ITEM 1. BUSINESS.
We are an independent oil and gas company engaged in exploration, development and production of oil and natural gas. As production of these products continues, they will be sold to purchasers in the immediate area where the products are produced.
Until 2005, our focus was on our undeveloped mineral interests and we were considered, at that time, to be a development stage company engaged in the acquisition and exploration of mineral and oil and gas properties. We still hold an interest in undeveloped mineral interests located in New Mexico (the “Antelope Pass Project”). However, in 2005, we suspended activities on our undeveloped mineral properties indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on our undeveloped mineral properties during the fiscal year ended October 31, 2010.
During 2005 and 2006, we acquired undeveloped oil and gas interests and commenced exploration activities on those interests. Our undeveloped oil and gas interests are located in Oklahoma, Mississippi and California. In 2006, we commenced oil and gas production and started earning revenues.
Our plan of operations is to continue to produce commercial quantities of oil and gas and to drill re-entries to test the oil and gas productive capabilities of our oil and gas properties. As noted above, we have suspended our efforts indefinitely on the Antelope Pass Project in order to focus on our oil and gas interests.
Corporate Background
We were incorporated under the laws of the State of Nevada on December 23, 1998, initially to explore mining claims and property in New Mexico.
Property Acquisitions and Dispositions
Three Sands Project
On October 6, 2005, we acquired a 40% working interest in Vector Exploration Inc.’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs (the “Three Sands Project”). The Three Sands Project is located in Oklahoma. For the year ended October 31, 2006, we expended $530,081 in exploration costs. In June 2007, we acquired a 40% working interest in the William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well. On March 19, 2008, we participated in the KC 80 #1-11 well and paid $75,000 for the prepaid drilling costs. During March and April 2008, we expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 during May to July 2008 for the KC 80 #1-11 well. The total cost of the Three Sands Project as of October 31, 2010 was $1,279,633. Our working interest in the Three Sands Project includes leasehold interests, one re-entry production well, one salt water disposal well and three drilled oil and gas wells. We also participate in drilling operations and related costs, in proportion to our working interest.
Palmetto Point Project
On February 28, 2006, we acquired a 10% working interest before completion and an 8.5% revenue interest after completion, in a 10-well program at the Palmetto Point Project operated by Griffin & Griffin Exploration LLC (“Griffin & Griffin”) for a total buy-in cost of $350,000 (the “Palmetto Point Project”). The Palmetto Point Project is located in Mississippi. On September 26, 2006, we acquired two additional wells (the PPB and PP-A wells) within the Palmetto Point Project for $70,000. On October 1, 2007, we acquired and participated in drilling two more wells within the Palmetto Point Project (the PP-2 and PP-3 wells) at a cost of $69,862. On October 25, 2007, we paid $17,000 for a sidetrack, a deviation of the existing PP-F-12-3 well at an angle to reach additional targeted oil sands. The well was successfully completed as a flowing oil well.
On January 30, 2008, we incurred $36,498 for workovers to install submersible pumps. During November 2008 to July 2009, we incurred $44,623 for the Belmont Lake Project. The total cost of the Palmetto Point Project, including costs for the PP-2, PP-3, PP-4 and PP wells, was $732,630 as of October 31, 2010.
Mississippi Frio-Wilcox Joint Venture
On August 2, 2006, we executed a memorandum agreement with Griffin & Griffin (as operator of the project), Delta Oil and Gas, Inc., Turner Valley Oil and Gas Company, Lexaria Corp., a Nevada corporation (“Lexaria”), and the Stallion Group to participate in two proposed drilling programs located in Southwest Mississippi and Northeast Louisiana, comprised of up to 50 natural gas and/or oil wells, at a price of $400,000 (the “Mississippi Frio-Wilcox Joint Venture”). We hold a 10% working interest in the Mississippi Frio-Wilcox Joint Venture project before production and a prorated reduced working interest after production based on the operator’s interest portion.
On June 21, 2007, we assigned our future development interests and obligations for any new wells on our Mississippi Frio-Wilcox Joint Venture property to Lexaria for the sum of $1. We believe the assigned interests to be of nominal value. We maintained our original interest, rights, title and benefits to all seven wells drilled with our participation at the Mississippi Frio-Wilcox Joint Venture property between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC, CMR/BR, RB Red Bug #2, BR, and Randall #1, and any offset wells that could be drilled to any of these specified wells. We do not anticipate expending additional exploration funds on the project.
2008-3 Drilling Program, Oklahoma
On January 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The Before Casing Point (“BCP”) Interest shall be 6.25% and the After Casing Point (“ACP”) Interest shall be 5.00%. From January to July 2009, we expended an additional $213,925 in addition to $18,850 that was spent in previous periods. The well, Wigley #1-11, was abandoned during March 2009, and the cost and its buy-in cost total of $33,423 were moved to the proved properties pool. Selman #1-21 and Bagwell #1-20 started producing during May 2009, Ard #1-36 started producing during June 2009, and Selman #2-21 started producing during July 2009. The Selman #2-21 was later abandoned in April 2010. The interests are located in Garvin County, Oklahoma. The total cost of the 2008-3 Drilling Program was $257,564 as of October 31, 2010.
King City, California
Effective May 25, 2009, we entered into an agreement with Sunset Exploration to explore for oil and gas on 10,000 acres located in west central California. We paid $100,000 to earn a 20% working interest in the project by funding a maximum of 50% of a $200,000 geophysical survey composed of gravity and seismic surveys and agreeing to carry Sunset Exploration for 33.33% of dry hole cost of the first well. Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each parties’ working interest. The Company has expended $6,091 for the year ended October 31, 2010.
2009-2 Drilling Program, Oklahoma
On June 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Point Interest shall be 5.00%. The well, James #1-18, was abandoned in September 2009 and the cost and its buy-in cost total of $41,934 were moved to the proved properties pool. Little Chief #1-3 was abandoned in November 2009 and the cost and its buy-in cost total of $35,528 were moved to the proved properties pool. J.C. Carlton #1-31 was abandoned in April 2010 and the cost and its buy-in cost total of $38,630 were moved to the proved properties pool. As of October 31, 2010, the total cost of the 2009-2 Drilling Program was $115,582. The interests are located in Garvin County, Oklahoma.
2009-3 Drilling Program, Oklahoma
On August 12, 2009, we acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Jackson #1-18 started producing in January 2010 and an amount of $63,725, which included the buy-in cost, was moved to the proved properties pool. Miss Gracie #1-18 started producing in March 2010 and an amount of $62,268, which included its buy-in cost, was moved to the proved properties pool. Brewer #1-20 was abandoned in June 2010 and the cost and its buy-in cost total of $64,936 were moved to the proved properties pool. Waunice #1-36 started producing in June 2010 and an amount of $43,848, which included its buy-in cost, was moved to the proved properties pool. It was later abandoned in September 2010. The total cost of the 2009-3 Drilling Program, including drilling costs, as of October 31, 2010 was $294,164. The interests are located in Garvin County, Oklahoma.
2009-4 Drilling Program, Oklahoma
On December 19, 2009, we acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Dennis #1-8 started producing in May 2010 and an amount of $79,892, which included the buy-in cost, was moved to the proved properties pool. It was later abandoned in September 2010. As of October 31, 2010, the total cost of the 2009-4 Drilling Program was $172,530. The interests are located in Garvin County, Oklahoma.
Washita Bend 3D Exploration Project, Oklahoma
On March 1, 2010, we acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project for a buy-in cost of $46,250. As of October 31, 2010, the total cost, including seismic costs, was $337,398.
South Wayne Prospect, Oklahoma
On March 14, 2010, we acquired a 5.00% working interest in McPherson #1-1 well for a payment of $5,000 for leasehold, prospect and geophysical fees, and dry hole costs of $32,370. The total cost, including drilling costs, as of October 31, 2010 was $60,914. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The interests are located in McClain County, Oklahoma.
2010-1 Drilling Program, Oklahoma
On April 23, 2010, we acquired a 5.00% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Julie #1-14 was abandoned in October 2010 and the cost and buy-in cost total of $47,035 were moved to the proved properties pool. The estimated completion cost of $16,860 for Jack #1-13 was accrued for the year end. As of October 31, 2010, the total cost of the 2010-1 Drilling Program was $232,212. The interests are located in Garvin County, Oklahoma.
International Exploration Program
The Company is attempting to expand its property base by locating other resource properties internationally. Accordingly, we have hired consultants to gather data on properties that may be of interest to us. The consultants on a best efforts basis will attempt to acquire option agreements, lease agreements and/or the outright purchase of oil and /or gas properties internationally. As of the date of this filing, we have not found a suitable acquisition.
Antelope Pass Project
In September 2002, we acquired a 100% interest in leases on unpatented lode mining claims in the Antelope Pass Project, located in the Hidalgo County, New Mexico for $811, from Leroy Halterman, who was a non-affiliate of our company at that time. The Antelope Pass Project consists of the Kendra 1 through Kendra 8 mineral claims. Unpatented claims are mining claims for which the holder has no patent, or document that conveys title. The 2010-2011 Bureau of Land Management maintenance fee has been paid and the claims are valid until September 2011 without any additional expenditure. We have suspended our efforts indefinitely on the Antelope Pass Project.
Exploration and Acquisition Capital Expenditures
During the fiscal years ended October 31, 2010, 2009, and 2008, we incurred $1,170,104, $668,446, and $291,150, respectively, in identifying and acquiring oil and natural gas interests, and for exploration costs.
Principal Products
We conduct exploration activities to locate oil and natural gas. As we continue our production of these products, we anticipate that generally they will be sold to purchasers in the immediate area where the products are produced. We expect that the principal markets for oil and natural gas will continue to be refineries and transmission companies that have facilities near our producing properties.
Competition
Oil and gas exploration, mineral exploration and acquisition of undeveloped properties are highly competitive and speculative businesses. We compete with a number of other companies, including major mining and oil and gas companies and other independent operators that are more experienced and which have greater financial resources. We do not hold a significant competitive position in either the mining industry or the oil and gas industry.
Major Customers
During the fiscal years ended October 31, 2010 and 2009, we collected $451,359 (69%) and $171,418 (43%), respectively, of our revenues from Ranken Energy Corporation, the operator of the Oklahoma Properties. Since we work with only a few operators, we will continue to be dependent on these few operators for a substantial portion of our revenues in fiscal year 2011.
Compliance with Government Regulation
Our oil and gas operations are subject to various levels of government controls and regulations in the United States. Legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas drilling, gas processing plants and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. A breach or violation of such laws and regulations may result in the imposition of fines and penalties. At present, we do not believe that compliance with environmental legislation and regulations will have a material effect on our operations; however, any changes in environmental legislation or regulations or in our activities may cause compliance with such legislation and/or regulation to have a material impact on our operations. In addition, certain types of operations require the submission and approval of environmental impact assessments. Environmental legislation is evolving in a manner that means stricter standards, and enforcement, fines and penalties for non-compliance are becoming more stringent. Environmental assessments of proposed projects carry a heightened degree of responsibility for companies and directors, officers and employees. The cost of compliance with changes in governmental regulations has a potential to reduce the
profitability of operations. We intend to ensure that we comply fully with all environmental regulations relating to our operations.
With respect to our Oklahoma oil and gas interests, we are required to file Oklahoma Form 1000 and pay $100 to obtain state permits for oil and gas drill sites on private lands. With respect to our Mississippi oil and gas interests, we are required to file Mississippi Form 2 and pay $350 to obtain state permits for oil and gas drill sites on private lands. Although we do not presently hold any interest in leases on state or federal lands, in the future we may be required to obtain environmental assessments in connection with wildlife impacts or archeological clearances.
With respect to our Antelope Pass Project, we will be required to conduct all mineral exploration activities in accordance with the Bureau of Land Management (“BLM”) of the United States Department of the Interior. If we proceed with our Antelope Pass Project, we will be required to obtain a permit prior to the initiation of exploration. To obtain a permit we will have to submit plans of operations to both the BLM and the State of New Mexico as part of our permit application.
Employees
Leroy Halterman serves as our president and secretary and a director. As of the date of this report, Mr. Halterman receives monthly management fees of $5,000 and a reimbursement for office space. For the fiscal years ended October 31, 2010 and 2009, we incurred $60,000 and $60,000, respectively, for Mr. Halterman’s services.
We engaged Kulwant Sandher to serve as our chief financial officer on a part-time basis beginning November 2009 and pay him CAD$2,500 per month. For the fiscal year ended October 31, 2010, we paid Mr. Sandher $72,068 for his services.
We pay management fees of $7,500 per month to Kenneth Cabianca, one of our directors. For the fiscal years ended October 31, 2010 and 2009, we paid Mr. Cabianca $90,000 and $102,000 in management fees, respectively.
For the fiscal years ended October 31, 2010 and 2009, we incurred $60,000 and $60,500, respectively, for administrative services performed by Downtown Consulting. Downtown Consulting is an entity owned and controlled by Sarah Cabianca, the daughter of Kenneth Cabianca and one of our shareholders. We pay Downtown Consulting a monthly fee of $5,000 for its services. We anticipate that we will be conducting most of our business through agreements with consultants and third parties. We have not entered into any arrangements or negotiations with any other consultants or third parties and our employees are not covered under a collective bargaining agreement.
ITEM 1A.
ITEM 1A. RISK FACTORS.
Not required for smaller reporting companies.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not required for smaller reporting companies.
ITEM 2.
ITEM 2. PROPERTIES.
Oil and Gas Properties
Current Oklahoma Projects
2008-3 Drilling Program, Oklahoma. On January 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581. We agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. From January 2009 to July 2009, we expended $213,925 in addition to $18,850 that was spent in previous periods. The total cost of the 2008-3 Drilling Program as of October 31, 2010 was $257,564. The interests are located in Garvin County, South Central Oklahoma.
This program is composed of four 3-D seismically defined separate prospects with one exploratory well in three of the prospects and two in the fourth prospect. Targeted pay zones include the prolific Bromide Sands, Viola Limestone, Deese Sandstone and Layton Sandstone. One of the wells has very similar geology and structure to the Bromide sands in the Owl Creek field.
Five wells were drilled during 2009. Production casing was set on four of the five wells and the fifth well was deemed non-commercial and was plugged and abandoned. Two of the four completed wells are still producing commercial quantities of oil and gas, with one of the wells still flowing naturally and producing most of the oil. During calendar year 2011 at least one development well is planned to be drilled. As of October 31, 2010, the two producing wells in this program have produced a total of 131,217 Bbls of oil and 22,654 Mcf of natural gas.
2009-2 Drilling Program, Oklahoma. On June 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562. We agreed to participate in the drilling operations to casing point in the initial test well of each of three prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The interests are located in Garvin County, Oklahoma. A total of three wells were drilled in this program and targeted pay zones that were the same as in the 2008-3 program. The zones included the prolific Oil Creek, Bromide Sands, Viola, Deese and Layton Sandstone. This program is composed of three 3-D seismically defined separate prospects. All wells were drilled in the last fiscal quarter of 2009. Two of the wells were deemed non-commercial and were plugged and abandoned. Production casing was set on one of the three wells and completion efforts have taken place on the third well; however, after testing it was also deemed non-commercial and plugged. As of October 31, 2010, the total cost of the 2009-2 Drilling Program was $115,582.
2009-3 Drilling Program, Oklahoma. On August 12, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775. We agreed to participate in the drilling operations to casing point in the initial test well on each of four prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total costs incurred, including drilling costs, as of October 31, 2010 was $294,164. The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the four prospects. All four of the wells have been drilled and production casing has been set on all four. Two of the wells had successful drill stem test that flowed oil and gas to the surface. Electric and radiation logs indicate multiple pay zones in all four wells.
One of the four wells in this program was completed in late January 2010 as a flowing oil and gas well. The well was flowing naturally at rates between 400 and 500 barrels of fluid per day with an oil cut of between 50% and 70% oil. Natural gas was being produced at a rate of over 400 Mcf per day. The well only produced for a few days before snow and ice storms forced shutting the well in because the produced oil and water could not be hauled away from the location and the storage tanks for these liquids were full. Conditions have improved and the well is now producing and selling oil and natural gas. The second well that also had a flowing drill stem test was completed in late March 2010 and that well is currently producing as a naturally flowing oil and gas well. Total production from these two producing wells as of October 31, 2010 totaled 57,553 Bbls of oil and 22,437 Mcf of natural gas.
In late June 2010, a successful development well was drilled as an offset to the naturally flowing well that is still producing at a rate of 230 Bbls oil and 28 Mcf of natural gas per day. This development well was completed
in early August 2010 and is flowing at a rate of 320 Bbls of oil and 40 Mcf of natural gas per day and should add significantly to this program’s future oil and gas production. Total production from this producing well as of October 31, 2010 was 26,280 Bbls of oil and 2,808 Mcf of natural gas.
The two remaining wells were completed in late May 2010. After testing, both wells were deemed to be non-commercial and have been plugged and abandoned.
2009-4 Drilling Program, Oklahoma. On December 19, 2009, we acquired a 5% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482. We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total costs incurred, including drilling costs, as of October 31, 2010 was $172,530. The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.
Drilling of the first well started in early February 2010 and reached total depth on February 20, 2010. The second well drilling started in late February 2010 and reached total depth on April 8, 2010. Both of the wells intercepted multiple potential productive horizons and production casing was set. The lowest horizon in the first well flowed oil and gas on a drill stem test. Weather was initially a problem with heavy rain causing flooding and other delays but both wells have now been completed. Both wells were treated for a poor cement bond and only one remains in production. The one well that could not be successfully treated for the poor cement bond was plugged and abandoned. Another well is being drilled as a twin to this well. If it is not successful it will be left unplugged as a possible salt water disposal well. As of October 31, 2010, both wells have produced a total of 2,734 Bbls of oil and have produced 1,733 Mcf of natural gas.
2010-1 Program, Oklahoma. On April 23, 2010, we acquired a 5% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,163. We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total cost incurred, including drilling costs, as of October 31, 2010 was $232,212. The interests are located in Garvin County, Oklahoma. Targeted pay zones include the prolific Oil Creek, Bromide Sands, Viola and Deese sands. This program is composed of four 3-D seismically defined separate prospects with one exploratory well in each of the two prospects.
As of late October 2010, all four wells of the four-well program had been drilled. Three of the wells had production casing set and one well was plugged and abandoned. The three successful wells intercepted multiple pay zones including the prolific lowest zone. One well had a flowing drill stem test but the other two wells were not drill stem tested. All three wells show excellent porosity, permeability, and hydrocarbon shows. Completion of these wells started in mid-September. Two of the wells have been completed in the deepest pay zone with one well producing between 90 to 110 barrels of oil water free and the second was producing at a rate of 360 to 400 barrels of oil per day in early December 2010. An offset development well to the previously mentioned high flow rate well is planned for the second or third fiscal quarter. These wells did not have any commercial production prior to October 31, 2010.
South Wayne Prospect, Oklahoma. On March 14, 2010, we acquired a 5% working interest in Okland Oil’s South Wayne prospect for a total buy-in cost of $5,000 and dry hole costs of $32,370. We agreed to participate in the drilling operations to casing point in the initial test well on each of two prospects. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The total cost incurred, including drilling costs, as of October 31, 2010 was $60,914. The well and related leasehold interests are located in McClain County, Oklahoma. As of October 31, 2010, the well had been drilled and production casing has been set. The well was perforated in July 2010 and immediately started flowing oil at a rate of 200 Bbls per day. The flow of oil was slowed and stopped due to a buildup of paraffin. A pumping unit was placed on the well in late August 2010 and the well is now producing at a rate of 85 Bbls of oil and 25 Mcf of natural gas. Total production for the McPherson well as of October 31, 2010 was 6,068 Bbls of oil and 1,726 Mcf of natural gas.
Washita Bend 3D Exploration Project, Oklahoma. On March 1, 2010, we agreed to participate with a 5% interest in a 3-D seismic program managed by Ranken Energy Corporation for a buy-in cost of $46,250. The
Oklahoma 3-D seismic program will cover approximately 135 square miles in a known oil and gas producing area. An earlier 2-D seismic program over the same area indicated a number of untested structures. We expect the 3-D program will refine and better define the structures discovered during the earlier program and pinpoint drill locations. We will participate in the seismic program and the related prospect generation and acquisition phase without any promotion. The BCP Interest shall be 5.625% and the ACP Interest shall be 5.00% on the first eight wells and then 5% before and after casing point on succeeding wells. The total cost, including seismic costs, as of October 31, 2010 was $337,398.
Work has commenced on this project and, as of August 11, 2010, almost half of all the surface permits have been acquired. Ownership reports are being completed. The start date for the surveying was early December 2010 with seismic data acquisition expected to start in early February 2011. A total of 5,148 acres of leases have been acquired thus far.
Three Sands Project
Location and Access. The Three Sands Project is an oil and gas exploration project located in Noble County, Oklahoma. The property can be reached by Oklahoma State Highway 77 and then accessed by a secondary gravel and dirt road.
Previous Operations and History. The Three Sands field was drilled on 10-acre spacing in the 1920s and 1930s and was very active in producing over 200 million Bbls of oil and an unknown amount of gas from a six-section (3,800 acres) area. However, during this period, most wells were abandoned within twenty years as the wells became commercially unviable due to the lack of technology. In particular, during this period, technology was not available, as it is today, to handle high volumes of water and its subsequent disposal, nor was it capable of drilling in areas where the tightness of rock limited flow.
The primary targets of the Three Sands Project are the Arbuckle, Wilcox and Viola Formations. These were the deep pay zones first discovered in the field, and in addition to the oil they produced, large amounts of water were eventually produced forcing the abandonment of the well. Today the water problem has been overcome with down hole electrical high volume pumps and adequate disposal wells, allowing continued exploration.
Geology of the Three Sands Project. Geologically, this field is a balded structure in which a combination of structure and erosion has aided in producing the field. Pay zones in the project vary from the Arbuckle to the Pennsylvanian and are productive over a 5,000-foot interval that starts at less than 1,000 feet from the surface. In a 2004 drill test, more than two-dozen pay zones were encountered (some of which have not been produced).
Costs Including Previous Work. As of October 31, 2010, we have expended $1,279,633 in connection with the Three Sands Project, including leasing, title, drilling, and casing.
Present Activities. Drilling of the Kodesh #1 disposal well was completed on October 3, 2005 and drilling of the Kodesh #2 well was completed on October 23, 2005. Completion and equipping of these wells took place during mid-December 2005 through early January 2006. The Kodesh #1 is being used for salt water disposal well. The Kodesh #2 well no longer produces oil on a daily basis, but there is a small amount of natural gas being produced. As of October 31, 2010, it has produced 3,690 Bbls of oil and 8,269 Mcf of natural gas. At the time of this report, the Kodesh #2 well has not been producing oil because of a failure of the downhole pump. In late December 2010, additional casing was placed in the well and in mid-January 2011, new pay zones were perforated and fracture treated. A new pumping unit was placed on the well and the unit is currently pumping load water back that was used to the fracture treat the formation along with commercial quantities of oil and natural gas. Once most of the load water is pumped back a production rate can be established.
During January 2007, we re-entered the Dye Estate #1 well. Production of natural gas from the Dye Estate #1 well commenced in mid-August 2007. As of October 31, 2010, the Dye Estate #1 well has produced 6,439 Mcf of natural gas and is currently averaging natural gas production at a rate of 8 Mcf per day. Water from the Dye Estate #1 well is being disposed in the Kodesh #1 disposal well.
We commenced drilling the William #4-10 well in early June 2007, reaching a total depth of 4,810 feet in mid-June 2007. Electric and radiation logs indicated that the William #4-10 well contained four potential commercial pay zones, the Wilcox Sand, Mississippi Lime, Layton Sand and the Tonkawa Sand. Completion of the lowest zone, the Wilcox Sand, occurred in mid-August 2007. Production from the William #4-10 well started in mid-October 2007. During the first quarter of 2008, we perforated, fracture treated and tested the Mississippi Lime and the lower Layton Sand to increase the production rate of both gas and oil from the William #4-10 well and provide data regarding the potential of these formations for the remainder of the leases on the Three Sands Project. As of October 31, 2010, the William #4-10 well has produced 2,449 Bbls oil and 67,491 Mcf of gas. The well is currently producing at a rate of 1 barrel of oil per day and 107 Mcf of natural gas.
Drilling commenced on the KC 80 #1-11 well in mid-February 2008 and reached total depth of 4,720 feet by the end of February 2008. The KC 80 #1-11 has been surveyed with radiation and electrical logs. The primary target for the well is the upper Mississippian Limestone and Chat Formation. The KC-80 well’s logs indicate significant thickness of Chat and upper Mississippi Limestone with good porosity, permeability, and hydrocarbon shows.
Completion of the KC 80 #1-11 well started in late April 2008. The lowest pay zone, the Mississippian, was acidized and partially fracture treated. In early August a similar treatment was given to the Chat zone or the horizon that lies above the lowest pay zone. As of October 31, 2010, the KC 80 #1-11 well is producing at a rate of 3 Bbls of oil and 30 Mcf of natural gas daily. As of October 31, 2010, the KC 80 #1-11 has produced 5,086 Bbls of oil and 32,091 Mcf of natural gas.
Drilling commenced on the Taylor #1 well on October 7, 2010 and reached a total depth of 4,825 feet on October 14, 2010. The primary target of the well was the Mississippian Limestone. The well was fracture treated in mid-December 2010 and production testing will follow. There was no production from this well prior to October 31, 2010.
Palmetto Point Project
Location and Access. The Palmetto Point Project is located on the border of southern Mississippi and Louisiana along the floodplain of the Mississippi river. The area is approximately 20 miles west of Woodville, Mississippi and approximately 50 miles northwest of Baton Rouge, Louisiana. The wells are located in Township 2 North, Ranges 4 & 5, in West Adams and Wilkinson Counties in the state of Mississippi. The area may be accessed via Interstate 55 (approximately 100 miles south of Jackson, Mississippi) and then west via state highways. The drill locations are accessed by secondary gravel and dirt roads. Transporting natural gas to the market will be accomplished via a series of pipelines which cross the project area.
Previous Operations and History. Griffin & Griffin, the operator for the Palmetto Point Project, has over 40 years of operations history in the Palmetto Point Project area and has acquired substantial data and 3-D seismic data for the Palmetto Point Project. To date, Griffin & Griffin has drilled, owned or operated more than 100 Frio wells in the region. More specifically, Griffin & Griffin has drilled to a subsurface depth and has penetrated the sands of the Frio Formation on the Palmetto Point Project.
Geology of the Palmetto Point Project. The prospect wells were located to test the Frio Geological Formation. Frio wells typically enjoy low finding costs. Griffin & Griffin has utilized seismic “bright spot” technology, which helps to identify gas reservoirs and to delineate reservoir geometry and limits. The term “bright spot” is used to describe a geophysical amplitude anomaly, which is simply a velocity change from a higher velocity to lower velocity. Sands that contain gas are predictable by this method because the gas will provide a slower velocity response giving an abnormally intense trough-peak reflections, therefore termed a “bright spot”. The data evaluation in the Frio section gives a direct hydrocarbon indication (“HCI”) allowing one to not only see gas seismically, but also the lateral extent of each gas reservoir at various depths to include multiple horizons at some locations.
The gas targets at the Palmetto Point Project occur at shallow depths and have minimal completion costs. The Frio project in the area of Southwest Mississippi and North-Central Louisiana is a very complex series of sand representing marine transgressions and regressions and resulting in the presence of varying depositional
environments. Structurally, the Frio gas accumulations are a function of local structure and/or structural nose formed as a result of differential compaction features. However, stratigraphic termination (updip pinchout of sands within shales) also plays a role in most Frio accumulations. The stratigraphy is so complex that seismic direct HCI evaluations are presently the only viable exploratory tool for the Frio prospect.
Proposed Program of Exploration. The Palmetto Point Project program has been completed and no further exploration wells are planned. We are assessing additional development wells in the Belmont Lake oil field discovered by the PP well. The Mississippi Frio-Wilcox Joint Venture program described below is the successor to the Palmetto Point Program and will continue our exploration and development in the Frio and Wilcox projects.
Costs Including Previous Work. As of October 31, 2010, we have expended $732,630 in connection with the Palmetto Point Project, including leasing, title, drilling, and casing.
Present Activities. As of October 31, 2007, Griffin & Griffin, operator of the Palmetto Point Project, drilled all ten of the wells in the Palmetto Point Project. Eight of the wells were successful and two were dry holes which were not completed. Seven of the eight successful wells were completed and are currently producing. One of the eight wells, the PP, was completed as a flowing oil well in early October 2007. The PP well flowed oil at rates of over 100 Bbls per day and in December 2007 was offset by two additional wells in the project, the PP-2 and PP-3. The PP-2 was a dry hole and the PP was completed as a flowing oil well.
Both the PP and the PP oil well locations and several of our gas well locations were flooded at the Palmetto Point Project. Prior to the flooding, we had partly completed work to install gas lift pumps at each well; however, the work could not be completed before the locations were flooded. There was virtually no damage to our surface equipment located at the well heads, as our batteries and other production facilities were located above the flood waters. The only damage was to our lost production because the well had to be shut-in. We do not believe that the flooding will adversely affect future oil recovery from these wells.
In early September 2008, flood waters had receded sufficiently and work began on placing the PP and PP-3 back on line and producing oil. Gas lift pumps were installed on both wells and other modification and additional equipment such as compressors were also installed. At the end of October 2009 both wells were producing oil at combined rates of between 80 and 100 barrels of oil per day.
In early September 2010, flood waters had receded sufficiently again to resume work on the Palmetto Point Project and three development wells were drilled in the field. One well encountered only natural gas and was plugged and abandoned. The remaining two wells were completed as oil wells. One of the completed oil wells flowed naturally and contributed approximately 2,000 barrels of oil to the production totals prior to October 31, 2010. Present activities include completion of a source gas well, completing a salt water disposal well and running gas injection line and production line to the new wells and tanks battery. All four oil wells including both the new wells and previously drilled and completed well should be in production by the start of the second fiscal quarter.
During the three-month period ended October 31, 2010, the Belmont Lake Oil field produced 7,168 Bbls of oil and sold no natural gas.
Mississippi Frio-Wilcox Joint Venture
Location and Access. The Mississippi Frio-Wilcox Joint Venture is located on the border of southern Mississippi and Louisiana along the floodplain of the Mississippi river. The area is approximately 20 miles west of Woodville, Mississippi and approximately 50 miles northwest of Baton Rouge, Louisiana. The wells are located in Township 2 North, Ranges 4 & 5, in West Adams and Wilkinson Counties in the state of Mississippi. The area is accessible via Interstate 55 (approximately 100 miles south of Jackson, Mississippi) and then west via state highways. The drill locations are accessed by secondary gravel and dirt roads. Transporting natural gas to the market will be accomplished via a series of pipelines which cross the project area.
Previous Operations and History. As described above, we participated in the ten-well Palmetto Point Project program in the same area as the Mississippi Frio-Wilcox Joint Venture. The Mississippi Frio-Wilcox Joint
Venture is the successor to the Palmetto Point Project. Griffin & Griffin, the operator for the Palmetto Point Project, is also the operator for the Mississippi Frio-Wilcox Joint Venture. Griffin & Griffin has over 40 years of operations history in the Mississippi Frio-Wilcox Joint Venture area and has acquired substantial data and 3-D seismic for the Mississippi Frio-Wilcox Joint Venture. To date, Griffin & Griffin has drilled, owned or operated more than 100 Frio wells in the region.
Geology of the Palmetto Point Project. The prospect wells are located to test the Frio Geological Formation. The gas targets at the Mississippi Frio-Wilcox Joint Venture occur at shallow depths and have minimal completion costs. The Frio in the area of Southwest Mississippi and North-Central Louisiana is a very complex series of sand representing marine transgressions and regressions and resulting in the presence of varying depositional environments. Structurally, the Frio gas accumulations are a function of local structure and/or structural nose formed as a result of differential compaction features. However, stratigraphic termination (updip pinchout of sands within shales) also plays a role in most Frio accumulations. The stratigraphy is so complex that seismic HCI evaluations are the only viable exploratory tool for the Mississippi Frio-Wilcox Joint Venture.
Proposed Program of Exploration. On June 21, 2007, we assigned our interests and all future development obligations for any new wells in the Mississippi Frio-Wilcox Joint Venture to Lexaria for the sum of $1. We believe the assigned interest to be of nominal value. We have maintained our original interest, rights, title and benefits to all seven wells drilled with our participation at the Mississippi Frio-Wilcox Joint Venture between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC, CMR/BR, RB Red Bug #2, BR, and Randall #1, and any offset wells that could be drilled to any of these specified wells.
Costs Including Previous Work. As of October 31, 2010, we have expended $400,000 in connection with the Mississippi Frio-Wilcox Joint Venture, including leasing, title, drilling, and casing.
Present Activities. Nine wells were drilled on the Mississippi Frio-Wilcox Joint Venture, of which, five wells were initially deemed successful and four wells were dry holes and were not completed. One of the five wells initially deemed to be successful was the BR. However, subsequent testing of the BR indicated that it was not commercially viable and the well was plugged and abandoned in 2007. The four remaining successful wells were the Faust #1, USA 39-14, USA 1-37 and the BR. The USA 39-14 has been completed and is now producing natural gas. As of October 31, 2010, these four wells were shut-in natural gas wells with no production. No further exploration wells are currently planned for this project.
King City Oil Field
Effective May 25, 2009, we entered into an agreement with Sunset Exploration to explore for oil and gas on 10,000 acres located in west central California. The agreement calls for us to earn a 20% working interest in the project by funding a maximum of 50% of a $200,000 geophysical survey composed of gravity and seismic surveys and agreeing to carry Sunset Exploration for 33.33% of dry hole cost of the first well. Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each party’s working interest. The geophysical surveys have been completed and most have been processed and interpreted. The initial surveys indicated that several more short geophysical survey lines would improve the interpretation. These additional lines have been completed and subsequently several stages of reprocessing have been applied to the original data. Based on this data, two drill locations have been selected and permitting is underway. Drilling of one of these locations is anticipated in the spring of 2011.
International Exploration Program
The Company is attempting to expand its property base by locating other resource properties internationally. Accordingly, we have hired consultants to gather data on properties that may be of interest to us. The consultants on a best efforts basis will attempt to acquire option agreements, lease agreements and/or the outright purchase of oil and /or gas properties internationally. As of the date of this filing, we have not found a suitable acquisition.
Production and Prices
The following table sets forth information regarding net production of oil and natural gas, and certain price and cost information for fiscal years ended October 31, 2010, 2009 and 2008.
Productive Wells
The following table summarizes information at October 31, 2010, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, but specifically exclude wells drilled and cased during the fiscal year that have yet to be tested for completion (e.g., all of the operated wells drilled by the Company during this year have been cased in preparation for completion, but no operations have been initiated that would allow these wells to be productive). Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests in the gross wells.
Unaudited Oil and Gas Reserve Quantities
The following unaudited reserve estimates for Oklahoma, presented as of October 31, 2010, were prepared by J L. Thomas Engineering and Harper and Associates, both independent petroleum engineering firms. The unaudited reserve estimates for Mississippi and Louisiana, as of October 31, 2010, were prepared by Veazey & Associates, an independent petroleum engineering firm.
The combined estimated proved reserves prepared by J L. Thomas Engineering, Veazey and Associates and Harper and Associates are summarized in the table below, in accordance with definitions and pricing requirements as prescribed by the Securities and Exchange Commission (the “SEC”). Prices paid for oil and natural gas vary widely depending upon the quality such as the Btu content of the natural gas, gravity of the oil, sulfur content and location of the production related to the refinery or pipelines.
There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, reserve estimates of new discoveries that have little production history are more imprecise than those of properties with more production history. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.
Unaudited net quantities of proved developed and undeveloped reserves of crude oil and natural gas (all located within United States) are as follows:
Oil and Gas Acreage
The following table sets forth the undeveloped and developed acreage, by area, held by us as of October 31, 2010. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Developed acres are acres, which are spaced or assignable to productive wells. Gross acres are the total number of acres in which we have a working interest. Net acreage is obtained by multiplying gross acreage by our working interest percentage in the properties. The table does not include acreage in which we have a contractual right to acquire or to earn through drilling projects, or any other acreage for which we have not yet received leasehold assignments.
Drilling Activity
The following table sets forth our drilling activity during the years ended October 31, 2010, 2009 and 2008.
Mineral Property
Antelope Pass Project
We suspended activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties in 2005. We have not conducted any operations or exploration activities on the Antelope Pass Project since 2005. To date, we have expended $8,207 in connection with the Antelope Pass Project, including geological mapping, sampling and assaying.
Location and Access. The Antelope Pass Project is located in west central Hidalgo County, New Mexico, approximately ten miles east of the New Mexico-Arizona border. The Antelope Pass Project lies in the Peloncillo Mountains, 35 miles southwest of Lordsburg, New Mexico. The closest major air service to the property is located in Tucson, Arizona. Access to the property is from Tucson traveling east via Interstate Highway 10 for approximately 130 miles to the Animas, New Mexico exit. From that exit, travel is south 20 miles on State Highway 338 to the town of Animas and then west for seven miles via State Highway 9. The property can be reached on gravel roads and dirt tracks.
The property is comprised of low hills and alluvial valleys, with elevations ranging from a low of 4,480 feet to a high of 4,580 feet. Vegetation is sparse and includes desert grasses, cacti, and creosote bushes. The Antelope Pass Project consists of eight unpatented lode mining claims totaling 160 acres, situated in Township 27 South, Range 20 West, Sections 18 and 19 and Township 27 South, Range 21 West, Sections 13 and 24. A lode is a mineral deposit in consolidated rock as opposed to a placer deposit, which is a deposit of sand or gravel that contains particles of gold, ilmenite, gemstones, or other heavy minerals of value.
The claims are located on federal lands under the administration of the Bureau of Land Management (BLM). They are not subject to any royalties, but annual maintenance fees must be paid to the BLM of $125 per claim or a total of $1,000 for the entire claim block to keep them valid. Including federal and county filing fees, an expenditure of approximately $125 per claim for total payment of $1,000 per year for the entire claim block is required to keep the claims valid.
Under the General Mining Law of 1872, which governs our mining claims and leases, we, as the holder of the claim, have the right to develop the minerals located in the land identified in the claim. We must pay an annual maintenance fee of $125 per claim to hold the claim. Claims can be held indefinitely with or without mineral production, subject to challenge if not developed. Using land under an unpatented mining claim for anything but mineral and associated purposes violates the General Mining Law of 1872.
Office Space
We are using the offices of Leroy Halterman, our president. These offices are located at 820 Piedra Vista Road NE, Albuquerque, New Mexico 87123. We reimburse Mr. Halterman for the use of this space.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
None.
ITEM 4.
ITEM 4. (Removed and Reserved).
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Our common stock has been listed for quotation on the OTC Bulletin Board since July 27, 2004 under the symbol “BNXR”. The following table sets forth the range of high and low bid quotations for each fiscal quarter of the last two fiscal years. These quotations reflect inter-dealer prices without retail mark-up, markdown, or commissions and may not necessarily represent actual transactions.
As of December 31, 2010, there were 34 record holders of our common stock. The closing bid price of our stock on January 28, 2011 was $0.11.
Since our inception, no cash dividends have been declared on our common stock.
We had no sales of unregistered securities during the quarter ended October 31, 2010.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
Not required for smaller reporting companies.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Our original business plan was to proceed with the exploration of the Antelope Pass Project to determine whether there were commercially exploitable reserves of gold located on the property comprising the mineral claims. Based on the geological report and recommendation prepared by Leroy Halterman, who was our geological consultant at that time, we completed geological mapping, sampling and assaying in connection with the first phase of a staged exploration program during the fiscal year ended October 31, 2004. In 2005, we suspended our activities on the Antelope Pass Project indefinitely in order to focus on our oil and gas properties and we did not conduct any operations or exploration activities on the Antelope Pass Project during the fiscal years ended October 31, 2010 or 2009. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.
Our present plan of operation is to continue our exploration and production activities on our oil and gas properties. We anticipate that we will incur the following expenses over the next twelve months in connection with our oil and gas properties:
§
$620,000 to $1,120,000 in connection with our oil and gas properties to include seismic acquisitions, lease and associated broker costs, drilling, completing and equipping new wells and for costs associated with production;
§
$900,000 for operating expenses, including professional, legal, investor relations and accounting expenses associated with our being a reporting issuer under the Securities Exchange Act of 1934.
Accordingly, we anticipate spending approximately $1,520,000 to $2,020,000 over the next twelve months in pursuing our stated plan of operations. The Company expects currently producing and new wells to come online, generating sufficient cash to offset any increase in expenses.
Critical Accounting Policies
Oil and Gas Interests. We utilize the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas interests is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production. Amortizable costs include estimates of future development costs of proved undeveloped reserves.
Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying average prices calculated on a simple average from the first day in the trailing 12 months, of oil and gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.
Asset Retirement Obligations. We follow FASB ASC 410-20 “Accounting for Asset Retirement Obligations”. FASB ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. FASB ASC 410-20 requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of October 31, 2010 and 2009, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with FASB ASC 410-20. The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. We amortize the amount added to the oil and gas properties and recognize accretion expense in connection with the discounted liability over the remaining life of the respective wells. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%. Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.
The information below reflects the change in the asset retirement obligations during the years ended October 31, 2010 and 2009:
The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; the Palmetto Point Project well at the Frio-Wilcox Project; and ARD #1-36, Bagwell #1-20, Jackson #1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis #1-8, Gehrke #1-24, Jack #1-13 and Miss Jenny #1-8 wells at the Oklahoma Properties. The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes to the applicable laws and regulations. Such changes will be recorded in our accounts as they occur.
Reserve Estimates. Our estimates of oil and natural gas reserves are projections based on an interpretation of geological and engineering data. 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. Estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on the risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Results of Operations
We realized revenues of $657,929 from natural gas and oil sales during the fiscal year ended October 31, 2010, compared with $398,274 during the fiscal year ended October 31, 2009, an increase of $259,655 due primarily to an increase in the number of producing wells and an increase in commodity prices. In 2010, we sold 17,574 Mcf of natural gas and 8,213 Bbls of oil, and in 2009, we sold approximately 18,597 Mcf of natural gas and 6,461 Bbls of oil. Our natural gas volumes decreased by 10%, while our oil sales increased by 27%. The average price received for our natural gas sales in 2010 was $4.85 per Mcf, versus $2.90 per Mcf in 2009, representing an increase of $1.95 or 67%. The average price received for our crude oil sales in 2010 was $65.66 per Bbl, versus $51.41 per Bbl in 2009, representing an increase of $14.25 or 28%.
For the fiscal year ended October 31, 2010, we incurred a net loss of $550,296, compared with a net loss of $377,866 for the fiscal year ended October 31, 2009 (an increase in net loss of $172,430).
We incurred direct costs of $1,210,140 for the fiscal year ended October 31, 2010, compared with $1,024,206 for the fiscal year ended October 31, 2009, an increase of $185,934. The increase in our direct costs was largely attributable to an increase in our general and administrative costs. Our general and administrative costs increased to $893,795 for the fiscal year ended October 31, 2010, from $720,391 for the fiscal year ended October 31, 2009. The increase in our general and administrative costs was attributable to an increase in fees for consulting and investor relations services and increases in management fees and costs of administration services.
Our depletion and accretion costs increased from $190,046 during the fiscal year ended October 31, 2009 to $220,078 for the fiscal year ended October 31, 2010, an increase of $30,032. Depletion is calculated based on production rates produced during the year. Our depletion and accretion costs increased as a result of an increase in our oil and gas producing wells.
Our production costs decreased from $113,769 for the fiscal year ended October 31, 2009 to $96,267 for the fiscal year ended October 31, 2010, a decrease of $17,502.
Liquidity and Capital Resources
As of October 31, 2010, we had cash and short term investments of $821,029 and working capital of $1,060,231, compared to cash of $1,947,950 and working capital of $2,494,387 as of October 31, 2009. We had sold our interest in our Owl Creek Project in fiscal 2008, resulting in cash of $3,617,109 as of October 31, 2008.
During the fiscal year ended October 31, 2010, net cash provided by operating activities was $43,183, compared to cash of $1,000,714 used in operating activities for the fiscal year ended October 31, 2009.
Net cash used in investing activities during the fiscal year ended October 31, 2010 was $1,970,104, compared with $668,446 used during the fiscal year ended October 31, 2009. We used $1,170,104 in cash for our oil and gas interests compared to $668,446 during the previous year; we invested $800,000 in a certificate of deposit with the Company’s bank.
No cash was provided by or used in financing activities during the fiscal years ended October 31, 2010 and 2009.
Recent Accounting Pronouncements
In January 2010, the FASB issued Accounting Standards Update 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. The ASU amends Subtopic 820-10 with new disclosure requirements and clarification of existing disclosure requirements. New disclosures required include the amount of significant transfers in and out of levels 1 and 2 fair value measurements and the reasons for the transfers. In addition, the reconciliation for level 3 activity will be required on a gross rather than net basis. The ASU provides additional guidance related to the level of disaggregation in determining classes of assets and liabilities and disclosures about inputs and valuation techniques. The amendments are effective for annual or interim reporting periods beginning after December 15, 2009, except for the requirement to provide the reconciliation for level 3 activities on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The Company is currently assessing the impact of ASU 2010-06 and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements as of October 31, 2010.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not required for smaller reporting companies.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Brinx Resources, Ltd.
We have audited the accompanying balance sheet of Brinx Resources, Ltd. as of October 31, 2010 and the related statements of operations, stockholders’ equity and, cash flows for the period ended October 31, 2010. Brinx Resources, Ltd.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Brinx Resources, Ltd. as of October 31, 2010, and the results of its operations and its cash flows for the period ended October 31, 2010 in conformity with accounting principles generally accepted in the United States of America.
/s/ Mark Bailey & Company, Ltd.
Mark Bailey & Company, Ltd.
Reno, Nevada
February 2, 2011
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Brinx Resources Ltd.
Albuquerque, New Mexico
We have audited the accompanying balance sheets of Brinx Resources Ltd. (the “company”) as of October 31, 2009 and 2008 and the related statements of operations, stockholders' equity (deficit) and cash flows for 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 audit in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal controls over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 Brinx Resources Ltd. as of October 31, 2009 and 2008 and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ Chisholm, Bierwolf, Nilson & Morrill, LLC
Chisholm, Bierwolf, Nilson & Morrill, LLC
Bountiful, Utah
January 28, 2010
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Brinx Resources Ltd. (the “Company”) was incorporated under the laws of the State of Nevada on December 23, 1998, and issued its initial common stock in February 2001. The Company holds undeveloped mineral interests located in New Mexico and holds oil and gas interests located in Oklahoma, California, Mississippi and Louisiana. In 2006, the Company commenced oil and gas production and started earning revenues.
USE OF ESTIMATES
The preparation of 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 reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which the Company may be currently liable. In addition, the Company’s oil and gas business makes it vulnerable to changes in prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated reserves. Price declines reduce the estimated quantity of proved reserves and increase annual depletion expense (which is based on proved reserves).
OIL AND GAS INTERESTS
The Company utilizes the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration; are capitalized within a cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas interests unless the sale represents a significant portion of oil and gas interests and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas interests is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production. Amortizable costs include estimates of future development costs of proved undeveloped reserves.
Capitalized costs of oil and gas interests may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved interests. Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying average prices of oil and gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.
REVENUE RECOGNITION
Revenue from sales of crude oil, natural gas and refined petroleum products are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customers. Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred. Revenues from the production of oil and natural gas properties in which the Company shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Gas imbalances occur when the Company’s actual sales differ from its entitlement under existing working interests. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that the partners can recoup their share of production from the field. At October 31, 2010 and 2009, the Company had no overproduced imbalances.
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
1.
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
ACCOUNTS RECEIVABLE
Accounts receivable are carried at net receivable amounts less an estimate for doubtful accounts. Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering a customer’s financial condition, credit history, and current economic conditions. Trade receivables are written off when deemed uncollectible. Recoveries of receivables previously written off are recorded when received.
IMPAIRMENT OF LONG-LIVED ASSETS
The Company has adopted FASB ASC 360 (prior authoritative literature: SFAS No. 144) "Accounting for the Impairment or Disposal of Long-Lived Assets", which requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and gas interests accounted for under the full cost method are subject to a ceiling test, described above, and are excluded from this requirement.
ASSET RETIREMENT OBLIGATIONS
The Company follows FASB ASC 410-20 (prior authoritative literature: SFAS No. 143) "Accounting for Asset Retirement Obligations", that addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
FASB ASC 410-20 requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount.
Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. The Company's asset retirement obligations are related to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and gas exploration activities.
INCOME / (LOSS) PER SHARE
Basic income/(loss) per share is computed based on the weighted average number of common shares outstanding during each period. The computation of diluted earnings per share assumes the conversion, exercise or contingent issuance of securities only when such conversion, exercise or issuance would have the dilutive effect on income/(loss) per share. The dilutive effect of convertible securities is reflected in diluted earnings per share by application of the "as if converted method." The dilutive effect of outstanding options and warrants and their equivalents is reflected in diluted earnings per share by application of the treasury stock method. Hence 500,000 options were excluded from the earnings per share calculation for the year ended October 31, 2010, since they were considered to be anti-dilutive. The table below presents the computation of basic and diluted earnings per share for the year ended October 31, 2010 and 2009:
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
INCOME / (LOSS) PER SHARE (continued)
The calculation for earnings per share excluded 500,000 stock options and 400,000 stock options as these were not in the money as at October 31, 2010 and 2009, respectively.
INCOME TAXES
Deferred tax assets and liabilities are recognized for temporary differences between the financial reporting and tax bases of the firm’s assets and liabilities. Valuation allowances are established to reduce deferred tax assets to the amount that more likely than not will be realized. The firm’s tax assets and liabilities are presented as a component of “Other assets” and “Other liabilities and accrued expenses,” respectively, in the consolidated statements of financial condition. Tax provisions are computed in accordance with FASB ASC 740 (prior authoritative literature: SFAS No. 109), “Accounting for Income Taxes”.
The firm adopted the provisions of FASB ASC 740-10 “Accounting for Uncertainty in Income Taxes - an Interpretation”, as of December 1, 2007. A tax position can be recognized in the financial statements only when it is more likely than not that the position will be sustained upon examination by the relevant taxing authority based on the technical merits of the position. A position that meets this standard is measured at the largest amount of benefit that will more likely than not be realized upon settlement. A liability is established for differences between positions taken in a tax return and amounts recognized in the financial statements. FASB ASC 740-10 also provides guidance on derecognition, classification, interim period accounting and accounting for interest and penalties. Prior to the adoption of this policy, contingent liabilities related to income taxes were recorded when the criteria for loss recognition had been met.
CASH EQUIVALENTS
For purposes of reporting cash flows, the Company considers as cash equivalents all highly liquid investments with a maturity of three months or less at the time of purchase. On occasion, the Company may have cash balances in excess of federally insured amounts.
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
FAIR VALUE
On January 1, 2008, the Company adopted FASB ASC 820-10-50, “Fair Value Measurements”. This guidance defines fair value, establishes a three-level valuation hierarchy for disclosures of fair value measurement and enhances disclosure requirements for fair value measures. The three levels are defined as follows:
Level 1 inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 inputs to valuation methodology are unobservable and significant to the fair measurement.
The carrying amounts reported in the balance sheets for the cash and cash equivalents, investments in certificates of deposits, receivables and current liabilities each qualify as financial instruments and are a reasonable estimate of fair value because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.
CONCENTRATION OF CREDIT RISK
Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, investments in certificates of deposit and accounts receivable. The Company maintains cash at one financial institution. The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. The Company believes credit risk associated with cash and cash equivalents to be minimal.
The Company has recorded trade accounts receivable from the business operations. Management periodically evaluates the collectability of the trade receivables and believes that the Company’s receivables are fully collectable and that the risk of loss is minimal.
EQUITY BASED COMPENSATION
Effective November 1, 2006, the Company adopted the fair value recognition provisions of FASB ASC 718 (prior authoritative literature: SFAS No. 123R) “Share Based Payment” using the modified prospective method as described in “Accounting for Stock-Based Compensation - Transition and Disclosure”, as prescribed by the United States Securities and Exchange Commission (“SEC”).
The fair value of each option granted has been estimated as of the date of the grant using the Black-Scholes option pricing model with the following assumptions:
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
RECENT ACCOUNTING PRONOUNCEMENTS
In January 2010, the FASB issued Accounting Standards Update 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. The ASU amends Subtopic 820-10 with new disclosure requirements and clarification of existing disclosure requirements. New disclosures required include the amount of significant transfers in and out of levels 1 and 2 fair value measurements and the reasons for the transfers. In addition, the reconciliation for level 3 activity will be required on a gross rather than net basis. The ASU provides additional guidance related to the level of disaggregation in determining classes of assets and liabilities and disclosures about inputs and valuation techniques. The amendments are effective for annual or interim reporting periods beginning after December 15, 2009, except for the requirement to provide the reconciliation for level 3 activities on a gross basis, which will be effective for fiscal years beginning after December 15, 2010. The Company is currently assessing the impact of ASU 2010-06 and does not expect the adoption of this guidance to have a material impact on its consolidated financial statements.
2. ACCOUNTS RECEIVABLE
Accounts receivable consists of revenues receivable from the operators of the oil and gas projects for the sale of oil and gas by the operators on our behalf and are carried at net receivable amounts less an estimate for doubtful accounts. Management considers all accounts receivable to be fully collectible at October 31, 2010 and October 31, 2009. Accordingly, no allowance for doubtful accounts or bad debt expense has been recorded.
3.
OIL AND GAS INTERESTS
The Company holds the following oil and natural gas interests:
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
3.
OIL AND GAS INTERESTS (continued)
2008-3 Drilling Program, Oklahoma
On January 12, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2008-3 Drilling Program for a total buy-in cost of $28,581. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The Before Casing Point Interest “BCP” shall be 6.25% and the After Casing Point Interest “ACP” shall be 5.00%. During January to July 2009, the Company expended a $213,925 in addition to $18,850 that was spent in previous periods. The well, Wigley#1-11, was abandoned during March 2009. The cost and its buy-in cost total of $33,423 were moved to the proved properties. Selman#1-21 and Bagwell#1-20 started producing during May 2009, the cost and its buy-in cost total of $67,707 for Selman#1-21 and $57,921 for Bagwell#1-20 were moved to the proved properties. Ard#1-36 started producing during June 2009 and the cost and its buy-in cost total of $42,647 was moved to the proved properties. Selman#2-21 started producing during July 2009 and was abandoned on April 20, 2010; the cost and its buy-in cost total of $57,483 were moved to the proved properties pool. The total cost of the 2008-3 Drilling Program as at October 31, 2010 was $257,564. The interests are located in Garvin County, Oklahoma.
2009-2 Drilling Program, Oklahoma
On June 19, 2009, the Company acquired a 5% working interest in the Ranken Energy Corporation’s 2009-2 Drilling Program for a total buy-in cost of $26,562. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The well, James#1-18, was abandoned on September 21, 2009. The cost and its buy-in cost total of $41,934 were moved to the proved properties. Little Chief#1-3 was abandoned on November 17, 2009; the cost and its buy-in cost total of $35,528 were moved to the proved properties. J.C. Carlton#1-31 was abandoned on April 30, 2010; the cost and its buy-in cost total of $38,630 were moved to the proved properties. As at October 31, 2010, the total cost of the 2009-2 Drilling Program was $115,582. The interests are located in Garvin County, Oklahoma.
2009-3 Drilling Program, Oklahoma
On August 12, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-3 Drilling Program for a total buy-in cost of $37,775. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Jackson#1-18 started producing during January 2010; an amount of $63,725 which included the buy-in cost was moved to the proved property pool. Miss Gracie#1-18 started producing during March 2010; an amount of $62,268 which included its buy-in cost was moved to the proved property pool. Brewer#1-20 was abandoned on June 2, 2010; the cost and its buy-in cost total of $64,936 were moved to the proved properties. Waunice#1-36 started producing during June 2010; an amount of $43,848 which included its buy-in cost was moved to the proved property pool, it was abandoned on September 23, 2010. As at October 31, 2010, the total cost of the 2009-3 Drilling Program was $294,164. The interests are located in Garvin County, Oklahoma.
2009-4 Drilling Program, Oklahoma
On December 19, 2009, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2009-4 Drilling Program for a total buy-in cost of $13,482. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Dennis#1-8 started producing during May 2010; an amount of $79,892 which included the buy-in cost was moved to the proved property pool, it was abandoned on September 27, 2010. As at October 31, 2010, the total cost of the 2009-4 Drilling Program was $172,530. The interests are located in Garvin County, Oklahoma.
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
3.
OIL AND GAS INTERESTS (continued)
2010-1 Drilling Program, Oklahoma
On April 23, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s 2010-1 Drilling Program for a total buy-in cost of $39,162.50. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. Julie#1-14 was abandoned on October 2, 2010; the cost and its buy-in cost total of $47,035 were moved to the proved properties. The estimated completion cost of $16,860 for Jack 1-13 was accrued for the year ended October 31, 2010. As at October 31, 2010, the total cost of the 2010-1 Drilling Program was $232,212. The interests are located in Garvin County, Oklahoma.
Washita Bend 3D Exploration Project, Oklahoma
On March 1, 2010, the Company acquired a 5.00% working interest in Ranken Energy Corporation’s Washita Bend 3D Exploration Project for a buy-in cost of $46,250. As at October 31, 2010, the total costs, including seismic costs was $337,398.
King City Prospect, California
A Farmout agreement was made effective on May 25, 2009 between the Company and Sunset Exploration, Inc., to explore for oil and natural gas on 10,000 acres located in west central California. The Company paid $100,000 (50% pro rata share of $200,000) to earn a 20% working interest in the project by funding a maximum of 50% of a $200,000 in a geophysical survey composed of gravity and seismic surveys and carry Sunset exploration for 33.33% of dry hole cost of the first well. Completions and drilling of this first well and completion of subsequent wells on the 10,000 acres will be proportionate to each parties working interest.
Three Sands Project, Oklahoma
On October 6, 2005, the Company acquired a 40% working interest in Vector Exploration Inc’s Three Sands Project for a total buy-in cost of $88,000 plus dry hole costs. For the year ended October 31, 2006, the Company expended $530,081 in exploration costs. In June 2007, the Company acquired a 40% working interest in William #4-10 well for a total cost of $285,196 and paid a further $17,000 in costs relating to the well. On March 19, 2008, the Company participated in the KC 80#1-11 well and paid $75,000 for the prepaid drilling costs. During March and April 2008, the Company expended an additional amount of $48,763 for the intangible and tangible costs, and $161,650 during May to July 2008 for the KC 80#1-11 well. The total cost of the Three Sands Project as at October 31, 2010 was $1,279,633. The interests are located in Oklahoma.
South Wayne Prospect, Oklahoma
On March 14, 2010, the Company acquired a 5.00% working interest in McPherson#1-1 well for a payment for leasehold, prospect and geophysical fees of $5,000, and dry hole costs of $32,370. The total costs, including drilling costs as at October 31, 2010 was $60,914. The Company agreed to participate in the drilling operations to casing point in the initial test well of each prospect. The BCP Interest shall be 6.25% and the ACP Interest shall be 5.00%. The interests are located in McClain County, Oklahoma.
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
3. OIL AND GAS INTERESTS (continued)
Palmetto Point Project, Mississippi
On February 28, 2006, the Company acquired a 10% working interest before production and 8.5% revenue interest after production in a 10 well program at Griffin & Griffin Exploration Inc.’s Palmetto Point Project for a total buy-in cost of $350,000. On September 26, 2006, the Company acquired an additional two wells within this program for $70,000. On October 1, 2007, the Company acquired a 10% working interest and participated in drilling two more wells within the Palmetto Point Project, the (PP-2 and PP-3 wells), at a cost of $69,862. On October 25, 2007, the Company paid $17,000 for a sidetrack, a deviation of the existing PP-F-12-3 well at an angle to reach additional targeted oil sands.
On January 30, 2008, the Company incurred $36,498 for work-overs to install submersible pumps. From November 2008 to July 2009, the Company incurred $44,623 for Belmont Lake Project. The total cost of the Palmetto Point Project, which included costs for the PP-2, PP-3, PP-4 and PP wells, were $732,630 as of October 31, 2010. The interests are located in Mississippi.
Frio-Wilcox Project, Mississippi
On August 2, 2006, the Company signed a memorandum agreement with Griffin & Griffin LLC (the “Operator”) to participate in two proposed drilling programs located in Mississippi and Louisiana. The Company acquired a 10% working interest in this project before production and a prorated reduced working interest after production based on the Operator’s interest portion. The Company paid $400,000 for the interest.
On June 21, 2007, the Company assigned all future development obligations for any new well at its Frio-Wilcox Prospect to a third party. The Company maintained its original interest, rights, title and benefits to all seven wells drilled with the Company’s participation at the Frio-Wilcox Prospect property between August 3, 2006 and June 19, 2007, specifically wells CMR-USA-39-14, Dixon #1, Faust #1 TEC, CMR/BR, RB Red Bug #2, BR, and Randall #1, and any offset wells that could be drilled to any of these specified wells.
Impairment
Under the full cost method, the Company is subject to a ceiling test. This ceiling test determines whether there is an impairment to the proved properties. The impairment amount represents the excess of capitalized costs over the present value, discounted at 10%, of the estimated future net cash flows from the proven oil and gas reserves plus the cost, or estimated fair market value. There was no impairment cost for the year ended October 31, 2010 or 2009, respectively.
Depletion
Under the full cost method, depletion is computed on the units of production method based on proved reserves, or upon reasonable estimates where proved reserves have not yet been established due to the recent commencement of production. Depletion expense recognized was $215,638 and $186,354 for the year ended October 31, 2010 and 2009, respectively.
Capitalized Costs
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
3. OIL AND GAS INTERESTS (continued)
Results of Operations
Results of operations for oil and gas producing activities during the years ended are as follows:
4. ASSET RETIREMENT OBLIGATIONS
The Company follows FASB ASC 410-20 “Accounting for Asset Retirement Obligations” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This policy requires recognition of the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. As of October 31, 2010 and October 31, 2009, we recognized the future cost to plug and abandon the gas wells over the estimated useful lives of the wells in accordance with “Accounting for Asset Retirement Obligations”. The liability for the fair value of an asset retirement obligation with a corresponding increase in the carrying value of the related long-lived asset is recorded at the time a well is completed and ready for production. The Company amortizes the amount added to the oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining life of the respective well. The estimated liability is based on historical experience in plugging and abandoning wells, estimated useful lives based on engineering studies, external estimates as to the cost to plug and abandon wells in the future and federal and state regulatory requirements. The liability is a discounted liability using a credit-adjusted risk-free rate of 12%.
Revisions to the liability could occur due to changes in plugging and abandonment costs, well useful lives or if federal or state regulators enact new guidance on the plugging and abandonment of wells.
The Company amortizes the amount added to oil and gas properties and recognizes accretion expense in connection with the discounted liability over the remaining useful lives of the respective wells.
The information below reflects the change in the asset retirement obligations during the years ended October 31, 2010 and the year ended October 31, 2009:
The reclamation obligation relates to the Kodesh, Dye Estate, KC 80 and William wells at the Three Sands Property; the Palmetto Point Project well at the Frio-Wilcox Project; and ARD#1-36, Bagwell#1-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Dennis#2-8, Gehrke#1-24, Jack#1-13 and Miss Jenny#1-8 wells at Oklahoma Properties. The present value of the reclamation liability may be subject to change based on management’s current estimates, changes in remediation technology or changes in applicable laws and regulations. Such changes will be recorded in the accounts of the Company as they occur.
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
5.
COMMON STOCK
The Company entered into the agreement for corporate development services for consideration of 100,000 restricted common shares of the Company and two payments of $4,000 which were paid during the three months ended January 31, 2010. The shares were issued on February 1, 2010 with a cost of $27,000.
STOCK OPTIONS
Although the Company does not have a formal stock option plan, all options granted in the past have been approved by the Board of Directors.
On November 2, 2007, the Company granted a non-qualified stock option with respect to 200,000 shares to the President. The exercise price is $0.24 per share. The Option expired on November 2, 2009.
On October 30, 2009, the Company granted a non-qualified stock option with respect to 200,000 shares to the CFO. The exercise price is $0.10 per share. The options will fully vest in six months and expire in two years from the Grant Date. The Company recorded a total of $15,585 and $136 in stock compensation expenses for the years ended October 31, 2010 and 2009.
On November 2, 2009, the Company granted a non-qualified stock option with respect to 300,000 shares to the President. The exercise price is $0.10 per share. The options will fully vest in six months and expire in two years from the Grant Date. The Company recorded a total of $23,581 for stock compensation expenses for the year ended October 31, 2010.
A summary of the changes in stock options for year ended October 31, 2010 is presented below:
The Company has the following options outstanding and exercisable.
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
6.
RELATED PARTY TRANSACTIONS
During the years ended October 31, 2010 and 2009, the Company entered into the following transactions with related parties:
a)
The Company paid $60,000 (2009 - $60,000) in management fees and reimbursement of office space of $4,800 (2009 - $4,800) to the President of the Company.
b)
The Company paid $60,000 (2009 - $60,500) to a related entity, for administration services, and $nil (2009 - $ 96,500) for consulting.
c)
The Company paid $90,000 (2009 - $102,000) in management fees to the director of the Company.
d)
The Company paid $72,068 (2009 - $nil) in consulting and accounting fees to the Chief Financial Officer of the Company.
7.
INCOME TAXES
Income tax expense (benefit) for the years ended October 31, 2010 and for the year ended October 31, 2009 consists of the following:
The effective income tax rate for years ended October 31, 2010 and the year ended October 31, 2009 differs from the U.S. Federal statutory income tax rate due to the following:
The components of the deferred tax assets and liabilities as of October 31, 2010 and as of October 31, 2009 are as follows:
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
7.
INCOME TAXES (continued)
The Company has approximately $550,000 net operating loss carry forward as of October 31, 2010 which will expire on October 31, 2030. Subsequent to the 10-K filing for the fiscal year ended October 31, 2009 we filed our tax returns which included carrying back all net operating losses previously reported in order to offset tax gains recognized in fiscal 2008.
The Company believes that all of its positions taken in tax filings are more likely than not to be sustained upon examination by tax authorities.
8.
UNAUDITED OIL AND GAS RESERVE QUANTITIES
The following unaudited reserve estimates presented as of October 31, 2010 and 2009 were prepared by independent petroleum engineers. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, reserve estimates of new discoveries that have little production history are more imprecise than those of properties with more production history. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., process and costs as of the date the estimate is made. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.
Unaudited net quantities of proved developed reserves of crude oil and natural gas (all located within United States) are as follows:
BRINX RESOURCES LTD.
NOTES TO FINANCIAL STATEMENTS
8.
UNAUDITED OIL AND GAS RESERVE QUANTITIES (continued)
The following information has been developed utilizing procedures prescribed by FASB ASC 932-235-55, "Disclosures About Oil and Gas Producing Activities", and based on crude oil and natural gas reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
Future cash inflows were computed by applying average price calculated using a simple arithmetic average of the prices as of the first day of the trailing twelve months of oil and gas to the estimated future production of proved oil and gas reserves. The future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved oil and gas reserves and the tax basis of proved oil and gas properties and available net operating loss carry-forwards. Discounting the future net cash inflows at 10% is a method to measure the impact of the time value of money.
UNAUDITED STANDARIZED MEASURE
The following presents the principal sources of the changes in the standardized measure of discounted future net cash flows.
9. MAJOR CUSTOMERS
We collected $451,359 (2009: $171,418) or 69% of our revenues from one of our operators during the year ended October 31, 2010. As of October 31, 2010, $102,122 was due from this operator.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
On September 1, 2010, we accepted the resignation of Chisholm, Bierwolf, Nilson & Morrill, LLC (“Chisholm”), our independent public accountants, who chose to not stand for re-election as the auditors of record. Chisholm had audited our financial statements for the fiscal years ended October 31, 2008 and October 31, 2009. Also on September 1, 2010, we engaged Mark Bailey & Company, Ltd. (“Mark Bailey”) to serve as our independent public accountants for the fiscal year ending October 31, 2010. Our board of directors approved both actions.
The reports of Chisholm on our consolidated financial statements for the two most recent fiscal years ended October 31, 2009 and 2008, did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles.
During the fiscal years ended October 31, 2009 and 2008 and through the subsequent interim period ending September 1, 2010, there were no disagreements with Chisholm on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Chisholm, would have caused Chisholm to make reference thereto in its report on our financial statements for such years. Further, there were no reportable events as described in Item 304(a)(1)(v) of Regulation S-K occurring within our two most recent fiscal years and the subsequent interim period ending September 1, 2010.
We provided Chisholm with a copy of our Form 8-K disclosing this event and requested Chisholm to furnish a letter addressed to the Commission stating whether it agreed with the above statements. A copy of that letter, dated September 8, 2010, was filed as Exhibit 16.1 to the Form 8-K on September 9, 2010.
During our fiscal years ended October 31, 2009 and 2008 and through September 1, 2010, the period prior to the engagement of Mark Bailey, neither we nor anyone on our behalf consulted Mark Bailey regarding the application of accounting principles to a specific completed or contemplated transaction, or the type of audit opinion that might be rendered on our financial statements. Further, Mark Bailey did not provide written or oral advice to us that was an important factor considered by us in reaching a decision as to any accounting, auditing or financial reporting issues.
We requested that Mark Bailey review our disclosure on Form 8-K and provided Mark Bailey with the opportunity to furnish a letter addressed to the SEC containing any new information, clarification of our reviews, or the respects in which it did not agree with the statements in the Form 8-K. Mark Bailey advised that it reviewed the Form 8-K and had no need to submit a letter in accordance with Item 304 of Regulation S-K.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures, as defined in Rule 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”), are our controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Act is accumulated and communicated to our officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Rule 15d-15 under the Exchange Act, requires us to carry out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of October 31, 2010, being the date of our most recently completed fiscal year end. This evaluation was conducted under the supervision and with the participation of our officers, Leroy Halterman and Kulwant Sandher. Based on this evaluation, Messrs. Halterman and Sandher concluded that the design and operation of our disclosure controls and procedures were effective.
As of October 31, 2009, the following material weaknesses existed:
·
We relied on external consultants for the preparation of our financial statements and reports. As a result, it was possible that our officers were not able to identify errors and irregularities in the financial statements and reports.
·
We had an officer who was also a director. Our board of directors consisted of only two members. Therefore, there was an inherent lack of segregation of duties and a limited independent governing board.
·
We relied on an external consultant for administration functions, some of which do not have standard procedures in place for formal review by our officers.
On October 30, 2009, we appointed Kulwant Sandher to serve as our Chief Financial Officer. As a result of this action, we no longer relied on external consultants for the preparation of our financial statements and reports. While Mr. Halterman continues to serve as both an officer and director, adding Mr. Sandher as another officer resulted in greater segregation of duties. We continue to rely on an external consultant for administration functions; however such functions are now reviewed by Mr. Sandher.
Management’s Annual Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 15d-15(f) under the Exchange Act. Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our officers have assessed the effectiveness of our internal controls over financial reporting as of October 31, 2010. In making this assessment, management used the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment using those criteria, management believes that, as of October 31, 2010, our internal controls are not effective as there is a reasonable possibility that a material misstatement of the Company’s financial statements may not be prevented or detected on a timely basis. This is due to the size of the Company and the fact that we have only one financial expert on our management team and no audit committee. Management believes that the material weakness set forth above does not have an effect on our financial statements.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to an exemption for smaller reporting companies under Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
Changes In Internal Controls Over Financial Reporting
There have been no changes in our internal controls over financial reporting during the quarter ended October 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We note, however, the changes described above that took place beginning October 30, 2009.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information about our executive officers and directors follows:
Our Bylaws provide for a board of directors ranging from 1 to 12 members, with the exact number to be specified by the board. All directors hold office until the next annual meeting of the stockholders following their election and until their successors have been elected and qualified. The board of directors appoints officers. Officers hold office until the next annual meeting of our board of directors following their appointment and until their successors have been appointed and qualified.
Set forth below is a brief description of the recent employment and business experience of our directors and executive officers:
Leroy Halterman was appointed as a director and as our sole officer at the time on August 9, 2005. Mr. Halterman has 40 years of geology experience. From 1999 to 2004, Mr. Halterman served as vice president of Tecumseh Professional Associates, a private environmental, facility management, government consultant and natural resource firm based in Albuquerque, New Mexico. During this period he directed the company’s oil, gas and natural resource consulting and investments. Mr. Halterman served as principal in charge of maintenance and security for two U.S. Army Ammunition Plants. Additionally, he directed Tecumseh’s efforts in over thirty mineral project appraisals and evaluations. Since 2004, Mr. Halterman has been working as a consultant in the fields of oil and gas, precious and base metals, and aggregated resources. Since 1993, Mr. Halterman has been president and a director of Consolidated North American Resources, a private natural resource investment firm located in Las Vegas, Nevada. Mr. Halterman is a graduate of the Missouri School of Mines with a BS degree in Geology. He is registered as a geologist in Wyoming. During the past five years, Mr. Halterman has not served as an officer or director of any company, other than as described in this paragraph.
Kenneth A. Cabianca was our sole officer and director from our inception in December 1998 until August 9, 2005. On August 9, 2005, Mr. Cabianca resigned as our president but he remains a director. Since 1983, Mr. Cabianca has been an independent businessman and a management consultant of various companies. Many of his activities have been conducted through his company, Wellington Financial Corporation. His experience includes raising venture capital, general management, and public relations. From August 1991 to September 1999, Mr. Cabianca was a director and president of Primo Resources International Inc., a mining company whose stock trades on the CDNX. While he served as president Primo Resources engaged in joint ventures projects with Mitsubishi Corp., Mitsubishi Materials Corp., and Golden Peaks Resources Ltd. He served as a director of Primo Resources International again from October 2001 to November 2002. Mr. Cabianca received a D.D.S. degree and practiced dentistry in Vancouver, British Columbia from 1965 to 1986. He also received a Bachelor of Science degree from Creighton University in 1965. During the past five years, Mr. Cabianca has not served as an officer or director of any company, other than as described in this paragraph.
Kulwant Sandher was appointed on October 30, 2009 our Chief Financial Officer. He has been the Chief Financial Officer and a director of Delta Oil & Gas, Inc., a publicly-traded company since January 2007. Mr. Sandher was appointed as President and Chief Financial Officer of Turner Valley Oil & Gas Inc., a publicly-traded company, on August 2004 and continues in serve in these positions. Mr. Sandher is a Chartered Accountant in both England and Canadian jurisdictions. From April 2006 to October 2008, Mr. Sandher acted as Chief Financial Officer and as a member of the board of directors of The Stallion Group. From May 2004 to March 2006, Mr. Sandher served as Chief Operating Officer and Chief Financial Officer of Marketrend Interactive Inc. He also acted
as Chief Financial Officer of Serebra Learning Corporation, a public company on the TSX Venture Exchange, from September 1999 to October 2002.
Conflicts of Interest
Our officers and directors are associated with other firms involved in a range of business activities. Consequently, there are potential inherent conflicts of interest in their acting as officers and/or directors of our company. Insofar as they are engaged in other business activities, we anticipate that they will not devote all of their time to our affairs.
Our officers and directors are now and may in the future become shareholders, officers or directors of other companies, which may be formed for the purpose of engaging in business activities similar to us. Accordingly, additional direct conflicts of interest may arise in the future with respect to such individuals acting on behalf of us or other entities. Moreover, additional conflicts of interest may arise with respect to opportunities which come to the attention of such individuals in the performance of their duties or otherwise. Currently, we do not have a right of first refusal pertaining to opportunities that come to their attention and may relate to our business operations.
Our officers and directors are, so long as they are our officers or directors, subject to the restriction that all opportunities contemplated by our plan of operation which come to their attention, either in the performance of their duties or in any other manner, will be considered opportunities of, and be made available to us and the companies that they are affiliated with on an equal basis. A breach of this requirement will be a breach of the fiduciary duties of the officer or director. If we or the companies with which the officers and directors are affiliated both desire to take advantage of an opportunity, then said officers and directors would abstain from negotiating and voting upon the opportunity. However, all directors may still individually take advantage of opportunities if we should decline to do so. Except as set forth above, we have not adopted any other conflict of interest policy with respect to such transactions.
We do not have any audit, compensation, and executive committees of our board of directors. We do not have an audit committee financial expert.
Section 16(a) Beneficial Ownership Reporting Compliance
We are not subject to Section 16(a) of the Securities Exchange Act of 1934.
Code of Ethics
We have not yet adopted a code of ethics that applies to our principal executive officers, principal financial officer, principal accounting officer or controller, or persons performing similar functions, due to our relatively low level of activity to date. At a later time, the board of directors may adopt such a code of ethics.
Changes to Director Nominating Procedures
The Company adopted Amended and Restated Bylaws on December 10, 2009 pursuant to which Series A Preferred Shareholders would be entitled to elect one director to the Company’s board of directors. The Company has not issued any Series A Preferred Shares.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The following table sets forth information about the remuneration of our principal executive officer for services rendered for each of the last two fiscal years ended October 31, 2010. We do not have any executive officers with total compensation of $100,000 or more. Certain columns as required by the regulations of the Securities and Exchange Commission have been omitted as no information was required to be disclosed under those columns.
SUMMARY COMPENSATION TABLE
Name and Principal Position
Year
Salary
($)
Option Awards
($)
Total
($)
Leroy Halterman
President and Secretary
60,000
60,000
23,581(1)
83,581
60,000
_____________
(1)
The fair value of the option grant to Mr. Halterman was estimated as of the date of grant using the Black-Scholes option pricing model with the following assumptions: expected volatility of 219%, risk-free interest rate of 0.92%, expected life of 2 years and dividend yield of 0.00%.
In addition to the above, we reimbursed Mr. Halterman $4,800 and $4,800 for office space for the fiscal years ended October 31, 2010 and 2009, respectively.
During the last two fiscal years ended October 31, 2010, there were no grants of stock options, stock appreciation rights, benefits under long-term incentive plans or other forms of compensation involving our officers, except for the stock option grant made to Mr. Halterman on November 2, 2009 and to Mr. Sandher on October 30, 2009. We have no employment agreements with our executive officers. We do not pay compensation to our directors for attendance at meetings. We reimburse our direc­tors ­for reasonable expenses incurred during the course of their perfor­mance.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
Name
Number of Securities Underlying Unexercised Options (#) exercisable
Number of Securities Underlying Unexercised Options (#)
Unexercisable
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options
Option Exercise
Price ($)
Option
Expiration Date
Leroy Halterman
300,000
0.10
11/2/11
On November 2, 2009, we granted Mr. Halterman options to purchase 300,000 shares of common stock at $0.10 per share. The options fully vested six months from the date of grant and expire November 9, 2011.
The following table sets forth compensation of our directors for the last completed fiscal year ended October 31, 2010. Mr. Halterman does not receive any additional compensation for serving as a director.
DIRECTOR COMPENSATION
Name
Fees Earned or Paid in Cash ($)
Stock Awards ($)
Option Awards ($)
All Other Compensation ($)
Total ($)
Kenneth Cabianca
90,000
90,000
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table provides certain information as to the officers, directors and more than 5% shareholders. As of December 31, 2010, we had 24,529,832 shares common stock outstanding.
________________
(1)
To our knowledge, except as set forth in the footnotes to this table and subject to applicable community property laws, each person named in the table has sole voting and investment power with respect to the shares set forth opposite such person’s name.
(2)
This table is based on 24,529,832 shares of common stock outstanding as of December 31, 2010. Shares of common stock subject to options currently exercisable or exercisable within 60 days of December 31, 2010 are deemed outstanding for purposes of computing the percentage ownership of the person holding such options, but are not deemed outstanding for purposes of computing the percentage ownership of any other person.
(3)
Kenneth Cabianca may be deemed to be a promoter of our company.
(4)
128,000 shares of common stock are held by Golden Capital in trust for Mr. Cabianca.
(5)
Includes 300,000 shares of common stock issuable upon exercise of vested stock options.
(6)
Includes 200,000 shares of common stock issuable upon exercise of vested stock options.
(7)
Includes 500,000 shares of common stock issuable upon exercise of vested stock options.
Equity Compensation Plan Information
As of October 31, 2010, our compensation plans (including individual compensation arrangements) under which our equity securities are authorized for issuance, are as follows
EQUITY COMPENSATION PLAN INFORMATION
Changes in Control
There are no agreements known to management that may result in a change of control of our company.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
For the fiscal years ended October 31, 2010 and 2009, we incurred $60,000 and $60,500, respectively, for administrative services performed by Downtown Consulting. Downtown Consulting is an entity owned and controlled by Sarah Cabianca, the daughter of Kenneth Cabianca, and one of our shareholders.
During the fiscal years ended October 31, 2010 and 2009, we paid $60,000 and $60,000, respectively, in management fees and $4,800 and $4,800, respectively, as reimbursement for office space to our president, Lee Halterman.
During the fiscal years ended October 31, 2010 and 2009, we paid $90,000 and $102,000, respectively, in management fees to a director, Ken Cabianca.
As of the date of this report, other than the transactions described above, there are no, and have not been since inception, any material agreements or proposed transactions, whether direct or indirect, with any of the following:
-
any of our directors or officers;
-
any nominee for election as a director;
-
any principal security holder identified in Item 12 above; or
-
any relative or spouse, or relative of such spouse, of the above referenced persons.
Future Transactions
All future affiliated transactions will be made or entered into on terms that are no less favorable to us than those that can be obtained from any unaffiliated third party.
Director Independence
Our common stock trades on the OTC Bulletin Board. As such, we are not currently subject to corporate governance standards of listed companies, which require, among other things, that the majority of the board of directors be independent.
Since we are not currently subject to corporate governance standards relating to the independence of our directors, we choose to define an “independent” director in accordance with the NASDAQ Global Market’s requirements for independent directors (NASDAQ Marketplace Rule 5605(a)(2)). The NASDAQ independence definition includes a series of objective tests, such as that the director is not an employee of the company and has not engaged in various types of business dealings with the company. We do not currently have an independent director under the above definition. We do not list that definition on our Internet website.
We presently do not have an audit committee, compensation committee, nominating committee, executive committee of our Board of Directors, stock plan committee or any other committees.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
Audit Fees
For the fiscal year ended October 31, 2010, Mark Bailey & Company, Ltd. (“Bailey”) is expected to bill us approximately $25,000 for the audit of our annual financial statements and review of financial statements included in our quarterly reports on Form 10-Q. For the fiscal year ended October 31, 2009, Chisholm, Bierwolf, Nilson & Morrill, LLC (“Chisholm”) billed us $19,085 for the audit of our annual financial statements and review of financial statements included in our quarterly report on Form 10-Q.
Audit-Related Fees
There were no fees billed for services reasonably related to the performance of the audit or review of our financial statements outside of those fees disclosed above under “Audit Fees” for fiscal years 2010 and 2009.
Tax Fees
For the fiscal year ended October 31, 2010, Bailey is expected to bill us $6,000 for tax compliance services. For the fiscal year ended October 31, 2009, Chisholm billed us $5,075 for tax compliance services.
All Other Fees
There were no other fees billed by our principal accountants other than those disclosed above for fiscal years 2010 and 2009.
Pre-Approval Policies and Procedures
Prior to engaging our accountants to perform a particular service, our directors obtain an estimate for the service to be performed. The directors in accordance with our procedures approved all of the services described above.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
__________________
(1)
Incorporated by reference to the exhibits to the registrant’s registration statement on Form SB-1, file number 333-102441.
(2)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated September 26, 2004, filed September 27, 2004.
(3)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 3, 2008, filed January 13, 2009.
(4)
Incorporated by reference to the exhibits to the registrant’s current report on Form 8-K dated December 11, 2009, filed December 15, 2009.
(5)
Incorporated by reference to the exhibits to the registrant’s amended current report on Form 8-K dated September 1, 2010, filed September 9, 2010.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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.