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| BNXR.OB > SEC Filings for BNXR.OB > Form 10QSB on 17-Mar-2008 | All Recent SEC Filings |
17-Mar-2008
Quarterly Report
Overview
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 extracted.
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. 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 three-month period ended January 31, 2008 or during the fiscal years ended October 31, 2007 or 2006. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.
Our plan of operations is to continue to produce commercial quantities of oil and gas and to drill new exploratory and development wells and re-entries to test the oil and gas productive capabilities of our oil and gas properties.
The report of our independent auditors on our financial statements for the year ended October 31, 2007, includes an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. Our accumulated deficit was $483,610 and $260,354 at October 31, 2007 and January 31, 2008, respectively. We need to generate additional revenues and successfully maintain and expand our current level of operations. These factors raise substantial doubt about our ability to continue as a going concern. We expect that we will require additional funding to cover these anticipated costs and that such additional funding will be in the form of equity financing from the sale of our common stock. However, we cannot provide investors with any assurance that we will be able to raise sufficient funding from the sale of our common stock to cover our oil and gas operations or our other working capital requirements. We do not presently have any arrangements in place for any future equity financing. We believe that debt financing will not be an alternative for our cash needs.
Oil and Gas Properties
"Bbl" is defined herein to mean one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
"Mcf" is defined herein to mean one thousand cubic feet of natural gas at standard atmospheric conditions.
"Working interest" is defined herein to mean an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the mineral owners of royalties.
Owl Creek Project
Acquisitions and Sales of Oil and Gas Interests. On August 10, 2005, we acquired a 70% working interest in Ranken Energy Corporation's Owl Creek Project for a total buy-in cost of $211,750 plus dry hole costs (the "Owl Creek Project"). The Owl Creek Project is located in Oklahoma. Our working interest in the Owl Creek Project includes leasehold interests, two re-entry test wells, geologic expenses, brokerage costs, 3-D seismic usage, geophysical interpretations, and overhead. We also participate in drilling operations and related costs.
On June 1, 2006, we completed the sale of 20% of the Powell #2 well and future drill sites on the Owl Creek Project. We received a one-time cash payment of $300,000 and each party is responsible for its portion of the cost to complete the Powell #2 well and future drill sites. Delta has funded its portion of the completion cost of the Powell #2 as well as costs related to future wells on the project. As a result of the sale to Delta, we now hold a 50% interest in the Powell #2 well.
On August 3, 2006, we completed the sale of 7.5% of the Isbill #1 well and future drill sites on the Owl Creek Project. We received a one-time cash payment of $100,000. We retained a 42.5% working interest in the Owl Creek Project. Each party is responsible for its portion of the costs to drill and complete the Isbill #1 well and future drill sites. We have also retained a 70% interest in two spacing unit and the wells containing the Johnson #1 and Powell #1 and a 50% interest in one spacing unit and the well containing the Powell #2.
On March 15, 2007, we expended $403,675 on Isbill #2-36 well. We hold a working interest of 42.5% in the Isbill #2-36 well.
On October 19, 2007, we expended $238,784 on Powell #3-25 well. On November 9, 2007, Powell #3-25 was abandoned and $174,245 was transferred to the proven cost pool for depletion. The unused estimated drilling costs were applied to other operating well costs.
Operations. We completed the Powell #1 well on the Owl Creek Prospect in early February 2006. As of the date of this filing, the Powell #1 well has produced 1,280 Bbl of oil and 8,227 MCF of natural gas. The well is currently shut in and may be converted to a saltwater disposal well in the near future.
We completed drilling the Powell #2 well in June 2006. In April 2007, the Powell #2 well was placed on a submersible pump. As of January 31, 2008, the Powell #2 well has produced 69,842 Bbl of oil and 21,418 MCF of natural gas. As of the date of this filing, the Powell #2 was averaging 60 Bbls of oil and 20 MCF of natural gas per day.
In late August 2006, we commenced drilling an offset well to the Powell #2 well, the Isbill #1 well. The well reached a total depth of 5,775 feet in mid-September 2006. After examination of the well logs it was determined that the sands that are producing in the Powell #2 were too thin in the Isbill #1 to produce economic quantities of oil and gas. The Isbill #1 well has been plugged and abandoned.
We commenced drilling of the Isbill #2 well, a direct offset well to the Powell #2, in February 2007. The Isbill #2 well reached a total depth of 5,700 feet in mid-March 2007. The Isbill #2 well was successfully completed and was placed into production in April 2007. As of January 31, 2008, the Isbill #2 well has produced 14,093 Bbls of oil and 2,489 MCF of natural gas through October 31, 2007 and is currently averaging 42 Bbls of oil and 12 MCF of natural gas per day.
In October 2007, drilling commenced on the Powell #3 well, a direct offset well to the Powell #2 well. Powell #3 well reached a total depth of 5,720 feet in November 2007. After examination of the well logs, it was determined that the sands that are producing in the Powell #2 and Isbill #2 wells were too thin in the Powell #3 well to produce economic quantities of oil and gas. As of the date of this filing, the Powell #3 well has been plugged, reclaimed and abandoned.
Three Sands Project
Acquisitions and Sales of Oil and Gas Interests. 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. As of January 31, 2008, the total cost for our Three Sands Project is $906,309. Our working interest in the Three Sands Project includes leasehold interests, one re-entry production well, and two drilling wells. We also participate in drilling operations and related costs, in proportion to our working interest.
Operations. 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 #2 well is now producing oil and gas on a daily basis and as of January 31, 2008, it has produced 2,950 Bbls of oil and 4,086 MCF of natural gas.
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. Initial production rates from the William #4-10 well averaged 3.5 Bbls of oil and 10 MCF of natural gas per day. During January 2008, we moved up the hole and perforated and fracture treated the Mississippi Lime Formation, increasing daily production to seven Bbls of oil and 25 MCF of natural gas. As of January 31, 2008, the Williams #4-10 has produced 322 Bbls of oil and 1,466 MCF of natural gas.
Drilling commenced on the KC 80 #1-11 well at the Three Sands Project in mid February 2008 and reached total depth of 4,720 feet by late February. 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 well should start by late March 2008.
Palmetto Point Project
Acquisitions and Sales of Oil and Gas Interests. 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 PP F-6B and PP F52-A wells) within the Palmetto Point Project for $70,000.
On October 1, 2007, we acquired a 10% working interest in the PP F-12-2 and PP F-12-3 wells within the Palmetto Point Project 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. On January 30, 2008, we incurred an additional $36,498 for our share of workover costs, including costs to install tubing and submersible pumps to maintain production rates. We subsequently paid these costs on February 1, 2008.
Operations. As of January 31, 2008, 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 have been completed and are currently producing. One of the eight wells, the PP F-12, was completed as a flowing oil well in early October, 2007. The PP F-12 well flowed oil at rates of over 100 Bbls of oil per day and in December 2007 was offset by two additional wells, the PP F-12-2 and PP F-12-3. The PP F-12-2 was a dry hole and the PP F-3 was completed as a flowing oil well. Additionally, we commenced production at the PP F-6B and PP F52-A wells in October 2007. In December 2007, the PP F52-A well started producing oil along with the natural gas, flowing naturally. However, as of January 31, 2008, the well has ceased flowing and will be placed on a pump during the second calendar quarter of 2008.
As of January 31, 2008, the completed oil and gas wells at the Palmetto Point Project have had total production of 185,066 MCF of natural gas and 15,267 Bbls of oil, and are current average daily production rate of 450 MCF per day of natural gas and 85 Bbls of oil per day. It should be noted that daily production was lower than normal at the end of January 2008 because both the PP F-12 and 12-3 were having submersible pumps installed to increase production and maintain pressure to the stock tanks.
Mississippi Frio-Wilcox Joint Venture
Acquisitions and Sales of Oil and Gas Interests. 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
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 have 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 F-1, CMR/BR F-14, RB F-1 Red Bug #2, BR F-33, and Randall #1 F-4, and any offset wells that could be drilled to any of these specified wells.
Operations. 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 F-24. However, subsequent testing of the BR F-24 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 F-33. The USA 39-14 and BR f-30 have been completed and are now also producing natural gas. As of January 31, 2008, these three wells have produced over 85,160 MCF of natural gas and are currently averaging a combined daily flow of 284 MCF per day of natural gas. No further exploration wells are currently planned for this project.
Mineral Interests
Antelope Pass
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 three month period ended January 31, 2008 or during the fiscal years ended October 31, 2007 or 2006. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project.
Results of Operations
Three months ended January 31, 2008 compared to the three months ended January 31, 2007.
We realized revenues of $495,292 during the three months ended January 31, 2008, compared with $247,789 during the three months ended January 31, 2007, an increase of $247,503, all due to our increased oil and gas production. However, we can provide no assurance that we will continue to produce commercially exploitable levels of oil and gas resources on our properties, or if additional resources are discovered, that we will enter into commercial production of such oil and gas properties.
We incurred direct costs of $271,827 during the three months ended January 31, 2008, compared with $263,053 during the three months ended January 31, 2007, an increase of $8,774. Our depletion and accretion costs were $83,056 during the three months ended January 31, 2008, compared with $181,766 during the three months ended January 31, 2007, a decrease of $98,710.
The decrease in our depletion and accretion costs was offset by increases in our production costs and general and administrative costs. Our production costs during the three months ended January 31, 2008 were $67,025, compared with $20,960 during the three months ended January 31, 2007, an increase of $46,065, all directly attributable to our increased oil and gas activities. Our general and administrative costs increased to $121,746 for the three months ended January 31, 2008, from $60,327 for the three months ended January 31, 2007. The increase in our general and administrative costs was largely attributable to an increase in costs associated with professional legal and accounting services necessary as a reporting issuer under the Securities Exchange Act of 1934.
For the three months ended January 31, 2008, our net income was $223,256, compared with a net loss of $15,847 for the three months ended January 31, 2007 (an increase in net income of $239,103). The increase of our net
Our accumulated deficit through January 31, 2008 was $260,354.
Liquidity and Capital Resources
As of January 31, 2008, we had cash of $270,181 and working capital of $481,855, compared to cash of $42,257 and working capital of $107,602 as of October 31, 2007. Our accounts receivable increased to $312,486 at January 31, 2008, compared with $281,500 at October 31, 2007.
During the three months ended January 31, 2008, net cash provided by operating activities was $255,534, compared with $135,173 during the three months ended January 31, 2007, an increase of $120,361.
Net cash used by investing activities during the three months ended January 31, 2008 was $6,896, compared with $216,915 during the three months ended January 31, 2007.
We used cash of $20,714 for financing activities during the three months ended January 31, 2008, compared with $10,000 during the three months ended January 31, 2007.
We had no proceeds from the sale of our common stock during the three months ended January 31, 2008 or 2007, respectively.
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements as of January 31, 2008.
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 year end 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.
Asset Retirement Obligations
We follow SFAS 143 "Accounting for Asset Retirement Obligations" ("SFAS
143"). SFAS 143 addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS 143 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. Our asset
retirement obligations are
Forward Looking Statements
Certain statements in this Quarterly Report on Form 10-QSB, as well as
statements made by us in periodic press releases and oral statements made by our
officials to analysts and shareholders in the course of presentations about the
company, constitute "forward-looking statements". Such forward-looking
statements involve known and unknown risks, uncertainties, and other factors
that may cause our actual results, performance or achievements to be materially
different from any future results, performance or achievements expressed or
implied by the forward looking statements. Such factors include, among other
things, (1) general economic and business conditions; (2) interest rate changes;
(3) the relative stability of the debt and equity markets; (4) government
regulations particularly those related to the natural resources industries; (5)
required accounting changes; (6) disputes or claims regarding our property
interests; and (7) other factors over which we have little or no control.
Going Concern
The report of our independent auditors on the financial statements for the year ended October 31, 2007, included an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. Additionally, our accumulated deficit through January 31, 2008 was $260,354. These factors, among others, raise substantial doubt about our ability to continue as a going concern. There can be no assurance that we will be able to obtain additional funding to engage in further exploration of our mineral properties nor is there assurance that our operations will be profitable.
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