ITEM 1. BUSINESS.
General
EFLO Energy, Inc. (formerly, EFL Overseas, Inc.) is a development stage company incorporated in 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. Under U.S. GAAP we have only one reportable operating segment which focuses upon our development of the Kotaneelee Gas Project (the “KGP”).
During March 2011, we initiated oil and gas operations by entry into the Eagleford Agreement which provided for our acquisition of a net working interest, ranging from 21.25% to 42.5%, in the San Miguel Lease. The San Miguel Lease is located in Zavala County, Texas. Our investment in the San Miguel Lease has been fully impaired, and we have no current production or reserves relating to that investment.
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 shut in gas well) in the KGP located 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. The KGP has no proven reserves.
We completed our acquisition of an initial working interest of 22.989% (including a 69.337% working interest in one shut in gas well) in the KGP 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 net revenues and development costs as an increase to the unamortized cost pool related to our unproven interests while economic viability is being evaluated.
Prior to our initial working interest acquisition in the KGP, we had generated no revenues.
On March 1, 2013, our shareholders approved amendments to our Articles of Incorporation to: (a) change our name to "EFLO Energy, Inc."; and (b) change our authorized capital to 150,000,000 shares of common stock and 10,000,000 shares of preferred stock.
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 KGP covers 30,188 gross acres in the Yukon Territory in Canada, and includes; a gas dehydration plant, one shut in gas well, one water disposal well (capacity: 6,000 bbl/d), 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 a 24 person permanent camp facility. The KGP’s gas dehydration plant has a processing capacity of 70 MMcf/d, outlet gas compression of 1,200 psig and is tied-in to a 24-inch gas sales line to a gas processing plant in Fort Nelson, British Columbia. The Fort Nelson plant is owned and operated by Spectra Energy and connected to the North American gas grid with a delivery capacity of approximately 1 Bcf/d.
The KGP is located in the Liard Basin, a Western Canadian sedimentary basin. The Liard Basin extends across the border between northeast British Columbia and the southeastern-most corner of the Yukon. It is located west of the Horn River Basin, between the Rocky Mountains to the south and the Mackenzie and Franklin Mountains to the north.
The Liard Basin in the Yukon Territory contains portions of three fields that are all on trend with each other: Beaver River Field, Kotaneelee Field and Pointed Mountain Field. The Kotaneelee field is currently the only field with in place infrastructure capable of production in the Yukon Territory. These three fields all produced from the Nahanni formation which is a naturally fractured Devonian carbonate section. The Nahanni formation at the KGP has produced over 230 Bcf of gas out of three wells with two such wells having had calculated AOF's of 200 to 430 Mcf/d. We believe that there are remaining volumes of gas in the Nahanni reservoir at the KGP and plan to exploit these resources are part of our business plan.
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 shut in gas well) in the KGP. 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 our restricted common stock valued at $15,950,000, and the absorption of approximately $7,058,000 in asset retirement obligations.
On October 17, 2012, we 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, we paid Nahanni approximately $13,761,000. The consideration was comprised of approximately $133,000 in cash ($398,550 offset by $265,950 paid in connection with the acquisition of the Devon Assets in settlement of certain Nahanni indebtedness), 1,614,767 shares of one of our subsidiaries, which are exchangeable, under certain terms and circumstances, for 1,614,767 shares of our restricted common stock valued at approximately $4,191,000, and the absorption of approximately $9,437,000 in asset retirement obligations. The number of shares issued by our subsidiary was calculated by dividing the fair value of the exchangeable shares 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.
As a result of its purchase of the Nahanni Assets and Devon Assets, the Company now generally owns a 53.65% interest in the KGP, including a 100% interest in one gas well which has been shut in while economic viability is being evaluated.
After giving effect to these acquisitions, the current voting interest allocations in the KGP are described in the table below:
During the tenure of Nahanni's prior ownership of the Nahanni Assets, Nahanni entered into an agreement with a third party in consideration of certain funding obligations of the third party (which were in part never performed by the third party) which would enable the third party to earn potential net profits interests in a portion of the Nahanni Assets. We are of the view that the foregoing agreement potentially resulted in a 20% net profit interest applicable to a maximum of 250 Mcf/d of production in certain of the Nahanni Assets payable to the third party. In addition, the third party has previously alleged that the agreement between the third party and Nahanni resulted in a further 20% net profits interest, convertible into a working interest, in certain of the Nahanni Assets. We have disputed this assertion on several bases, including that any potential arrangement between the third party and Nahanni, even if valid, (a) did not necessarily attach to the relevant properties and is personal between Nahanni and the third party; (b) pertains at most to Nahanni's former working interest in six potential wells included in the Nahanni Assets; and (c) even if valid, the third party is responsible for accrued and unpaid operating costs to date. See Risk Factors - “Our business will suffer if we cannot obtain or maintain necessary licenses or if there is a defect in the chain of title.”
The Company 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. The Company’s preliminary assessment of the fair value of the Nahanni Assets and the Devon Assets resulted in a valuation of $25,526,554 and $22,103,530, respectively. As a result of the Company’s purchase price allocation, a gain on bargain purchase of $11,766,787 was recognized on the Nahanni Assets. The gain on bargain purchase was primarily attributable to the strategic nature of the divestiture by the motivated seller, coupled with a confluence of certain favorable economic trends in the industry and the geographic region in which the Nahanni Assets are located. The excess of the consideration paid over the estimated fair value of the Devon Assets was $1,194,365. This amount has been recognized as goodwill.
Future Development and Exploration
During the year ended August 31, 2014, we pursed a variety of geological, geophysical and engineering studies related to the KGP including, but not limited to seismic reprocessing and reinterpretation, mapping and subsurface modeling. Although certain of these studies are still underway, we believe the results in hand enhance our understanding and the overall value of the KGP. Our long term exploration plan for the KGP involves the exploitation of both conventional and unconventional (shale) gas resources. Phase one of that plan includes the rework or recompletion of up to three wells, and the drilling, completion and equipping of two new wells. These efforts will focus on previously identified or tested conventional gas zones. During phase one, we intend to target lower cost development and exploration targets with the potential to create positive cash flows and long term sustainability for the KGP. During this period we also plan to carry out feasibility studies to investigate the potential of developing a modular LNG project to supply LNG to the Yukon and other areas of north western Canada. Early estimates indicate the cost of phase one may range from $20,000,000 to $25,000,000 on a gross basis. We expect that approximately $5,000,000 to $7,000,000 in costs associated with phase one exploration to be incurred during the next twelve months.
Phases two and three of our exploration plan anticipate further development of conventional reservoirs and testing and development of shale resources.
The San Miguel Lease - Zavala County, Texas
We are party to a farmout and participation agreement (the "Eagleford Agreement"), which provides for our acquisition of a 21.25% net working interest in a 2,629 acre oil and gas lease known as the San Miguel 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 reserves or production.
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 a test well on the San Miguel Lease (the “Test Well”), performed injection operations and earned our initial interest. 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. Oil viscosity, however, has prohibited economic operation of the Test Well. As a result, during August 2011, and November 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 continue to consider methods to improve production from the Test Well. 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. We have made no additional expenditures on the San Miguel Lease since November 30, 2011.
Industry Conditions
Competition
The petroleum and natural gas industry is highly competitive. Numerous independent oil and gas companies 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.
More particularly, matters subject to current governmental regulation and/or pending legislative or regulatory changes include the licensing for drilling of wells, the method and ability to produce wells, surface usage, conservation matters, bonds or other financial responsibility requirements, the spacing of wells, unitization and pooling of properties, and royalties and taxation. Failure to comply with the laws and regulations in effect from time to time may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that could delay, limit, or prohibit operations.
We do not expect that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas companies of similar size, however these controls and regulations should be considered carefully by those investing in the oil and gas industry. All current legislation is a matter of public record, and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in Canada and, in particular, in the Yukon.
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.
Climate Change Regulation -
Internationally, Canada is a signatory to the United Nations Framework Convention on Climate Change and previously ratified the Kyoto Protocol established thereunder, which set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide, and other greenhouse gases (“GHG”). In December 2011, the Canadian federal government announced that it would not agree to another commitment period under the Kyoto Protocol after 2012. The federal government instead endorsed the Durban Platform, a broad agreement reached among the 194 countries that are party to the United Nations Framework Convention on Climate Change. The Durban Platform sets forth a process for negotiating a new climate change treaty that would create binding commitments for all major GHG emitters. The Canadian government expressed cautious optimism that agreement on a new treaty could be reached by 2015. The Durban Platform followed the Copenhagen Accord reached in December 2009 which represents a broad political consensus and reinforces commitments to reducing GHG emissions but is not a binding international treaty. Although Canada had committed under the Copenhagen Accord to reduce its GHG emissions by 17% from 2005 levels by 2020, the target is not legally binding. The impact of Canada's withdrawal from the Kyoto Protocol on prior GHG emission reduction initiatives is uncertain.
Domestically, the Canadian federal government released in 2007 its Regulatory Framework for Air Emissions, which was updated in March 2008 in a document entitled Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions. On January 30, 2010 the Canadian federal government announced a GHG emission reduction target consistent with its commitment under the Copenhagen Accord to reduce GHG emissions to 17% below 2005 levels by 2020. Canada's framework proposes mandatory emissions intensity reduction obligations on a sector-by-sector basis. To date, regulations for Canada's transportation and coal-fired electricity sectors have been developed, but none have been developed for the oil and gas sector and regulations for the electricity sector aren't expected to take effect until 2015. In 2009, the Canadian federal government announced its commitment to work with the provincial governments to implement a North America-wide cap and trade system for GHG emissions, in cooperation with the United States, under which Canada would have its own cap-and-trade market for Canadian-specific industrial sectors that could be integrated into a North American market for carbon permits. The Government of Canada currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. It is uncertain whether or when either Canadian federal GHG regulations for the oil and gas industry or an integrated North American cap-and-trade system will be implemented, or what obligations might be imposed under any such systems.
Land Tenure and Production Rights Processes
Federal Crown Lands -
Crude oil and natural gas located in the Yukon is owned predominantly by the Crown and governed by the Government of the Yukon.
The Government of the Yukon, through the Minister of Economic Development (Minister), grants rights to explore for and produce oil and natural gas pursuant to dispositions (oil and gas permits, oil and gas leases, and other instruments or contracts). Dispositions may be issued by the Minister pursuant to a call for bids, on application, or pursuant to any other procedure determined by the Minister.
Permits allow the permit-holder to explore, drill and test for oil and gas. Permits may be renewed under certain conditions and, subject to the regulations and legislations, convey to the permit-holder the right to apply for a lease. The lease grants, in accordance with the terms and conditions of the lease, the right to oil and gas. An oil and gas lease's term is ten years and renewable for further terms of five years under certain conditions. In addition, the foregoing dispositions are subject to the legislations, regulations and any terms and conditions prescribed by the Minister of Economic Development.
The above tenure regime applies to dispositions made after November 19, 1998. Federal dispositions relating to oil and gas interests in the Yukon Territory prior to such date remain in effect until such dispositions expire, are cancelled, or are surrendered by the holder thereof. Properties in the KGB are all federal dispositions made before November 19, 1998.
Freehold Lands -
Oil and natural gas located in the Yukon Territory can also be owned privately and rights to explore for and produce such oil and natural gas are granted through leases on such terms and conditions as may be negotiated between the parties. Further, pursuant to agreements made between First Nations (the Canadian native peoples) and the Government of Canada, First Nations have been granted title to certain lands in the Yukon Territory, in fee simple, including mines and minerals within, upon or under such lands.
In order to obtain the right to explore and produce minerals within these lands, corporations enter into an oil and gas lease with the owner (or its designated organization) of the lands. Generally, such a lease functions similar to crown oil and gas leases, whereby the lessor as the legal owner grants the lessee certain rights to explore for and produce oil and gas, subject to the specific terms of the lease. Typically, upon entering into the lease, the lessee is granted the right to explore and produce oil and gas from the land, for an initial term, followed by potential renewable terms. The lease generally includes, among other terms, various drilling and payment obligations, which if not satisfied by the lessee, may result in the termination of certain rights, the surrendering of specific portions of the leased land, payment penalties and/or termination of the lease. The grant to the lessee is also generally subject to the payment of royalties to the lessor based on production from the leased lands or revenues from production from the leased lands.
In addition, in First Nation leases, the lessee is often obligated to consult with the lessor and to commit to community support incentives and benefit agreements such as consideration for employment, training and business opportunities; support and utilization of local business; development of employment opportunity procedures; and development training plans.
Pricing and Marketing
Natural Gas -
In Canada, the price of natural gas sold is determined by negotiations between buyers and sellers. Such price depends, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, weather conditions, the supply/demand balance, pipeline capacity and contractual terms. Natural gas exported from Canada is subject to regulation by the Canadian National Energy Board (“NEB”) and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB and the government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities not exceeding 30,000 m3/day) are subject to an NEB order. Any natural gas exported under a contract of longer duration (to a maximum of 25 years) or in larger quantities requires the exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the NEB and its Governor in Council.
Crude Oil -
Producers of crude oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends, in part, on crude oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, contractual terms, pipeline capacity and the world price of oil. Oil may be exported from Canada pursuant to export contracts with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude, provided that an order approving such export has been obtained from the National Energy Board (the NEB). Any oil exported under a contract of longer duration (to a maximum of 25 years) requires the exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council.
The North American Free Trade Agreement
Under the North American Free Trade Agreement (NAFTA), the Canadian government is free to determine whether exports of energy resources to the United States or Mexico should be allowed, provided that export restrictions do not: (1) reduce the proportion of energy resources exported relative to energy resources consumed domestically; (2) impose a higher export price than domestic price (subject to an exception relating to certain voluntary measures that restrict the volume of exports); and (3) disrupt normal channels of supply.
NAFTA prohibits discriminatory border restrictions and export taxes and also prohibits the imposition of minimum or maximum export or import price requirements except with respect to the enforcement of countervailing and anti-dumping orders and undertakings. Discipline on regulators is addressed as the signatories to NAFTA agree to ensure that their regulatory bodies provide equitable implementation of regulatory measures and minimize the disruption of contractual arrangements.
Royalties and Incentives
Royalties payable on production from privately owned lands are determined by negotiations between the lessor and lessee.
For crude oil, natural gas and related production from Crown lands, the royalty regime is a significant factor in the profitability of a corporation's production. Crown royalties payable in respect of Crown lands are determined by governmental regulation and are typically calculated as a percentage of the value of gross production. The Oil and Gas Royalty Regulations (Yukon) were passed in February 2008 and authorized the Government of Yukon to collect oil and gas royalties on Crown lands.
The lessees are considered the royalty client and are responsible for the payment of royalties in proportion to the lessee's interest in the disposition of production. Royalty clients are required to submit a Yukon Royalty Return for every month in which there is production detailing the quantity of oil, gas, and field condensate extracted from a well in a production month and summarizing royalty payable for a production month, along with allowances, and prescribed prices.
The Yukon Territory royalty system is based on an ad valorem structure. The rate of the royalty is based on a select price and par price (reference price) which vary between crude oil and gas. These rates along with the royalty allowances are prescribed by the Oil and Gas Resources Division Head. Par prices and select prices are generally set for each month in which there is production and select prices will vary from time to time. The royalty allowances function as proxies in lieu of transportation and processing costs.
The royalty rate for federal leases that have been grandfathered under the Oil and Gas Act (Yukon), which includes our leases under the KGP, is 10%.
Risks Factors
There may be ongoing doubt about our ability to continue as a going concern. We require substantial capital to develop our properties, conduct operations, engage in acquisition activities, and commence production. If we are unable to obtain, on satisfactory terms, financing necessary to execute our operating strategy, you could lose your entire investment in our company.
We require substantial capital to develop our properties, conduct exploration, development, and production operations, engage in acquisition activities, and commence production.
Under the agreements governing our Kotaneelee properties, in the event any one or more of the interest owners elect not to participate in our planned exploration and development activities at Kotaneelee, we may be required to fund or seek funding for the entire costs of such activities rather than solely our proportionate interest.
We may need to access the private or public equity or debt capital markets or complete asset sales to fund such activities. If we are unable to obtain additional equity or debt financing in the private or public capital markets or access alternative sources of funds, we may be required to reduce the level of our planned capital expenditures and may lack the capital necessary to replace our reserves or commence production.
Our future revenues, cash flows, and spending levels are subject to a number of factors, including commodity prices, the level of production from existing and future wells, and our success in developing and or recompleting existing wells and successfully drilling new wells.
Our ability to access the private and public equity and debt markets and complete future asset realization transactions is also dependent upon primarily natural gas and NGL prices, and to a lesser extent oil prices in addition to a number of other factors, some of which are outside our control. These factors include, among others:
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the value and performance of our equity securities;
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domestic and global economic conditions; and
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conditions in the domestic and global financial markets.
Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to implement our business plans fully, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our business, financial condition, cash flows, and results of operations.
Our pursuit of natural resource properties may fail, and/or our 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 discover commercially recoverable quantities of resources on our properties and develop them into commercially viable operations. Resource exploration and development 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 and development is determined in part by the following factors: (i) the identification of potential resources; (ii) availability of government-granted exploration permits and well licenses; (iii) the quality of management and geological and technical expertise; and (iv) the capital available for exploration.
The oil and natural gas industry is highly competitive, and there is no assurance that we will be successful in acquiring leases, equipment and personnel.
The oil and natural gas industry is intensely competitive. Although we do not compete with other oil and gas companies for the sale of any oil and gas that we may produce, as there is sufficient demand in the world market for these products, we compete with numerous individuals and companies for desirable oil and natural gas leases, suitable properties for drilling operations and necessary drilling equipment, access to pipelines and other transportation infrastructure, qualified personnel and access to capital. Many of these individuals and companies with whom we compete have substantially greater technical, financial and operational resources and staff than we have. If we cannot compete for personnel, equipment and oil and gas properties, our business could be harmed.
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, failing to successfully recomplete existing wells, 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, down hole 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.
The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.
The marketability of our production depends in part upon the availability, proximity, and capacity of pipelines, natural gas gathering systems, and processing facilities. Any significant change in market factors affecting these infrastructure facilities, as well as delays in the construction of new infrastructure facilities, could harm our business. Any oil, natural gas or NGLs that we may produce will be delivered through gathering facilities that we do not own or operate. As a result, we are subject to the risk that these facilities may be temporarily unavailable due to mechanical reasons or market conditions, or may not be available to us in the future. If we experience interruptions or loss of pipelines or access to gathering systems that impact a substantial amount of our production, it could have a material adverse effect on our business, financial condition, cash flows, and results of operations.
Our business will suffer if we cannot obtain or maintain necessary licenses or if there is a defect in the chain of title.
Our operations require that we obtain and maintain licenses and permits from various governmental authorities. Our ability to obtain, maintain or renew such licenses and permits on acceptable terms is subject to extensive regulation and to changes, from time-to-time, in those regulations. Also, the decision to grant or renew a license or permit is frequently subject to the discretion of the applicable government. If we cannot obtain, maintain, extend or renew these licenses or permits our business could be harmed.
Also, although internal title reviews have been conducted on our existing properties, we have not engaged third party or legal title reviews. As a result, internal reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim which could result from the loss of title and a reduction of the revenue received, if any. Also, adverse claims of third parties, if successful, may result in the recognition of net profit interests or working interest with respect to all or a portion of our interest in the KGP. The recognition of any such claims could also result in a reduction in the potential revenue derived from our operation of the KGP.
First Nations peoples have claimed aboriginal title and rights in portions of Canada. We are not aware that any claims have been made against us with respect to our properties and assets; however, if a claim arose and was successful, it could prevent or delay exploration, increase costs and/or cause us to forego exploration opportunities and therefore such claim may have a material adverse effect on our business, financial condition, cash flows, and results of operations. Our operations may be delayed or interrupted to the extent that they are deemed to encroach on the traditional rights of aboriginal people to hunt, trap, or otherwise have access to natural resources or lands.
Lower oil, natural gas, and NGL prices and other factors have resulted, and in the future may result in write-downs and other impairments of our asset carrying values.
We use the full cost method of accounting under U.S. GAAP to report our oil and gas operations. Under this method, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and gas properties may not exceed a "ceiling limit," which is based upon the present value of estimated future net cash flows from proved reserves (calculated in accordance with SEC rules and regulations and corresponding U.S. accounting standards), discounted at 10%. If net capitalized costs of proved oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling test write-down." Under the accounting rules, once we begin reclassifying our oil and gas assets from unproved to proved, we will be required to perform a ceiling test each quarter. A ceiling test write-down would not impact cash flow from operating activities, but it would reduce our stockholders’ equity.
We also assess investments in unproved properties, including capitalized interest costs, periodically to ascertain whether impairment has occurred. The cost of unproved properties, which costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the amount by which the ceiling limit exceeds the capitalized costs of proved oil and gas properties would be reduced.
The risk that we will be required to write-down the carrying value of our oil and gas properties, our unproved properties, or goodwill increases when oil, natural gas, and NGL prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase.
Environmental risks may result in delays, claims or additional costs which could adversely affect our business.
All phases of the oil and gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. The application of environmental laws to our business may cause us to curtail our production or increase the costs of any production, development or exploration activities.
Future environmental regulation may also encompass a prohibition or moratorium on the use of certain exploration techniques, including hydraulic fracturing. The implementation of any such prohibition or moratorium would have a material adverse effect on our business, financial condition and operating results.
Losses and liabilities arising from uninsured or under-insured hazards could have a material adverse effect on our business.
If we develop and exploit oil and gas reserves, those operations will be subject to the customary hazards of recovering, transporting and processing hydrocarbons, such as fires, explosions, and gas leaks, migration of harmful substances, blowouts and oil spills. An accident or error arising from these hazards might result in the loss of equipment or life, as well as injury, property damage or other liability. We cannot assure investors that we will obtain insurance on reasonable terms or that any insurance we may obtain will be sufficient to cover any such accident or error. Our operations could be interrupted by natural disasters or other events beyond our control. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our business, financial condition and results of operations.
Amendments to current laws and regulations governing our proposed operations could have a material adverse impact on our proposed business.
We are subject to substantial regulation relating to the exploration for, and the development, marketing, pricing, taxation, and transportation of, oil and gas. Amendments to current laws and regulations governing operations and activities of oil and gas exploration and extraction operations could have a material adverse impact on our proposed business. In addition, we cannot assure investors that income tax laws, royalty regulations and government incentive programs related to the oil and gas industry generally or to us specifically will not be changed in a manner which may adversely affect us and cause delays or require us to abandon our projects.
Penalties we may incur could impair our business.
Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights or licenses, and may affect the value of our assets. We may be required to take corrective actions, such as installing additional equipment, which could require substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.
Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.
Our ability to discover reserves, to initiate or participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants and government officials and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. We may not be able to establish these strategic relationships or, if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.
Our articles of incorporation limit the liabilities of our officers and directors to us and our stockholders.
Our articles of incorporation contain a provision limiting the liability of our officers and directors for their acts or failures to act, except for acts involving intentional misconduct, fraud or a knowing violation of law. This limitation on liability may reduce the likelihood of derivative litigation against our officers and directors and may discourage or deter our stockholders from suing our officers and directors based upon breaches of their duties to our company.
The loss of certain key management personnel could have a material adverse effect on our business.
The nature of our business, to perform technical exploration and development, depends, in large part, on our ability to attract and maintain qualified key personnel. Competition for such personnel is intense, and we cannot assure you that we will be able to attract and retain them. Our development now and in the future will depend on the efforts of our current executive officers. The loss of any of these key people could have a material adverse effect on our business. We do not currently maintain key-man life insurance on any of our key personnel.
There are potential conflicts of interest between our company and some of our directors and officers.
Some of our directors and/or officers are also directors and/or officers of other companies. As of the date of this report and to the knowledge of our directors and officers, there are no existing conflicts of interest between our company and any of these individuals but situations may arise where our directors and/or officers may be in competition with us. Any conflicts of interest will be subject to and governed by the law applicable to directors' and officers' conflicts of interest. In the event that such a conflict of interest arises at a meeting of our directors, a director who has such a conflict is required to abstain from any discussion and voting for or against the approval of such participation or such terms. As a result, our board of directors will be deprived of that person's experience and expertise, which could adversely affect the outcome.
The price of our common stock may become volatile, which could lead to losses by investors and costly securities litigation.
The trading price of our common stock is likely to be highly volatile and could fluctuate in response to factors such as:
●
actual or anticipated variations in our operating results;
●
announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures, capital commitments, or other business developments, such as oil or gas discoveries;
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adoption of new accounting standards affecting our industry;
●
additions or departures of key personnel;
●
sales of our common stock or other securities in the open market;
●
conditions or trends in our industry;
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changes in business, legal or regulatory conditions, or other developments affecting the oil and gas industry; and
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other events or factors, many of which are beyond our control.
If we obtain additional financing through the sale of additional equity in our company, the issuance of additional shares of common stock will result in dilution to our existing stockholders.
We are authorized to issue 150,000,000 shares of common stock, and, as of the date of this report, 19,897,714 shares of our common stock were issued and outstanding. Our board of directors has the authority to issue additional shares of common stock up to the authorized capital without the consent of any of our stockholders. Our board of directors may choose to issue some or all of such shares to acquire one or more businesses or to provide additional financing in the future. The issuance of any such shares may result in a reduction of the book value or market price of the outstanding shares of our common stock. If we do issue any such additional shares, such issuance will cause a reduction in the proportionate ownership and voting power of all other stockholders. Further, any such issuance may result in a change of control of our company.
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 shares of common stock or resales in the open market will decrease the market price of shares of our common stock. The impact of any such issuances or resales of shares 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 shares of our common stock in connection with acquisitions and other issuances of shares of our common stock could have an adverse effect on the market price of shares of our common stock. In addition, future issuances of shares of our common stock may be dilutive to existing shareholders. Any sales or other issuances of substantial amounts of shares of our common stock in the public market, or the perception that such sales might occur, could lower the market price of shares of our common stock.
Our directors and executive officers own a significant percentage of our outstanding common stock.
In the aggregate, our directors and executive officers own approximately 13.58% of our outstanding common stock, and they have the right to exercise options and warrants that would permit them to acquire, in the aggregate, up to approximately an additional 4.33% of our common stock. In addition, certain of our directors and executive officers are also directors and/or executive officers of our two principal security holders, Holloman Value Holdings, LLC and Pacific World Energy Corp., or their affiliates. As a result, our directors and executive officers as a group may be able to delay, defer or prevent any potential change in control of our company, and they may be able to strongly influence the actions of our board of directors even if they were to cease being our directors and control the outcome of actions brought to our stockholders for approval. Such a high level of ownership may adversely affect the voting and other rights of other stockholders.
We do not expect to pay dividends in the foreseeable future.
We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, investors will not receive any funds unless they sell their common stock, and stockholders may be unable to sell their shares on favorable terms or at all. We cannot assure you of a positive return on investment or that you will not lose the entire amount of your investment in our common stock.
Also see discussions under Industry Conditions which may be additive to your understanding of the business and other risks we face.
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 RISKS. INVESTORS ARE URGED TO CONSIDER ALL OF THE RISKS INHERENT IN OUR SECURITIES PRIOR TO PURCHASING OR MAKING AN INVESTMENT DECISION.
Other
Research and Development
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.
Employees
We currently have no full or part-time employees. We use consultants and contractors to provide us with, among other things, executive management, accounting services, field operating support and technical engineering. See Item 10 of this report.
ITEM 2.
ITEM 2. PROPERTIES.
Oil and Gas Properties
Our crude oil and gas properties consist almost entirely of our KGP working interests located in the Yukon Territory in Canada. The following is a brief synopsis of our operation, as of August 31, 2014. Lease and well data is presented as of November 28, 2014.
Capital Expenditures, Including Acquisitions and Costs Incurred
Capitalized acquisition, exploration and development costs incurred on the KGP during the fiscal years ended August 31, 2014 and 2013 are summarized as follows:
Development costs incurred to obtain access and provide facilities for extracting, gathering, treating and storing oil and gas related to unproved oil and gas properties that are being evaluated for economic viability are added to the full cost pool until proved reserves are established, or determination is made that the unproved properties are impaired. During the years ended August 31, 2014 and 2013, the full cost pool was increased by $1,408,017 and $1,264,037, respectively, as a result of these costs.
Oil and Gas Wells
During the years ended August 31, 2014, 2013 and 2012, we did not drill or participate in the drilling of any wells. During the year ended August 31, 2011, we drilled one exploratory well which, as August 31, 2014, was not productive. As of November 28, 2014, we were not drilling or completing any wells.
At August 31, 2014, we had a 100% working interest in one conventional natural gas well in the KGP. This well was shut in during September 2012 and remained shut in as of August 31, 2014.
Production, Pricing and Lease Operating Cost Data
The following table describes, for the years ended August 31, 2014 and 2013, 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, 2014, we had no delivery commitments.
Oil and Gas Wells, 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 28, 2014:
(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 28, 2014, 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.
Additional Information Concerning Abandonment and Reclamation Costs
In connection with our acquisition of the KGP, we absorbed asset retirement obligations totaling $16,687,000. In addition, we have recognized $80,000 in abandonment liabilities related to the San Miguel Lease. Other than these liabilities, we have no other retirement obligations or abandonment and reclamation costs.
Please also see Item 1 of this report for additional information regarding our oil and gas properties.
Offices
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.
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, 2014 and 2013. 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 28, 2014, we had 19,897,714 outstanding shares of common stock and approximately 65 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 three months ended August 31, 2014, we accrued fees payable in stock totaling $52,500 under the terms of two consulting agreements and one administrative agreement. One of these agreements, for fees in the amount of $30,000, is with an entity controlled by our Chief Executive Officer. Effective August 31, 2014, we issued 55,979 shares of our common stock, at a weighted average price of $0.94 per share, in satisfaction of these liabilities.
We relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 with respect to the sale of these securities. 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 securities. The certificates representing the common stock 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, 2014 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, 2014 none of our officers or directors, or 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 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 KGP located on 30,188 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 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 net revenues and costs. Prior to our initial working interest acquisition in the KGP, we had generated no revenues.
During March 2011, we initiated oil and gas operations by entry into the Eagleford Agreement which provided for our acquisition of a net working interest, ranging from 21.25% to 42.5%, in the San Miguel Lease. The San Miguel Lease is located in Zavala County, Texas. Our investment in the San Miguel Lease has been fully impaired, and we have no current revenue or reserves relating to that investment.
We have no proven reserves.
See Items 1 and 2 of this report for a more detailed discussion of our history, assets and business plan.
Financial Condition and Results of Operations
KGP
Development costs incurred to obtain access and provide facilities for extracting, gathering, treating and storing oil and gas related to unproved oil and gas properties that are being evaluated for economic viability are added to the full cost pool until proved reserves are established, or determination is made that the unproved properties are impaired. During the years ended August 31, 2014 and 2013, the full cost pool was increased by $1,408,017 and $1,264,037, respectively, as a result of these costs.
The San Miguel Lease
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 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 the 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
The excess of the estimated fair value of the Nahanni Assets over the consideration paid was $11,766,787. This amount has been recognized as a gain on the acquisition of assets. The tax impact of $2,779,849 relating to this gain has been recorded as a deferred tax obligation. The excess of the consideration paid over the estimated fair value of the Devon Assets was $1,194,365. This amount has been recognized as goodwill.
Our operating loss for the year ended August 31, 2014, decreased by approximately $1,595,000 or 31% (from $5,212,548 to $3,617,365) when compared to the year ended August 31, 2013. This net decrease resulted from a blend of higher and lower costs incurred, including:
1.
A current year decrease of approximately $316,000 or 27%% (from $1,193,410 to $876,953) in management and directors fees relating to the discontinued directors fees in September 2013;
2.
A current year decrease of approximately $873,000 or 68% (from $1,282,384 to $409,563) in stock based compensation expense consisting of $259,000 in lower option plan expense when compared to 2014. Stock based compensation during 2013 also included$259,000 (100,583 shares) payable to our Chief Executive Officer, and $259,000 (100,553 shares) payable to our Chief Financial Officer, respectively, as finders' fees in connection with our acquisition of the KGP, and a Stock Bonus Plan issuance to our new Chief Operating Officer in the amount of of $97,000 (50,000 shares at $1.94 per share). None of these expenses were repeated during the year ended August 31, 2014;
3.
A current year decrease of approximately $664,000 or 61% (from $1,081,442 to $417,173) in consulting fees consisting in largest part of 2013 expenditures of ; $230,100 payable for investor relations services (payable to a consultant in 90,000 shares of our restricted common stock), and $259,000 in finders' fees incurred in connection with the acquisition of the KGP (payable to a consultant in 100,553 shares of our restricted common stock) which were note repeated in 2014, and a reduction in fees for engineering services incurred in connection with the KGP;
4.
A current year increase of approximately $63,000 10% (from $629,666 to $692,471), in professional fees incurred in connection with regulatory compliance and our pursuit of financing in 2014;
5.
A current year decrease of approximately $101,000 or 22% (from $453,138 to $352,533), in office, travel and general expense, relating primarily to reduced travel, insurance, and operation of the KGP compared to those in fiscal year 2013;
6.
A current year increase of approximately $120,000 or 21% (from $572,508 to $692,272), in accretion of asset retirement obligations incurred during 2014 in connection with our working interests in the KGP resulting from a full, rather that partial, period’s accretion during that period; and
7.
A current year increase of $176,400 in 2014 financing costs consisting entirely of finders’ fees paid in connection with the 2013 Convertible Note offering completed on October 30, 2013; and
During the year ended August 31, 2014 we recognized interest expense of $620,682 incurred in connection with the 2013 Convertible Note and 2014 Convertible Note Offerings. No such notes were outstanding during 2013.
During the year ended August 31, 2013, we also recognized approximately $28,000 in gains related to our settlement of certain vendor payables at less than their face amounts.
From September 2012 through May 2014, we used fuel gas from the Spectra pipeline system to maintain operations at the KGP. This fuel gas was to be re-delivered into the Spectra pipeline once production at the KGP was re-established. In March 2014, we agreed to purchase monthly fuel gas from Spectra on an as-used basis (approximately 10,075 gigajoules “GJs” per month). We also agreed to repay Spectra in cash, or in kind, prior to December 31, 2014, for our previous consumption of fuel gas (approximately 174,000 GJs at an estimated net cost to us of approximately $262,000).
We have initiated cost savings measures, including the termination of directors fees effective September 1, 2013, and intend to decrease our administrative costs further during the upcoming fiscal quarter.
Liquidity and Capital Resources
We are an exploration stage company. Since inception, we have expended net cash of $6,941,363 to fund our operating activities, and have invested net cash of $2,921,887 in our oil and gas assets. As of August 31, 2014, we have negative working capital of approximately $5,400,000. Of that amount approximately $2,300,000 in accrued liabilities (consisting of finders’, Director’s and other fees), $282,000 in accrued interest, and $2,230,000 in net principal outstanding on the 2013 Convertible Notes (see below) are expected to be settled in shares of our common stock.
Our operations and investment to date have been funded through the issuance of capital stock and debt. We plan to generate profits by drilling productive gas wells or improving the production of existing wells. We will, however, need to raise additional funds 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, that we begin to generate significant revenue from oil and gas sales.
During the period from June 2012 through February 2013, we sold 4,405,667 shares of our common stock to twenty eight accredited investors at a price of $1.20 per share. Gross proceeds from these private placements totaled $5,286,800. We paid $164,038 in finders' fees in connection with the sale of these shares.
During June 2014, we sold convertible notes having an aggregate principal amount of $1,400,000, to two accredited investors and one non-accredited investor, under the following general terms:
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the maturity date of the 2014 Convertible Notes is December 31, 2014;
●
at the option of the note holder, the principal amount of the 2014 Convertible Notes was to be convertible into shares of our common stock at a price per share to be determined in connection with a planned offering of shares upon migration to a senior stock exchange, less a 10% discount (the “2014 Conversion Right”):
●
a 6% financing fee on the principal sum of the 2014 Convertible Notes, is payable:
a.
in the event the note holder exercises its 2014 Conversion Right, in shares of our common stock (the number of which is to be calculated using the closing market price of our shares on the conversion table); or
b.
in the event the note holder does not exercise its 2014 Conversion Right, at the option of the note holder, in shares of the our common stock (the number of which is to be calculated using the closing market price at December 31, 2014), or in cash of $84,000.
●
the 2014 Convertible Notes are non-interest bearing so long as they are paid or converted prior to December 31, 2014. In the event of default, or if a 2014 Convertible Note is not paid, or converted on or December 31, 2014:
a.
the notes will bear interest at 10% per annum, payable monthly; and
b.
an additional 4% financing fee (the Default Financing Fee) on the then outstanding principal balance of the 2014 Convertible Notes shall become due and payable. We are obligated to pay the Default Financing Fee in common shares at a conversion price equal to the closing market price of the common shares on the date of the event of default, or December 31, 2014, whichever is earliest.
Companies affiliated with our Chairman and one of our Directors purchased $1,000,000 and $350,000 in 2014 Convertible Notes, respectively, in the 2014 Convertible Note Offering.
The 2014 Convertible Notes provide added liquidity to support fund raising efforts, and the planning and licensing of phase one exploration.
On October 30, 2013, we sold convertible notes having an aggregate principal amount of $2,255,000 to 22 accredited investors, under the following general terms:
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the maturity date of the 2013 Convertible Notes is April 30, 2015;
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the principal amount of the 2013 Convertible Notes is convertible into shares of the our common stock, and repayable at our election in shares of our common stock , at a price of $1.00 per share;
●
the 2013 Convertible Notes bear interest at 15% per annum payable, at our election, in cash or shares of our common stock at a rate of $1.25 per share; and
●
we also issued stock purchase warrants in connection with the 2013 Convertible Note Offering providing for the purchase of up to 1,127,500 shares of our common stock (one full share for each $2.00 invested in the 2013 Convertible Notes) at an exercise price of $1.25 per share for a period of three years (the Warrants).
In total, 3,382,500 shares of our common stock (comprised of 2,255,000 shares issuable on conversion of the principal of the 2013 Convertible Notes and 1,127,500 shares issuable on exercise of the Warrants), or such greater number of shares as may be issuable upon our election to pay interest in shares of our common stock under the terms of the 2013 Convertible Notes, has been reserved for issuance upon conversion of the 2013 Convertible Notes or exercise of the Warrants in accordance with their terms. On June 2, 2014, $25,000 in principal payable on the 2013 Convertible Notes was converted to 25,000 shares of our common stock at a conversion price of $1.00 per share.
We paid $176,400 in finders' fees with respect to the 2013 Convertible Note Offering. Entities controlled by our Chief Executive Officer and President acquired $50,000 and $150,000 of 2013 Convertible Notes and were issued 25,000 and 75,000 Warrants, respectively, in the 2013 Convertible Note Offering under these terms.
The 2013 Convertible Notes enhanced our capital resources and supported on-going operations including the acquisition of scientific and engineering data relating to our oil & gas assets.
Effective January 20, 2011, a company controlled by our Chief Executive Officer, our Chief Financial Officer, and an unrelated consultant (the “Finders”) entered into an agreement with us providing for the payment of finders’ compensation ranging from 5% (on transaction values greater than $1,000,000) to 10% (on transactions valued up to $300,000) on transactions introduced to us by or through the Finders for a period of two years (the “Finders’ Fee Agreement”). Under the Finders’ Fee Agreement, compensation is divided among the Finders and the Finders may elect whether the finders’ compensation is payable in cash, or shares of our restricted common stock. If the Finders elect to receive payment in stock, the shares into which finders’ compensation will be converted will be calculated using the average closing price of our common stock for the ten trading days preceding the closing date of the transaction to which the compensation relates. The Finders’ Fee Agreement specifically recognizes that the KGP has been presented to us by the Finders. As of August 31, 2014, finders’ compensation of $1,619,621 has been accrued under the Finders’ Fee Agreement in connection with our acquisition of the Devon Assets and the Nahanni Assets.
Other than the Finders’ Fee Agreement, and obligations associated with the operation, acquisition and exploration of our oil and gas leases disclosed elsewhere in this report, our material future contractual obligations as of August 31, 2014 consisted of convertible notes having an aggregate principal amount of $3,630,000.
We anticipate that our acquisition of the KGP will generate significant capital requirements. During the twelve month period ending November 30, 2014, 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 $5,000,000 to $7,000,000. We are attempting to raise the capital needed to implement our business plan.
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 30, 2015, to cover general, administrative, and other costs.
In June 2014, we filed a Canadian Prospectus and a US Form S-1 Registration Statement to facilitate our planned migration and initial public offering of common stock on the TSX Venture Exchange (Canada). As a result of poor and deteriorating conditions in Canadian capital markets, however, we withdrew our offering documents effective November 25, 2014. We currently plan to undertake further cost reduction strategies and a combination of farm-out strategies and working interest acquisitions to facilitate our KPG exploration plans.
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.
The oil and gas industry is cyclical in nature and tends to reflect general economic conditions. The pattern of historic fluctuations in gas prices 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 exploration ventures.
As of November 28, 2014 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, result of operations, liquidity or capital resources.
Critical Accounting Policies and Estimates
Use of Estimates
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, 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
We routinely assess the recoverability of all material receivables to determine their collectability. All of our receivables are from joint venture partners. We are exposed to a concentration of credit risk with respect to our accounts receivable. We believe our financial partners are financially strong and the risk of loss is minimal. We accrue a reserve on a receivable when, based on our judgment, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of August 31, 2014 and 2013, the Company had no amount recorded as an allowance for doubtful accounts.
Oil and 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. We do not amortize costs of unproved properties until the proved reserves associated with the projects can be determined or until impairment occurs. We periodically assess potential impairment of our unproven properties by applying factors based on historical asset experience, average holding periods for unproven properties and other data such as remaining lease term, and geological and geophysical information If an assessment of such properties indicates that properties are impaired, we added the amount of impairment to the capitalized cost base to be amortized.
We calculate Depreciation, Depletion and Amortization (DD&A) of proved oil and gas properties, using the Units of Production (UOP) method. 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 preceding twelve-month period 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, 2014, and 2013 all of our oil and gas interests were unproven.
We account for sales of proved and unproved properties as adjustments of capitalized costs and recognize no gain or loss, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case we recognize the gain or loss in the statement of operations.
Oil and Gas Acquisitions
We account for all property acquisitions that include working interests in proved leaseholds, 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 leaseholds. In large part, however, our acquisitions of the KGP targeted its high-functioning infrastructure which is capable of being conducted and managed as a business in our hands. The KGP’s principal business activities included the production of outputs, which have access to a proven customer base. 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 acquisitions from Devon and Nahanni effective July 18, 2012 and October 17, 2012, respectively.
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:
●
Level 1 - quoted prices in active markets for identical assets or liabilities.
●
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).
●
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 $650,599 and $476,522 at August 31, 2014 and 2013, 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.
Oil and natural gas revenues and lease operating expenses related to unproved oil and gas properties that are being evaluated for commercial viability are offset against the unamortized cost pool until proved reserves are established, or determination is made that the unproved properties are impaired. The Company has generated no material revenue during the years ended August 31, 2014 or 2013.
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, 2014, 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. Our Diluted EPS amounts did not differ from Basic EPS for the year ended August 31, 2014, as we generated net losses during that period and any adjustment would have been anti-dilutive. Our Diluted EPS amounts differ from Basic EPS for the year ended August 31, 2013, as we were in a net income position and adjusted the weighted average number of shares outstanding during that period by 1,411,262 shares issued by of one of our subsidiaries in connection with our acquisition of the KGP, which are exchangeable for 1,614,767 shares of our restricted common stock.
As of August 31, 2014 and 2013, we had 5,972,267 and 3,748,101 shares of our common stock, respectively, considered non-dilutive for EPS purposes, available through the exercise stock rights agreements.
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 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, 2014, 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 the issuer's 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 published in 1992. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of August 31, 2014.
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, Chairman of the Board of Directors
Henry Aldorf has nearly 40 years of 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 and as the Chief Executive Officer and Chairman of the Board of Directors of Terra Nova Energy Ltd. since August 2012. 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 Corporation 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 received 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, Chief Executive Officer, Secretary and Director
Keith Macdonald has been President of Bamako Investment Management Ltd., a private holding and financial advisory company since 1994. Mr. Macdonald has served on the board of Bellatrix Exploration Ltd. (TSX) since November 2009, Madalena Ventures Inc. (TSXV) since June 2010, Surge Energy Inc. (TSX) since April 2010, Mountainview Energy Ltd. (TSXV) since December 2010, and Holloman Energy Corporation (OTCQB) since August 2009. Most recently, he was a director of Rocky Mountain Dealership Inc. (TSX) from November 2007 to May 2013, WCSB Oil & Gas Royalty Income Funds from December 2009 to October 2011, Profound Energy Inc. (TSX) from November 2007 to July 2009, Cirrus Energy Corporation (TSXV) from March 2004 to April 2011, Cordy Oilfield Services Inc.(TSXV) from July 2009 to August 2011, Stratabound Minerals Inc.(TSXV) from November 2006 to October 2001, and Breaker Energy Ltd (TSX) from August 2005 to December 2009, and prior thereto a director of several public and private oil and gas companies. Mr. Macdonald was founder, President and
Robert Wesolek, Chief Financial and Accounting Officer and Director
Robert Wesolek served as the Chief Financial Officer of Holloman Energy Corporation from August 2009 to August 2014, and has been an executive consultant providing financial, regulatory and system design services to emerging corporations since 2006. In July, 2013, Mr. Wesolek also joined Pacific Hunt Energy Corp. as a director and its Chief Financial Officer. 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.
H. Wayne Hamal, Chief Operating Officer
H. Wayne Hamal has over 25 years of oil and gas industry experience with both major and independent oil companies. From January 2012 to January 2013, Mr. Hamal was Managing Director of HDH Resources, and from August 2011 to December 2011 he acted as a self-employed oil and gas consultant. He was General Manager of Exploration and Production (2008-2011), and Senior Engineering and Drilling Manager (2005-2008), for InterOil Corporation (NYSE) operating in Papua New Guinea. In that role, he was instrumental in the development of the drilling program for InterOil and was integral to the discovery and appraisal of the Elk/Antelope gas condensate fields. From 2002 to 2005, Mr. Hamal worked for Marathon Oil Company as Joint Venture Manager, Equatorial Guinea, West Africa, where he worked directly with production operations and major projects primarily involved with the development of the Alba gas condensate field and associated LPG, methanol and LNG plants. Before joining Marathon, Mr. Hamal worked for CMS Oil and Gas (1987-2001) where he held a variety of engineering positions, both domestic and international, including Production Manager Equatorial Guinea, West Africa. Mr. Hamal holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines.
James Hutton, Director
James Hutton 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) from March 2010 to June 2012, SantaCruz Silver Mining Inc. (TSXV) from September 2011 to present, Batero Gold Corp. (TSXV) from November 2010 to June 2012, and Caymus Resources Inc. (TSXV) from January 2012 to September 2013. Mr. Hutton served as our President from June 2012 until June 2014.
Eric Prim, Director
Eric Prim 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 since September 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.
James Ebeling, Director
James Ebeling has been the Chief Financial Officer of Holloman Corporation since November 2007. 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).
The Board of Directors, either directly or through its committees, is responsible for the supervision of management of our business and affairs with the objective of enhancing shareholder value. We believe our directors benefit us as a result of their expertise in the following areas:
Audit Committee
The Board of Directors has adopted a written charter and terms of reference for the Audit Committee, which sets out the Audit Committee's responsibility for (among other things) reviewing our financial statements and our public disclosure documents containing financial information and reporting on such review to the board of directors, ensuring our compliance with legal and regulatory requirements, overseeing qualifications, engagement, compensation, performance and independence of our external auditors, and reviewing, evaluating and approving the internal control and risk management systems that are implemented and maintained by management.
Mr. Ebeling, Mr. Aldorf and Mr. Prim are independent directors, as that term is defined in Section 803 of the listing standards of the NYSE MKT. Mr. Ebeling, Mr. Aldorf, and Mr. Prim comprises 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.
Our Board of Directors 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 incorporated by reference to Exhibit 14.1 to our Form 10-K for the year ended August 31, 2012.
Compensation Committee
On June 23, 2012 our Board of Directors created a separate Compensation Committee. The members of the Compensation Committee are Messrs. Prim and Ebeling each of whom is independent. The Compensation Committee's charter is to discharge the responsibilities of the board of directors relating to compensation of the directors and executive officers. The Compensation Committee has overall responsibility for evaluating and recommending the compensation plans, policies and programs of our company.
During the year ended August 31, 2014 none of our officers served as a compensation committee member of another entity, one of which entity’s officers served as a member of our compensation committee or as one of our directors.
Nominating Committee
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. At present, the Board of Directors does not have a process by which it identifies new candidates for nomination to the board of directors but rather the identification of new candidates is done on an informal and ad hoc basis.
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; Henry Aldorf (a current director) who filed one Form 4 covering one transaction after its due date; James Hutton (a current officer and director) who filed a two Form 4s covering two transactions after their due dates, Keith Macdonald (a current officer and director) who filed two Form 4s covering four transactions after their due dates, and Holloman Corporation (our largest shareholder) who filed one Form 4 covering four 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, 2014 and 2013:
Summary Compensation Table
(1)
Mr. Macdonald provides services under the terms of Consulting Services Agreements with Bamako Investment Management Ltd. (until September 1, 2012) and Country Rock Resources Ltd. (until October 31, 2014), which are both companies over which he exercises control. These agreements were cancellable by either party, with or without cause, following 30 day notice. Under these agreements, Mr. Macdonald was compensated $20,000 per month for up to 50% of his time as our Chief Executive Officer. Compensation is payable in equal parts cash and shares of our restricted common stock. Compensation payable in stock is computed at the closing price of the stock on the last trading-day of the applicable monthly earning period.
For the year ended August 31, 2014, $120,000 was earned by Mr. Macdonald in cash and $120,000 was paid in stock at a weighted average conversion price of $0.97 per share (124,021 shares) under Consulting Services Agreements.
During the year ended August 31, 2013, Mr. Macdonald also received $258,495 in finders’ compensation, payable in 100,583 shares of stock at $2.57 per share, respectively, in connection with our acquisition of the KGP (see footnote 5 to this table). All of Mr. Macdonald’s finders’ compensation which totaled $532,894 as of August 31, 2014, is accrued but unpaid.
Of the compensation reported for Mr. Macdonald for the years ended August 31, 2014 and 2013, $100,000 in cash compensation, and $599,894 in finders’ and director’s compensation to be paid in stock, remained accrued and unpaid as of August 31, 2014.
(2)
Mr. Hamal provides services under the terms of Consulting Services Agreement with HDH Resources, LLC (“HDH”), an entity over which he exercises control. During fiscal 2014 and 2013, we paid Mr. Hamal fees totaling $297,810 and $190,625, respectively. In 2013, Mr. Hamal was granted 50,000 shares of stock (fair value $97,000) and stock options providing for the purchase of 400,000 shares of stock (fair value $313,646) under our 2012 Stock Bonus and Options Plans (Plan details are provided below).
Of the compensation reported for Mr. Hamal for the year ended August 31, 2014, $7,480 in cash compensation remained accrued and unpaid as of August 31, 2014.
(3)
During the year ended August 31, 2014, we paid Mr. Wesolek fees for his services as our Chief Financial Officer of $172,350.
During the year ended August 31, 2013.Mr. Wesolek also received $258,421 in finders’ compensation, payable in 100,553 shares of stock at $2.57 per share, in connection with our acquisition of the KGP (see footnote 5 to this table). Of the compensation reported for Mr. Wesolek for the years ended August 31, 2014 and 2103, $6,654 in cash compensation, and $599,905 in finders’ and director’s compensation to be paid in stock, remained accrued and unpaid as of August 31, 2014.
(4)
Mr. Hutton provided services as our President under the terms of an informal agreement with Hutton Capital Corporation (“Hutton Capital”), an entity over which he exercises control. He resigned as President in June 2014. Under that agreement, we paid Hutton Capital $10,000 per month until his resignation.
During the year ended August 31, 2014 we paid Hutton Capital $163,193 for Mr. Hutton’s services as our President ($133,918 of which was paid in shares of our common stock at a price of $0.80 per share). During the year ended August 31, 2013 we paid Hutton Capital $108,424 for Mr. Hutton’s services as our President and $60,000 in other compensation for his services as director.
Of the compensation reported for Mr. Hutton for the years ended August 31, 2014 and 2103, $60,000 in director’s compensation to be paid in stock, remained accrued and unpaid as of August 31, 2014.
(5)
Effective January 20, 2011, an entity controlled by Mr. Macdonald, Mr. Wesolek, and Open Bay Holdings Ltd. (the “Finders”) entered into an agreement with us providing for the payment of finders’ compensation. This arrangement was finalized prior to Mr. Macdonald and Mr. Wesolek tenure as our Directors/Officers. Finders’ compensation under the agreeement ranges 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 “Finders’ Fee Agreement”). Under the Finders’ Fee Agreement, compensation is divided between the Finders. The Finders have elected to receive payment in stock. The shares into which finders’ compensation is paid were 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 Finders’ Fee Agreement specifically recognizes that the KGP has been presented to us by the Finders’.
During the years ended August 31, 2013 and 2012, we accrued a total of $775,339 and $844,823 in finders’ compensation, payable in 301,688 and 354,741 shares of stock at $2.57 and $2.38 per share, respectively, in connection with our acquisition of the KGP (see footnotes 1 and 3 to this table). All finders’ compensation is accrued but unpaid as of August 31, 2014
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 our 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, 2014. The options in the table were all granted pursuant to our Non-Qualified Stock Option Plan.
Outstanding Equity Awards at August 31, 2014
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, 2014. Our Non-Qualified Stock Option Plan has not been approved by our shareholders.
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As of August 31, 2014, the following shares of our common stock have been issued to the following persons pursuant to our Stock Bonus Plan:
At August 31, 2014, no shares of our common stock remain available for distribution under our 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 the years ended August 31, 2014 and 2013, the following 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)
All directors fees payable to Mr. Aldorf ($81,000), Mr. Prim ($78,000), and Mr. Ebeling ($78,000) remained accrued and unpaid as of August 31, 2014.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table lists, as of November 28, 2014, 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 72,500 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) 67,000 shares owned directly by Mr. Macdonald, (b) 305,335 shares held of record by Bamako Investment Management and 351,364 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, (e) 50,000 derivative shares available under the terms of convertible notes, and those stock options detailed in (5) below.
(3)
Includes 1,027,938 shares, and 150,000 derivative shares available under the terms of the convertible notes, 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 shares held directly and those stock options detailed in (5) below. Eric Prim and Jim Ebeling also share investment control over 4,592,880shares held of record by Holloman Value Holdings, LLC.
(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.
To secure our indemnity of the asset retirement obligations 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 delivered a letter of credit in the amount of CAD$625,000 (USD$629,000) to the government of the Yukon Territory (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. The Devon LOC was provided to Devon by Pacific LNG Operations Ltd. (“PLNG”). PLNG also provided the Yukon LOC. 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.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
On September 26, 2011, we 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 Weaver for the audit of our annual financial statements for the years ended August 31, 2014 and 2013, and the aggregate fees paid or accrued for audit-related services and all other services rendered by Weaver for those years.
The category of “Audit fees” includes fees for our annual audit, quarterly reviews and services rendered in connection with statutory or 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.
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.
(4)
Incorporated by reference to the Company’s 10-K report for the year ended August 31, 2012, filed November 29, 2012.
(5)
Incorporated by reference to Exhibit 4 to the Company’s Form 10-Q report for the quarter ended November 30, 2013, filed January 14, 2014.
(6)
Incorporated by reference to Form S-1 Preliminary Registration Statement filed June 16, 2014.
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.
Signature
Date
/s/ Henry Aldof
November 28, 2014
Henry Aldorf, Chairman and Director
/s/ Keith Macdonald
November 28, 2014
Keith Macdonald, Principal Executive Officer and Director
/s/ Robert Wesolek
November 28, 2014
Robert Wesolek, Principal Financial and Accounting Officer and Director
/s/ James Hutton
November 28, 2014
James Hutton, Director
/s/ James Ebeling
November 28, 2014
James Ebeling, Director
/s/ Eric Prim
November 28, 2014
Eric Prim, Director
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
of EFLO Energy, Inc.
(An Exploration Stage Company)
We have audited the accompanying consolidated balance sheets of EFLO Energy, Inc. (an Exploration Stage Company) (the Company) as of August 31, 2014 and 2013, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and for the period from inception (July 22, 2008) to August 31, 2014. 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 EFLO Energy, Inc. (an Exploration Stage Company) as of August 31, 2014 and 2013, 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, 2014, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming that EFLO Energy, Inc. will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, EFLO Energy, Inc. has not generated significant operating revenues since inception, has incurred losses in developing its business, and further losses are anticipated. EFLO Energy, Inc. requires additional funds to meet its obligations and the costs of its operations. These factors raise substantial doubt about EFLO Energy, 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.
/s/ WEAVER AND TIDWELL, L.L.P.
WEAVER AND TIDWELL, L.L.P.
Houston, Texas
December 1, 2014
AN INDEPENDENT
WEAVER AND TIDWELL LLP
HOUSTON
MEMBER OF BAKER TILLY
CERTIFIED PUBLIC ACCOUNTANTS AND CONSULTANTS
24 GREENWAY PLAZA, SUITE 1800, HOUSTON, TX 77046
INTERNATIONAL
WWW.WEAVER.COM
P: (713) 850 8787 F: (713) 850 1673
EFLO ENERGY, INC.
(An Exploration Stage Company)
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
EFLO ENERGY, INC.
(An Exploration Stage Company)
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
EFLO ENERGY, INC.
(An Exploration Stage Company)
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
EFLO ENERGY, INC.
(An Exploration Stage Company)
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
From July 22, 2008 (Inception) to August 31, 2014
The accompanying notes are an integral part of these consolidated financial statements.
EFLO ENERGY, INC.
(An Exploration Stage Company)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE AND CONTINUANCE OF OPERATIONS
EFLO Energy, 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. During the period from July 18, 2012 through October 17, 2012, the Company acquired working interests totaling 53.65% (including a 100% working interest in one shut in gas well) in the Kotaneelee Gas Project (“KGP”) located on 30,188 gross acres in the Yukon Territory in Canada. (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 operating losses of $13,269,399 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 three wholly owned subsidiaries 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, 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. 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. 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, 2014 and 2013, 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 properties, 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. The Company periodically assesses potential impairment of its unproven properties by applying factors based on historical asset experience, average holding periods for unproven properties and other data such as remaining lease terms, and geological and geophysical information. 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, 2014 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.
The Company reviewed its unproven properties for potential impairment as of August 31, 2014 and 2013 and determined that since the estimated fair values of such assets exceeded carrying values no impairment was warranted. The Company did not drill any oil or gas wells during the two years ended August 31, 2014 and 2013.
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 leaseholds, 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 undeveloped leaseholds, which is in compliance with ASC Topic 805. In large part, the Company’s acquisitions of the KGP targeted its high-functioning infrastructure which is capable of being conducted and managed as a business in its hands. In connection with its acquisitions, the Company began its pursuit of the KGP’s principal business activities including the production of outputs, which have access to a proven customer base. Accordingly, the Company has recognized the fair value of all the assets acquired and liabilities assumed in connection with its KGP working interest acquisitions.
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.
Contingencies and Factors Which May Affect Future Operations
In the course of business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state and local environmental, health and safety laws and regulations and third party litigation. At August 31, 2014 and 2013, the Company was not party to any legal actions arising incidental to its business nor is it aware of any threatened litigation. There are no matters which, in the opinion of management, will have an adverse effect on the financial position, results of operations or cash flows for the Company.
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. The Company has generated no material revenue during the years ended August 31, 2014 or 2013.
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 the Company’s Canadian subsidiary is the Canadian dollar. Financial statements of the Company's 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. At August 31, 2014 and 2013, the Company had 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. The Company’s Diluted EPS amounts did not differ from Basic EPS for the year ended August 31, 2014, as it generated net losses during that period and any adjustment would have been anti-dilutive. The Company’s Diluted EPS amounts differ from Basic EPS for the year ended August 31, 2013, as the Company was in a net income position and adjusted the weighted average number of shares outstanding during that period by 1,411,262 shares of one of the Company’s subsidiaries issued in connection with the Company’s acquisition of the KGP, which are exchangeable for 1,614,767 shares of the Company’s restricted common stock.
As of August 31, 2014 and 2013, the Company had 5,972,267 and 3,238,101 shares of its common stock, respectively, considered non-dilutive for EPS purposes, available through the exercise stock rights agreements.
Recent Accounting Pronouncements
In June 2014, the FASB issued Accounting Standards Update 2014-10, Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation (ASU 2014-10), which eliminates the concept of a development stage entity (DSE) from U.S. GAAP. This change rescinds certain financial reporting requirements that have historically applied to DSEs and is intended to result in cost-savings for affected entities. ASU 2014-10 is effective for public entities for annual reporting periods beginning after December 15, 2014 and interim periods therein. The adoption of this guidance results in the removal of certain inception-to-date amounts and disclosures previously reported. The Company does not expect, however, that the removal of this information will have a material effect on its consolidated financial statements or the related footnote disclosures thereto.
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:
●
Level 1 - quoted prices in active markets for identical assets or liabilities.
●
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).
●
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 Notes 2 and 4, 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 $650,599 and $476,522 at August 31, 2014 and 2013, 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 (the “KGP”)
As a result of two working interest acquisitions, the Company now generally owns a 53.65% working interest in the KGP, including a 100% working interest in one shut in gas well.
The KGP covers 30,188 gross acres in the Yukon Territory in Canada, and includes: a gas dehydration plant (capacity: 70 MMcf/d), one shut in gas well, one water disposal well (capacity: 6,000 bbl/d), 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 a 24 person permanent camp facility. The KGP gas dehydration plant has a processing capacity of 70 MMcf/d, outlet gas compression of 1,200 psig and is tied-in through a 24-inch gas sales line to a gas processing plant in Fort Nelson, British Columbia.
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 shut in gas well) in the KGP. 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 approximately $7,058,000 in asset retirement obligations.
On October 17, 2012, the Company completed a Share 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”) which, in addition to the 69.337% working interest acquired from Devon on July 18, 2012, provided the Company with a 100% interest in one shut in gas well in the KGP.
As consideration for the Nahanni Assets, the Company paid Nahanni approximately $13,761,000. The consideration was comprised of approximately $133,000 in cash ($398,550 offset by $265,950 paid in connection with the acquisition of the Devon Assets in settlement of certain Nahanni indebtedness), 1,614,767 shares of one of the Company’s subsidiaries, which are exchangeable for 1,614,767 shares of the Company’s restricted common stock valued at approximately $4,191,000, and the absorption of approximately $9,437,000 in asset retirement obligations. The number of shares issued by the Company’s subsidiary was calculated by dividing the fair value of the exchangeable shares by the volume weighted average trading price of the Company’s stock for the ten (10) trading days prior to closing the purchase agreement. The fair value of the exchangeable shares has been recorded as additional paid in capital in the Company’s equity. The exchangeable shares enjoy no voting or revenue participation rights in the subsidiary.
The Company is pursuing the acquisition of additional working interests in the KGP.
The Company 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. The Company’s preliminary assessment of the fair value of the Nahanni Assets resulted in a valuation of $25,526,554. As a result of incorporating this information into the purchase price allocation, a gain on bargain purchase of $11,766,787 was recognized in the accompanying consolidated statement of operations. The gain on bargain purchase was primarily attributable to the strategic nature of the divestiture by the motivated seller, coupled with a confluence of certain favorable economic trends in the industry and the geographic region in which the Nahanni Assets are located.
The Company allocated the consideration paid for the Nahanni Assets and Devon assets based upon its assessment of their fair value at the dates of purchase, as follows:
Capitalized acquisition, exploration and development costs incurred on the KGP during the fiscal years ended August 31, 2013 and 2014 are summarized as follows:
Development costs incurred to obtain access and provide facilities for extracting, gathering, treating and storing oil and gas related to unproved oil and gas properties that are being evaluated for economic viability are added to the full cost pool until proved reserves are established, or determination is made that the unproved properties are impaired. During the years ended August 31, 2014 and 2013, the full cost pool was increased by $1,408,017 and $1,264,037, respectively, as a result of these costs.
Capitalized Costs Excluded from Amortization
The following table summarizes costs related to unproved properties that have been excluded from amounts subject to depletion, depreciation, and amortization at August 31, 2014. The KGP was the only individually significant property and development project included in the Company’s unevaluated property balance. No impairment occurred as of August 31, 2014 or 2013. The Company regularly evaluates these costs to determine whether impairment has occurred. The majority of these costs are expected to be evaluated and included in the amortization base before April 2016.
5. ASSET RETIREMENT OBLIGATIONS
In connection with its acquisition of the Devon Assets and the Nahanni Assets, the Company acquired $7,057,716 and $9,436,526 in asset retirement obligations, respectively, relating with its portion of the abandonment, reclamation and environmental liabilities associated with the KGP.
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, insofar as that lease covers from the surface to the base of the San Miguel formation (the “San Miguel Lease”). The San Miguel Lease, which is located in Zavala County, Texas, is unproven and has no current production. The Company incurred $80,000 in asset retirement obligations related to the future plugging and abandonment of a test well on the San Miguel Lease. At August 31, 2014, 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 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$9,188,000) and delivered a letter of credit in the amount of CAD$4,380,000 (USD$4,024,000) to Devon (the “Devon LOC”). The Company also delivered a letter of credit in the amount of CAD$625,000 (USD$574,000) to the government of the Yukon Territory (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 for the fiscal years ended August 31, 2014 and 2013:
6. CONVERTIBLE NOTES PAYABLE
As of August 31, 2014 convertible notes consisted of the following:
2013 Convertible Note Offering
On October 30, 2013 the Company sold convertible notes having an aggregate principal amount of $2,255,000 (the “2013 Convertible Notes”), to 22 accredited investors, under the following general terms (the "2013 Convertible Note Offering"):
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the maturity date of the 2013 Convertible Notes is April 30, 2015;
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the principal amount of the 2013 Convertible Notes is convertible into shares of the Company’s common stock at a price of $1.00 per share;
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the 2013 Convertible Notes bear interest at 15% per annum payable, at the Company’s election, in cash or shares of its common stock at a rate of $1.25 per share; and
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the Company also issued stock purchase warrants in connection with the 2013 Convertible Note Offering providing for the purchase of up to 1,127,500 shares of its common stock (1 full share for each $2.00 invested in the 2013 Convertible Notes”) at an exercise price of $1.25 per share for a period of three years (the "Stock Purchase Warrants”).
During the year ended August 31, 2014, the Company also paid $176,400 in finders’ fees and recognized $281,564 in interest expense relating to the 2013 Convertible Notes.
On June 2, 2014, $25,000 in principal payable on the 2013 Convertible Notes was converted to 25,000 shares of the Company’s common stock at a conversion price of $1.00 per share.
2014 Convertible Note Offering
During June 2014, the Company sold convertible notes having an aggregate principal amount of $1,400,000 (the “2014 Convertible Notes”), to two accredited investors, and one non-accredited investor, under the following general terms (the “2014 Convertible Note Offering”):
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the maturity date of the 2014 Convertible Notes is December 31, 2014;
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at the option of the note holder, the principal amount of the 2014 Convertible Notes was to be convertible into shares of the Company’s common stock at a price per share to be determined in connection with the Company’s planned offering of shares upon migration to a senior stock exchange, less a 10% discount (the “2014 Conversion Right”);
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a 6% financing fee on the principal sum of the 2014 Convertible Notes, is payable:
a.
in the event the note holder exercises its 2014 Conversion Right, in shares of the Company’s common stock (the number of which is to be calculated using the closing market price of the Company’s shares on the conversion date); or
b.
in the event the note holder does not exercise its 2014 Conversion Right, at the option of the note holder, in shares of the Company’s common stock (the number of which is to be calculated using the closing market price of the Company’s shares at December 31, 2014), or in cash of $84,000.
During the year ended August 31, 2014, the Company recognized $37,183 in interest expense relating to the 2014 Convertible Notes.
7. RELATED PARTY TRANSACTIONS
Companies affiliated with the Company’s Chairman and one of its Directors purchased convertible notes in the principal amounts of $1,000,000 and $350,000, respectively, in the 2014 Convertible Note Offering (Note 6).
Effective September 1, 2013, the Company executed an administrative services agreement with its largest shareholder, Holloman Corporation. Under this agreement, fees of $5,000 per month are payable to Holloman Corporation covering; office and meeting space, supplies, utilities, office equipment, network access and other administrative facilities costs. These fees are payable quarterly in shares of the Company’s restricted common stock at the closing price of the stock on the last trading-day of the applicable monthly billing period. This administrative services agreement can be terminated by either party with 30-day notice. Proceeds from this administrative service agreement have been assigned to a wholly owned subsidiary of Holloman Corporation.
In connection with its acquisition of the Devon Assets, the Company acquired $7,057,716 in asset retirement obligations. To secure this 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 the Company’s restricted common stock. Likewise, the Devon LOC was provided to Devon by Pacific LNG Operations Ltd. (“PLNG”). PLNG also provided 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. Two of the Company’s 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 finders’ compensation ranging from 5% (on transaction values greater than $1,000,000) to 10% (on transactions valued up to $300,000) on transactions introduced to the Company by or through the Finders for a period of two years (the “Finders’ Fee Agreement”). Under the Finders’ Fee Agreement, compensation is divided among the Finders and the Finders may elect whether the finders’ 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 finders’ 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 Finders’ Fee Agreement specifically recognizes that the KGP has been presented to the Company by the Finders. During the year ended August 31, 2013, finders’ compensation of $844,282 was recognized as stock based compensation and consulting fees in connection with the Company’s acquisition of the Nahanni Assets. As of August 31, 2014 a total of $1,619,621 remains accrued and unpaid in connection with the Finders’ Fee Agreement.
Management Fees
During each of the years ended August 31, 2014 and 2013, management fees totaling $240,000, 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 $100,000 and $50,000 of this compensation remained accrued and unpaid as of August 31, 2014 and 2013, respectively.
During the years ended August 31, 2014 and 2013, management fees totaling $297,810 and $190,624 were incurred with an entity controlled by the Company’s Chief Operating Officer. The amount of compensation was established and approved by the Company’s Board of Directors. Of the amounts incurred, $7,480 and $13,541 remained accrued and unpaid as of August 31, 2014 and 2013, respectively.
For the years ended August 31, 2014 and 2013, compensation to the Company’s Chief Financial Officer totaled $172,350 and $227,272, respectively. Of those compensation amounts, $6,654 and $9,750 were accrued at August 31, 2014 and 2013, respectively. These 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, and were approved by the Company’s Board of Directors.
During the years ended August 31, 2014 and 2013, management fees totaling $83,193 and $108,424, respectively, were incurred with an entity controlled by the Company’s President. On June 2, 2014 the Company’s President resigned. On that date, $54,350 in unpaid fees were settled using 67,938 shares of the Company’s restricted common stock. The Company also granted the outgoing President 100,000 shares of its common stock as additional compensation. On June 2, 2014, the closing price of the Company’s common stock was $0.80 per share. As of August 31, 2013, $19,220 in fees and reimbursable expenses remained accrued and unpaid to this officer.
8. CAPITAL STOCK AND STOCK-BASED COMPENSATION
Convertible Notes
In connection with the 2013 Convertible Note Offering (Note 6), the Company issued the Stock Purchase Warrants providing for the purchase of up to 1,127,500 shares of its common stock (1 full share for each $2.00 invested in the 2013 Convertible Notes) at an exercise price of $1.25 per share for a period of three years. The Company applied the Black-Scholes option pricing model to determine the fair market value of the Stock Purchase Warrants. In applying the model, the Company used the following parameters: contractual lives of 3 years, historical stock price volatility of 77%, a risk-free rate of 4.5% and an annual dividend rate of 0%. As a result, the Company determined that the total fair market value of the Stock Purchase Warrants was $533,803, and that amount was recognized as a discount against the principal of 2013 Convertible Notes. This is considered to be a Level 2 fair value measurement. During the year ended August 31, 2014, $299,839 of the 2013 Convertible Note discount was amortized to interest expense.
In aggregate, 3,357,500 shares of the Company’s common stock (comprised of 2,230,000 shares issuable on conversion of the principal of the 2013 Convertible Notes and 1,127,500 shares issuable on exercise of the Stock Purchase Warrants), or such greater number of shares as may be issuable upon election of the interest repayment in common stock under the terms of the 2013 Convertible Notes, has been reserved for issuance upon conversion of the Convertible Notes or exercise of the Stock Purchase Warrants in accordance with their terms.
Sales of Common Stock and Investment Units
During January and February 2013, the Company sold 350,000 shares of its common stock to two (2) accredited investors at a price of $1.20 per share. Gross proceeds from these private placements totaled $420,000. The Company paid $14,700 in finders’ fees in connection with the sale of these shares.
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. The Company paid $64,289 in finders’ fees in connection with the sale of these shares.
The Company relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 with respect to the sale of these securities.
Non-Qualified Stock Option Plan and a Stock Bonus Plan
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 it deems appropriate, provided that any amendment, termination or suspension may not adversely affect rights or obligations with respect to options or shares previously granted.
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%. As a result, the Company determined that the total fair market value of the options granted was $1,131,900 and the weighted-average grant-date fair value per option granted was $0.94.
In addition, 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 was the market price of the stock at date of grant. The 300,000 Bonus Shares had a value of $2.07 per share.
On January 15, 2013, the Company also authorized the issuance of 50,000 bonus shares of its common stock to its new Chief Operating Officer pursuant to the 2012 Stock Bonus Plan. The Company recognized non-cash management fees of $97,000, or $1.94 per share related to these Bonus Shares in the statements of operations during the year ended August 31, 2013.
On January 15, 2013, the Company granted its new Chief Operating Officer 400,000 stock options in accordance with its 2012 Non-Qualified Stock Option Plan under the terms shown below:
The Company applied the Black-Scholes option pricing model to determine the fair market value of the options granted. In applying the model, the Company used the following parameters: contractual lives of 2 to 4.5 years, historical stock price volatility of 65%, a risk-free rate of 4.5% and an annual dividend rate of 0%. As a result, the Company determined that the total fair market value of the options granted was $313,646 and the weighted-average grant-date fair value per option granted was $0.78.
During the years ended August 31, 2014 and 2013, the Company recognized $437,107 and $714,665, respectively, of non-cash expense related to stock-based compensation under the Option Plan. As of August 31, 2014, $46,798 of total unrecognized compensation cost remains under the Option Plan. This amount, $46,798 is expected to be recognized during fiscal 2015.
The weighted-average grant-date fair value of options granted during the year ended August 31, 2013 was $0.78.
Other Stock-Based Compensation
During the years ended August 31, 2014 and 2013, $120,000 and $120,000 in fees were paid to entities controlled by the Company’s Chief Executive Officer using 124,021 and 64,344 shares of the Company’s restricted common stock at weighted average prices of $0.97 and $1.87 per share, respectively.
During the year ended August 31, 2014, fees totaling $60,000 incurred in connection with an administrative services agreement were paid to the Company’s largest shareholder using 62,010 shares of the Company’s restricted common stock at a weighted average price of $0.97.
On June 2, 2014 the Company’s President resigned. On that date, $54,350 in unpaid fees were settled using 67,938 shares of the Company’s restricted common stock. The Company also granted the outgoing President 100,000 shares of its common stock as additional compensation. On June 2, 2014, the closing price of the Company’s common stock was $0.80 per share.
During the year ended August 31, 2014, fees totaling $30,000 were paid using 31,005 shares of the Company’s restricted common stock at a weighted average price of $0.97 to an unrelated consultant.
The Company relied upon the exemption provided by Section 4(2) of the Securities Act of 1933 with respect to the sale of these securities.
Stock Warrants and Other
At August 31, 2014, warrants for 1,127,500 shares of the Company’s common stock were outstanding with a weighted-average remaining life and exercise price of 26 months and $1.25, respectively. During the year ended August 31, 2014, 1,127,500 warrants were issued and 23,334 warrants were forfeited or expired. During the year ended August 31, 2013, 23,334 warrants were issued and 596,870 warrants were forfeited or expired.
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:
Statutory tax rates:
The significant components of deferred income tax assets and liabilities at August 31, 2014 and 2013are as follows:
During the year ended August 31, 2013, a gain on bargain purchase of $11,766,787 was recognized in the accompanying consolidated statement of operations. The gain on bargain purchase was primarily attributable to the strategic nature of the divestiture by the motivated seller, coupled with a confluence of certain favorable economic trends in the industry and the geographic region in which the Nahanni Assets are located. See Note 4 for additional information regarding the purchase of assets and the related gain. This gain was not recognized for tax purposes.
At August 31, 2014, the Company has accumulated United States non-capital loss carry-forwards of approximately $7,515,470. At August 31, 2013 the Company had accumulated United States non-capital loss carry-forwards of approximately $3,826,451. The United States loss carry-forwards begin to expire in 2032.
At August 31, 2014, the Company has accumulated Canadian non-capital loss carry-forwards of approximately $7,219,434. At August 31, 2013, the Company has Canadian non-capital loss carry-forwards of approximately $1,725,284. The Canadian loss carry-forwards begin to expire in 2019.
Deferred tax assets have resulted primarily from the Company’s future deductible temporary differences. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion, or all, of the deferred tax asset will be realized.
The Company’s ability to realize its deferred tax assets depends upon the generation of sufficient future taxable income to allow the utilization of its deductible temporary differences and tax planning strategies. If such estimates and related assumptions change in the future, the Company may be required to record a valuation allowance against its deferred tax asset. Management evaluates the realizablity of the deferred tax assets and the need for a valuation allowance periodically. At this time, based on current facts and circumstances, management does not believe that it is more likely than not that the Company will realize benefit from its gross deferred tax assets.
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
In June 2014, the Company filed a Canadian Prospectus and a US Form S-1 Registration Statement to facilitate its planned migration and initial public offering of common stock on the TSX Venture Exchange (Canada). As a result of poor and deteriorating conditions in Canadian capital markets, however, the Company withdrew its offering documents effective November 25, 2014. The Company currently plans to undertake further cost reduction strategies and a combination of working interest acquisition and farm-out strategies to facilitate its KPG exploration plans.