ITEM 1. BUSINESS.
Background
EFL Overseas, Inc. is a development stage company incorporated in the State of Nevada on July 22, 2008. We are engaged in the acquisition, exploration and development of oil and gas properties in the United States and Canada.
During the period from July 18, 2012 through October 17, 2012, we acquired working interests totaling 53.65% (including a 100% working interest in one gas well) in the Kotaneelee Gas Project located on 30,542 gross acres in the Yukon Territory in Canada. We believe the Kotaneelee Gas Project has significant conventional and shale gas potential and is supported by an environment of growing investment in gas processing and export in the Pacific Northwest.
During March 2011, we initiated oil and gas operations by entry into a Farmout and Participation Agreement (the “Eagleford Agreement”) with Dyami Energy LLC and Eagleford Energy Inc. The Eagleford Agreement provided for our acquisition of a net working interest, ranging from 21.25% to 42.5%, in a 2,629 acre oil and gas lease known as the Matthews Lease, insofar as that lease covers from the surface to the base of the San Miguel formation (the “San Miguel Lease”). The San Miguel Lease is located in Zavala County, Texas, and has no current production or proven reserves.
Prior to March 2011, we were relatively inactive. We were originally organized to recruit amateur instructors to teach English in Japan and Brazil. We were unable, however, to identify a sufficient number of instructors to fulfill our business plan.
On April 28, 2010, shareholders owning a majority of our outstanding shares approved a 20 for 1 forward split of our common stock. The stock split was based on market conditions and upon a determination by our Board of Directors that the stock split was in our best interests and in the best interests of our shareholders. The amendment to our Articles of Incorporation pertaining to the forward stock split was filed with the Nevada Secretary of State on May 3, 2010. The forward stock split became effective on the OTC Bulletin Board on June 30, 2010. Prior to the forward stock split, we had 330,000 shares of common stock outstanding. Subsequent to the forward stock split we had 6,600,000 outstanding shares of common stock.
On April 20, 2010, a former officer and director sold 4,835,000 shares of common stock (on a pre-forward split basis) to us for $100. The shares were cancelled following their purchase.
The Kotaneelee Gas Project (“KGP”) - Yukon Territory, Canada
Working Interest Acquisitions
The Devon Assets
On July 18, 2012, we completed an acquisition of Devon Canada’s (“Devon”) entire right and interest (generally a working interest of 22.989%, with a working interest of 69.337% in one gas well) in the Kotaneelee Gas Project (“KGP”). The KGP covers 30,542 gross acres in the Yukon Territory in Canada, and includes; a gas dehydration plant (capacity: 70 million cubic feet per day (“MMCFD”)), one water disposal well (capacity: 6,000 barrels per day), one gas well temporarily shut-in for maintenance, and two suspended gas wells, flarestack, storage tanks, airstrip, roads, gathering systems, geological data, equipment, and other transportation and camp infrastructure.
As consideration for Devon’s working interest in the KGP, (the “Devon Assets”), we paid approximately $23,298,000. The consideration was comprised of $290,000 in cash, 7,250,000 shares of our restricted common stock valued at $15,950,000, and the absorption of $7,058,000 in asset retirement obligations. Our previous estimate of the fair value of the common stock paid to acquire the Devon Assets has been modified to reflect the market price of our stock at the purchase date. We allocated the consideration paid to the assets acquired based upon their fair value at the date of purchase, as follows:
The Nahanni Assets
On October 17, 2012, we closed a Share Purchase Agreement (the “Purchase Agreement”) with Nahanni Energy Inc., 1700665 Alberta Ltd., Apex Energy (2000), Inc. and Canada Southern Petroleum #1 L.P. (jointly “Nahanni”) for the acquisition of its entire right and interest (generally a working interest of 30.664%) in the KGP (the “Nahanni Assets”).
As consideration for the Nahanni Assets, we paid Nahanni CAD$400,000 (USD$398,550) in cash, and CAD$4,100,000 (USD$4,190,610) in shares of one of our subsidiaries, which are exchangeable for 1,614,767 shares of our restricted common stock. The cash portion of Nahanni’s consideration was offset by CAD$270,000 (USD$265,950) paid in connection with the acquisition of the Devon Assets in settlement of certain Nahanni indebtedness. The number of shares issued by our subsidiary was calculated by dividing $4,190,610 by the volume weighted average trading price of our stock for the ten (10) trading days prior to closing the Purchase Agreement. Both the cash paid and stock issued for the Nahanni Assets are subject to certain holdbacks for Asset related liabilities or breach of representations and warranties. In addition, we indemnified Nahanni against its portion of the abandonment, reclamation and environmental liabilities associated with the Assets. Early estimates of those liabilities range from USD$9,000,000 to USD$10,000,000.
Our allocation of the consideration paid for the Nahanni Assets is awaiting the results of our fair market valuation study.
Future Exploration and Development
Our exploration plan for the KGP involves the exploitation of both conventional and unconventional (shale) gas resources. Phase One of that plan includes the acquisition of new seismic data, the recompletion of two existing wells, and the drilling, completion and equipping of one new well. Phase One efforts will focus on previously identified or tested conventional gas zones. During Phase One we intend to target lower cost exploration with the potential to create positive cash flows and long term sustainability for the KGP. Early estimates indicate the cost of Phase One exploration may range from $22,000,000 to $23,000,000. If we pursue the completion of one well in an unconventional zone, our Phase One costs could increase by $9,000,000 to $10,000,000.
Phase Two and Phase Three of our exploration plan anticipates the drilling, completion, and tie-in of eights wells divided almost evenly between conventional and unconventional targets. Early estimates indicate the total cost of Phase Two and Three exploration may range from $145,000,000 to $150,000,000.
The San Miguel Lease - Zavala County, Texas
The Eagleford Agreement provided for our acquisition of a net working interest, ranging from 21.25% to 42.5%, in a 2,629 acre oil and gas lease known as the Matthews Lease, insofar as that lease covers from the surface to the base of the San Miguel formation. The San Miguel Lease is located in Zavala County, Texas, and has no current production or proven reserves.
Under the Eagleford Agreement, to earn our initial 21.25% working interest (net revenue interest 15.94%), we were obligated to drill and complete a vertical test well (the “Test Well”) in the San Miguel shale formation. We were also obligated to perform an injection operation on the Test Well. If the Test Well was prospective for production in commercial quantities, we were required to equip the Test Well and place it on production. If we determine that the Test Well is not prospective for production in commercial quantities, we are responsible for the abandonment of the Test Well.
During April and May 2011, we drilled and completed the Test Well, performed injection operations and earned our initial interest in the San Miguel Lease. The Test Well was drilled into the San Miguel heavy oil zone to a depth of 3,168 feet. The well encountered oil and was completed as a San Miguel producer. After completion, it was determined that the oil was subject to significant viscosity changes related to temperature reductions from formation to recovery at surface. The Test Well was stimulated with nitrified hydrochloric acid and placed on production. To date, however, oil viscosity has prohibited economic operation. Although we continue to investigate various methods to improve production from the Test Well, we cannot estimate what cost, if any, will be associated with future production efforts on the San Miguel Lease. We have no current plans to spend the funds necessary to earn an additional interest in the San Miguel Lease. In the event we are unable to substantially improve production, we intend to abandon the Test Well, or actively pursue the sale of our interest in the San Miguel Lease.
As a result of the application of a full cost pool "ceiling test", we determined that the book value of the San Miguel Lease was impaired to the extent of its carrying value. Accordingly, during the year ended August 31, 2011 and the three months ended November 30, 2011, we recognized losses on the impairment of oil and gas assets of $835,659 and $44,335, respectively. The carrying value of oil and gas properties was likewise reduced to reflect the impairment of the San Miguel Lease. We have made no additional expenditures on the San Miguel Lease since November 30, 2011.
Competition
The petroleum and natural gas industry is highly competitive. Numerous independent oil and gas companies, oil and gas syndicates and major oil and gas companies actively seek out and bid for oil and gas properties as well as for the services of third party providers, such as drilling companies, upon which we rely. From time to time, seismic vendors, drilling contractors, rigs and supplies may be in short supply. Their availability may be controlled by other larger explorers in the area. Native title holders or certain of our competitors may control pipeline capacity, roads, bridges and other infrastructure we require to access or fully exploit our properties. Our reliance upon their resources may create a competitive disadvantage for us. A substantial number of our competitors have longer operating histories and substantially greater financial and personnel resources than we do, and have demonstrated the ability to operate through industry cycles.
Some of our competitors not only explore for, produce and market petroleum and natural gas, but also carry out refining operations and market the resultant products on a worldwide basis which may provide them with additional sources of capital. Larger and better capitalized competitors may be in a position to outbid us for particular prospect rights. These competitors may also be better able to withstand sustained periods of unsuccessful drilling. Larger competitors may be able to absorb the burden of any changes in laws and regulations more easily than we can, which would adversely affect our competitive position.
Petroleum and natural gas producers also compete with other suppliers of energy and fuel to industrial, commercial and individual customers. Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments and/or their agencies and other factors which are out of our control including, international political conditions, terrorism, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources.
Regulation
The exploration, production and sale of oil and gas are extensively regulated by governmental authorities. Applicable legislation is under constant review for amendment or expansion. These efforts frequently result in an increase in the regulatory burden on companies in our industry and consequently an increase in the cost of doing business and decrease in profitability. Numerous governmental departments and agencies are authorized to, and have, issued rules and regulations imposing additional burdens on the oil and gas industry that often are costly to comply with and carry substantial penalties for non-compliance. Production operations are affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible delays, interruptions or termination by government authorities.
Oil and gas mineral rights may be held by individuals, corporations or governments having jurisdiction over the area in which such mineral rights are located. As a general rule, parties holding such mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights. The terms of the leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which mineral rights are located generally retains authority over the drilling and operation of oil and gas wells.
Environmental considerations
Our operations are also subject to a variety of constantly changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with environmental laws and regulations can result in the imposition of substantial fines and penalties as well as potential orders suspending or terminating our rights to operate. Some environmental laws to which we are subject provide for strict liability for pollution damage, rendering a company liable for environmental damage without regard to negligence or fault on the part of such company. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances, such as oil and gas related products or for other reasons.
Some environmental protection laws and regulations may expose us to liability arising out of the conduct of operations or conditions caused by others, or for acts which were in compliance with all applicable laws at the time the acts were performed. Changes in environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities to us. These laws and regulations may substantially increase the cost of exploring, developing, producing or processing oil and gas and may prevent or delay the commencement or continuation of a given project and thus generally could have a material adverse effect upon our capital expenditures, earnings, or competitive position. We believe that we are in substantial compliance with current applicable environmental laws and regulations. Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on us and the oil and gas industry in general.
Risks
Our failure to obtain capital may significantly restrict our proposed operations.
We received an audit report from our independent registered public accounting firm containing an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern. We have not generated significant revenues and has never been profitable. We need additional capital to fund operating losses, acquire assets and to explore for oil and gas. We do not know what the terms by which we may obtain any future capital, but any future sale of our equity securities would dilute the ownership of existing stockholders and could be at prices substantially below the market price of our common stock. We may not be able to obtain the capital we need.
Our pursuit of natural resource properties may fail and/or exploration activities may not be commercially successful, which could lead us to abandon our plans to develop properties.
Our long-term success depends on our ability to establish commercially recoverable quantities of resources on our properties that can then be developed into commercially viable operations. Resource exploration is highly speculative in nature, involves many risks and is frequently non-productive. These risks include unusual or unexpected geologic formations, and the inability to obtain suitable or adequate machinery, equipment or labor. The success of exploration is determined in part by the following factors:
a)
The identification of potential resources;
b)
availability of government-granted exploration permits and well licenses;
c)
the quality of management and geological and technical expertise; and
d)
the capital available for exploration.
Substantial expenditures are required to establish proven and probable resource reserves. Whether a resource will be commercially viable depends on a number of factors outside our control, which include, without limitation, the particular attributes of the resource formation, and proximity to infrastructure; prices, which fluctuate widely; and government regulations, including, without limitation, regulations relating to prices, taxes, development, production, stimulation and fracking, royalties, land tenure, land use, importing and exporting of resources and environmental protection. We may invest significant capital and resources in exploration activities and abandon such investments if we are unable to identify commercially exploitable reserves. Our inability to acquire or the decision to abandon a project may reduce the trading price of our common stock and impair our ability to raise future financing. We cannot provide any assurance to our shareholders that we will identify or acquire any resources in sufficient quantities on any properties to justify commercial operations. Further, we will not be able to recover the funds that we spend on exploration if we are not able to establish commercially recoverable quantities of resources on any property we may acquire.
Oil and gas exploration is not an exact science, and involves a high degree of risk.
Our primary exploration risk lies in the drilling of dry holes or drilling and completing wells which, though productive, do not produce gas and/or oil in sufficient amounts to return the amounts expended and produce a profit. Hazards, such as unusual or unexpected formation pressures, downhole fires, blowouts, loss of circulation of drilling fluids and other conditions are involved in drilling and completing oil and gas wells and, if such hazards are encountered, completion of any well may be substantially delayed or prevented. In addition, adverse weather conditions can hinder or delay operations, as can shortages of equipment and materials or unavailability of drilling, completion, and/or work-over rigs. Even though a well is completed and is found to be productive, water and/or other substances may be encountered in the well, which may impair or prevent production or marketing of oil or gas from the well. Exploratory drilling involves substantially greater economic risks than development drilling because the percentage of wells completed as producing wells is usually less than in development drilling. Exploratory drilling itself can be of varying degrees of risk and can generally be divided into higher risk attempts to discover a reservoir in a completely unproven area or relatively lower risk efforts in areas not too distant from existing reservoirs. While exploration adjacent to or near existing reservoirs may be more likely to result in the discovery of oil and gas than in completely unproven areas, exploratory efforts are nevertheless high risk activities.
Although the completion of oil and gas wells is, to a certain extent, less risky than drilling for oil and gas, the process of completing an oil or gas well is nevertheless associated with considerable risk. In addition, even if a well is completed as a producer, the well for a variety of reasons may not produce sufficient oil or gas in order to repay our investment in the well.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. The reserves we report in our filings with the SEC are estimates and such estimates may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Substantial sales or other issuances of our Common Stock, or the perception that such sales might occur, could depress the market price of our Common Stock.
We cannot predict whether future issuances of our Common Stock or resales in the open market will decrease the market price of our Common Stock. The impact of any such issuances or resales of our Common Stock on our market price may be increased as a result of the fact that our Common Stock is thinly, or infrequently, traded. The exercise of any options or the vesting of any restricted stock that we may grant to directors, executive officers and other employees in the future, the issuance of Common Stock in connection with acquisitions and other issuances of our Common Stock could have an adverse effect on the market price of our Common Stock. In addition, future issuances of our Common Stock may be dilutive to existing shareholders. Any sales or other issuances of substantial amounts of our Common Stock in the public market, or the perception that such sales might occur, could lower the market price of our Common Stock.
Penny Stock Regulations may impose certain restrictions on marketability of the Company’s securities.
The trading of our Common Stock is subject to rules pertaining to “penny stocks.” The Securities and Exchange Commission (“SEC”) has adopted regulations which generally define a “penny stock” to be any equity security that has a market price (as defined) of less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. As a result, our Common Stock is subject to rules that impose additional sales practice requirements on broker-dealers who sell such securities to persons other than established clients and “accredited investors.” For transactions covered by these rules, the broker-dealer must make a special suitability determination for the purchase of such securities and have received the purchaser’s written consent to the transaction prior to the purchase. Additionally, for any transaction involving a penny stock, unless exempt, the rules require the delivery, prior to the transaction, of a risk disclosure document mandated by the SEC relating to the penny stock market. The broker-dealer must also disclose the commission payable to both the broker-dealer and the registered representative, current quotations for the securities and, if the broker-dealer is the sole market maker, the broker-dealer must disclose this fact and the broker-dealers presumed control over the market. Finally, monthly statements must be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks. Consequently, the “penny stock” rules may restrict the ability of broker-dealers to sell shares of the Company’s Common Stock and may affect the ability of investors to sell such shares of Common Stock in the secondary market and the price at which such investors can sell any of such shares.
Investors should be aware that, according to the SEC, the market for penny stocks has suffered in recent years from patterns of fraud and abuse. Such patterns include:
●
control of the market for the security by one or a few broker-dealers that are often related to the promoter or issuer;
●
manipulation of prices through prearranged matching of purchases and sales and false and misleading press releases;
●
“boiler room” practices involving high pressure sales tactics and unrealistic price projections by inexperienced sales persons;
●
excessive and undisclosed bid-ask differentials and markups by selling broker-dealers; and
●
the wholesale dumping of the same securities by promoters and broker-dealers after prices have been manipulated to a desired level, along with the inevitable collapse of those prices with consequent investors losses
IN ADDITION TO THE RISK FACTORS SET FORTH ABOVE, WE ARE SUBJECT TO NUMEROUS OTHER RISKS SPECIFIC TO OUR PARTICULAR BUSINESS AS WELL AS GENERAL BUSINESS RISK. INVESTORS ARE URGED TO CONSIDER ALL OF THE RISKS INHERENT IN OUR SECURITIES PRIOR TO PURCHASING OR MAKING AN INVESTMENT DECISION.
Other
We currently have no full-time employees. We use consultants and contractors to provide us with, among other things, executive management,accounting services, field operating support and technical engineering.
Other than engineering, geochemical, geophysical and exploration programs capitalized in connection with our oil and gas concessions, we have devoted no substantial efforts to research and development within the last two fiscal years.
ITEM 2.
ITEM 2. PROPERTIES.
Oil and Gas Properties
Our crude oil and gas properties consist essentially of working interests owned by us in various oil and gas wells, plant, equipment and related leases located in the Yukon Territory in Canada. Recapped below is a brief synopsis of our core area of operation, as at August 31, 2012. Lease and well data is presented as at November 29, 2012, and includes the impact of acquisition of the Nahanni Assets on October 17, 2012.
Capital Expenditures, Including Acquisitions and Costs Incurred
Capitalized acquisition, exploration and development costs incurred on the KGP during the fiscal year ended August 31, 2012 are summarized as follows:
Revenue and direct costs incurred on the KGP from the date of acquisition through August 31, 2012 are summarized as follows:
The costs incurred on the San Miguel Lease during the fiscal years ended August 31, 2012 and 2011 are summarized as follows:
Drilling Statistics
During the years ended August 31, 2012 and 2011, we drilled or participated in the drilling of the following wells. We did not drill any development wells during the years ended August 31, 2012 or 2011.
As of November 29, 2012 we were not drilling or completing any wells.
Productive Oil and gas Wells
At August 31, 2012, we had an interest in one gross productive natural gas well (0.7 net well) in the KGP. This well was shut in for maintenance in September 2012 and remains shut in as of November 29, 2012.
Production, Pricing and Lease Operating Cost Data
The following table describes, for the years ended August 31, 2012 and 2011, crude oil and natural gas production, average lease operating expenses per mcf (including severance and other taxes and transportation costs) and our average sales prices. All of this information relates to our working interest in the KGP:
Delivery Commitments
As of August 31, 2012, we had no delivery commitments.
Well and Lease Data
Gross and Net Undeveloped and Developed Acreage
The following table shows, by state/territory, our producing wells, developed acreage, and undeveloped acreage, excluding service (injection and disposal) wells as of November 29, 2012:
(1)
Undeveloped acreage includes leasehold interests on which wells have not been drilled, or completed, to the point that would permit the production of commercial quantities of natural gas and oil, regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.
The following table shows, as of November 29, 2012, the status of our gross acreage:
Acres that are Held by Production remain in force so long as oil or gas is produced from the well on the particular lease. Leased acres, which are not Held by Production, often require annual rental payments to maintain the lease until the first to occur of the following: the expiration of the lease or the time oil or gas is produced from one or more wells drilled on the leased acreage. At the time oil or gas is produced from wells drilled on the leased acreage, the lease is considered to be Held by Production.
The following table shows the years our leases, which are not Held by Production, will expire, unless a productive oil or gas well is drilled on the lease.
Estimated Proved Reserves and Future Net Cash Flows
In January 2009, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting” (Release 33-8995), amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K and bringing full-cost accounting rules into alignment with the revised disclosure requirements. The new rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other new or revised definitions and disclosures. In January 2010, the Financial Accounting Standards Board (FASB) amended Accounting Standards Codification (ASC) Topic 932, “Extractive Industries - Oil and Gas” to align the guidance with the changes made by the SEC. The Company adopted Release 33-8995 and the amendments to ASC Topic 932 (collectively, the Modernization Rules) effective January 1, 2010.
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserve estimates are considered proved if economical productivity is supported by either actual production or conclusive formation tests. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program in the reservoir provides support for the engineering analysis on which the project or program is based. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.
As of August 31, 2012, the Company had total estimated proved reserves of 5,363,400 mcf of natural gas, of which 2,067,900 mcf of natural gas were proved producing reserves and the balance were PUD reserves. Combined, these total estimated proved reserves are equivalent to 893,900 barrels of oil equivalent.
The Company emphasizes that its reported reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data.
AJM Deloitte prepared the estimates of our proved reserves, future productions and income attributable to our leasehold interests for the year ended August 31, 2012. AJM Deloitte is independent petroleum engineering firm that has been providing petroleum consulting services worldwide for over 20 years. The estimates of proved reserves, future production and income attributable to certain leasehold and royalty interests are based on technical analysis conducted by teams of geoscientists and engineers employed at AJM Deloitte. AJM Deloitte prepared our reserve estimate based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for our wells. Additionally, authorizations for expenditure, geological and geophysical data, and other engineering data that complies with SEC guidelines are among that which we provide to AJM Deloitte engineers for consideration in estimating our underground accumulations of crude oil and natural gas.
The report of AJM Deloitte dated September 28, 2012, which contains further discussions of the reserve estimates and evaluations prepared by AJM Deloitte as well as the qualifications of AJM Deloitte’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.2 to this report.
Keith McDonald, our President and Chief Executive Officer, oversaw the preparation of the reserve estimates by AJM Deloitte to ensure accuracy and completeness of the data prior to and after submission. Mr. McDonald has over twenty-five years of experience in oil and gas exploration and development.
Our proved reserves include only those amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under existing economic and operating conditions, at current prices and costs, under existing regulatory practices and with existing technology. Accordingly, any changes in prices, operating and development costs, regulations, technology or other factors could significantly increase or decrease estimates of proved reserves.
Estimates of volumes of proved reserves at year end are presented in barrels (Bbls) for oil and for, natural gas, in thousands of cubic feet (Mcf) at the official temperature and pressure bases of the areas in which the gas reserves are located.
The proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include decline curve analysis, which utilized extrapolations of historical production and pressure data available through August 31, 2012, in those cases where this data was considered to be definitive. The data used in this analysis was obtained from public data sources and were considered sufficient for calculating producing reserves.
The proved non-producing and undeveloped reserves were estimated by the analogy method. The analogy method uses pertinent well data obtained from public data sources that were available through August 2012.
The estimates of our present value of estimated future net revenues from such reserves is based upon the standardized measure of discounted future net cash flows relating to proved oil and gas reserves in accordance with the provisions of Accounting Standards Codification Topic 932, Extractive Activities - Oil and Gas. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on period-end economic conditions. The estimated future production is based upon benchmark prices that reflect the unweighted arithmetic average of the first-day-of-the-month price for oil and gas during the year ended August 31, 2012. The resulting estimated future cash inflows are then reduced by estimated future costs to develop and produce reserves based on period-end cost levels. No deduction has been made for depletion, depreciation or for indirect costs, such as general corporate overhead. Present values were computed by discounting future net revenues by 10% per year.
We have represented to AJM Deloitte, our independent engineers that we have provided all relevant operating data and documents, and in turn, we review the reserve reports provided by the independent engineers to ensure completeness and accuracy. Management cautions that there are many inherent uncertainties in estimating proved reserve quantities and related revenues and expenses, and in projecting future production rates and the timing and amount of development expenditures. Accordingly, these estimates will change, as future information becomes available.
The Company’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves as of August 31, 2012 and 2011, changes in estimated proved reserves during the last two years, and estimates of future net cash flows from proved reserves are contained in Note 11 - Supplementary Oil and Gas Information in the Notes to Consolidated Financial Statements included in this Form 10-K. Estimated future net cash flows as of August 31, 2012, were calculated using a discount rate of 10 percent per annum, end of period costs, and an un-weighted arithmetic average of commodity prices in effect on the first day of each month in 2012, and held flat for the life of the production, in accordance with the SEC guidelines.
(1)
We refer to PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated using a discount rate of 10%. This amount includes projected revenues, estimated production costs and estimated future development costs. PV-10 is not a financial measure prescribed under generally accepted accounting principles (GAAP); therefore, the table reconciles this amount to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Management believes that the non-GAAP financial measure of PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 is used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of this pre-tax measure is valuable because there are unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. Average prices used in determining future net revenues were $2.14 per Mcf of gas.
Other
Our offices are located at 333 North Sam Houston Parkway East, Suite 410, Houston, Texas 77060. Our offices are provided at will, and at no cost, by Holloman Corporation, our largest shareholder.
Please also see Item 1 of this report for additional information regarding our oil and gas properties.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
None.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES.
None
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
In August 2010 our common stock began trading on the OTC Bulletin Board under the symbol “EFLO”. There was no established trading market for our common stock prior to that date. The following chart shows the high and low bid prices as quoted on the OTC Bulletin Board or OTCQB Markets for each quarter during the fiscal years ended August 31, 2012 and 2011. Such prices represent quotations between dealers, without dealer markup, markdown or commissions, and may not represent actual transactions.
There is currently only a limited market for our common stock. A limited market is characterized by a relatively limited number of shares in the public float, relatively low trading volume and the small number of brokerage firms acting as market makers. The market for low priced securities is generally less liquid and more volatile than securities traded on national stock markets. Fluctuations in market prices are not uncommon. No assurance can be given that the market for our common stock will continue or that the stock price will be maintained.
As of November 29, 2012, we had 19,009,205 outstanding shares of common stock and approximately 55 certificated shareholders of record.
On June 30, 2010, a 20 for 1 forward stock split, approved by our shareholders on April 28, 2010, became effective.
Holders of our common stock are entitled to receive dividends as may be declared by our Board of Directors. Our Board of Directors is not restricted from paying any dividends but is not obligated to declare a dividend. We have not declared any dividends and we do not plan to declare any dividends in the foreseeable future. We plan to retain earnings to finance the expansion of our operations.
During the period from October 20, 2012 through October 31, 2012, we sold 530,666 shares of our common stock to eight (8) accredited investors at a price of $1.20 per share. Gross proceeds from this private placement totaled $636,800. We paid $22,288 in finder’s fees in connection with the sale of these shares.
We relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 with respect to these sales. The purchasers were sophisticated investors who were provided full information regarding our business and operations. There was no general solicitation in connection with the offer or sale of these shares. The certificates representing the shares will bear a restricted legend providing that they cannot be sold unless pursuant to an effective registration statement or an exemption from registration.
During the year ended August 31, 2012 we did not purchase any shares of our common stock from third parties in a private transaction or the open market. During the year ended August 31, 2012 none of our officers or directors, nor any of our principal shareholders, purchased any shares of our common stock on our behalf from third parties in a private transaction or as a result of purchases in the open market.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
Not applicable.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
General
We are a development stage company incorporated in the State of Nevada on July 22, 2008. We are engaged in the acquisition, exploration and development of oil and gas properties in the United States and Canada.
During the period from July 18, 2012 through October 17, 2012, we acquired working interests totaling 53.65% (including a 100% working interest in one gas well) in the Kotaneelee Gas Project (“KGP”) located on 30,542 gross acres in the Yukon Territory in Canada. We believe the KGP has significant conventional and shale gas potential and is supported by an environment of growing investment in gas processing and export in the Pacific Northwest.
Our acquisition of an initial working interest of 22.989% (including a 69.337% working interest in one gas well) in the KGP was completed on July 18, 2012, with an effective date of July 1, 2012. Since that date, we have been responsible for the operations of the KGP and have recognized our portion of its related revenues and costs.
During March 2011, we initiated oil and gas operations by entry into a the Eagleford Agreement which provided for our acquisition of a net working interest, ranging from 21.25% to 42.5%, in a 2,629 acre oil and gas lease known as the Matthews Lease, insofar as that lease covers from the surface to the base of the San Miguel formation (the “San Miguel Lease”). The San Miguel Lease is located in Zavala County, Texas, and has no current production or proven reserves.
Prior to our initial working interest acquisition in the KGP, we had generated no revenues and had no proven reserves. We have acquired reserves in connection with our acquisition of the KGP and have begun to generate revenue. See Item 2 of this report for a more detailed discussion of the KGP.
Financial Condition and Results of Operations
KGP
For the period from July 1, 2012 (the effective date of our initial KGP working interest acquisition) to August 31, 2012, we have recognized revenues from gas sales of $251,290 (net of royalties of $6,309). All of our revenues related to production from our L-38 well which was temporarily shut-in for plant maintenance during September 2012. In total, we sold 111,425 mcf of natural gas during this period at an average sales price of $2.31 per mcf.
For July and August 2012, our lease operating expenses totaled $255,143. Our operating expenses for the two month period were higher than average as they contained deferred maintenance costs relating to on-site road maintenance. Recurring depreciation, depletion and amortization expense totaled $400,744 during the same period.
See Items 1 and 2 of this report for a more detailed discussion of the KGP.
The San Miguel Lease
Under the Eagleford Agreement, to earn our initial 21.25% working interest (net revenue interest 15.94%), we were obligated to drill and complete a vertical Test Well in the San Miguel shale formation. We were also obligated to perform an injection operation on the Test Well. If the Test Well was prospective for production in commercial quantities, we were required to equip the Test Well and place it on production. If we determine that the Test Well is not prospective for production in commercial quantities, we are responsible for the abandonment of the Test Well.
During April and May 2011, we drilled and completed the Test Well, performed injection operations and earned our initial interest in the San Miguel Lease. The Test Well was drilled into the San Miguel heavy oil zone to a depth of 3,168 feet. The well encountered oil and was completed as a San Miguel producer. After completion, it was determined that the oil was subject to significant viscosity changes related to temperature reductions from formation to recovery at surface. The Test Well was stimulated with nitrified hydrochloric acid and placed on production. To date, however, oil viscosity has prohibited economic operation. Although we continue to investigate various methods to improve production from the Test Well, we cannot estimate what cost, if any, will be associated with future production efforts on the San Miguel Lease. We have no current plans to spend the funds necessary to earn an additional interest in the San Miguel Lease. In the event we are unable to substantially improve production, we intend to abandon the Test Well, or actively pursue the sale of our interest in the San Miguel Lease.
As a result of the application of a full cost pool "ceiling test", we determined that the book value of the San Miguel Lease was impaired to the extent of its carrying value. Accordingly, during the years ended August 31, 2012 and 2011, we recognized losses on the impairment of oil and gas assets of $44,335 and $835,659, respectively. The carrying value of oil and gas properties was likewise reduced to reflect the impairment of the Lease. We have made no additional expenditures on the San Miguel Lease since November 30, 2011.
Other
Our loss from operations increased by $1,660,000 (101%) from $1,547,000 to $3,207,000 for the year ended August 31, 2012. In largest part, this increased loss was the result of amounts recognized during fiscal 2012 as stock-based fees and compensation paid to our officers and directors, and net operating losses incurred in connection with the KGP.
During the year ended August 31, 2012, we increased our Board of Directors from four (4) to six (6) members and added two (2) new officers. We began to expand both the number and experience of our executive team during the year ended August 31, 2011. We had not, however fully addressed compensation relating to these individuals. We believe the services of this executive team are necessary to support our current and future financing and operating efforts.
During the year ended August 31, 2011, we had approximately $174,000 in management and director’s fees and no stock based compensation expense. During fiscal 2012 we paid or accrued cash-based management and director’s fees of $146,000. The remaining $1,641,000 in management and director’s fees and stock-based compensation consisted of; $621,000 (300,000 shares) issued in connection with our 2012 Stock Bonus Plan, $247,000 recognized in fair value of options granted under the 2012 Stock Option Plan, $210,000 (109,660 shares) in fees payable to our Chief Executive Officer, and $563,000 (236,505 shares) payable as finder’s fees to in connection with our acquisition of the KGP.
Consulting, travel and legal expense incurred during the years ended August 31, 2012 and 2011, in connection with our pursuit of the acquisition of the KGP totaled approximately $566,000 and $355,000, respectively. The expenses incurred during the year ended August 31, 2012 include $288,900 in finder’s fees incurred in connection with the acquisition of the KGP which are payable to a consultant in shares of our common stock (118,235 shares).
During the year ended August 31, 2011, we raised $1,709,401 through debt and equity financings and invested approximately $1,191,000 in the exploration of the San Miguel Lease and our pursuit of the acquisition of the KGP. Our residual general and administrative expense for the year ended August 31, 2011 (approximately $356,000) resulted from an expansion of our executive team and professional resources, and the enhancement of our accounting and administrative infrastructure.
We expect our expenses will continue to increase as we expand operations. We are actively seeking additional capital to fund those expenditures.
Liquidity and Capital Resources
The oil and gas industry is cyclical in nature and tends to reflect general economic conditions. The pattern of historic price fluctuations in oil and gas has resulted in additional uncertainty in capital markets. Our access to capital, as well as that of our partners and contractors, has been limited due to tightened credit markets. These limitations may inhibit the size and timing of formation of exploration ventures.
We plan to generate profits by drilling productive oil or gas wells or improving the production of existing wells. We will, however, need to raise the funds we require through the sale of our securities, from loans from third parties or by joint venturing operations with third parties which will pay a portion of the costs required to explore for oil and gas in the area covered by our leases. Any wells which we may drill may not produce oil or gas in commercial quantities. We plan to report losses from our operations until such time, if ever, we begin to generate significant revenue from oil and gas sales.
To secure our indemnity of the environmental liabilities associated with the Devon Assets, we provided Devon a corporate guarantee (the “Guarantee”) in the amount of CAD$10,000,000 (USD$10,050,000) and delivered a letter of credit in the amount of CAD$4,380,000 (USD$4,410,000) to Devon (the “Devon LOC”). We also agreed to deliver a letter of credit in the amount of CAD$625,000 (USD$629,000) to the government of the Yukon Territory as soon as practicable (the “Yukon LOC”). The amounts of the Devon LOC and Yukon LOC reduce the amount of the Guarantee on a dollar-for-dollar basis. We intend to actively develop and explore the KGP lands which will defer potential abandonment and reclamation liabilities into the longer term.
The Guarantee was provided to Devon by our largest shareholder, Holloman Corporation, in exchange for 3,250,000 shares of our restricted common stock. Likewise, the Devon LOC was provided to Devon by Pacific LNG Operations Ltd. (“PLNG”). PLNG is also committed to provide the Yukon LOC to the government of the Yukon Territory. In exchange for the Devon LOC and Yukon LOC we issued PLNG 4,000,000 shares of our restricted common stock. Our directors, James Ebeling and Eric Prim are officers of Holloman Corporation, and Henry Aldorf, the Chairman of our Board of Directors, is a director of PLNG.
In addition to providing the Yukon LOC, we committed to certain post closing undertakings which include, but are not limited to; the completion of assignments of service, transportation and handling agreements, and the registration of all conveyances and transfers.
We anticipate that our acquisition of the KGP will generate significant capital requirements. During the twelve month period ending November 30, 2013, early estimates indicate that investment in the KGP, including operating costs, the acquisition of additional working interests, and Phase One exploration costs may range from $38,000,000 to $40,000,000. We are attempting to raise the capital needed to implement our business plan.
Other than the obligations associated with the acquisition and exploration of our oil and gas leases disclosed elsewhere in this report, we have no material future contractual obligations as of August 31, 2012.
During the period from June 26, 2012 through October 31, 2012, we sold 4,055,667 shares of our common stock to twelve (12) accredited investors at a price of $1.20 per share. Gross proceeds from these private placements totaled $4,866,800. We paid $149,338 in finder’s fees in connection with the sale of these shares.
During December 2011, we retired $70,000 in non-interest bearing notes payable to an unrelated party. In exchange for the notes, we issued 23,334 investment units to the noteholder. The investment units were priced at $3.00 each and consisted of one share of our common stock, and one stock purchase warrant. Each stock purchase warrant entitles the holder to purchase one share of our common stock at a price of $4.50 per share until November 5, 2013.
During May 2011, we sold 120,000 investment units. The investment units were priced at $3.00 each and consisted of one share of our common stock and one stock purchase warrant. Each stock purchase warrant entitles the holder to purchase one share of our common stock at a price of $4.50 per share until April 15, 2013. Proceeds from the private placement totaled $360,000, all of which were paid in cash. We paid $2,400 in finder’s fees in connection with the sale of the units. Our Chief Executive Officer acquired 50,000 investment units in this private placement.
During April 2011, we sold 390,000 investment units at a price of $3.00 per unit. Each unit consisted of one share of our common stock and one warrant. Each warrant entitles the holder to purchase one share of our common stock at a price of $4.50 per share until April 1, 2013. Proceeds from the private placement totaled $1,170,000, all of which was paid in cash. We paid $46,800 in finder's fees in connection with the sale of the units.
During December 2010, we sold 86,870 investment units at a price of $2.30 per unit. Each unit consisted of one share of our common stock and one warrant. Each warrant entitles the holder to purchase one share of our common stock at a price of $3.50 per share until December 29, 2012. Proceeds from the private placement totaled $191,100 (net of $8,700 in fees) of which $166,100 was paid in cash and $25,000 was a repayment of a loan.
In connection with the San Miguel Farmout Agreement, we obtained $400,000 in temporary financing from our largest shareholder. This financing was subject to a non-interest bearing demand note payable. The entire $400,000 note balance was repaid from proceeds of a private placement of investment units during April 2011.
We believe our plan of operations, exclusive of costs associated with the KGP or other acquired assets, will require from $1,000,000 to $1,500,000 in financing over the twelve-month period ending November 2013.
If we are unable to raise the financing we need, our business plan may fail and our stockholders could lose their investment. There can be no assurance that we will be successful in raising the capital we require, or that if the capital is offered, it will be subject to terms we consider acceptable. Investors should be aware that even if we are able to raise the funds we require, there can be no assurance that we will succeed in our acquisition, exploration or production plans and we may never be profitable.
As of November 29, 2012 we did not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future material effect on our financial condition, changes in financial condition, results of operations, liquidity or capital resources.
Critical Accounting Policies and Estimates
Measurement Uncertainty
The preparation of consolidated financial statements in conformity with US GAAP requires us 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We regularly evaluate estimates and assumptions. We base our estimates and assumptions on current facts, historical experience and various other factors we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities and the accrual of costs and expenses that are not readily apparent from other sources. The actual results experienced by us may differ materially and adversely from our estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected. The most significant estimates with regard to our consolidated financial statements relate to carrying values of oil and gas properties, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows, asset retirement obligations, the valuation of goodwill, determination of fair values of stock-based transactions, deferred income tax rates, and environmental risks and exposures.
Petroleum and Natural Gas Properties
We utilize the full cost method to account for our investment in oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs relating to unproved properties, geological expenditures, tangible and intangible development costs including direct internal costs are capitalized to the full cost pool. When we commence production from established proven oil and gas reserves, capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage, will be depleted on the units-of-production method using estimates of proved reserves. Costs of unproved properties are not amortized until the proved reserves associated with the projects can be determined or until impairment occurs. If an assessment of such properties indicates that properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized.
Depletion, depreciation and amortization (DD&A) of oil and gas properties is calculated quarterly, using the Units of Production Method (UOP). The UOP calculation, in simplest terms, matches the percentage of estimated proved reserves produced each quarter with the costs of those reserves. The result is to recognize expense at the same pace that the reservoirs are actually depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A, estimated future development costs (future costs to access and develop reserves) and asset retirement costs which are not already included in oil and gas property, less related salvage value.
The capitalized costs included in the full cost pool are subject to a "ceiling test" (based on the average of the first-day-of-the-month prices during the twelve-month period prior to August 31, 2012 pursuant to the SEC’s “Modernization of Oil and Gas Reporting” rule), which limits such costs to the aggregate of the (i) estimated present value, using a ten percent discount rate, of the future net revenues from proved reserves, based on current economic and operating conditions, (ii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, (iii) the cost of properties not being amortized, less (iv) income tax effects related to differences between the book and tax basis of the cost of properties not being amortized and the cost or estimated fair value of unproved properties included in the costs being amortized. If net capitalized costs exceed this limit, the excess is charged to expense in the current period. At August 31, 2011, all of our oil and gas interests were impaired and expensed.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations.
Oil and Gas Acquisitions
We account for all property acquisitions that include working interests in proved leasehold, both operated and non-operated, that would generate more than an immaterial balance of goodwill as business combinations. We do not apply acquisition accounting to the purchase of oil and gas properties entirely comprised of unproved leasehold. In accordance with this guidance, we have recognized the fair value of all the assets acquired and liabilities assumed in connection with our KGP working interest acquisition from Devon effective July 18, 2012.
On an ongoing basis, we conduct assessments of net assets acquired to determine if acquisition accounting is appropriate. When we determine a "business" has been acquired under the requirements of ASC Topic 805, we record assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred. We use relevant market assumptions to determine fair value and allocate purchase price, such as future commodity pricing for purchased hydrocarbons, market multiples for similar transactions and replacement value for certain equipment. Many of the assumptions are unobservable.
Asset Retirement Obligations
We record asset retirement obligations based on guidance set forth in ASC Topic 410, as a liability in the period in which we incur an obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The estimated balance of the asset retirement obligation is based on the current cost escalated at an inflation rate and discounted at a credit adjusted risk-free rate. This liability is capitalized as part of the cost of the related asset and amortized over its useful life.
Fair Value Measurements
Our valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:
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Level 1 - quoted prices in active markets for identical assets or liabilities.
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Level 2 - inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).
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Level 3 - unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.
We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. Cash and cash equivalents totaled $2,206,347 and $487,017 at August 31, 2012 and 2011, respectively. We are exposed to a concentration of credit risk with respect to our cash deposits. We place cash deposits with highly rated financial institutions in the United States and Canada. At times, cash balances held in financial institutions may be in excess of insured limits. We believe the financial institutions are financially strong and the risk of loss is minimal. We have not experienced any losses with respect to the related risks and do not believe our exposure to such risks is more than normal.
The estimated fair values for financial instruments are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, other receivables, accounts payable, accrued liabilities and demand notes payable approximates their carrying value due to their short-term nature.
Revenue Recognition
We recognize natural gas revenue under the sales method of accounting for our interests in producing wells as natural gas is produced and sold from those wells. We recognize revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is reasonably assured. Gas sales are reported net of applicable production taxes.
Stock-Based Compensation
We record compensation expense in the financial statements for stock-based payments using the fair value method. The fair value of stock options granted to directors and employees is determined using the Black-Scholes option valuation model at the time of grant. Fair value for common shares issued for goods or services rendered by non-employees are measured based on the fair value of the goods and services received. Stock-based compensation is expensed as earned with a corresponding increase to share capital.
Foreign Currency Gains and Losses
Our functional and reporting currency is the United States dollar. The functional currency of our Canadian subsidiary is the Canadian dollar. Financial statements of our Canadian subsidiary are translated to United States dollars using period-end rates of exchange for assets and liabilities, and average rates of exchange for the period for revenues and expenses. Translation gains (losses) are recorded in accumulated other comprehensive income as a component of stockholders’ equity. Transaction gains and losses are included in the determination of income. Foreign currency transactions are primarily undertaken in Canadian dollars. As of August 31, 2012, we have not entered into derivative instruments to offset the impact of foreign currency fluctuations.
Income Taxes
We follow the asset and liability method of accounting for future income taxes. Under this method, future income tax assets and liabilities are recorded based on temporary differences between the carrying amount of balance sheet items and their corresponding tax bases. In addition, the future benefits of income tax assets, including unused tax losses, are recognized, subject to a valuation allowance, to the extent that it is more likely than not that such future benefits will ultimately be realized. Future income tax assets and liabilities are measured using enacted tax rates and laws expected to apply when the tax liabilities or assets are to be either settled or realized.
Earnings per share
We present both basic and diluted earnings (loss) per share (EPS) on the face of the statements of operations. Basic EPS is computed by dividing net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS gives effect to all dilutive potential common shares outstanding during the period including convertible debt, stock options, and warrants, using the treasury stock method. Diluted EPS excludes all dilutive potential shares if their effect is anti-dilutive. Diluted EPS amounts are equal to those of Basic EPS for each period since we are in a net loss position.
See Note 2 to our consolidated financial statements for a discussion of recent accounting pronouncements.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Attached.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
On September 26, 2011, we dismissed De Joya Griffith & Company, LLC as our independent registered public accounting firm and engaged Weaver and Tidwell, L.L.P. as our independent registered public accounting firm. See our Form 8-K filed with U.S. Securities and Exchange Commission on September 29, 2011.
.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
An evaluation was carried out under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report on Form 10-K. Disclosure controls and procedures are procedures designed with the objective of ensuring that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934, such as this Form 10-K, is recorded, processed, summarized and reported, within the time period specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and is communicated to our management, including our Principal Executive Officer and Principal Financial Officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our management concluded that, as of August 31, 2012, our disclosure controls and procedures were effective.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as required by Sarbanes-Oxley (SOX) Section 404.A. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States and includes those policies and procedures that:
(1)
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets;
(2)
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors; and
(3)
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer's assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. In evaluating the effectiveness of our internal control over financial reporting, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of August 31, 2012.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
See Item 5 of this report for information concerning recent sales of unregistered securities.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Our Directors are elected for a one-year term and hold office until the next annual meeting of our shareholders or until their resignation or removal by a vote of our shareholders. Officers are appointed by the Board of Directors and serve at the discretion of the Board. There is no family relationship between or among any of our Directors or Officers.
Henry Aldorf
Mr. Aldorf joined our Board of Directors as Chairman on June 18, 2012. He has 37 years experience in the petroleum and chemicals industry. Since February 2010, Mr. Aldorf has served as President of Pacific LNG Operations Ltd. and Liquid Niugini Gas Limited. Pacific LNG Operations Ltd. is a substantial indirect interest holder in the Elk and Antelope gas discoveries in Papua New Guinea, and 47.5% LNG partner in Liquid Niugini Gas Limited with InterOil Corporation (NYSE-IOC). From August 2001 to January 2010, Mr. Aldorf held a variety of senior executive positions with Marathon Oil including; President of Marathon International and Vice-President of Global Upstream of Marathon Oil (2008-2010), Senior Vice President International Business Development - Marathon Oil International (2006-2008), Senior Vice-President West Africa, Middle East and Asia Business Development (2005-2006), and Senior Vice-President West Africa Business Development (2004-2005). In the latter position Mr. Aldorf was responsible for Marathon's EG LNG project in Equatorial Guinea and was the first Managing Director of EG LNG Co. Before joining Marathon in 2001, Mr. Aldorf worked for Unocal in a variety of positions of increasing responsibility, in both the chemical and business development organization of that company. His international experience includes Europe, United States, Canada, Russian Federation, Brazil, the Asia Pacific Region, Japan, Korea and China. He graduated from the University of Leiden in the Netherlands, with a Bachelor of Science degree in Chemistry and Biochemistry. He also gained a Master of Science degree in Chemical Engineering from Technical University in Delft in the Netherlands, and holds a master of Business Administration from the INSEAD graduate business school, Fountainebleau, France.
Keith Macdonald
Keith Macdonald was appointed as our Chairman, President, Chief Executive officer and Secretary on March 10, 2011. On June 18, 2012, he resigned from his role as Chairman in favor of Mr. Aldorf. Mr. Macdonald has been President of Bamako Investment Management Ltd., a private holding and financial advisory company since 1994. He is currently Chairman and director of Drakkar Energy Ltd., a private in situ oil sands company. In addition, Mr. Macdonald currently serves on the board of Bellatrix Exploration Ltd. (TSX), Rocky Mountain Dealerships Inc. (TSX), Madalena Ventures Inc. (TSVX), Surge Energy Inc. (TSVX), Mountainview Energy Ltd. (TSVX), Holloman Energy Corporation (OTCQB), WCSB Oil & Gas Royalty Income Funds and Orange Directional Services Inc.. Most recently, he was a director of Profound Energy Inc. (TSX), Cordy Oilfield Services Inc.(TSVX), Stratabound Minerals Inc.(TSVX) and Breaker Energy Ltd (TSX) , and prior thereto a director of several public and private oil and gas companies. Mr. Macdonald was founder, President and Director of New Cache Petroleums from 1987 until it’s amalgamation in 1994 and thereafter Chief Financial Officer and Director until its sale in 1999. He is a past Chairman and director of the Small Explorers and Producers of Canada.
Robert Wesolek
Robert Wesolek, was appointed as a director on June 16, 2011 and was elected as our Chief Financial Officer on August 7, 2012. He has provided us financial consulting services since October, 2010. He has been the Chief Financial Officer of Holloman Energy Corporation since August 4, 2009, and has acted as an executive consultant providing financial, regulatory and system design services to emerging corporations since 2006. Prior to 2006 Mr. Wesolek; served as Chief Financial Officer and director of House of Brussels Chocolates Inc. (2004-2006), President and Chief Executive Officer of The Navigates Corporation (1998-2004), Chief Financial Officer of Sharp Technology Inc. (1998-2001), President of the Desktop Software Division of Citadel Security Software (1996-1998), and Chief Operating Officer of Kent Marsh Ltd., Inc. (1988-1996). During the period from 1980 to 1988, Mr. Wesolek was a Senior Practice Manager in the Audit Division of Arthur Andersen LLP.
James Hutton
Mr. Hutton was elected our President and was appointed as a director on June 18, 2012. He has spent his career in the financial services industry and for the past 25 years has specialized in structured finance and resource company finance. He has served as President and Chief Executive Officer of Hutton Capital Corporation, a company engaged in investment banking since September 1996. In April 1998, Mr. Hutton also founded, and was President and Chief Executive Officer of the Canada Dominion Resources Group of companies, one of the largest flow-through share funds in Canada. The Canada Dominion Resources Group focused their investments on mining and energy issuers actively exploring for resources in Canada. The Canada Dominion Resources Group was acquired from Mr. Hutton by the Dundee/Dynamic Mutual fund organization in December of 2006. In addition, Mr. Hutton was the President and Chief Operating Officer of the CMP Resource Group from 2003 to 2005. He also serves as director of Tasman Metals Ltd. (AMEX/TSXV-TSM), SantaCruz Silver Mining Inc. (TXSV-SCZ), Batero Gold Corp. (TSXV-BAT) and Caymus Resources Inc. (TSXV-CJX).
James Ebeling
James Ebeling was appointed as a director on June 22, 2011. He has been the Chief Financial Officer of Holloman Corporation since November 2007. Holloman Corporation’s operations extend to three continents and include plant and pipeline construction, oil and gas exploration, and international heavy-equipment leasing. During the period from 2001 to 2007, Mr. Ebeling was Vice President of SUEZ Energy North America, Inc. In that capacity, he provided project management and development services on a variety of multi-billion dollar energy related projects. Prior to 2001, Mr. Ebeling served as; Vice President of Hawkins Oil and Gas (1996-2001), Vice President of Transworld Oil Company (1989-1996), Vice President of Anchor Coupling (1984-1989), and Vice President of the Charter Company (1981-1984).
Eric Prim
Eric Prim, was appointed as a director on March 17, 2011. He is the President of Pilot Energy Solutions, and has been Vice President of its affiliate, Holloman Corporation since 1997. He has served as a director of Holloman Energy Corporation (OTCBB) since 2007 and also became that company’s Chief Operating Officer in 2009. Prior to his association with Holloman, Mr. Prim held senior technical management positions with Hunt Energy (1982-1987) and Rexene Corporation (1987-1997). Mr. Prim holds a B.S. in Chemical Engineering from The University of Texas (1982) and an M.B.A. from Amber University (1987). Mr. Prim is a registered Professional Engineer in Texas and holds eight issued or pending U.S. Patents, all pertaining to energy technology.
We believe our directors benefit us as a result of their expertise in the following areas:
Mr. Ebling, Mr. Aldorf and Mr. Prim are independent directors, as that term is defined in Section 803 of the listing standards of the NYSE AMEX. Mr. Ebeling, Mr. Aldorf, and Mr. Prim comprise our Audit Committee. Mr. Ebeling and Mr. Aldorf are our Audit Committee financial experts as that term is defined in Item 407 of Regulation S-K of the Securities and Exchange Commission. Mr. Ebeling and Mr. Aldorf are qualified to act in that capacity by virtue of their extensive experience as senior executive and financial officers in enterprises similar, or more mature than ours. In those capacities, both Mr. Ebeling and Mr. Aldorf have been responsible for the review and analysis of financial statements including the application and assessment of accounting principles, and the implementation and assessment of internal controls.
The board regularly makes inquiries regarding the existence of conflicts of interest and indications of fraudulent behavior. On July 16, 2011, our Board of Directors adopted a code of ethics that applies to our principal executive and financial officers. A copy of our Code of Ethics is included as Exhibit 14.1 to this report.
Our operations to date have been limited. As a result, we have not formed a separate nominating committee to our Board of Directors. Instead, our entire Board of Directors acts in the capacity of that committee.
Compensation Committee Interlocks and Insider Participation
On June 23, 2012 our Board of Directors created a separate Compensation Committee authorized to determine or make recommendations to the Board of Directors concerning officer and director compensation. Mr. Prim and Mr. Ebeling comprise our Compensation Committee.
During the year ended August 31, 2012, our Chief Executive Officer, Keith Macdonald was a director of Holloman Energy Corporation. Two of our directors, Eric Prim and Robert Wesolek are executive officers of Holloman Energy Corporation.
Except for the foregoing, during the year ended August 31, 2012 none of our officers served as a compensation committee member or director of another entity, one of which entity’s officers served as one of our directors.
Compliance with Section 16A of the Exchange Act
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires that our directors and executive officers and persons who beneficially own more than 10% of our common stock (referred to herein as the “reporting persons”) file with the Securities and Exchange Commission various reports as to their ownership of and activities relating to our common stock. Such reporting persons are required by the SEC regulations to furnish us with copies of all Section 16(a) reports they file. Based solely upon a review of copies of Section 16(a) reports and representations received by us from reporting persons, and without conducting any independent investigation of our own, we believe all Forms 3, 4 and 5 were timely filed with the Securities and Exchange Commission by such reporting persons, with the exception of; Holloman Corporation (a greater than 10% shareholder) and its wholly-owned subsidiary which filed a Form 4 for one transaction, two days after its due date; Pacific LNG Operations Ltd. (a greater than 10% shareholder) which filed a Form 3 after its due date; Eric Prim, James Ebeling, and Robert Wesolek (all current directors) each of whom filed a Form 4 covering one transaction, one day after its due date; Henry Aldorf (a current director) who filed a Form 3 and a Form 4 covering one transaction after its due date; James Hutton (a current officer and director) who filed a Form 3 and two Form 4s covering three transactions after their due dates, and Keith Macdonald (a current officer and director) who filed three Form 4s covering three transactions after their due dates.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The following table shows the compensation paid or earned by our executive officers and other reportable person(s) during the two years ended August 31, 2012 and 2011:
Summary Compensation Table
(1)
Mr. Macdonald provides services under the terms of Consulting Services Agreement with Bamako Investment Management Ltd. (“Bamako”), an entity over which he exercises control. This agreement was made effective March 11, 2011 for a twelve month term and may be cancelled by either party, with or without cause, following 30 days notice. We have continued the contract with Mr. Macdonald on a month-to-month basis since the completion of its initial term on March 11, 2012. Under this agreement, Bamako is compensated $20,000 per month for up to 50% of Mr. Macdonald’s time as our Chief Executive Officer, or in such roles as may be approved, from time to time, by our Board of Directors. Compensation is payable in equal parts cash and shares of our restricted common stock. Compensation payable in stock is convertible at the closing price of the stock on the last trading-day of the applicable monthly earning period.
In an effort to conserve cash, Mr. Macdonald elected to accept stock for all but $30,000 of this compensation during fiscal 2012 and 2011. For the year ended August 31, 2012, we paid Bamako $210,000 in stock at a weighted average conversion price of $1.73 per share (121,660 shares). For the year ended August 31, 2011, $113,548 in compensation was paid to Bamako in stock at a weighted average conversion price of $1.84 per share (61,673 shares). In addition, Bamako was granted 50,000 shares of stock (fair value $103,500) and stock options providing for the purchase of 200,000 shares of stock (fair value $188,650) under our 2012 Stock Bonus and Options Plans (Plan details are provided below). Mr. Macdonald also received $5,000 in other compensation for his services as director during 2012.
Bamako also received $281,399 in finder’s compensation, payable in 118,235 shares of stock at $2.38 per share, in connection with our acquisition of the KGP (see footnote 5 to this table). This commission is accrued but unpaid as of November 29, 2012.
(2)
During fiscal 2012 and 2011, we paid Mr. Wesolek financial consulting fees totaling $126,975 and $108,675, respectively. He also received $5,000 in other compensation for his services as director during 2012. In addition, Mr. Wesolek was granted 50,000 shares of stock (fair value $103,500) and stock options providing for the purchase of 200,000 shares of stock (fair value $188,650) under our 2012 Stock Bonus and Options Plans (Plan details are provided below).
Mr. Wesolek also received $281,484 in finder’s compensation, payable in 118,270 shares of stock at $2.38 per share, in connection with our acquisition of the KGP (see footnote 5 to this table). This commission is accrued but unpaid as of November 29, 2012.
(3)
Mr. Hutton provides services as our President under the terms of an informal agreement with Hutton Capital Corporation (“Hutton Capital”), an entity over which he exercises control. Under that agreement, we pay Hutton Capital $10,000 per month. For the year ended August 31, 2012, we paid Hutton Capital $28,161. In addition, Hutton Capital was granted 50,000 shares of stock (fair value $103,500) and stock options providing for the purchase of 200,000 shares of stock (fair value $188,650) under our 2012 Stock Bonus and Options Plans (Plan details are provided below). Mr. Hutton also received $5,000 in other compensation for his services as director during 2012.
(4)
Effective January 20, 2011, Bamako, Mr. Wesolek, and Open Bay Holdings Ltd. (the “Finders”) entered into an agreement with us providing for the payment of finder’s compensation ranging from 5% (on transaction values greater than $1,000,000) to 10% (on transactions values up to $300,000) on transactions introduced to us by or through the Finders for a period of two years (the “Finder’s Fee Agreement”). Under the Finder’s Fee Agreement, compensation is divided between the Finders. The Finders have elected to receive payment in stock. The shares into which finder’s compensation will be converted are calculated using the average closing price of our common stock for the last ten trading days preceding the closing date of the transaction to which the compensation relates. The Finder’s Fee Agreement specifically recognizes that the KGP has been presented to us by the Finder’s. For the year ended August 31, 2012 we accrued a total of $844,283 payable in 354,741 shares of stock at $2.38 per share, in connection with our acquisition of Devon’s working interest in the KGP. This finder’s compensation is accrued but unpaid as of November 29, 2012.
Stock-Based Compensation and Stock Option Grants
On August 27, 2012, we established a Non-Qualified Stock Option Plan and a Stock Bonus Plan (the “Plans”). The Non-Qualified Stock Option Plan (the “Option Plan”) authorizes the issuance of up to 2,000,000 shares of our common stock. The Stock Bonus Plan provides for the issuance of up to 350,000 common shares (“Bonus Shares”). Under the Plans, shares may only be issued to employees, directors, officers, consultants and advisors, provided qualifying services are rendered.
The Compensation Committee to our Board of Directors has full and final authority in its discretion, subject to the provisions of the Plans, and subject to the approval of its Board of Directors, to determine the individuals to whom, and the time or times at which shares or options shall be granted and the number of such shares or options; to construe and interpret the Plans; to determine the terms and provisions of the respective option agreements, which need not be identical, including, but without limitation, terms covering the payment of the option price; and to make all other determinations and take all other actions deemed necessary or advisable for the proper administration of the Plans. All such actions and determinations shall be conclusively binding for all purposes and upon all persons.
We may at any time, and from time to time, amend, terminate, or suspend one or more of the Plans in any manner we deem appropriate, provided that any amendment, termination or suspension may not adversely affect rights or obligations with respect to options or shares previously granted.
The following table shows the options held by our officers and directors as of August 31, 2012. The options in the table were all granted pursuant to our Non-Qualified Stock Option Plan.
Outstanding Equity Awards at August 31, 2012
The following table shows the weighted average exercise price of the outstanding options granted pursuant to our Non-Qualified Stock Option Plan as of August 31, 2012. Our Non-Qualified Stock Option Plan has not been approved by our shareholders.
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On August 27, 2012, we issued shares of our common stock to the following persons pursuant to our Stock Bonus Plan:
At August 31, 2012, 800,000 options and 50,000 shares of our common stock, respectively, remain available for distribution under our Option Plan and Stock Bonus Plan.
We have never offered any annuity, pension or retirement benefits for our officers, directors or employees.
Director’s Compensation
Our Directors are reimbursed for reasonable out-of-pocket expenses in connection with attendance at Board of Director and committee meetings. During 2011, no compensation was paid to our directors.
Director Compensation Table (1)
(1)
This table excludes compensation paid to directors Keith Macdonald, Robert Wesolek and James Hutton who are also our officers. Compensation information relating to these directors is included in the Summary Compensation Table above.
(2)
Each director was granted 50,000 shares of stock (fair value $103,500) under our 2012 Stock Bonus Plan (Plan details are provided above).
(3)
Mr. Aldorf was granted stock options providing for the purchase of 200,000 shares of stock (fair value $188,650) under our 2012 Stock Options Plan. Mr. Prim and Mr. Ebeling were each granted stock options providing for the purchase of 150,000 shares of stock (fair value $141,488) under our 2012 Stock Options Plan (Plan details are provided above).
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table lists, as of November 29, 2012, the shareholdings of (i) each person owning beneficially 5% or more of our common stock (ii) each officer and director, and (iii) all officers and directors as a group. Unless otherwise indicated, each owner has sole voting and investment powers over their shares of common stock.
(1)
Includes 50,000 shares owned directly by Mr. Aldorf, and those stock options detailed in (5) below. Mr. Aldorf also shares investment control over 4,000,000 shares held by Pacific LNG Operations Ltd.
(2)
Includes: (a) 57,000 shares owned directly by Mr. Macdonald, (b) 305,335 shares held of record by Bamako Investment Management and 150,000 shares held of record by Country Rock Resources, Ltd., companies controlled by Mr. Macdonald, (c) 20,000 shares, over which Mr. Macdonald has investment control, which are held of record by a third person, (d) 50,000 shares held of record by Mr. Macdonald's wife, and those stock options detailed in (5) below.
(3)
Includes 750,000 shares held of record by Hutton Capital Corporation, a company over which James Hutton exercises investment control, and those stock options detailed in (5) below.
(4)
Comprised of 4,530,870 shares held of record by Holloman Value Holdings, LLC, a company over which Eric Prim and Jim Ebeling share investment control and those stock options detailed in (5) below.
(5)
Includes the following shares which may be acquired on the exercise of options or warrants listed below.
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* Warrants are held of record by an entity controlled by the named person.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
As detailed more fully in our financial statements and Items 1, 7 and 11 of this report, from time to time, we have had non-interest bearing advances from certain of our directors and shareholders; and non-employee related contract compensation and commission arrangements with our directors and officers. During the year ended August 31, 2011 those advances and arrangements included a temporary loan from our largest shareholder Holloman Value Holdings, LLC in the amount of $400,000 (April 2011) provided to us in connection with the San Miguel Farmout and Participation Agreement. The loan did not bear interest and was repaid by us during May 2011.
As more fully explained in Item 7 of this report, two of our largest shareholders, over which certain of our directors share control, have provided a corporate guarantee or letters of credit in connection with our acquisition of the Devon Assets.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
On September 26, 2011, we dismissed De Joya Griffith & Company, LLC (“DeJoya Griffith”) as our independent registered public accounting firm and engaged Weaver and Tidwell, L.L.P. (“Weaver”) as our independent registered public accounting firm.
The following table sets forth the aggregate fees paid or accrued for professional services rendered by DeJoya Griffith and Weaver for the audit of our annual financial statements for the years ended August 31, 2012 and 2011, and the aggregate fees paid or accrued for audit-related services and all other services rendered by DeJoya Griffith and Weaver for those years.
The category of “Audit-related fees” includes fees for our annual audit, quarterly reviews and services rendered in connection with regulatory filings with the SEC. “Tax fees” include fees incurred in the review and preparation of our annual income tax filings.
The Audit Committee of our Board of Directors pre-approves the scope and estimated costs of all services rendered by our Principal Accountants. We concluded that the service provided by DeJoya Griffith and Weaver was compatible with the maintenance of each firms’ independence in the conduct of its auditing functions.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)
Consolidated Financial Statements
(b)
Exhibits
__________________________
(1)
Incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-1 dated November 12, 2008.
(2)
Incorporated by reference to Exhibit 3.1 to the Company’s 8-K report dated April 28, 2010.
(3)
Incorporated by reference to Exhibit 3.2 to the Company’s 8-K report dated April 28, 2010.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
In accordance with the Securities Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
of EFL Overseas, Inc.
(An Exploration Stage Company)
We have audited the accompanying consolidated balance sheets of EFL Overseas, Inc. (an Exploration Stage Company) (the Company) as of August 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the years then ended, and for the period from inception (July 22, 2008) to August 31, 2012. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit 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 audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EFL Overseas, Inc. (an Exploration Stage Company) as of August 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for the years then ended, and for period from inception (July 22, 2008) to August 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that EFL Overseas, Inc. will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, EFL Overseas, Inc. has not generated significant operating revenues since inception, has incurred losses in developing its business, and further losses are anticipated. EFL Overseas, Inc. requires additional funds to meet its obligations and the costs of its operations. These factors raise substantial doubt about EFL Overseas, Inc.’s ability to continue as a going concern. Management’s plans in this regard are described in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
WEAVER AND TIDWELL, L.L.P.
Houston, Texas
November 29, 2012
EFL OVERSEAS, INC.
(An Exploration Stage Company)
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
EFL OVERSEAS, INC.
(An Exploration Stage Company)
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
EFL OVERSEAS, INC.
(An Exploration Stage Company)
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
EFL OVERSEAS, INC.
(An Exploration Stage Company)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE AND CONTINUANCE OF OPERATIONS
EFL Overseas, Inc. (the “Company”), was incorporated in the State of Nevada on July 22, 2008, and prior to March 2011, was relatively inactive. During March 2011, the Company initiated operations focused on oil and gas exploration and development in the United States and Canada. On July 18, 2012, the Company’s wholly owned subsidiary, EFLO Energy Yukon Ltd., completed an acquisition of Devon Canada’s entire right and interest (generally a working interest of 22.989%, with a working interest of 69.337% in one gas well) in the Kotaneelee Gas Project (Note 4).
The Company’s Consolidated financial statements are prepared on a going concern basis in accordance with generally accepted accounting principles in the United States (“US GAAP”) which contemplates the realization of assets and discharge of liabilities and commitments in the normal course of business. The Company is in the exploration stage. It has not generated operating revenues, and has accumulated losses of $4,838,081 since inception. The Company has funded its operations through the issuance of capital stock and debt. Management plans to raise additional funds through third-party equity or debt financings and the joint venturing of its exploration efforts with third parties. There is no certainty that further funding will be available as needed. These factors raise substantial doubt about the ability of the Company to continue operating as a going concern. The Company’s ability to continue its operations as a going concern, realize the carrying value of its assets, and discharge its liabilities in the normal course of business is dependent upon its ability to raise capital sufficient to fund its commitments and ongoing losses, and ultimately generate profitable operations.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These consolidated financial statements include the accounts of the Company and its wholly owned subsidiary EFLO Energy Yukon Ltd., after elimination of intercompany balances and transactions. The Company’s interest in oil and gas exploration and production ventures and partnerships are proportionately consolidated. These consolidated financial statements and related notes are presented in accordance with US GAAP, and are expressed in United States dollars. The Company is an exploration stage company as defined by “Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 915, Development Stage Entities.”
Use of Estimates
The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company regularly evaluates estimates and assumptions. The Company bases its estimates and assumptions on current facts, historical experience and various other factors it believes to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities and the accrual of costs and expenses that are not readily apparent from other sources. The actual results experienced by the Company may differ materially and adversely from the Company’s estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected. The most significant estimates with regard to these consolidated financial statements relate to carrying values of oil and gas properties, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows there from, asset retirement obligations, the valuation of goodwill, determination of fair values of stock-based transactions, deferred income tax rates, and environmental risks and exposures.
Allowance for Doubtful Accounts
The Company routinely assesses the recoverability of all material receivables to determine their collectability. All of the Company's receivables are from joint venture partners and large gas marketers. The Company is exposed to a concentration of credit risk with respect to its accounts receivable. The Company believes its financial partners are financially strong and the risk of loss is minimal. Generally, the Company's natural gas receivables are collected within three months. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of August 31, 2012 and 2011, the Company had no amount recorded as an allowance for doubtful accounts.
Oil and Gas Properties
The Company utilizes the full cost method to account for its investment in oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs relating to unproved properties, geological expenditures, tangible and intangible development costs including direct internal costs are capitalized to the full cost pool. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in the statement of operations.
Depletion, depreciation and amortization (DD&A) of oil and gas properties is calculated quarterly, using the Units of Production Method (UOP). The UOP calculation, in simplest terms, matches the percentage of estimated proved reserves produced each quarter with the costs of those reserves. The result is to recognize expense at the same pace that the reservoirs are actually depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A, estimated future development costs (future costs to access and develop reserves) and asset retirement costs which are not already included in oil and gas property, less related salvage value. Costs of unproved properties are not amortized until the proved reserves associated with the projects can be determined or until impairment occurs. If an assessment of such properties indicates that properties are impaired, the amount of impairment is added to the capitalized cost base to be amortized.
The capitalized costs included in the full cost pool are subject to a "ceiling test" (based on the average of the first-day-of-the-month prices during the twelve-month period prior to August 31, 2012 pursuant to the SEC’s “Modernization of Oil and Gas Reporting” rule), which limits such costs to the aggregate of the (i) estimated present value, using a ten percent discount rate, of the future net revenues from proved reserves, based on current economic and operating conditions, (ii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, (iii) the cost of properties not being amortized, less (iv) income tax effects related to differences between the book and tax basis of the cost of properties not being amortized. If net capitalized costs exceed this limit, the excess is charged to expense in the current period. At August 31, 2011, all of the Company’s oil and gas properties were impaired and expensed to the extent of their carrying value. At August 31, 2012, the Company recorded no write-downs of the carrying value of its proved oil and gas properties.
Oil and Gas Acquisitions
The Company accounts for the acquisition of oil and gas properties under the requirements of Financial Accounting Standards Board (FASB) ASC Topic 805, Business Combinations (ASC Topic 805), issued in December 2007, with additional guidance issued in April 2009. ASC Topic 805 requires an acquiring entity to recognize all assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided they qualify for acquisition accounting under the standard. The Company accounts for all property acquisitions that include working interests in proved leasehold, both operated and non-operated, that would generate more than an immaterial balance of goodwill as business combinations. The Company does not apply acquisition accounting to the purchase of oil and gas properties entirely comprised of unproved leasehold, which is in compliance with ASC Topic 805. In accordance with this guidance the Company has recognized the fair value of all the assets acquired and liabilities assumed in connection with its Kotaneelee Gas Project working interest acquisition from Devon effective July 18, 2012.
The Company adopted ASC Topic 805 effective December 23, 2009. Accordingly, the Company, on an ongoing basis, conducts assessments of net assets acquired to determine if acquisition accounting is appropriate. As appropriate, the Company properly records assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred. The Company uses relevant market assumptions to determine fair value and allocate purchase price, such as future commodity pricing for purchased hydrocarbons, market multiples for similar transactions and replacement value for certain equipment. Many of the assumptions are unobservable.
Asset Retirement Obligations
The Company records asset retirement obligations based on the guidance set forth in ASC Topic 410, as a liability in the period in which it incurs an obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The estimated balance of the asset retirement obligation is based on the current cost escalated at an inflation rate and discounted at a credit adjusted risk-free rate. This liability is capitalized as part of the cost of the related asset and amortized over its useful life.
Long-Lived Assets
The carrying value of intangible assets and other long-lived assets is reviewed on a regular basis for the existence of facts or circumstances that may suggest impairment. The Company recognizes impairment when the sum of the expected undiscounted future cash flows is less than the carrying amount of the asset. Impairment losses, if any, are measured as the excess of the carrying amount of the asset over its estimated fair value.
Environmental
Oil and gas activities are subject to extensive federal, state and provincial environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when an environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Revenue Recognition
The Company recognizes natural gas revenue under the sales method of accounting for its interests in producing wells as natural gas is produced and sold from those wells. Natural gas sold by the Company is not significantly different from the Company’s share of production. The Company recognizes revenue upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and the Company, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is reasonably assured. Gas sales are reported net of applicable production taxes.
Stock-Based Compensation
The Company records compensation expense in the consolidated financial statements for stock-based payments using the fair value method. The fair value of stock options granted to directors and employees is determined using the Black-Scholes option valuation model at the time of grant. Fair value for common shares issued for goods or services rendered by non-employees are measured based on the fair value of the goods and services received. Stock-based compensation is expensed with a corresponding increase to share capital.
Income Taxes
Income taxes are determined using the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes that date of enactment. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.
The Company accounts for uncertainty in income taxes by applying a two-step method. First, it evaluates whether a tax position has met a more likely than not recognition threshold, and second, it measures that tax position to determine the amount of benefit, if any, to be recognized in the financial statements. The application of this method did not have a material effect on the Company's consolidated financial statements.
Foreign Currency Gains and Losses
The Company’s functional and reporting currency is the United States dollar. The functional currency of our Canadian subsidiary is the Canadian dollar. Financial statements of our Canadian subsidiary are translated to United States dollars using period-end rates of exchange for assets and liabilities, and average rates of exchange for the period for revenues and expenses. Translation gains (losses) are recorded in accumulated other comprehensive income as a component of stockholders’ equity. Transaction gains and losses are included in the determination of income. Foreign currency transactions are primarily undertaken in Canadian dollars. As of August 31, 2012, the Company has not entered into derivative instruments to offset the impact of foreign currency fluctuations.
Earnings Per Share
The Company presents both basic and diluted earnings per share (“EPS”) on the face of the consolidated statements of operations. Basic EPS is computed by dividing net earnings (loss) available to common shareholders by the weighted average number of shares outstanding during the period. Diluted EPS gives effect to all dilutive potential common shares outstanding during the period including convertible debt, stock options, and warrants, using the treasury stock method. Diluted EPS excludes all dilutive potential shares if their effect is anti-dilutive. Diluted EPS amounts are equal to those of Basic EPS for each period since the Company is in a net loss position.
As of August 31, 2012 and 2011, the Company had 1,820,204 and 596,870 shares of its common stock available through the exercise of non-dilutive stock warrants, respectively (Note 8).
Recent Accounting Pronouncements
The Company has reviewed recently issued accounting pronouncements and plans to adopt those that are applicable to it. It does not expect the adoption of these pronouncements to have a material impact on its financial position, results of operations or cash flows.
3. FAIR VALUE MEASUREMENTS
The Company estimates the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the consolidated balance sheet, as well as to supplemental fair value information about financial instruments not carried at fair value.
Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:
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Level 1 - quoted prices in active markets for identical assets or liabilities.
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Level 2 - inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).
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Level 3 - unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquired oil and gas properties are reported at fair value on a nonrecurring basis in the Company’s balance sheet. See Note 2, Oil and Gas Acquisitions for further discussion of the methods and assumptions used to estimate fair values.
Cash, Cash Equivalents and the Fair Value of Financial Instruments
The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. Cash and cash equivalents totaled $2,206,347 and $487,017 at August 31, 2012 and 2011, respectively. The Company is exposed to a concentration of credit risk with respect to its cash deposits. The Company places cash deposits with highly rated financial institutions in the United States and Canada. At times, cash balances held in financial institutions may be in excess of insured limits. The Company believes the financial institutions are financially strong and the risk of loss is minimal. The Company has not experienced any losses with respect to the related risks and does not believe its exposure to such risks is more than normal.
The estimated fair values for financial instruments are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, other receivables, accounts payable, accrued liabilities and demand notes payable approximates their carrying value due to their short-term nature.
4. OIL AND GAS PROPERTIES
Oil and Gas Acquisition - Kotaneelee Gas Project
On July 18, 2012, the Company completed an acquisition of Devon Canada’s (“Devon”) entire right and interest (generally a working interest of 22.989%, with a working interest of 69.337% in one producing gas well) in the Kotaneelee Gas Project (“KGP”). The KGP covers 30,542 gross acres in the Yukon Territory in Canada, and included; a gas dehydration plant (capacity: 70 million cubic feet per day (“MMCFD”)), one gas well producing approximately 3.5 MMCFD, one water disposal well (capacity: 6,000 barrels per day), and two suspended gas wells. The KGP has a fully developed gas gathering, sales and delivery infrastructure, airstrip, roads, flarestack, storage tanks, barge dock and permanent camp facilities.
As consideration for Devon’s working interest in the KGP, (the “Devon Assets”), the Company paid approximately $23,298,000. The consideration was comprised of $290,000 in cash, 7,250,000 shares of the Company’s restricted common stock valued at $15,950,000, and the absorption of $7,058,000 in asset retirement obligations. The Company allocated the consideration paid to the assets acquired based upon their fair value at the date of purchase, as follows:
Capitalized acquisition, exploration and development costs incurred on the KGP during the fiscal year ended August 31, 2012 are summarized as follows:
Revenue and direct costs incurred on the KGP from the date of acquisition through August 31, 2012 are summarized as follows:
San Miguel Oil Project
On March 31, 2011, the Company initiated oil and gas operations by entry into a Farmout and Participation Agreement which provided for its acquisition of a net working interest ranging from 21.25% to 42.5%, in a 2,629 acre oil and gas lease known as the Matthews Lease, insofar as that lease covers from the surface to the base of the San Miguel formation (the “San Miguel Lease”). The San Miguel Lease is located in Zavala County, Texas, is unproven and has no current production.
During April and May 2011, the Company drilled and completed a test well on the San Miguel Lease (the “Test Well”), performed injection operations and earned its initial interest in the Matthews Lease. The Test Well was drilled into the San Miguel heavy oil zone to a depth of 3,168 feet. The well encountered oil and was completed as a San Miguel producer. After completion, it was determined that the oil was subject to significant viscosity changes related to temperature reductions from formation to recovery at surface. The Test Well was stimulated with nitrified hydrochloric acid and placed on production. To date, however, oil viscosity has prohibited economic operation. As a result of the application of a full cost pool "ceiling test", the Company determined that the book value of the San Miguel Lease was impaired to the extent of its carrying value. Accordingly, during August 2011 and November 2011, the Company recognized losses on the impairment of oil and gas assets of $835,659 and $44,335, respectively. The carrying value of oil and gas properties was likewise reduced to reflect the impairment of the San Miguel Lease.
The Company continues to investigate various methods to improve production from the Test Well. In the event the Company is unable to substantially improve production, it intends to abandon the Test Well, or actively pursue the sale of its interest in the Matthews Lease.
The costs incurred on the Mathews Lease during the fiscal years ended August 31, 2012 and 2011 are summarized as follows:
5. ASSET RETIREMENT OBLIGATIONS
In connection with its acquisition of the Devon Assets, the Company acquired $7,057,716 in asset retirement obligations relating with its portion of the abandonment, reclamation and environmental liabilities associated with the KGP. The Company also incurred $80,000 in asset retirement obligations related to the future plugging and abandonment of the Test Well on the San Miguel Lease. Under the provisions of “ASC Topic 410, Asset Retirement and Environmental Obligations”, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is amortized over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
At August 31, 2012, the Company’s interest in the San Miguel Lease was impaired and expensed to the extent of its carrying value, which included the full amount of the associated asset retirement obligation. The entire asset retirement obligation relating to the San miguel Lease has been classified as a current liability. The present value of the asset retirement obligation acquired in connection with the KGP is equivalent to its fair value computed as of July 18, 2012.
The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. As part of the Company’s acquisition of the Devon Assets, it provided Devon a corporate guarantee (the “Guarantee”) in the amount of CAD$10,000,000 (USD$9,980,000) and delivered a letter of credit in the amount of CAD$4,380,000 (USD$4,371,000) to Devon (the “Devon LOC”). The Company also agreed to deliver a letter of credit in the amount of CAD$625,000 (USD$624,000) to the government of the Yukon Territory as soon as practicable (the “Yukon LOC”). The amounts of the Devon LOC and Yukon LOC reduce the amount of the Guarantee on a dollar-for-dollar basis. The Company is primarily responsible for payment of all asset retirement obligations. The Guarantee, Devon LOC and Yukon LOC are only available to Devon in the event the Company defaults upon its asset retirement obligations relating to the Devon Assets.
The following table summarizes the Company’s asset retirement obligation transactions the fiscal years ended August 31, 2012 and 2011:
6. NOTES PAYABLE
Non-interest bearing notes, unsecured and payable upon demand to unrelated parties:
On December 26, 2011, the Company retired $70,000 in non-interest bearing notes payable to an unrelated party using 23,334 investment units paid to the noteholder (Note 8). The residual balance was paid in cash.
7. RELATED PARTY TRANSACTIONS
In connection with its acquisition of the Devon Assets, the Company acquired $7,057,716 in asset retirement obligations with its portion of the abandonment, reclamation and environmental liabilities associated with the KGP. To secure its obligation, the Company provided Devon the Guarantee, the Devon LOC, and the Yukon LOC (Note 5). The Guarantee was provided to Devon by the Company’s largest shareholder, Holloman Corporation, in exchange for 3,250,000 shares of its restricted common stock. Likewise, the Devon LOC was provided to Devon by Pacific LNG Operations Ltd. (“PLNG”). PLNG is also committed to provide the Yukon LOC to the government of the Yukon Territory. In exchange for the Devon LOC and Yukon LOC the Company issued PLNG 4,000,000 shares of its restricted common stock. Our directors, James Ebeling and Eric Prim are officers of Holloman Corporation, and Henry Aldorf, the Chairman of the Company’s Board of Directors, is a director of PLNG.
Effective January 20, 2011, a company controlled by the Company’s Chief Executive Officer, its Chief Financial Officer, and an unrelated consultant (the “Finders”) entered into an agreement with the Company providing for the payment of finder’s compensation ranging from 5% (on transaction values greater than $1,000,000) to 10% (on transactions values up to $300,000) on transactions introduced to the Company by or through the Finders for a period of two years (the “Finder’s Fee Agreement”). Under the Finder’s Fee Agreement, compensation is divided equally between the Finders and the Finders may elect whether the finder’s compensation is payable in cash, or shares of the Company’s restricted common stock. If the Finders elect to receive payment in stock, the shares into which finder’s compensation will be converted will be calculated using the average closing price of the Company’s common stock for the ten trading days preceding the closing date of the transaction to which the compensation relates. The Finder’s Fee Agreement specifically recognizes that the KGP has been presented to the Company by the Finder’s. As of August 31, 2012 total finder’s compensation of $844,282 has been accrued under the Finder’s Fee Agreement in connection with the Company’s acquisition of the KGP.
In connection with the San Miguel Agreement, the Company obtained $400,000 in temporary financing from its largest shareholder. This financing was subject to a non-interest bearing demand note payable. The entire $400,000 note balance was repaid by the Company during May 2011.
During fiscal years 2012 and 2011, management fees totaling $240,000 and $113,548, respectively, were incurred with an entity controlled by the Company’s Chief Executive Officer. Under the terms of a consulting agreement, this compensation is payable in equal parts cash and shares of the Company’s restricted common stock (Note 8). The fees were incurred as compensation for services rendered in the normal course of operations. The amount and form of the compensation was established and approved by the Company’s Board of Directors. Amounts of $20,000 and $113,548 of this compensation remained unpaid as of August 31, 2012 and 2011, respectively.
During fiscal years 2012 and 2011, fees totaling $150,900 and $108,675 were incurred with one of the Company’s directors for services provided as a financial consultant. That director became the Company’s Chief Financial Officer during August 2012. Fees in the amount of $28,948 and $14,285 were accrued and unpaid as of August 31, 2012 and 2011, respectively. The fees were incurred as compensation for services rendered in the normal course of operations and were paid at the amount established and agreed to by the related parties.
During fiscal year 2012, management fees totaling $23,161 (2011- $0.00) were incurred with an entity controlled by the Company’s President. The amount of compensation was established and approved by the Company’s Board of Directors. A balance of $47,106, which includes all fees incurred and certain reimbursable expenses, remained unpaid as of August 31, 2012.
8. CAPITAL STOCK AND STOCK-BASED COMPENSATION
Sales of Common Stock and Investment Units
During the period from June 2012, through August 2012, the Company sold 2,525,001 shares of its common stock to nineteen (19) accredited investors at a price of $1.20 per share. Proceeds, net of fees of $85,050 from these private placements, totaled $2,944,950. The sales were made pursuant to the terms of the offering approved by our Board of Directors on May 29, 2012. The Company’s President acquired 500,000 shares in the private placement under these terms.
To secure obligations undertaken in connection with the Company’s acquisition of the Devon Assets, the Company provided Devon the Guarantee, the Devon LOC, and the Yukon LOC (Note 5). The Guarantee was provided to Devon by the Company’s largest shareholder, Holloman Corporation, in exchange for 3,250,000 shares of its restricted common stock with a market value of $2.20 per share. Likewise, the Devon LOC was provided to Devon by Pacific LNG Operations Ltd. (“PLNG”). PLNG is also committed to provide the Yukon LOC to the government of the Yukon Territory. In exchange for the Devon LOC and Yukon LOC the Company issued PLNG 4,000,000 shares of its restricted common stock with a market value of $2.20 per share. The total market value of the 7,250,000 restricted shares provided in connection with acquisition is $15,950,000.
On December 26, 2011, the Company retired $70,000 in non-interest bearing notes payable to an unrelated party. In exchange for the notes, the Company issued 23,334 investment units to the note holder. The investment units were priced at $3.00 each and consisted of one share of the Company’s common stock, and one stock purchase warrant. Each stock purchase warrant entitles the holder to purchase one share of the Company’s common stock at a price of $4.50 per share until November 5, 2013.
During May 2011, the Company sold 120,000 investment units. The investment units were priced at $3.00 each and consisted of one share of the Company’s common stock, and one stock purchase warrant. Each stock purchase warrant entitles the holder to purchase one share of the Company’s common stock at a price of $4.50 per share until April 15, 2013. Proceeds from the private placement totaled $360,000, all of which was paid in cash. The Company paid $2,400 in finder’s fees in connection with the sale of the units. The Company’s Chief Executive Officer acquired 50,000 investment units in the private placement under these terms.
During March 2011, the Company sold 390,000 investment units. The investment units were priced at $3.00 each and consisted of one share of the Company’s common stock, and one stock purchase warrant. Each stock purchase warrant entitles the holder to purchase one share of the Company’s common stock at a price of $4.50 per share until April 1, 2013. Proceeds from the private placement totaled $1,170,000, all of which was paid in cash. The Company paid $46,800 in finder’s fees in connection with the sale of the units.
During December 2010, the Company sold 86,870 investment units. The investment units were priced at $2.30 each and consisted of one share of the Company’s common stock, and one stock purchase warrant. Each stock purchase warrant entitles the holder to purchase one share of the Company’s common stock at a price of $3.50 per share until December 29, 2012. Proceeds from the private placement totaled $199,800 of which $174,800 was paid in cash and $25,000 was issued as repayment of indebtedness to the Company’s largest shareholder. Finder’s fees in the amount of $8,700 were paid in connection with the sale of the units.
Stock-Based Compensation
On August 27, 2012, the Company established a Non-Qualified Stock Option Plan and a Stock Bonus Plan (the “Plans”). The Non-Qualified Stock Option Plan (the “Option Plan”) authorizes the issuance of up to 2,000,000 shares of the Company’s common stock. The Stock Bonus Plan provides for the issuance of up to 350,000 common shares (“Bonus Shares”). Under the Plans, shares may only be issued to employees, directors, officers, consultants and advisors, provided qualifying services are rendered.
The Company has full and final authority in its discretion, subject to the provisions of the Plans, and subject to the approval of its Board of Directors, to determine the individuals to whom, and the time or times at which shares or options shall be granted and the number of such shares or options; to construe and interpret the Plans; to determine the terms and provisions of the respective option agreements, which need not be identical, including, but without limitation, terms covering the payment of the option price; and to make all other determinations and take all other actions deemed necessary or advisable for the proper administration of the Plans. All such actions and determinations shall be conclusively binding for all purposes and upon all persons.
The Company may at any time, and from time to time, amend, terminate, or suspend one or more of the Plans in any manner they deem appropriate, provided that any amendment, termination or suspension may not adversely affect rights or obligations with respect to options or shares previously granted.
Issuance of Options and Bonus Shares
On August 27, 2012, the Company granted options to officers,directors and consultants under the terms shown below. The options were granted pursuant to the Option Plan.
In applying the Black-Scholes model, the Company used; expected terms of 2-5 years, historical stock price volatility of 67%, a risk-free rate of 4.5% and annual dividend rate of 0%.
The weighted-average grant-date fair value of options granted during fiscal 2012 was $0.94.
As of August 31, 2012 there was $885,000 of total unrecognized compensation cost related to non-vested share-based compensation under the Option Plan. Of this amount, $554,000 is expected to be recognized during fiscal 2013, and $331,000 during fiscal 2014. A total of $246,976 in non-cash, stock-based compensation has been recognized in the consolidated statement of operations during 2012 in connection with the Option Plan.
On August 27, 2012, the Company issued 300,000 shares of its common stock to officers and directors pursuant to the Stock Bonus Plan. The fair value for shares of common stock given as compensation is the market price of the stock at date of grant. The 300,000 Bonus Shares had a value of $2.07 per share. The Company recognized non-cash management and director’s fees of $621,000 related to the Bonus Shares in the statements of operations.
Other Stock-Based Compensation
During fiscal years 2012 and 2011, management fees totaling $240,000 and $113,548, respectively, were incurred with an entity controlled by the Company’s Chief Executive Officer. At August 31, 2011, all fees incurred under this arrangement remained unpaid. During the year ended August 31, 2012, $323,548 in fees were paid in shares of the Company’s restricted common stock at a weighted average conversion price of $2.018 per share (160,360 shares).
Stock Warrants and Other
At August 31, 2012, warrants for 620,204 shares of the Company’s common stock were issued and outstanding with a weighted-average remaining life and exercise price of 6.98 months and $4.35, respectively. Of these warrants, 23,334 were issued during fiscal 2012, and 596,870 were were issued during fiscal year 2011. No warrants have been exercised or forfeited since inception.
On April 28, 2010, shareholders owning a majority of the Company’s outstanding shares approved a 20 for 1 forward split of its common stock. The forward stock split became effective on June 30, 2010. All references in these financial statements and related notes to number of shares, price per share and weighted average number of shares outstanding prior to this split have been adjusted to reflect the split on a retroactive basis unless otherwise noted. At no time has the Company issued more common stock than is legally authorized.
9. INCOME TAXES
The Company is subject to United States federal income taxes at an approximate rate of 35%, and Canadian income taxes at a rate of 30%. The reconciliation of the provision for income taxes at the applicable statutory rate compared to the Company’s income tax expense as reported is as follows:
The significant components of deferred income tax assets at August 31, 2012 and 2011 are as follows:
At August 31, 2012, the Company had accumulated United States and Canadian non-capital loss carry-forwards of approximately $1,558,755 and $720,949, respectively, that expire in 2032.
The potential future tax benefits of these expenses and losses carried-forward have not been reflected in these consolidated financial statements due to the uncertainty regarding their ultimate realization.
The Company has no uncertainties in income tax positions which, in the opinion of its management, need to be recognized in the consolidated financial statements. The Company’s tax returns for all years since inception remain open to review and examination by tax authorities.
10. SUBSEQUENT EVENTS
Oil and Gas Acquisition - Kotaneelee Gas Project
On October 17, 2012, the Company completed a Share Purchase Agreement (the “Purchase Agreement”) with Nahanni Energy Inc., 1700665 Alberta Ltd., Apex Energy (2000), Inc. and Canada Southern Petroleum #1 L.P. (jointly “Nahanni”) for the acquisition of its entire right and interest (generally a working interest of 30.664%) in the KGP (the “Nahanni Assets”).
As consideration for the Nahanni Assets, the Company paid Nahanni CAD$400,000 (USD$398,550) in cash, and CAD$4,100,000 (USD$4,190,610) in shares of one of the Companies subsidiaries, which are exchangeable for 1,614,767 shares of the Company’s restricted common stock. The cash portion of Nahanni’s consideration was offset by CAD$270,000 (USD$265,950) paid in connection with the acquisition of the Devon Assets in settlement of certain Nahanni indebtedness. The number of shares issued by the Company’s subsidiary was calculated by dividing $4,190,610 by the volume weighted average trading price of the Company’s stock for the ten (10) trading days prior to closing the Purchase Agreement. Both the cash paid and stock issued for the Assets are subject to certain holdbacks for Asset related liabilities or breach of representations and warranties.
In addition, the Company indemnified Nahanni against its portion of the abandonment, reclamation and environmental liabilities associated with the Nahanni Assets. Early estimates of those liabilities range from $9,000,000 to $10,000,000.
As a result of the closing of the Nahanni acquisition, the Company now generally owns a 53.67% interest in the KGP, including an 100% interest in one producing well which was temporarily shut-in for maintenance subsequent to August 31, 2012.
Sales of Common Stock
During October 2012, the Company sold 1,530,666 shares of its common stock to ten (10) accredited investors at a price of $1.20 per share. Gross proceeds from these private placements totaled $1,836,800. We paid $64,288 in finder’s fees in connection with the sale of these shares. The sales were made pursuant to the terms of the offering approved by our Board of Directors on May 29, 2012.
11. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Estimated Net Quantities of Oil and Natural Gas Reserves
The following estimates of the net proved oil and natural gas reserves of our oil and gas properties, located entirely in Canada, are based on evaluations prepared by AJM Deloitte, (“AJM”) independent petroleum engineers. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.
Estimated quantities of proved domestic oil and gas reserves and changes in quantities of proved developed and undeveloped reserves in barrels (Bbls) and thousands of cubic feet (Mcf) for each of the periods indicated were as follows:
As of August 31, 2012, on a barrel of equivalent basis, 61% (2011 - NIL) of our estimated reserves, respectively, were classified as proved undeveloped. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 11, under “standardized measure of discounted future net cash.”
We did not have any PUD reserves that were not scheduled to be converted into proved developed reserves within the five year requirement at August 31, 2012.
Standardized Measure of Discounted Future Net Cash Flows
A summary of the standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is shown below. Future net cash flows are computed using the average of the first-day-of-the-month commodity prices during the 12-month period ending on August 31, 2012, costs and statutory tax rates (adjusted for tax credits and other items) that relate to our existing proved crude oil and natural gas reserves.
The standardized measure of discounted future net cash flows related to proved oil and gas reserves as of August 31, 2012 and 2011 are as follows:
Changes in Standardized Discounted Future Net Cash Flows
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil and natural gas reserves follows: