Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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. 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, 2012 or 2011 or the six months ended April 30, 2013. 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. In addition to the drilling and producing of oil and gas wells, we have expanded and plan to continue to expand into exploration and project acquisition through the participation in new 3-D geophysical surveys and related project acquisitions.
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.
Note that all production amounts disclosed for the individual properties below are for the Company’s working interest.
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 is 6.25% and the ACP Interest is 5.00%. The total cost of the 2008-3 Drilling Program as of April 30, 2013 was $309,152. 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. One development well was drilled in August of 2011 near the highest producing well in the program. For the six months
ending April 30, 2013, the three producing wells in this program have produced a total of 218Bbls of oil and 72 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 is 6.25% and the ACP Interest is 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 April 30, 2013, the total cost of the 2009-2 Drilling Program was $114,420.
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 is 6.25% and the ACP Interest is 5.00%. The total costs incurred, including drilling costs, as of April 30, 2013 was $338,470. 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 tests 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 Bbls 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. This 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. The well is now producing oil and gas with the use of a pumping unit. The second well that also had a flowing drill stem test was completed in late March 2010 and that well is currently producing oil and natural gas with the use of a pumping unit. Total production from these two producing wells for the six months ending April 30, 2013 totaled 323 Bbls of oil and nil 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 is 6.25% and the ACP Interest is 5.00%. The total costs incurred, including drilling costs, as of April 30, 2013 was $190,182
.
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. The other well has been converted to a salt water disposal well. As of the six months ending April 30, 2013, there has been no production of hydrocarbons.
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 is 6.25% and the ACP
Interest is 5.00%. The total cost incurred, including drilling costs, as of April 30, 2013 was $264,298. 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. All three of the wells were completed in the deepest pay zone. The third well in this program is currently shut-in. Total production from these wells for the six months ended April 30, 2013 was 738 Bbls of oil and 225 Mcf of natural gas.
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 is 6.25% and the ACP Interest is 5.00%. The total cost incurred, including drilling costs, as of April 30, 2013 was $61,085. The well and related leasehold interests are located in McClain County, Oklahoma. 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 water-free at a rate of 12 Bbls of oil and 4 Mcf of natural gas. Total production for the McPherson well for the six months ending April 30, 2013 was 72 Bbls of oil and 19 Mcf
of natural gas. Additional pay zones are located above the currently producing horizon and it is anticipated that these zones will be perforated in the future adding additional production to the well.
Washita Bend 3D Exploration Project, Oklahoma
.
On March 1, 2010, we agreed to participate with a 5% working 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 covered 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. The 3-D program was designed to refine and better define the structures discovered during the earlier program and pinpoint drill locations. We participated in the seismic program and the related prospect generation and acquisition phase without any promotion. The BCP Interest is 5.625% and the ACP Interest is 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 April 30, 2013 was $581,456.
As of April 30, 2013, all of the permitted area had been shot and data acquired. All initial or first run processing data has been completed and interpretation of the data and mapping as well as prospect delineation has started. Title research and leasing on a number of potential prospects has been completed. A total of 5,148 acres of leases have been acquired thus far and leasing of additional lands is still under way. As a result of seismic evaluation and analysis, eight initial prospects have been identified, with the first well drilled on May 14, 2013. On May 27, 2013, this well was classified as a dry hole and costs associated therewith will be moved to proved properties. Depending on the success of this program, additional wells may be drilled.
Double T Ranch#1 SWDW, Oklahoma.
On July 17, 2012, we acquired a 3.00% working interest in the drilling, completion and operations of the Double T Ranch#1 SWDW located in Garvin County from Ranken Energy Corporation. At April 30, 2013, the cost of the Double T Ranch#1 SWDW was $50,324.
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.
On September 10, 2012, we signed an asset purchase agreement with GLM Energy Inc., to sell the oil and gas assets in the Three Sands Project effective June 1, 2012 for a total of $352,144. The disposed reserves represented more than 25% of the total reserves which we considered to represent a significant alteration between capitalized costs and proved reserves and hence a loss on the sale was recognized in the Statements of Comprehensive Income in the amount of $96,491 for the year ended October 31, 2012.
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 called 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 were to 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. In midsummer 2011, permitting of the first drill hole began and the well was completed in January 2012. On April 15, 2013, we elected to plug and abandon this well. All costs associated with this well have been moved to the proved property pool for depletion. After further and in-depth evaluation and consultation, we have elected not to participate any further at King City as we deem this project not to be economically viable. As at April 30, 2013, the total costs were $406,766.
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.
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 six-month period ended April 30, 2013 or during the fiscal years ended October 31, 2012 and 2011. At the time of this report, we do not know when or if we will proceed with the Antelope Pass Project. All Bureau of Land Management fees and filing have been paid and performed making the claim valid until August 31, 2013.
Results of Operations
Three months ended April 30, 2013 compared to the three months ended April 30, 2012.
We realized revenues of $58,182 during the three months ended April 30, 2013, compared with $158,730 during the three months ended April 30, 2012, a decrease of $100,548, due to the sale of our Three Sands property and a decrease in our oil and gas production. During the three-month period ended April 30, 2013, 615 Bbls of oil and 144 Mcf of gas (net to our working interest) were produced at our oil and gas properties, as compared to 1,405 Bbls of oil and 5,621 Mcf of gas for the three months ended April 30, 2012. The decrease in production was due primarily to a decrease in the number of producing wells caused by the sale of our Three Sands property.
We incurred production costs of $5,345 during the three months ended April 30, 2013, compared with $30,190 during the three months ended April 30, 2012, a decrease of $24,845. Our production costs decreased as a result of a decrease in the number of producing wells and a decrease in our oil and gas production.
Our depreciation, depletion and accretion costs were $39,894 during the three months ended April 30, 2013, compared with $50,181 during the three months ended April 30, 2012, a decrease of $10,287. The decrease in these costs is related to a decrease in the number of producing wells and a decrease in our oil and gas production.
Our general and administrative costs decreased to $149,159 for the three months ended April 30, 2013, from $165,511 for the three months ended April 30, 2012. The decrease of $16,352 is primarily attributable to a decrease in accounting, consulting and office costs, which were offset by an increase in management fees.
For the three months ended April 30, 2013, we incurred a net loss of $136,019, compared to a net loss of $87,692 for the three months ended April 30, 2012. The increase in net loss was largely attributable to the decrease in revenues.
As a result of our net loss for the quarter, we had a retained loss of $453,875 at April 30, 2013.
Six months ended April 30, 2013 compared to the six months ended April 30, 2012.
We realized revenues of $122,558 during the six months ended April 30, 2013, compared with $346,759 during the six months ended April 30, 2012, a decrease of $224,201.The decrease was due to the sale of the Company’s Three Sands property and due to a decrease in our oil and gas production. During the six-month period ended April 30, 2013, 1,351Bbls of oil and 516 Mcf of gas (net to our working interest) were produced at our oil and gas properties, as compared to 2,974 Bbls of oil and 11,736 Mcf of gas for the six months ended April 30, 2012. The decrease in production was due primarily to a decrease in the number of producing wells caused by the sale of our Three Sands property.
We incurred production costs of $19,250 during the six months ended April 30, 2013, compared with $53,175 during the six months ended April 30, 2012, a decrease of $33,925. Our production costs decreased as a result of a decrease in the number of producing wells and a decrease in our oil and gas production.
Our depreciation, depletion and accretion costs were $65,910 during the six months ended April 30, 2013, compared with $106,085 during the six months ended April 30, 2012, a decrease of $40,175. The decrease in these costs is related to a decrease in production from our wells.
Our general and administrative costs decreased to $311,578 for the six months ended April 30, 2013, from $320,388 for the six months ended April 30, 2012. The decrease of $8,810 is primarily attributable to a decrease in accounting, consulting and office costs, which were offset by an increase in management fees.
We received $nil in other income during the six months ended April 30, 2013, compared with $20,000 during the six months ended April 30, 2012 for late payment fees received from Lexaria Corp. in conjunction with the sale of our Mississippi properties.
For the six months ended April 30, 2013, we incurred a net loss of $275,824, compared to a net loss of $113,079 for the six months ended April 30, 2012. The increase in net loss was largely attributable to the decrease in revenues.
Liquidity and Capital Resources
As of April 30, 2013, we had cash and a certificate of deposit totaling $642,300 and working capital of $838,874, compared to cash and a certificate of deposit totaling $940,512 and working capital of $1,113,529 as of October 31, 2012. The decrease in working capital is due primarily to the use of cash to fund our operations. Our cash and cash equivalents decreased to $242,300 at April 30, 2013, compared with $540,512 at October 31, 2012, a decrease of $298,212.
During the six months ended April 30, 2013, operating activities used cash of $237,986, as compared to net cash provided of $22,767 for the six months ended April 30, 2012. The principal reason for the change was due to the net loss for the period.
Investing activities, which consisted of payments on our oil and gas interests, used net cash of $60,226 during the six months ended April 30, 2013, compared with $19,747 provided during the six months ended April 30, 2012. Investing activities were primarily payments on oil and gas interests of $57,904 in 2013. In 2012, payments on oil and gas interests were significantly higher $180,253, but were offset by $200,000 in proceeds from the sale of our Palmetto Point Project.
Off-Balance Sheet Arrangements
As of April 30, 2013, 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 are computed on the units of production method based on proved reserves. 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, in the preceding twelve 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”
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 April 30, 2013 and October 31, 2012, 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. 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 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.
We amortize the amount added to oil and gas properties and recognize 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 six-month period ended April 30, 2013 and the year ended October 31, 2012:
|
|
|
April 30, 2013
|
|
|
October 31, 2012
|
|
|
Balance, beginning of periods
|
|
$
|
27,554
|
|
|
$
|
26,335
|
|
|
Liabilities assumed
|
|
|
-
|
|
|
|
-
|
|
|
Revisions
|
|
|
-
|
|
|
|
(1,941
|
)
|
|
Accretion expense
|
|
|
1,654
|
|
|
|
3,160
|
|
|
Balance, end of periods
|
|
$
|
29,208
|
|
|
$
|
27,554
|
|
The reclamation obligation relates to the Ard#1-36, Bagwell#1-20, Bagwell#2-20, Jackson#1-18, Miss Gracie#1-18, Joe Murray Farm, Gehrke#1-24 and Miss Jenny#1-8 wells at Oklahoma Properties, and McPherson#1-1 well at South Wayne Prospect. 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 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.
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 (7) other factors over which we have little or no control.
