApClark Field. In April 2012, the parties agreed to further extend the note to May 1, 2014 and the investor agreed to an additional loan of $500,000 to the Company. The Company also granted a net proceeds interest (9% but reduced to 4.5% if the note is repaid prior to May 1, 2013) in the AP Clark properties included in the security agreement. The net proceeds interest represents the amount remaining from the proceeds of the sale of the property after deducting the related costs. The amendment was reviewed to determine its accounting treatment as a restructuring, extinguishment or modification and determined to be a modification. The Company received the additional $500,000 in June 2012.
Bridge Financing
In February 2011, the Company entered into a securities purchase agreement with 10 accredited investors (the “February Investors”), providing for the sale by the Company to the February Investors of an aggregate of (i) 8% debentures in the principal amount of $1,745,300 (the “Debentures”) and (ii) warrants to purchase 581,767 shares of common stock of the Company (the “February Warrants”).
The Debentures matured on the earlier of the (i) date the Company closed an offering that results in gross proceeds to the Company of at least $1,000,000 or (ii) first anniversary of the date of issuance (the “Maturity Date”) and bore interest at the annual rate of 8%. The February Warrants are exercisable for a period of three years from the date of issuance and are exercisable into shares of common stock of the Company at an exercise price of $4.50 per share.
On March 17, 2011, the Debentures came due as a result of obtaining at least $1,000,000 in gross proceeds from the private placement (see below). On that date, $1,694,000 of the Debentures were converted into (i) 564,667 shares of our common stock and (ii) warrants to purchase 564,667 shares of our common stock at an exercise price of $4.50 per share. The remaining $51,300 in Debentures was repaid. The Bridge Warrants were not affected by the conversion or repayment.
Private Placement Financing
Between March and June 2011, we sold to certain investors units (“Units”) for aggregate cash gross proceeds of $2,582,501 at a price of $3.00 per Unit and the exchange of $1,694,000 in previously issued debentures that were converted into Units at a price of $3.00 per Unit (the “Financing”). Each Unit consisted of (i) one (1) share of common stock (“Common Stock”) and (ii) a warrant (“Warrant”) to purchase one (1) share of Common Stock at an exercise price of $4.50.
Pursuant to the Warrants, no holder may exercise such holder’s Warrant if such exercise would result in the holder beneficially owning in excess of 4.99% of our then issued and outstanding common stock. A holder may, however, increase or decrease this limitation (but in no event exceed 9.99% of the number of shares of Common Stock issued and outstanding) by providing us with 61 days’ notice that such holder wishes to increase or decrease this limitation.
We entered into a registration rights agreement with the investors, under which we agreed to prepare and file with the SEC and maintain the effectiveness of a “resale” registration statement providing for the resale of (i) all of the shares of Common Stock (ii) all of the shares of Common Stock issuable upon exercise of the Warrants, and (iii) any securities issued or issuable upon any stock split, dividend or other distribution, recapitalization or similar event with respect to the foregoing.
Under the terms of the registration rights agreement, we are required to have a registration statement filed with the SEC within 90 days after the final closing date of the Financing, and declared effective by the SEC not later than 120 days from the closing date (or 180 days in the event of a full review by the SEC).
KP Energy Joint Venture Agreement
On July 20, 2012, the Company entered into a Contribution Agreement (the “Contribution Agreement”), between APClark and KP-RAHR Ventures III, LLC (“KP Ventures”). Pursuant to the Contribution Agreement (i) the Company contributed $1,000 and certain of the Company’s oil and gas assets to APClark in exchange for 1,000 shares of Class A Membership Units of ApClark (the “Class A Membership Units”) and (ii) KP Ventures contributed approximately $2,600,000 (the “KP Ventures Cash Consideration”) to APClark in consideration of 1,000 shares of Class B Non-Voting Convertible Preferred Membership Units of APClark (the “Class B Membership Units” and the transaction, the “Asset Transaction”). KP Ventures has the option to contribute additional funds to APClark, up to an aggregate of $7,600,000, for no further equity consideration.
In connection with the Contribution Agreement, the Company entered into a Company Agreement (the “Operating Agreement”) governing the operations of APClark and defining various rights of the Company and KP Ventures.
Pursuant to the Operating Agreement, KP Ventures shall receive a preferred return of 12% per annum (the “Preferred Return”) on the unrecovered KP Ventures Cash Consideration until such time as the KP Ventures Cash Consideration is repaid. In addition, KP Ventures receives a 1% overriding royalty from the production of the APClark oil and gas properties. Once the KP Ventures Cash Consideration is repaid, including all accrued Preferred Returns, the Class B Membership Units shall automatically convert into Class C Non-Voting Net Profit Membership Units (the “Class C Membership Units”), which represent a non-dilutable “Net Profits” interest (“NPI”) in APClark and the assets owned by APClark and a percentage of all outstanding membership units of APClark initially equal to the NPI. The amount of the NPI granted depends on when the KP Ventures Cash Consideration and Preferred Return is paid, as follows:
The Company will be responsible for the operations of APClark and has the right to appoint the sole director of APClark, The consent of KP Ventures is required in certain situations, including, but not limited to: expanding the scope of the business; admitting additional members or transfer of membership units; approve annual budget; any merger or sale of all or substantially all of the assets of APClark; voluntary liquidation, dissolution or winding up of APClark; and to make any cash distributions.
In addition, the Company entered into a Pledge Agreement (the “Pledge Agreement”) pursuant to which it pledged the Class A Membership Units to KP Ventures to secure the Company’s obligations and performance thereunder and under the Contribution Agreement and Operating Agreement, which such Class A Membership Units shall be held pursuant to an escrow agreement.
Previously, the Company entered into a security agreement, dated as of September 27, 2011, pursuant to which, as security for the repayment of promissory notes in the principal face amount of $3,000,000 (the “Notes”), issued to Silver Bullet Property Holdings SDN BHD (“Silver Bullet”) a first priority security interest (the “Security Interest”) in certain of the assets of the Company that were contributed to APClark pursuant to the Contribution Agreement (the “Pledged Assets”). In connection with the Asset Transaction, the Company, APClark, Silver Bullet and KP Ventures entered into a subordination agreement (the “Subordination Agreement”), pursuant to which Silver Bullet subordinated its Security Interest to KP Ventures, so that KP Ventures would have a first priority interest in the Pledged Assets until KP Ventures is repaid the KP Ventures Cash Consideration and Preferred Return. In addition, the Company previously granted Silver Bullet a “net proceeds” interest of 9% on the Pledged Assets (the “Silver Bullet NPI”), which Silver Bullet NPI was capped at 25% of the outstanding principal and accrued interest owed under the Notes (the “Silver Bullet NPI Limitation”).
As consideration for Silver Bullet to enter into the Subordination Agreement, the Company agreed to increase the interest on the Notes to 12% per annum and remove the Silver Bullet NPI Limitation so there is no cap on the maximum amount of Silver Bullet NPI that Silver Bullet can receive.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Critical Accounting Policies
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.
This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for project commercialization.
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.
During the year ended October, 31 2012 and 2011, we recorded impairments on the oil and gas assets in the Cabeza Creek Field totalling $147,370 and $158,487, respectively. In addition, in August 2011, leases covering approximately 1,240 acres in Del Norte expired. As a result, we reported an impairment charge of $77,703 for the expired leases. At October 31, 2012, we determined that due to title and ownership issues in one of our non-core properties, we would not be able to develop the property. As such, we reflected an impairment on that property totalling $78,173.
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.
During the fourth quarter 2011, we plugged and abandoned two wells in the Cabeza Creek Field. The cost to plug and abandon these wells totalled $33,513. The estimated amount of asset retirement obligations recorded on our books totalled $45,439. As a result, we recorded a gain of $11,926. There were no such expenses in the year ended October 31, 2012.
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.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Blacksands Petroleum, Inc. and its subsidiaries (collectively, the “Company”) as of October 31, 2012 and 2011 and the related consolidated statement of operations and comprehensive loss, stockholders’ equity, and cash flows for each of the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Blacksands Petroleum, Inc. and its subsidiaries as of October 31, 2012 and 2011 and the results of their operations and their cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ MaloneBailey, LLP
www.malonebailey.com
Houston, Texas
February 13, 2013
Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Balance Sheets
October 31, 2012 and 2011
The accompanying notes are an integral part of these consolidated financial statements.
Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Statements of Operations
Years Ended October 31, 2012 and 2011
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, 2012 and 2011
The accompanying notes are an integral part of these consolidated financial statements.
Blacksands Petroleum, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Years Ended October 31, 2012 and 2011
The accompanying notes are an integral part of these consolidated financial statements.
BLACKSANDS PETROLEUM, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
October 31, 2012
1.
The Company and Summary of Significant Accounting Policies
Description of business and history
Blacksands Petroleum, Inc. (hereinafter referred to as the “Company”) was incorporated in the State of Nevada on October 12, 2004. Since August 2007, the Company has been engaged in the exploration, development, exploitation and production of oil and natural gas. The Company sells its oil and gas products primarily to domestic pipelines and refineries. Its operations are presently focused in the States of 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, Copano Bay Holdings LLC, APClark LLC and BSPE Texas, LLC. All significant inter-company transactions and balances have been eliminated.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and natural gas properties. Oil and gas properties are periodically assessed to determine whether they have been impaired. Any impairment in value of unproved properties is charged to exploration expense. The costs of unproved properties, which are determined to be productive, are transferred to proved oil and gas properties and amortized on an equivalent unit-of-production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found proved oil and gas reserves. In accordance with ASC No. 935, exploratory drilling costs are evaluated within a one-year period after the completion of drilling. For proved properties, we compare expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant date, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
During the years ended October 31, 2012 and 2011, the Company impaired its oil and gas properties by $225,543 and $236,181, which is reflected in the consolidated statement of operations (see note 2).
Asset Retirement Obligation
The Company follows ASC 410-Asset Retirement and Environmental Obligations which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs excluding salvage values. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.
Accounting for Derivative Instruments
ASC 815-24 (formerly SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”), requires all derivatives to be recorded on the balance sheet at fair value. The Company’s derivatives are separately valued and accounted for on the balance sheet. Fair values for securities traded in the open market and derivatives are based on quoted market prices. Where market prices are not readily available, fair values are determined using market based pricing models incorporating readily observable market data and requiring judgment and estimates.
The pricing model the Company used for determining fair values of its derivatives is the Black-Scholes option-pricing model. Valuations derived from this model are subject to ongoing internal and external verification and review. The model uses market-sourced inputs such as interest rates, exchange rates and option volatilities. Selection of these inputs involves management’s judgment and may impact net income.
Cash and cash equivalents and short term investments
Cash and cash equivalents include cash on account and all highly liquid investments with original maturities of three months or less on the date of acquisition. Investments with original maturities of greater than three months but less than one year are considered short-term investments.
Use of estimates
The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
The most critical estimate is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion and amortization of the oil and gas properties and the estimate of the impairment of the oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future cash flows.
Concentration of credit risks
The Company’s consolidated financial assets that are exposed to credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company maintained substantially all of its cash balances in a limited number of financial institutions. The balances are insured by the Federal Deposit Insurance Corporation up to $250,000. Through December 31, 2012, all balances in U.S. non-interest bearing accounts are fully insured. The Company had no balances in excess of this limit at October 31, 2012, although the balances may exceed these limits at times throughout the year.
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, 2012, our aggregate production imbalances were not material.
Stock-based compensation
The Company follows the provisions of FASB ASC 718-Stock Compensation. The statement requires all stock-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values on the date of grant.
Income taxes
The Company accounts for its income taxes in accordance with ASC 740 Income Taxes, which requires recognition of deferred tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in operations in the period that includes the enactment date. A valuation allowance is provided for the amount of deferred tax assets that would otherwise be recorded for income tax benefits primarily relating to operating loss carryforwards as realization cannot be determined to be more likely than not.
The statement establishes a more-likely-than-not threshold for recognizing the benefits of tax return positions in the financial statements. Also, the statement implements a process for measuring those tax positions which meet the recognition threshold of being ultimately sustained upon examination by the taxing authorities. There are no uncertain tax positions taken by the Company on its tax returns and the adoption of the statement had no material impact to the Company’s consolidated financial statements. The Company files tax returns in the US and states in which it has operations and is subject to taxation. Tax years subsequent to 2008 remain open to examination by U.S. federal and state tax jurisdictions.
Net loss per common share
The Company computes net income or loss per share in accordance with ASC 260 Earnings Per Share. Under the provisions of the Earnings per Share Topic ASC, basic net loss per share is computed by dividing the net loss available to common stockholders for the period by the weighted average number of shares of common stock outstanding during the period. The calculation of diluted net loss per share gives effect to common stock equivalents; however, potential common shares are excluded if their effect is anti-dilutive. The weighted average number of potentially dilutive common shares excluded from the calculation of diluted net income (loss) per share totaled 3,511,934 and 3,423,934 for the years ended October 31, 2012 and 2011, respectively.
Fair Value of Financial Instruments
The carrying amounts of financial instruments, including cash and cash equivalents, short-term investments, accounts receivable, accounts payable and accrued liabilities approximate fair value at October 31, 2012 and October 31, 2011 because of the short period to maturity of these instruments.
2.
Oil and Gas Property Costs
In the years ended October 31, 2012 and October 31, 2011, the Company incurred property acquisition costs as follows:
Proved Properties
Unproved Properties
Blacksands Projects
Proved Properties
J.E. Pettus Gas Unit (known as “Cabeza Creek Field”) Acquisition in November 2009
On November 9, 2009, the Company purchased the J.E. Pettus Gas Unit located in Goliad County, Texas for $402,569. The Company also incurred approximately $25,000 in fees associated with the acquisition, which were expensed when incurred. The Gas Unit includes four (4) active gas wells, (1) active oil well and 22 non-producing wells located on 3,689 acres in Goliad County, Texas. The leasehold working interest acquired by BSPE Texas is 100% leasehold working interest (80% net revenue interest) from the surface to 8,500 feet below the surface and 10.67% leasehold working interest (8.536% net revenue interest) below 8,500 feet.
At October 31, 2012 and 2011, 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 $147,370 and $158,478, respectively.
Beech Creek Oil Wells (known as “Beech Creek Field”) Acquisition in April 2010
On April 5, 2010, the Company purchased different leasehold working interests in the Beech Creek Wells No. 1 and No A-2 located in Hardin County, Texas for $740,798 in cash. These property interests were previously owned by a group of five different working interest owners. A 30.0587% working interest (21.942851% net revenue interest) was acquired in the Beech Creek #1 well. A 24.4337% (18.3253% Net Revenue Interest) working interest was acquired in the Beech Creek A-2 well. Both of these wells are currently producing.
AP Clark Wells (known as “Jo-Mill Field”) Acquisition in August 2010
On August 10, 2010 the Company purchased an interest in two operating wells and its leasehold interest in 1,257 acres for $460,000. As a result of the acquisition, the Company has a 25% gross working interest (18.75% net revenue interest) in the two operating wells. The Company also has an 18.875% gross working interest (14.15625% net revenue interest) on the leasehold interests acquired on the 1,257 acres. 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.
On November 29, 2010, the acquired the leasehold interests and rights in the AP Clark II Prospect 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.
The Company incurred $1,342,539 in drilling costs related to the drilling and completion of the W.D. Everett Well No. 3. In addition, during the quarter ended October 31, 2011, the Company drilled the Beaver Valley Ranch 6-1 well. Westerly elected to not participate for its full working interest in this well and has a working interest on this well of 15%. The Company was able to arrange for two unrelated parties to participate for an additional 20%. As a result, the Company has a working interest in this well of 65%. The Company incurred costs relating to the well totaling $1,166,225.
During the fiscal year 2012, the Company drilled two wells, the Livestock 7-1 and Livestock 18-1 for a total cost of $1,223,535 and $1,275,699, respectively. Westerly elected to not participate for its full working interest in these wells and has a working interest of 11.4% and 8.55%, respectively. The Company was able to arrange for four unrelated parties to participate in each of these wells for an additional 26%. As a result, the Company has a working interest in these well of 62.8% and 65.65%. These wells began production in November 2012.
Copano Bay
Effective November 1, 2010, a newly organized subsidiary of 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. NRG Assets Management LLC, a Texas LLC and Texas registered operating company owned by the Company is the operator at all depths. In connection with the acquisition, the Company recorded an asset retirement obligation totaling $126,040. Effective July 1, 2012, the Company disposed of its interest in the property in exchange for $25,000. The Company reported a gain of $10,277 on the sale of this field.
The following is a summary of the unaudited proforma information assuming the sale of the Copano Bay field had occurred as of the beginning of each fiscal year presented:
Unproved Properties
Pedregosa Basin Field Acquisition in June 2010
On June 18, 2010, the Company acquired a 50% undivided leasehold working interest (with an associated 40% net revenue interest) in and to approximately 147,262 acres of land, located in the Pedregosa Basin (SW New Mexico) for an initial acquisition cost of $1.5 million (the “Exploration Agreement”). Pursuant to the agreement, $1 million was paid at purchase and the remaining $500 thousand was due and subsequently paid on November 1, 2010. This remaining $500 thousand was 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, The Company was responsible for acquiring 37 linear miles of 2-D seismic data. 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. During the quarter ended April 30, 2011, the Company began drilling on a test well. The Company incurred $1,665,142 in capitalized exploration costs. During the quarter ended October 31, 2011, the Company determined that there were not economically feasible hydrocarbons at the test well site and expensed the costs of the well as exploration costs. During 2012, the Company determined that it owed an additional $952,320 for the drilling of this test well based on cost over runs reported to the Company by the operator of the well. This amount is reported in the statement of operations as exploration costs.
Del Norte Acquisition in September 2010
On September 9, 2010, the Company acquired a 50% undivided leasehold working interest in and to approximately 3,200 acres of land located in Rio Grande County in Colorado from Dan A. Hughes Company for an initial acquisition cost of $200,000. The property has no production and was accounted for as an acquisition of unproved property. Pursuant to the agreement, the Company has the option to participate in the drilling of a test well. If the Company participates in the drilling of this test well, all costs associated with the well will be borne equally. As a result of this acquisition, the Company recorded $200,000 in unproved properties. In August 2011, leases covering approximately 1,240 of these acres expired. As a result, the Company reported an impairment charge of $77,703 for the expired leases.
Cometa Ranch
In September 2010, the Company acquired an undivided interest leased in approximately 1102 acres of land for approximately $78,000. As a result of the Company being unable to resolve title and ownership issues on this property, it has been determined the Company will not be able to develop this property. As such, a full impairment on the property was reported in 2012.
3.
Debt
The following is a summary of the debt outstanding at October 31,
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 principle 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 an 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. 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.
During the year ended October 31, 2011, the warrant agreement was amended to remove the full ratchet provision. As a result, the warrants no longer qualified as a derivative liability and the remaining derivative liability was reclassified to contributed capital.
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 unsecured note payable was due January 11, 2012 and incurs interest at the rate of 6%. In January 2012, the note was extended for a one year period. All other terms and conditions remain unchanged.
Bridge Loans
On February 2, 2011, the Company entered into a securities purchase agreement (the “Purchase Agreement”) providing for the Company to borrow $1,745,300. The notes incurred interest at the rate of 8% per annum. In connection with the issuance of the bridge loans, the Company issued warrants to purchase 581,767 shares of common stock of the Company (the “Warrants”).
The bridge loans mature on the earlier of the (i) date the Company closes an offering that results in gross proceeds to the Company of at least $1,000,000 or (ii) first anniversary of the date of issuance (the “Maturity Date”) and bears interest at the annual rate of 8%. The Company is not required to make any payments until the Maturity Date. The Warrants are exercisable for a period of three years from the date of issuance and are exercisable into shares of common stock of the Company at an exercise price of $4.50 per share. The Company was required to register the shares underlying the warrants within 60 days of the closing of the offering. There was no penalty if the shares were not promptly registered.
On March 17, 2011, the bridge loans came due as a result of obtaining at least $1,000,000 in gross proceeds from the private placement (Note 7). On that date, $1,694,000 of the Bridge Loans were converted into 564,667 shares of the Company’s common stock and an option to purchase 564,667 shares of the Company’s common stock at an exercise price of $4.50 per share. The remaining $51,300 in Bridge Loans was repaid. The warrants to purchase 581,767 shares of the Company’s common stock were not affected by the conversion or repayment.
In connection with the issuance of the Debentures, the Company reported a beneficial conversion feature of $872,404 and a discount related to the issuance of the warrants of $872,896. The beneficial conversion feature and discount were amortized to interest expense on the date of the conversion of the debentures to common stock. The relative fair value of the warrants was calculated using the Black-scholes method using the following assumptions: Discount rate of 1.2% to 1.4%, volatility of 155% and expected term of 3 years. The Company evaluated the warrants and concluded they were not derivatives.
Silver Bullet Properties
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. On September 27, 2011, the Company entered into an amendment to the promissory note dated November 19, 2010 (the “Note”) issued by the Company to Silver Bullet Property Holdings SDN BHD (the “Investor”). Pursuant to the amendment, the maturity date of the Note was amended from November 19, 2011 to February 1, 2013. In addition, the Investor loaned the Company an additional $1 million, with $500,000 loaned prior to October 31, 2011 and the remaining $500,000 received in two installments in November and December 2011. Pursuant to a security agreement, dated September 27, 2011, as security for the repayment of the Note, the Company granted the Investor a first priority lien on the Company’s oil and gas mineral leases in the ApClark Field. In April 2012, the parties agreed to further extend the note to May 1, 2014 and the investor agreed to an additional loan of $500,000 to the Company. The Company also granted a net proceeds interest (9% but reduced to 4.5% if the note is repaid prior to May 1, 2013) in the AP Clark properties included in the security agreement. The net proceeds interest represents the amount remaining from the proceeds of the sale of the property after deducting the related costs. The amendment was reviewed to determine its accounting treatment as a restructuring, extinguishment or modification and determined to be a modification. The Company received the additional $500,000 in June 2012.
PIE Energy
In November 2009, the Company received an interest-free advance from an unrelated third party totaling $60,000. In January 2011, the interest-free advances were converted into a note payable, which is due on January 11, 2012 and has a stated annual interest rate of 6%. In January 2012, the parties amended the agreement to extend the due date to January 11, 2013. All other terms and conditions remained unchanged.
Joint Venture Agreement
On July 20, 2012, Blacksands Petroleum, Inc. (the “Company”) entered into a Contribution Agreement (the “Contribution Agreement”), between APClark, LLC, a wholly-owned subsidiary of the Company (“APClark”) and KP-RAHR Ventures III, LLC (“KP Ventures”). Pursuant to the Contribution Agreement (i) the Company contributed $1,000 and certain of the Company’s oil and gas assets to APClark in exchange for 1,000 shares of Class A Membership Units of ApClark (the “Class A Membership Units”) and (ii) KP Ventures contributed approximately $2,600,000 (the “KP Ventures Cash Consideration”) to APClark in consideration of 1,000 shares of Class B Non-Voting Convertible Preferred Membership Units of APClark (the “Class B Membership Units” and the transaction, the “Asset Transaction”). KP Ventures has the option to contribute additional funds to APClark, up to an aggregate of $7,600,000, for no further equity consideration.
In connection with the Contribution Agreement, the Company entered into a Company Agreement (the “Operating Agreement”) governing the operations of APClark and defining various rights of the Company and KP Ventures.
Pursuant to the Operating Agreement, KP Ventures shall receive a preferred return of 12% per annum (the “Preferred Return”) on the unrecovered KP Ventures Cash Consideration until such time as the KP Ventures Cash Consideration is repaid. In addition, KP Ventures receives a 1% overriding royalty from the production of the APClark oil and gas properties. Once the KP Ventures Cash Consideration is repaid, including all accrued Preferred Returns, the Class B Membership Units shall automatically convert into Class C Non-Voting Net Profit Membership Units (the “Class C Membership Units”), which represent a non-dilutable “Net Profits” interest (“NPI”) in APClark and the assets owned by APClark and a percentage of all outstanding membership units of APClark initially equal to the NPI. The amount of the NPI granted depends on when the KP Ventures Cash Consideration and Preferred Return is paid, as follows:
The Company will be responsible for the operations of APClark and has the right to appoint the sole director of APClark, The consent of KP Ventures is required in certain situations, including, but not limited to: expanding the scope of the business; admitting additional members or transfer of membership units; approve annual budget; any merger or sale of all or substantially all of the assets of APClark; voluntary liquidation, dissolution or winding up of APClark; and to make any cash distributions.
In addition, the Company entered into a Pledge Agreement (the “Pledge Agreement”) pursuant to which it pledged the Class A Membership Units to KP Ventures to secure the Company’s obligations and performance thereunder and under the Contribution Agreement and Operating Agreement, which such Class A Membership Units shall be held pursuant to an escrow agreement.
Previously, the Company entered into a security agreement, dated as of September 27, 2011, pursuant to which, as security for the repayment of promissory notes in the principal face amount of $3,000,000 (the “Notes”), issued to Silver Bullet Property Holdings SDN BHD (“Silver Bullet”) a first priority security interest (the “Security Interest”) in certain of the assets of the Company that were contributed to APClark pursuant to the Contribution Agreement (the “Pledged Assets”). In connection with the Asset Transaction, the Company, APClark, Silver Bullet and KP Ventures entered into a subordination agreement (the “Subordination Agreement”), pursuant to which Silver Bullet subordinated its Security Interest to KP Ventures, so that KP Ventures would have a first priority interest in the Pledged Assets until KP Ventures is repaid the KP Ventures Cash Consideration and Preferred Return. In addition, the Company previously granted Silver Bullet a “net proceeds” interest of 9% on the Pledged Assets (the “Silver Bullet NPI”), which Silver Bullet NPI was capped at 25% of the outstanding principal and accrued interest owed under the Notes (the “Silver Bullet NPI Limitation”).
As consideration for Silver Bullet to enter into the Subordination Agreement, the Company agreed to increase the interest on the Notes to 12% per annum and remove the Silver Bullet NPI Limitation so there is no cap on the maximum amount of Silver Bullet NPI that Silver Bullet can receive.
As a result of the required repayment of the equity to KP Ventures, the amount of the contribution has been reflected as a liability on the balance sheet. The Company has also recorded a discount on this liability relating to the relative fair value of the overriding royalties totaling $163,786 and net profits interest totaling $1,915,231. These discounts reduced the carrying value of the proved oil and gas costs. The carrying value of the discounts totaled $2,008,134 at October 31, 2012. The Company amortized $70,883 as additional interest expense through October 31, 2012.
4.
Asset Retirement Obligation
The following table summarizes the change in the asset retirement obligation (“ARO”) 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.
5.
Stockholders Equity
Preferred Stock
The Company is authorized to issue 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, 2012, 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.
Private Placement
On March 1, 2011, the Company commenced a private placement offering of between 500,000 and 2,000,000 units at a price of $3 per unit. Each unit is to consist of one share of common stock and a warrant to purchase one share of common stock at an exercise price of $4.50 per common share. The warrants may be exercised for a period of three years and can be called by the Company if the closing bid price of the common stock is at least $6 per share for 10 consecutive trading days. The Company was required to file the initial registration statement registering the shares underlying the warrants within 90 days of the final closing of the offering (there are no monetary damages for non-compliance). This registration statement has not yet been filed. In addition, the shares included in the units, if not previously registered, are to be included in such future registration statements, subject to SEC limitations. The Company sold 860,834 units for gross proceeds totaling $2,582,501 ($2,464,400 in net proceeds including costs of $118,101). In addition, $1,694,000 of the Bridge Loans were converted into 564,667 units. The Company evaluated the warrants and concluded they were not derivatives.
Stock Options
As of June 26, 2006, the Company’s Board of Directors approved, and a majority of the Company’s stockholders ratified, the adoption of the Company’s 2006 Stock Option Plan (the “Plan”), pursuant to which the Board of Directors has the ability to provide incentives through the issuance of options, stock, restricted stock, and other stock-based awards, representing up to 2,000,000 shares of the Company’s common stock, to certain employees, outside directors, officers, consultants and advisors. The 2006 Stock Option Plan allows the term of options granted to be determined by the Board of Directors not to exceed ten years. The Board of Directors is authorized to determine the vesting requirements of the options granted.
During the Fiscal year ended October 31, 2012, stock options were granted to a director of the Company for options representing 88,000 common shares. The exercise price of the option is $4.50, with a ten year term, vesting equally over four years. The fair value of the option grants were estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: expected volatility of 134%, risk free interest rate of 0.77%; and expected lives of 3.7 years. During the year ended October, 31, 2012 and 2011, the Company recorded stock based compensation totaling $594,901 and $884,073, respectively, as a result of the 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, 2012 totaled $540,834. At October 31, 2012, the weighted average remaining life of the stock options is 7.37 years. At October 31, 2012, there was $302,184 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 1.03 years.
Warrants
A summary of the Company’s stock warrant activity and related information for the years ended October 31, 2012 and 2011 is as follows:
The intrinsic value for the outstanding warrants at October 31, 2012 totaled $0. The remaining term of the warrants is 1.38 years.
6.
Commitments and Contingencies
The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. The Company is not aware of any environmental claims existing as of October 31, 2012, 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.
In January 2012, the Company appointed a new director to the Board of Directors. In conjunction with this appointment, the Company entered into a compensation agreement with the director. Pursuant to this agreement, the director will receive cash compensation totaling $20,000 (paid quarterly) along with payment for attendance at Board meetings. In addition, the director will receive 25,000 shares of restricted Common Stock of the Company, of which 6,250 shares vest immediately and the remaining shares vest in semi-annual amounts of 3,125 shares. The Company also granted the director an option to purchase up to 88,000 shares of the Company’s common stock at an exercise price of $4.50 per share. The options vest equally over four years. During the year ended October 31, 2012, the Company recorded director expenses for the vesting of these shares totaling $64,688.
Operating leases
The Company leases its offices in Texas on a month to month basis. Rent expense for the years ended October 31, 2012 and 2011 was $33,600 and $28,000, respectively.
7.
Income Taxes
The reconciliation between the expected income tax benefit, computed using the statutory federal rate of 34%, and the actual income tax benefit is as follows:
The composition of deferred tax assets/liability is as follows:
The valuation allowance increased by $1,534,749 during the year ended October 2012. 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 $13,734,277 at October 31, 2012. These losses expire as follows:
8.
Supplemental Oil and Gas Disclosures (unaudited)
The following supplemental information regarding the oil and gas activities of the Company for 2012 and 2011 is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." Capitalized costs relating to oil and gas activities and costs incurred in oil and gas property acquisition, exploration and development activities for each year are shown below.
CAPITALIZED COST OF OIL AND GAS PRODUCING ACTIVITIES
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 by Hamilton and by Corridor & Associates for the years ended October 31, 2012 and 2011, respectively. The oil and natural gas price as of October 31, 2012 and 2011 is based on the 12-month unweighted average of the first of the month prices of the West Texas Intermediate posted price. The oil and natural gas prices were adjusted by lease for quality, transportation fees, and regional price differentials. The gas price as of October 31, 2012 and 2011 is based on the 12-month unweighted average of the first of the month prices of the Henry Hub spot price. All prices are adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States.
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 by Hamilton. 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, 2012 and 2011 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, 2012, 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, 2012:
ITEM 9
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
None
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 of October 31, 2012, 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)
Due to our small size, we did not have sufficient personnel in our accounting and financial reporting functions nor do we have a proper segregation of duties. During the year ended October 31, 2012, we had limited staff that performed nearly all aspects of our financial reporting process, including, but not limited to, access to the underlying accounting records and systems, the ability to post and record journal entries and responsibility for the preparation of the financial statements. This creates certain incompatible duties and a lack of review over the financial reporting process that would likely result in a failure to detect errors in spreadsheets, calculations, or assumptions used to compile the financial statements and related disclosures as filed with the Securities and Exchange Commission. In addition, we have had an overreliance on consultants involved in our financial statement closing process. As a result we were not able to achieve adequate segregation of duties and were not able to provide for adequate reviewing of the financial statements. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the financial statements will not be prevented or detected on a timely basis; and
b)
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 our complexity and our financial accounting and reporting requirements. As a result, our financial statement closing process, which involves the preparation of the financial statements included in this annual report, did not identify all of the adjusting journal entries that were required to be recorded in connection with our closing process. As part of the audit, our independent registered public accounting firm proposed a significant number of audit adjustments, including a material adjustment regarding the amount of depletion of our oil and gas reserves, which should have been recorded as part of the normal closing process. Our internal control over financial reporting did not detect such matters and, therefore, was not effective in detecting misstatements in the consolidated financial statements. 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 financial organization. We will look to increase our personnel resources and technical accounting expertise within the accounting function to resolve non-routine or complex accounting matters. In addition, when funds are available, we will take the following action to enhance our internal controls: Hiring additional knowledgeable personnel with technical accounting expertise to further support our current accounting personnel, which management estimates will cost approximately $100,000 per annum. As our operations are relatively small and we continue to have net cash losses each quarter, we do not anticipate being able to hire additional internal personnel until such time as our operations are profitable on a cash basis or until our operations are large enough to justify the hiring of additional accounting personnel. We currently engage an outside accounting firm to assist us in the preparation of our consolidated financial statements and anticipate doing so until we have a sufficient number of internal accounting personnel to achieve compliance. As necessary, we will engage consultants in the future in order to ensure proper accounting for our consolidated financial statements.
Management believes that hiring additional knowledgeable personnel with technical accounting expertise will remedy the following material weakness: insufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with our complexity and our financial accounting and reporting requirements.
Management believes that the hiring of additional personnel who have the technical expertise and knowledge with the non-routine or technical issues we have encountered in the past will result in both proper recording of these transactions and a much more knowledgeable finance department as a whole. Due to the fact that our internal accounting staff consists of a Chief Financial Officer and a bookkeeper, additional personnel will also ensure the proper segregation of duties and provide more checks and balances within the department. Additional personnel will also provide the cross training needed to support us if personnel turn over issues within the department occur. We believe this will greatly decrease any control and procedure issues we may encounter in the future.
(b) Changes in internal control over financial reporting.
There were no changes in our internal control over financial reporting that occurred during the quarter ended October 31, 2012 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 in effective as of October 31, 2012 for the reasons discussed above.
This annual report does not include an attestation report by Malone Bailey LLP, our independent registered public accounting firm regarding internal control over financial reporting. As a smaller reporting company, our management's report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management's report in this annual report.
ITEM 9B
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, 2012 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. Mr. DeMarco was selected to serve as a director due to his deep familiarity with our oil and gas business.
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.
Richard S. T. Hunter has been a Director since January 2012. Since September 2008, Mr. Hunter has served as the Vice President, Investor Relations for Carrizo Oil and Gas, Inc., a publicly traded company. Between 1993 and June 2008, Mr. Hunter worked for Lighthouse Capital Management, a Houston, Texas-based investment advisor, as a Principal and Director of Research (1998-2008) and an Energy Securities Analyst (1993-1998). Between 1985 and 1993, Mr. Hunter was a Stratigrapher for Shell Oil Company, a publicly traded company. Mr. Hunter holds BS degrees in Biology and Geology from Florida State University, a MS degree in Geology from Florida State University and MBA from Rice University Jones School of Business. In addition, Mr. Hunter is a registered investment advisor in the State of Texas. Mr. Hunter was selected to serve as a director due to his deep familiarity with our business, his extensive entrepreneurial background and his substantial financial and accounting experience.
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. Mr. Mosimann was selected to serve as a director due to his deep familiarity with our oil and gas business.
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. Mr. Wilson was selected to serve as a director due to his deep familiarity with our business, his extensive entrepreneurial background and his substantial financial and accounting experience.
Family Relationships
None.
Board Independence
We are not required to have any independent members of the Board of Directors. The board of directors has determined that (i) David DeMarco, has a relationship which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director and is not an “independent director” as defined in the Marketplace Rules of The NASDAQ Stock Market and (ii) Richard Hunter, Bruno Mosimann and Rick Wilson are each an independent director as defined in the Marketplace Rules of The NASDAQ Stock Market.
Meetings and Committees of the Board of Directors
During the fiscal year ended October 31, 2012, our board of directors held eight 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 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. Our Board of Directors has determined that 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.
Involvement in Certain Legal Proceedings
Our Directors and Executive Officers have not been involved in any of the following events during the past ten years:
1.
any bankruptcy petition filed by or against such person or any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;
2.
any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
3.
being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from or otherwise limiting his involvement in any type of business, securities or banking activities or to be associated with any person practicing in banking or securities activities;
4.
being found by a court of competent jurisdiction in a civil action, the Securities and Exchange Commission or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended, or vacated;
5.
being subject of, or a party to, any federal or state judicial or administrative order, judgment decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of any federal or state securities or commodities law or regulation, any law or regulation respecting financial institutions or insurance companies, or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
6.
being subject of or party to any sanction or order, not subsequently reversed, suspended, or vacated, of any self-regulatory organization, any registered entity or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers and holders of more than 10% of our common stock to file with the SEC reports regarding their ownership and changes in ownership of our securities. We believe that, during fiscal 2012, our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements.
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, 2012 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 2012 and 2011.
(1)
Other compensation represents consulting fees paid to or earned by the officers.
Employment Contracts and Termination of Employment and Change-In-Control Arrangements
None.
Option/SAR Grants in Fiscal Year Ended October 31, 2012
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, 2012.
Equity Compensation Plan Information
(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, 2012, 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, 2012, 1,046,333 shares were issuable upon exercise of options granted to employees and directors.
Director Compensation
The following table summarizes the compensation for our non-employee board of directors for the fiscal year ended October 31, 2012. All compensation paid to our employee directors is included under the summary compensation table above.
(1)
Represents 25,000 shares of restricted Common Stock of the Company, of which 6,250 shares vest immediately and the remaining shares vest in semi-annual amounts of 3,125 shares.
(2)
Represents an option to purchase up to 88,000 shares of the Company’s common stock at an exercise price of $4.50 per share. The options vest equally over four years
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 February 11, 2013:
•
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.
_____________
*
Less than 1%.
(1)
The address for each of our officers and directors is 800 Bering, Suite 250, Houston, Texas 77057.
(2)
Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and generally includes voting or investment power with respect to securities. Shares of common stock subject to options or warrants currently exercisable or convertible, or exercisable or convertible within 60 days of February 11, 2013 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 16,377,125 shares of common stock outstanding as of February 11, 2013.
(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 February 11, 2013 or become exercisable within 60 days of that date: David Demarco (200,000), Richard S. T. Hunter (22,000 shares), Bruno Mosimann (66,667 shares) and Rick Wilson (66,667 shares); and all officers and directors as a group, (355,334 shares).
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
During the last two fiscal years, there have been no transactions, or proposed transactions, which have materially affected or will materially affect us in which any director, executive officer or beneficial holder of more than 5% of the outstanding common, or any of their respective relatives, spouses, associates or affiliates, has had or will have any direct or material indirect interest. We have no policy regarding entering into transactions with affiliated parties.
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, 2012 and 2011, and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years were approximately $81,000 and $101,000, respectively.
Audit Related Fees. We incurred fees to our independent auditors of $nil for audit related fees during the fiscal years ended October 31, 2011 and 2010.
Tax and Other Fees. We did not incur fees to our independent auditors for tax and fees during the fiscal years ended October 31, 2012 and 2011.
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:
_________________________
*
Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
+ filed herewith
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 13, 2013
By:
/s/ DAVID DEMARCO
David DeMarco
Chief Executive Officer (Principal Executive Officer)
Date: February 13, 2013
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
Director
Date: February 13, 2013
David DeMarco
/s /BRUNO MOSIMANN
Director
Date: February 13, 2013
Bruno Mosimann
/s /RICHARD S. T. HUNTER
Director
Date: February 13, 2013
Richard S. T. Hunter
/s/ RICK WILSON
Director
Date: February 13, 2013
Rick Wilson