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| BNXR.OB > SEC Filings for BNXR.OB > Form 10-Q on 13-Jun-2008 | All Recent SEC Filings |
13-Jun-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 six-month period ended April 30, 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 $124,903 at October 31, 2007 and April 30, 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. As of April 30, 2008, our total costs associated with the Owl Creek Project are $1,979,563.
Operations. During the three-month period ended April 30, 2008, 7,809 Bbls of oil and 2,342 MCF of natural gas were produced at the Owl Creek Project.
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 April 30, 2008, the Powell #2 well has produced 74,208 Bbl of oil and 22,886 MCF of natural gas. As of the date of this filing, the Powell #2 is averaging 70 Bbls of oil and 24 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 April 30, 2008, the Isbill #2 well has produced 16,540 Bbls of oil and 4,945 MCF of natural gas through October 31, 2007 and as of the date of this filing is 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"). Our working interest in the Three Sands Project includes leasehold interests, one high-volume saltwater disposal well, one re-entry production well, and three drilled wells. We also participate in drilling operations and related costs, in proportion to our working interest. The Three Sands Project is located in Oklahoma.
During the year ended October 31, 2006, we expended $530,081 in exploration costs for the Three Sands Project. 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 prepaid drilling costs. During March and April 2008, we expended an additional $48,763 for intangible and tangible costs for the KC 80#1-11 well.
As of April 30, 2008, our total costs associated with the Three Sands Project are $1,029,967.
Operations. During the three-month period ended April 30, 2008, 599 Bbls of oil and 2,739 MCF of natural gas were produced at the Three Sands Project.
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 continues to produce oil on a daily basis, but is no longer producing natural gas. As of April 30, 2008, it has produced 3,114 Bbls of oil and 4,086 MCF of natural gas.
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 April 30, 2008, the Dye Estate #1 well has produced 1,630 MCF of natural gas and as is averaging natural gas production of 6 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. 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 April 30, 2008, the Williams #4-10 has produced 757 Bbls of oil and 3,575 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 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. As of April 30, 2008, the KC 80 #1-11 well is producing at a rate of 60 Bbls of oil and 100 MCF of natural gas daily.
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.
As of April 30, 2008, our total costs associated with the Palmetto Point Project, to include our costs for the PP F-12-2 and PP F-12-3 wells, are $543,360.
Operations. During the three-month period ended April 30, 2008, 4,304 Bbls of oil and 12,753 MCF of natural gas were produced at the Palmetto Point Project.
As of April 30, 2008, our completed oil and gas wells at the Palmetto Point Project have had total production of 197,819 MCF of natural gas and 19,451 Bbls of oil. However, the current average daily production rate at the Palmetto Point Project has dropped to 114 MCF per day of natural gas and 35 Bbls of oil per day (from 450 MCF per day of natural gas and 85 Bbls of oil per day at January 31, 2008). This decrease is a direct result of flooding due to unseasonably heavy rains and snow melt at the Palmetto Point Project.
Both the PP F-12 PP F-3 oil well locations and several of our gas well locations have been flooded at the Palmetto Point Project. Prior to the flooding, we had partly completed work to install submersible pumps at each well, however, the work could not be completed before the locations were flooded. There has been virtually no damage to our surface equipment located at the well heads, as our batteries and other production facilities are located above the flood waters. Thus far, the only damage has been to our recent 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. We expect the flood waters to recede by mid-summer 2008 and intend to resume full production by mid-August of 2008.
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 $400,000 (the "Mississippi Frio-Wilcox Joint Venture"). In exchange for our interest, we paid $100,000 as of October 31, 2006 and an additional $200,000 on November 16, 2006. As a result of weather related delays, the requirement for our final payment of $100,000 was deferred and paid in February 2007. 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 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. During the three-month period ended April 30, 2008, 43,107 MCF of natural gas was produced at the Mississippi Frio-Wilcox Joint Venture.
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 April 30, 2008, these three wells have produced 128,347 MCF of natural gas and are currently averaging a combined daily flow of 505 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 April 30, 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 April 30, 2008 compared to the three months ended April 30, 2007.
We realized revenues of $380,472 during the three months ended April 30, 2008, compared with $282,400 during the three months ended April 30, 2007, an increase of $98,072, due to our increased oil and gas production as well as increased oil and natural gas prices. During the three-month period ended April 30, 2008, 12,712 Bbls of oil and 61,021 MCF of natural gas were produced at our oil and gas properties. 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.
For the three months ended April 30, 2008, our net income was $135,451, compared with $41,106 for the three months ended April 30, 2007, an increase of $94,345. The increase of our net income was largely attributable to the increase in our revenues and the decrease of our direct costs as a percentage of revenues.
We incurred direct costs of $245,021 during the three months ended April 30, 2008, compared with $240,813 during the three months ended April 30, 2007, an increase of $4,208. Our depletion and accretion costs were $62,075 during the three months ended April 30, 2008, compared with $82,384 during the three months ended April 30, 2008, a decrease of $20,309. The decrease in our depletion costs is related to an increase in our reserves. We use the reserve report prepared during the last quarter of fiscal 2007 to calculate depletion on a quarterly basis for the following year. The reserve report indicated that our reserves increased relative to prior periods, which resulted in lower depletion for the current quarter.
Our general and administrative costs decreased to $110,261 for the three months ended April 30, 2008, from $115,362 for the three months ended April 30, 2007.
The decreases in our depletion and accretion costs and general and administrative costs were offset by an increase in our production costs. Our production costs during the three months ended April 30, 2008 were $72,685, compared with $43,067 during the three months ended April 30, 2007, an increase of $29,618, all directly attributable to our increased oil and gas activities.
Our accumulated deficit through April 30, 2008 was $124,903.
Six months ended April 30, 2008 compared to the six months ended April 30, 2007.
We realized revenues of $875,764 during the six months ended April 30, 2008, compared with $530,189 during the six months ended April 30, 2007, an increase of $345,575, due to our increased oil and gas production as well as increased oil and natural gas prices. 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.
For the six months ended April 30, 2008, our net income was $358,707, compared with $25,259 for the six months ended April 30, 2007, an increase of $333,448. The increase of our net income was largely attributable to the increase in our revenues and the decrease of our direct costs as a percentage of revenues.
We incurred direct costs of $516,848 during the six months ended April 30, 2008, compared with $503,866 during the six months ended April 30, 2007, an increase of $12,982. Our depletion and accretion costs were $145,130 during the six months ended April 30, 2008, compared with $264,150 during the six months ended April 30, 2008, a decrease of $119,020. The decrease in our depletion costs is related to an increase in our reserves. We
use the reserve report prepared during the last quarter of fiscal 2007 to calculate depletion on a quarterly basis for the following year. The reserve report indicated that our reserves increased relative to prior periods, which resulted in lower depletion for the current quarter.
The decrease in our depletion and accretion costs was offset by an increase in our production costs and general and administrative costs. Our production costs during the six months ended April 30, 2008 were $139,710, compared with $64,026 during the six months ended April 30, 2007, an increase of $75,684, all directly attributable to our increased oil and gas activities. Our general and administrative costs increased to $232,008 for the six months ended April 30, 2008, from $175,690 for the six months ended April 30, 2007, an increase of $56,318. 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 and stock based compensation costs of $26,077.
Liquidity and Capital Resources
As of April 30, 2008, we had cash of $374,817 and working capital of $542,497, compared to cash of $42,257 and working capital of $107,602 as of October 31, 2007. Our accounts receivable decreased to $232,954 at April 30, 2008, compared with $281,500 at October 31, 2007, a decrease of $48,546.
During the six months ended April 30, 2008, net cash provided by operating activities increased to $497,053, compared with $328,042 during the six months ended April 30, 2007, an increase of $169,011, largely due to our increased oil and gas production.
Net cash used by investing activities during the six months ended April 30, 2008 was $143,779, compared with $712,261 during the six months ended April 30, 2007, a decrease of $568,482. This decrease is largely due to lessened acquisition activity in fiscal 2008 compared to fiscal 2007.
We used cash of $20,714 for financing activities during the six months ended April 30, 2008, compared with $10,000 during the six months ended April 30, 2007. We had no proceeds from the sale of our common stock during the six months ended April 30, 2008 or 2007, respectively.
Off-Balance Sheet Arrangements
As of April 30, 2008, we did not have any off-balance sheet arrangements.
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 related to the plugging, dismantlement, removal, site reclamation and similar activities of our oil and gas exploration activities.
Forward Looking Statements
Certain statements in this Quarterly Report on Form 10-Q 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 . . .
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