Business of Delta Oil & Gas
We were incorporated under the laws of the State of Colorado on January 9, 2001 under the name Delta Oil & Gas, Inc.
We are engaged in the acquisition, development and production of oil and natural gas properties in North America. We seek to acquire and develop properties with undeveloped reserves that are economically attractive to us. We will employ expertise in geological and geophysical areas to mitigate, as reasonably possible, the inherent risk of oil and gas exploration. We seek to create value and reduce risks through the acquisition and development of property interests in areas that have:
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Significant undeveloped reserves;
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Close proximity to developed markets for oil and natural gas; and
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Existing infrastructure or the ability to install our own infrastructure of oil and natural gas pipelines and production platforms.
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During the first and second quarters of 2010, management engaged in a detailed strategic review of all of our development lands, exploratory lands and working interest partners held at that time. The outcome of these reviews lead to an internal declaration of core and non-core properties. Those properties within the “Core” grouping were to receive priority focus for development and expansion and those in the “non-core” grouping were to be considered as low priority for development and considered for divestment should offers fall within range of what management believes are their true values.
Historically, we have taken small working interest positions in multiple and diverse projects. Under our current Core / Non-core strategy, we generally focus on larger working interest relationships in substantive project areas and move to strategically explore and develop those projects. We believe that this core strategy will enable us to develop Delta Oil & Gas to the next level in its growth towards becoming a significant oil and natural gas producing entity.
Our current focus is on the exploration of our Core land portfolio comprised of working interests in acreage in Eastern Texas, (described below).
CORE PROPERTIES
Texas Prospect
On July 15, 2009, we entered into an assignment agreement with Mr. Barry Lasker (the “Assignor”) and were assigned all of Assignor’s rights and obligations under two oil, gas and liquid hydrocarbon lease agreements, each dated March 26, 2009 (the “Leases”) covering an aggregate area of approximately 243 acres in Newton County, Texas (the “Texas Prospect”). These Leases provide us with the ability to drill up to 3 exploration wells.
Following our disposition of a 60% interest in the Leases to Hillcrest Resources Ltd. (“Hillcrest”) in December 2009, we are responsible for 40% of all costs allocated to the Leases, drilling and completion of up to 3 exploration wells. We have drilled and completed the first two exploration holes. Once the 3 exploration wells are drilled, completed and production commences, if at all, we will receive a percentage distribution of net revenue, after deduction of all applicable expenses and royalties of approximately 25%, according to the following table:
Net Revenue Distribution
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Before Payout
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After Payout
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Well #1
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36%
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20%
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Well #2
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36%
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24%
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Well #3
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36%
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24%
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Under the terms of the Leases, we have the ability to participate in additional wells drilled in the Texas Prospect. In the event that we elect to participate, we will negotiate with Hillcrest our respective levels of participation in additional wells. Our percentage of the costs and net revenue distribution, both before and after payout, associated with each additional well will be proportional to our level of participation.
We paid our proportionate share of the drilling and completion costs during the quarter ended June 30, 2010. On June 4, 2010, the first well (the “Donner #1”) was successfully drilled and encountered hydrocarbons. The well was completed and the well went into production during the quarter ended September 30, 2010. On August 4, 2011, we successfully drilled and completed the second well (the “Donner #2”). The following represents the revenue from the drilling program:
Well Name
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Year ended
Dec 31, 2013
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Year ended
Dec 31, 2012
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Donner #1
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$
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243,614
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$
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245,496
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Donner #2
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$
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120,097
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$
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73,990
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Revenue has essentially remained consistent with the prior year, with no appreciable change in production. Any movement in revenue received was caused by a change in the price of oil.
The increase in revenue for Donner #2 was caused by an increase in natural gas prices when compared to fiscal 2012. The well has not achieved Payout and hence the Net Revenue Distribution will remain at 36%.
On February 4, 2014, the Company participated in the drilling of Donner #4, which has been completed as a natural gas well.
On December 16, 2013 the Company obtained a loan, from an investment group, restricted for the further development of Texas properties in which they hold a participation agreement. The loan is secured by an assignment of thirty percent of the revenues earned by the Company before payout and ten percent of revenues earned after payout from Donner 1 and Donner 2. The funds are to be used exclusively for the development of Donner 4. The loan carries an interest rate of ten percent on total proceeds of $255,000 with $155,000 received in 2013 and the balance received in January, 2014.
In conjunction with the loan, the lender was granted an option to purchase ten percent of the Company’s interest in Donner 1, 2 and 4 for $100,000. The option was exercised in January, 2014.
Payout is defined as the point when lenders have received payments, net of operating expenses, from the lender’s interest in the assets totaling $255,000 with interest calculated on the outstanding balance, at the rate of 10% per annum, and paid on a monthly basis.
Premont Northwest Field, USA
On August 20, 2012, the Company acquired its 10% working interest in the Garcia #3 and the continuing development rights in the field with an agreement with Progas Energy Services LLC, a Texas oil & gas company (“Progas”) to jointly develop the field located in Jim Wells County, Texas, known as the Premont Northwest Field. The Company acquired these interests through the issuance to Progas of 236,134 common shares at an initial cost of $0.15 per share and its pro-rata share of drilling costs, which was $49,460. The Company has also paid its pro-rata share of $42,000 for two re-completions.
The first four wells in this field have shown oil stains in at least one zone per well. The Company’s operator is awaiting an electric installation which will power the pumps so that testing of each well can begin. The Company’s operator expects production to start in the first quarter of 2014.
King City, California
On May 25, 2009, we entered into a farm-out agreement with Sunset Exploration (“Sunset”), a California corporation, to participate in the drilling and exploration of lands located in Monterey County, California. The prospect area where the drilling and exploration will take place was comprised of approximately 10,000 acres. We were obligated to pay 66.67% of the costs of the initial test well up to casing point, in order to earn a 40.0% working interest. Thereafter, we were obligated to pay 40.0% of the costs of any future wells which we elect to participate in order to earn a 40.0% working interest. We paid Sunset $100,000 as an advance towards the permitting and processing of lands and the costs of a gravity survey and a 2D seismic program.
We completed a gravity survey and 2D seismic program in 2010 and extensively reviewed the data provided from the program. The first exploration well was drilled in November 2011 at a cost of $608,084. The logs indicated potential pay zones and we completed a test well with a view toward full production if the tests indicate an economic potential. During the quarter ended March 31, 2013, testing results indicated that there were no economic hydrocarbons, hence the well was abandoned. Total costs of $363,231 were moved to the proven cost pool for depletion. The Company has no further interest in the King City lands.
NON-CORE PROPERTIES
2009-3 Drilling Program - 4 Wells
On August 7, 2009, we entered into an agreement with Ranken Energy Corporation (“Ranken Energy”) to participate in a four well drilling program in Garvin County, Oklahoma (the “2009-3 Drilling Program”). We purchased a 6.25% working interest before casing point and 5.0% working interest after casing point in the 2009-3 Drilling Program for $37,775. In addition to the total buy-in cost, we are responsible for our proportionate share of the drilling and completion costs. The first well (the “Jackson #1-18”) started production during the quarter ending March 31, 2010, the second well (the “Miss Gracie #1-18”) started production during the quarter ending June 30, 2010 and the third well (“Joe Murray Farms”) started production during the quarter ended September 30, 2010. On August 18, 2011, we plugged and abandoned Jackson #1-18 due to the well being uneconomic. The following represents the revenues from this drilling program:
Well Name
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Year ended
Dec 31, 2013
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Year ended
Dec 31, 2012
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Miss Gracie #1-18
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$
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30,089
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$
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54,298
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Joe Murray Farms
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$
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9,020
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$
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43,429
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On November 5, 2013, the Company sold its working interest in all wells in the 2009-3 drilling program except for Joe Murray Farms. The decrease in revenues for Joe Murray Farms was due to a reduction in production for the period as compared to the corresponding prior year. The reduced production was caused by a general decline in the wells’ reserves, however, the well has been reworked and production has increased subsequent to December 31, 2013.
Due to ongoing legal proceedings potentially impacting the Joe Murray Farms well, the revenue reported from the Joe Murray Farms well for the year ended December 31, 2013 and December 31, 2012 reflects fifty percent (50%) of the total revenues generated from production and the remaining fifty percent (50%) is being escrowed pending the outcome of these proceedings and has not been recognized as revenue. We have recognized an aggregate of $160,613 in revenue from the Joe Murray Farms well and $160,613 is the other fifty percent amount as of December 31, 2013 that is being escrowed pending the outcome of these proceedings and has not been recognized as revenue.
On October 1, 2013, the Company committed $50,000 of its escrow funds to the settlement provided that the balance of the Company’s escrow funds are returned to the Company upon achieving a settlements.
2009-1 Drilling Program - 5 Wells
On July 27, 2009, we entered into an agreement with Ranken Energy to participate in a five well drilling program in Garvin County, Oklahoma (the “2009-1 Drilling Program”). We initially acquired a 5.0% working interest in the 2009-1 Drilling Program in exchange for our payment of a total of $13,125 in buy-in costs, which equates to $2,625 in buy-in costs for each well, plus our proportionate share of the drilling and completion costs. During the fourth quarter of 2009, our working interest in the 2009-1 Drilling Program was reduced to 3.75%. The reduction in our working interest was attributable to the land owner exercising an option to increase its working interest causing a proportional reduction to all working interests held in this drilling program.
The first three wells in this drilling program referred to as Saddle #1-18, Saddle #2-18 and Saddle #3-18 started to produce hydrocarbons during the quarter ending March 31, 2010. Total revenue received from all three wells for the year ended December 31, 2013 was $3,995 (December 31, 2012: $7,912); the working interest in this drilling program was sold on November 5, 2013.
2007-1 Drilling Program - 3 Wells
On September 10, 2007, we entered into an agreement with Ranken Energy to participate in a four well drilling program in Garvin County, Oklahoma (the “2007-1 Drilling Program”). Drilling of the first and second wells (the “Pollock #1-35” and the “Hulsey #1”) was completed in the N.E. Anitoch Prospect and the Washington Creek Prospect respectively. The Pollock #1-35 did not prove to be commercially viable.
Drilling of the third well in this drilling program (the “River #1”) was completed during the three months ended September 30, 2008. River #1 is currently in production and the total revenue received for the year ended December 31, 2013 was $7,724 (December 31, 2012: $15,808); all wells in this drilling program were sold on November 5, 2013.
Hulsey #1-8 started producing during the first quarter of 2008 and the total revenue received for the year ended December 31, 2013 was $38,290 (December 31, 2012: $51,976). All wells in this drilling program were sold on November 5, 2013.
Hulsey #2-8 commenced production during the three months ended March 31, 2009 and produced $27,602 for the year ended December 31, 2013 (December 31, 2012: $28,349). All wells in this drilling program were sold on November 5, 2013.
2006-3 Drilling Program
On April 17, 2007, we entered into an agreement with Ranken Energy to participate in a six well drilling program in Garvin and Murray counties in Oklahoma (the “2006-3 drilling Program”). The leases secured and/or lands to be pooled for this drilling program total approximately 820 net acres. We agreed to take a 10% working interest in this program.
Three wells drilled (the “Wolf #1-7”, the “Loretta #1-22” and the “Ruggles #1-15”) were deemed by the operator to not be commercially viable and as such, were plugged and abandoned in September 2007.
Three other wells (the “Elizabeth #1-25”, the “Plaster #1-1” and the “Dale #1 re-entry”) drilled in August and September 2007 were deemed by the operator to be commercially viable and production casing was set in each. The Plaster #1 encountered hydrocarbon showings and produced natural gas commencing in January, 2008, but was sold in the second quarter of 2011 for net proceeds of $7,603. The Dale #1 re-entry has been producing in the range of 2 to 3 barrels of oil per day. The Elizabeth #1-25 has been plugged and abandoned as of February 7, 2008. The Plaster #1well was sold in the second quarter of 2011 for net proceeds of $7,603, resulting in a loss on the sale of $8,128.
Total revenue received from the Plaster #1 and Dale #1 wells for the year ended December 31, 2013 was $nil (December 31, 2012: $nil). All remaining wells in this drilling program were sold on November 5, 2013.
Market for Our Products and Services and Distribution Methods of Our Products and Services
Each oil and gas working interest that we now own and those that we may later acquire a percentage of interest in will have an operator who will be responsible for marketing production.
The availability of a ready market for oil and gas and the prices of such oil and gas depend upon a number of factors which are beyond our control. These include, among other things:
• the level of domestic production;
• actions taken by foreign oil and gas producing nations;
• the availability of pipelines with adequate capacity;
• the availability and marketing of other competitive fuels;
• fluctuating and seasonal demand for oil, gas and refined products; and
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the extent of governmental regulation and taxation (under both present and future legislation) of the production, importation, refining, transportation, pricing, use and allocation of oil, gas, refined products and alternative fuels.
In view of the many uncertainties affecting the supply and demand for crude oil, gas and refined petroleum products, it is not possible to predict accurately the prices or marketability of the gas and oil produced for sale.
In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state, local and tribal laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
Patents, Licenses, Trademarks, Franchises, Concessions, Royalty Agreements, or Labor Contracts
We do not own, either legally or beneficially, any patent or trademark.
Research and Development
We did not incur any research and development expenditures in the fiscal years ended December 31, 2013 or 2012.
Governmental Regulation
We monitor and comply with current government regulations that affect our activities, although our operations may be adversely affected by changes in government policy, regulations or taxation. There can be no assurance that we will be able to obtain all of the necessary licenses and permits that may be required to carry out our exploration and development programs. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other natural gas and oil companies operating in the areas in which we operate.
United States Government Regulation
The United States federal government and various state and local governments have adopted laws and regulations regarding the protection of human health and the environment. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, or where pollution might cause serious harm, and impose substantial liabilities for pollution resulting from drilling operations, particularly with respect to operations in onshore and offshore waters or on submerged lands. These laws and regulations may increase the costs of drilling and operating wells. Because these laws and regulations change frequently, the costs of compliance with existing and future environmental regulations cannot be predicted with certainty.
The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government. Production of any oil and gas by properties in which we have an interest will be affected to some degree by state regulations. States have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes and the regulations are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir.
State regulatory authorities may also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or pro-ration unit.
Any exploration or production on Federal land will have to comply with the Federal Land Management Planning Act which has the effect generally of protecting the environment. Any exploration or production on private property whether owned or leased will have to comply with the Endangered Species Act and the Clean Water Act. The cost of complying with environmental concerns under any of these acts varies on a case by case basis. In many instances the cost can be prohibitive to development. Environmental costs associated with a particular project must be factored into the overall cost evaluation of whether to proceed with the project.
Environmental Regulation
Oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution. The strict liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general.
Comprehensive Environmental Response, Compensation and Liability Act
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The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.
Compliance with Environmental Laws
We did not incur any costs in connection with the compliance with any federal, state, or local environmental laws. However, costs could occur at any time through industrial accident or in connection with a terrorist act or a new project. Costs could extend into the millions of dollars for which we could be totally liable. In the event of liability, we believe we would be entitled to contribution from other owners so that our percentage share of a particular project would be the percentage share of our liability on that project. However, other owners may not be willing or able to share in the cost of the liability. Even if liability is limited to our percentage share, any significant liability would wipe out our assets and resources.
Employees
We have no full-time employees at the present time. Our executive officers do not devote their services full time to our operations.
We engage contractors from time to time to consult with us on specific corporate affairs or to perform specific tasks in connection with our oil and gas operations. As of December 31, 2013, we engaged approximately 3 contractors that provided work to us on a recurring basis, which includes Messrs. Paton-Gay, Bolen and Sandher, our executive officers.
You should carefully consider the following risk factors in evaluating our business and us. The factors listed below represent certain important factors that we believe could cause our business results to differ. These factors are not intended to represent a complete list of the general or specific risks that may affect us. It should be recognized that other risks may be significant, presently or in the future, and the risks set forth below may affect us to a greater extent than indicated. If any of the following risks occur, our business, financial condition or results of operations could be materially and adversely affected. You should also consider the other information included in this Annual Report and subsequent quarterly reports filed with the SEC.
Risk Factors
Operational Risks of Delta Oil & Gas
Because we have experienced significant losses since inception, it is uncertain when, if ever, we will have significant operating income or cash flow from operations sufficient to sustain operations.
We suffered a net comprehensive loss of $1,211,814 for the year ended December 31, 2013 and $483,481 for the year ended December 31, 2012. These losses are the result of an inadequate revenue stream to compensate for our operating and overhead costs and the impairment of oil and gas properties. The volatility underlying the early stage nature of our business and our industry prevents us from accurately predicting future operating conditions and results, and we could continue to have losses. It is uncertain when, if ever, we will have significant operating income or cash flow from operations sufficient to sustain operations. If cash needs exceed available resources, additional capital may not be available through public or private equity or debt financings. If we are unable to arrange new financing on terms that are acceptable to us or generate sufficient revenue from our prospects, we will be unable to continue in our current form and our business will fail.
Because our auditor has raised substantial doubt about our ability to continue as a going concern, our business has a high risk of failure.
The audit report of Excelsis Accounting Group (f/k/a Mark Bailey & Company, Ltd.), dated April 9, 2014 issued a going concern opinion and raised substantial doubt as to our continuance as a going concern. When an auditor issues a going concern opinion, the auditor has substantial doubt that the company will continue to operate indefinitely and not go out of business and liquidate its assets. This is a significant risk to investors who purchase shares of our common stock because there is an increased risk that we may not be able to generate and/or raise enough resources to remain operational for an indefinite period of time. The success of our business operations depends upon our ability to obtain additional capital for obtaining producing oil and gas properties through either the purchase of producing wells or successful exploration activity. We plan to seek additional financing, as needed, through debt and/or equity financing arrangements to secure funding for our operations. There can be no assurance that such additional financing will be available to us on acceptable terms or at all. It is not possible at this time for us to predict with certainty the outcome of those efforts. If we are not able to successfully complete the development of our business plan and attain sustainable profitable operations, then our business will fail.
If we are unable to obtain additional funding, we may be unable to expand our acquisition, exploration and production of natural oil and gas properties.
We will require additional funds to expand our acquisition, exploration and production of natural oil and gas properties. Our management anticipates that current cash on hand may be insufficient to fund our operations at the current level for the next twelve months. We will require additional significant capital to fund the development of our existing proved undeveloped reserves and to effectively expand our operations through the acquisition and drilling of new prospects and implement our overall business strategy. There can be no assurance that financing will be available in amounts or on terms acceptable to us, if at all. The inability to obtain additional capital will restrict our ability to grow and may reduce our ability to continue to conduct current business operations. If we are unable to obtain additional financing when sought, we will be unable to acquire additional properties and may also be required to curtail our business plan. Any additional equity financing may involve substantial dilution to our then existing shareholders.
In preparing our consolidated financial statements for fiscal 2013, our management identified material weaknesses in our internal control over financial reporting and our failure to remediate these material weaknesses could result in material misstatements in our consolidated financial statements and the loss of investor confidence in our reported financial information.
Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Our management identified material weaknesses in our internal control over financial reporting as of December 31, 2013. A material weakness is defined as a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis. The material weaknesses identified by management as of December 31, 2013 was attributable to the size of the Company and the fact that we have only one financial expert on our management team and no audit committee. Although management believes that the material weakness set forth above has not had an effect on our financial statements, there can be no assurance that this will continue to be the case going forward.
If remedial measures are not taken or are insufficient to address these material weaknesses, or if additional material weaknesses or significant deficiencies in our internal control over our financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to restate our financial results. Any future restatement of consolidated financial statements could place a significant strain on our internal resources and harm our operating results. Further, any additional or un-remedied material weakness may preclude us from meeting our reporting obligations on a timely basis and cause investors to lose confidence in our reported financial information.
Because we cannot control activities on our properties, we may experience a reduction or forfeiture of our interests in some of our non-operated projects as a result of our potential failure to fund capital expenditure requirements.
We do not operate the properties in which we have a working interest and we have limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our returns on capital in drilling or acquisition activities and our targeted production growth rate. The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator’s expertise and financial resources, approval of other participants for drilling wells and utilization of technology. In addition, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.
If we are unable to successfully identify, execute or effectively integrate new prospects, our results of operations may be negatively affected.
Acquisitions of working interests in oil and gas properties have been an important element of our business, and we will continue to pursue acquisitions of new prospects in the future. In the last year, we have pursued and consummated the acquisition and drilling of new prospects that have provided us opportunities to grow our production and reserves. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition,
finance the acquisition or, if the acquisition occurs, effectively integrate the acquired business into our existing business. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available on reasonable terms or at all, any new properties may not generate revenues comparable to our existing properties, the anticipated cost efficiencies or synergies may not be realized and these properties may not be integrated successfully or operated profitably. The success of any acquisition will depend on a number of factors, including the ability to estimate accurately the recoverable volumes of reserves, rates of future production and future net revenues attainable from the reserves and to assess possible environmental liabilities. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations. Even though we perform a due diligence review (including a review of title and other records) of the properties we seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. Even an in-depth review of records and properties may not necessarily reveal existing or potential problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with the acquired properties. In addition, acquisitions of working interests may require additional debt or equity financing, resulting in additional leverage or dilution of ownership.
Unless we replace our oil and gas reserves, our reserves and production will decline.
Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.
Because our executive officers do not provide services on a full-time basis, they may not be able or willing to devote a sufficient amount of time to our business operations, causing our business to fail.
Our executive officers do not provide services to us on a full-time basis. We do not maintain key man life insurance policies for our executive officers. Currently, we do not have any employees other than our executive officers. If the demands of our business require the full business time of Messrs. Paton-Gay, Bolen, and Sandher, it is possible that Messrs. Paton-Gay, Bolen, and/or Sandher may not be able to devote sufficient time to the management of our business, as and when needed. If our management is unable to devote a sufficient amount of time to manage our operations, our business will fail.
If the employment of any of our executive officers is terminated for any reason, we may be required to make substantial severance payments and to repurchase any shares of common stock held by them, which could have a materially negative impact on our liquidity.
In the event that the employment of any of our executive officers is terminated for any reason, our executive officers would be entitled, among other things, to receive a lump sum payment equal to 150% of their annual compensation then in effect, including
the value
of
all stock awards that would have been received in the 18 months following termination, and to require us to purchase, for cash, any shares of our stock held by or due to them as of the date of termination. The purchase of any such shares would be consummated thirty (30) days following the date of termination and the price to be paid by us would be based upon the average closing price per share of our common stock in the ten business days preceding the purchase date. Any lump sum compensation payments to or the repurchase of shares held by one or more departing executive officers could have a materially negative impact on our cash available for operations and our liquidity.
Because our directors and officers may serve as directors or officers of other companies, they may have a conflict of interest in making decisions for our business.
Our directors and officers may serve as directors or officers of other companies or have significant shareholdings in other oil and gas companies and, to the extent that such other companies may participate in ventures in which we may participate, our directors and officers may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of our directors, a director who has such a conflict will abstain from voting for or against the approval of such participation or such terms. In determining whether or not we will participate in a particular program and the interest therein to be acquired by us, our directors will primarily consider the degree of risk to which we may be exposed and our financial position at that time.
Because we presently do not carry liability or title insurance on any of our properties and do not plan to secure any in the future, we are vulnerable to excessive potential claims and loss of title.
We do not maintain insurance against public liability, environmental risks or title on any of our properties. The possibility exists that title to existing properties or future prospective properties may be lost due to an omission in the claim of title. As a result, any claims against us may result in liabilities we will not be able to afford resulting in the failure of our business.
The laws of the State of Colorado and our Articles of Incorporation may protect our directors from certain types of lawsuits.
The laws of the State of Colorado provide that our directors will not be liable to us or our shareholders for monetary damages for all but certain types of conduct as directors of the company. Our articles of incorporation permit us to indemnify our directors and officers against all damages incurred in connection with our business to the fullest extent provided or allowed by law. The exculpation provisions may have the effect of preventing shareholders from recovering damages against our directors caused by their negligence, poor judgment or other circumstances. The indemnification provisions may require us to use our limited assets to defend our directors and officers against claims, including claims arising out of their negligence, poor judgment, or other circumstances.
Market Risks
Our stock price may be volatile and as a result you could lose all or part of your investment.
In addition to volatility associated with over the counter securities in general, the value of your investment could decline due to the impact of any of the following factors upon the market price of our common stock:
• changes in the worldwide price for oil and gas;
• disappointing results from our exploration or development efforts;
• failure to meet our revenue or profit goals or operating budget;
• decline in demand for our common stock;
• downward revisions in securities analysts’ estimates or changes in general market conditions;
• technological innovations by competitors or in competing technologies;
• investor perception of our industry or our prospects; and
• general economic trends.
In addition, stock markets generally have recently experienced price and volume fluctuations and the market prices of securities generally have been volatile. These fluctuations often have been unrelated to operating performance of a company; such market conditions may also adversely affect the market price of our common stock. As a result, investors may be unable to resell their shares at a profitable price.
Intense competition in the oil and gas exploration and production segment could adversely affect our ability to acquire desirable properties prospective for oil and gas, as well as producing oil and gas properties.
The oil and gas industry is highly competitive. We compete with major integrated and independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than ours, which could, in the future, make acquisitions of producing properties at economic prices difficult for us. In addition, many larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production, such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also face significant competition in attracting and retaining experienced, capable and technical personnel with experience in the oil and gas industry.
Numerous factors beyond our control could affect the marketability of oil and natural gas, so we may experience difficulty selling any oil and natural gas.
The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. The marketability of our production depends upon the availability and capacity of natural gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to generate revenue from oil and natural gas sales also depends on other factors beyond our control. These factors include:
• the level of domestic production and imports of oil and natural gas;
• the proximity of natural gas production to natural gas pipelines;
• the availability of pipeline capacity;
• the demand for oil and natural gas by utilities and other end users;
• the availability of alternate fuel sources;
• the effect of inclement weather, such as hurricanes;
• state and federal regulation of oil and natural gas marketing; and
• federal regulation of natural gas sold or transported in interstate commerce.
If these factors were to change dramatically, our ability to generate revenues from oil and natural gas sales or obtain favorable prices for our oil and natural gas could be adversely affected.
We have hurricane associated risks in connection with our properties in Texas.
The properties in Texas are vulnerable to significant production curtailments resulting from hurricane damage to certain fields or, even in the event that producing fields are not damaged, production could be curtailed due to damage to facilities and equipment owned by oil and gas purchasers, or vendors and suppliers, because a portion of our oil and gas properties are located near coastal areas of the Texas.
Risks Relating to Our Business
Because exploration, development and drilling efforts are subject to many risks, the operation of our wells may not be profitable or achieve our targeted returns.
Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We seek to acquire working interests in properties which we believe will result in projects that will add value over time. However, we cannot guarantee that all of our prospects will result in viable projects or that we will not abandon these properties. Additionally, we cannot guarantee that any undeveloped acreage we have an interest in will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are dependent upon the current and future market prices for crude oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.
Because our oil and natural gas reserve data is independently estimated, these estimates may still prove to be inaccurate.
Our reserve estimates generated for 2013 were compiled by Rosa Yvonne Scherz, P. Eng., independent consultant. In conducting their evaluations, the consultants evaluate our properties and independently develop proved reserve estimates. There are numerous uncertainties and risks that are inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. Many factors and assumptions are incorporated into these estimates including:
• expected reservoir characteristics based on geological, geophysical and engineering assessments;
|
•
|
future production rates based on historical performance and expected future operating and investment activities;
|
|
•
|
future oil and gas prices and quality and location differentials; and
|
|
•
|
future development and operating costs.
|
Although we believe the independent consultants’ reserve estimates are reasonably based on the information available to them at the time they prepare their estimates, our actual results could vary materially from these estimated quantities of proved oil and natural gas reserves (in the aggregate and for a particular location), production, revenues, taxes and development and operating expenditures. In addition, these estimates of reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing oil and natural gas prices, operating and development costs and other factors.
Use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results drilling operations on our properties.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are tools only used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, drilling activities on our properties may not be successful or economical.
Because our business is subject to operating hazards, our business may be adversely affected by the occurrence of any such hazards.
Our operations are subject to risks inherent in the oil and natural gas industry, such as:
• unexpected drilling conditions including blowouts and explosions;
• uncontrollable flows of oil, natural gas or well fluids;
• equipment failures, fires or accidents;
• pollution and other environmental risks; and
• shortages in experienced labor or shortages or delays in the delivery of equipment.
These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Our operations are also subject to a variety of operating risks such as adverse weather conditions and more extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations.
Possible regulation related to global warming and climate change could have an adverse effect on our business, financial condition or results of operations and demand for natural gas and oil.
Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation. Through 2013, domestic legislative and regulatory efforts included proposed federal legislation and state actions to develop statewide or regional programs, each of which could impose reductions in greenhouse gas emissions. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas.
Risks Relating to our Common Stock
Trading on the over-the-counter bulletin board may be volatile and sporadic, which could depress the market price of our common stock and make it difficult for our stockholders to resell their shares
.
Our common stock is quoted on the over-the-counter bulletin board service (the “OTCBB”) of the Financial Industry Regulatory Authority (“FINRA”). Trading in stock quoted on the OTCBB is often thin and characterized by wide fluctuations in trading prices, due to many factors that may have little to do with our operations or business prospects. This volatility could depress the market price of our common stock for reasons unrelated to operating performance. Moreover, the OTCBB is not a stock exchange, and trading of securities on the OTCBB is often more sporadic than the trading of securities listed on a stock exchange like NYSE or Nasdaq. Accordingly, shareholders may have difficulty reselling any of the shares.
Because our common stock is quoted and traded on the OTCBB, short selling could increase the volatility of our stock price.
Short selling occurs when a person sells shares of stock which the person does not yet own and promises to buy stock in the future to cover the sale. The general objective of the person selling the shares short is to make a profit by buying the shares later, at a lower price, to cover the sale. Significant amounts of short selling, or the perception that a significant amount of short sales could occur, could depress the market price of our common stock. In contrast, purchases to cover a short position may have the effect of preventing or retarding a decline in the market price of our common stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of our common stock. As a result, the price of our common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued at any time. These transactions may be effected on the OTCBB or any other available markets or exchanges. Such short selling, if it were to occur, could impact the value of our stock in an extreme and volatile manner to the detriment of our shareholders.
We may experience difficulties in the future in complying with Sarbanes-Oxley Section 404.
We are required to evaluate, and furnish a report by our management on, our internal controls under Section 404 of the Sarbanes-Oxley Act of 2002. Such report contains among other matters, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. Our management identified material weaknesses in our internal control over financial reporting as of December 31, 2013. If we fail to maintain proper and effective internal controls in future periods, it could adversely affect our operating results, financial condition and our ability to run our business effectively and could cause investors to lose confidence in our financial reporting.
We have never paid dividends and have no plans to in the future.
Holders of shares of our common stock are entitled to receive such dividends as may be declared by our board of directors. To date, we have paid no cash dividends on our shares of common stock and we do not expect to pay cash dividends on our common stock in the foreseeable future. We intend to retain future earnings, if any, to provide funds for operation of our business. Therefore, any return investors in our common stock will have to be in the form of appreciation, if any, in the market value of their shares of common stock.
We have additional securities available for issuance, which, if issued, could adversely affect the rights of the holders of our common stock.
Our Articles of Incorporation authorize the issuance of 100,000,000 shares of our common stock and 25,000,000 shares of preferred stock. The common stock or preferred stock can be issued by our board of directors, without stockholder approval. Any future issuances of our common stock would further dilute the percentage ownership of our common stock held by public stockholders.
If we issue shares of preferred stock with superior rights than our common stock, it could result in a decrease of the value of our common stock and delay or prevent a change in control of us.
Our board of directors is authorized to issue up to 25,000,000 shares of preferred stock. Our board of directors has the power to establish the dividend rates, liquidation preferences, voting rights, redemption and conversion terms and privileges with respect to any series of preferred stock. The issuance of any shares of preferred stock having rights superior to those of the common stock may result in a decrease in the value or market price of the common stock. Holders of preferred stock may have the right to receive dividends, certain preferences in liquidation and conversion rights. The issuance of preferred stock could, under certain circumstances, have the effect of delaying, deferring or preventing a change in control of us without further vote or action by the stockholders and may adversely affect the voting and other rights of the holders of common stock.
Because the SEC imposes additional sales practice requirements on brokers who deal in our shares, which are penny stocks, some brokers may be unwilling to trade them. This means that you may have difficulty reselling your shares and may cause the price of the shares to decline.
Our stock is a penny stock. The SEC generally defines “penny stock” to be any equity security that has a market price less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors”. The term “accredited investor” refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations and the broker-dealer and salesperson compensation information must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in, and limit the marketability of, our common stock.
In addition to the “penny stock” rules promulgated by the SEC, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative, low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low-priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock.
Indemnification of officers and directors.
Our articles of incorporation and the bylaws contain broad indemnification and liability limiting provisions regarding our officers, directors and employees, including the limitation of liability for certain violations of fiduciary duties. Our stockholders therefore will have only limited recourse against such individuals.
Description of Our Property
Our principal executive offices are located at Suite 604, 700 West Pender Street, Vancouver, British Columbia, Canada V6C 1G8. Our principle executive offices are provided to us at no cost by our Chief Financial Officer.
Proved Reserves Reporting
On December 31, 2008, the Securities and Exchange Commission, or the SEC, released a Final Rule,
Modernization of Oil and Gas Reporting
, approving revisions designed to modernize oil and gas reserve reporting requirements. The new reserve rules are effective for our financial statements for the year ended December 31, 2010 and subsequent years. The most significant revisions to the reporting requirements include:
·
|
Commodity prices.
Economic producibility of reserves is now based on the unweighted, arithmetic average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, unless prices are defined by contractual arrangements;
|
·
|
Undeveloped oil and gas reserves.
Reserves may be classified as “proved undeveloped” for undrilled areas beyond one offsetting drilling unit from a producing well if there is reasonable certainty that the quantities will be recovered;
|
·
|
Reliable technology.
The rules now permit the use of new technologies to establish the reasonable certainty of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes;
|
·
|
Unproved reserves.
Probable and possible reserves may be disclosed separately on a voluntary basis;
|
·
|
Preparation of reserves estimates.
Disclosure is required regarding the internal controls used to assure objectivity in the reserves estimation process and the qualifications of the technical person primarily responsible for preparing reserves estimates; and
|
·
|
Third party reports.
We are now required to file the report of any third party used to prepare or audit our reserves estimates.
|
We adopted the rules effective December 31, 2009, as required by the SEC.
Reported Reserves Table
The following table sets forth summary information regarding our estimated proved reserves at December 31, 2013, 2012 and 2011:
December 31,
|
|
2013
|
2012
|
2011
|
|
Gas
(Mcf)
|
Oil
(Bbls)
|
Gas
(Mcf)
|
Oil
(Bbls)
|
Gas
(Mcf)
|
Oil
(Bbls)
|
|
|
|
|
|
|
|
Proved Producing &
Non-Producing Reserves
(1)
|
26,000
|
3,930
|
155,540
|
73,902
|
156,630
|
48,950
|
|
|
|
|
Present value of proved
reserves
(2)
|
366,992
|
4,739,991
|
2,589.824
|
|
|
|
|
Standardized measure of discounted
future net cash flows
(3)
|
336,507
|
3,833,734
|
2,390,024
|
(1)
|
Estimates of reserves as of year-end 2013, 2012 and 2011 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period of the applicable year, in accordance with revised guidelines of the SEC applicable to reserves estimates beginning with the year-end 2009. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
|
(2)
|
Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports dated December 31, 2013, 2012 and 2011 is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year. PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP.
|
(3)
|
The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
|
The table below sets forth summary information regarding our estimated proved reserves. All of our estimated proved reserves are located in the United States and attributable to our properties in Newton County, Texas referenced above in
"Item 1, Business."
|
|
Reserves*
|
|
Reserve Category
|
Oil & NGL’s
(Bbls)
|
Natural Gas
(Mcf)
|
Total
(BOE)
|
|
|
|
|
PROVED
|
|
|
|
Developed:
|
3,930
|
26,000
|
8,263
|
Undeveloped:
|
-
|
-
|
-
|
TOTAL PROVED at December 31, 2013
|
3,930
|
26,000
|
8,263
|
* BOEs or
McfGEs
may be misleading, particularly if used in isolation. A BOE conversion ratio of 6
Mcf
: 1
bbl
(or an
McfGE
conversion ratio of 1
bbl
:6
Mcf
) is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value of equivalency at the wellhead.
The decrease in proved developed reserves from December 31, 2013 to December 31, 2012 was attributable to the disposal of the Company’s properties in Oklahoma, USA and a general decline in reserves due to nature of the geological properties around the reserve base.
The technologies used to establish the appropriate level of certainty for reserve estimates from properties included in the total reserves disclosed above consisted of seismic and geologic interpretations.
Proved Undeveloped Reserves
As of December 31, 2013, we had 43,340 BOE (Barrels of Oil Equivalent) of proved undeveloped reserves, or PUDs, as compared to 49,969 BOE of PUDs as of December 31, 2012. The decrease in PUDs from December 31, 2012 to December 31, 2013 was attributable to the disposal of the Company’s Oklahoma properties. All PUDs as of December 31, 2013 were located in the United States. Each of these PUDs will be converted from undeveloped to developed as the wells begin production. We anticipate that all of the PUDs will be developed within five years after first disclosure as proved undeveloped reserves. During the year ended December 31, 2013, we expended $nil to convert proved undeveloped reserves into proved developed reserves.
We have established our drilling budget for fiscal 2014 and set forth below are the amounts we anticipate expending on each of the core properties, subject to having sufficient resources to expend on drilling activity which cannot be assured. We have proposed to expend $300,000 for development drilling during 2014 at our Texas Prospect.
We have not proposed any other development drilling in 2014; however, depending on the success of the planned drilling activity previously noted, we may expand our drilling program during 2014.
Internal Controls Over Preparation of Proved Reserve Estimates
Our policies regarding internal controls over reserve estimates requires reserves to be in compliance with the SEC definitions and guidance and for reserves to be prepared by an independent third party reserve engineering firm under the supervision of our management. Our management provides to our third party reserves engineers reserves estimate preparation material such as property interests, production, current costs of operation and development, current prices for production, geoscience and engineering data, and other information. This information is reviewed by other members of management to ensure accuracy and completeness of the data prior to submission to our third party reserve engineering firm. During 2013, we retained D. Braxton & Assoicates as independent third-party reserve engineers, to prepare our estimates of proved reserves in accordance with the
COGE Handbook
. For more information about the evaluations performed by D. Braxton & Associates, see copies of their respective reports filed as exhibits to this Form 10-K.
Our Chief Executive Officer, Christopher Paton-Gay, is the person primarily responsible for overseeing the preparation of reserves audits conducted by independent third-party engineers. Mr. Paton-Gay has over 30 years of industry experience, which includes having founded and been chairman and president of two private oil and gas companies. In these capacities, Mr. Paton-Gay has a very high degree of working knowledge and understanding of geologic formations, drilling and completion parameters, and all facets of production. Given his extensive hands-on familiarity with the properties he has previously operated and those current properties we hold, we consider Mr. Paton-Gay to be a qualified person in overseeing the preparation of our internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. Mr. Paton-Gay was also one of the founding Directors of the Explorers and Producers Association of Canada and is a graduate of the ICD - Institute of Corporate Directors Canada.
Reserves Reported to Other Agencies
We did not file any reports during the year ended December 31, 2013 with any federal authority or agency other than the SEC with respect to our estimates of oil and natural gas reserves.
Production
The table below sets forth summary information regarding production by final product for each country containing 15% or more of our proved reserves for the years ended December 31, 2013, 2012 and 2011. The production in the United States is attributable to our properties in Newton County, Texas, Colusa County, California (for the 2011 period) and Garvin and Murray counties in Oklahoma that comprise the 2007-1, 2009-1 and 2009-3 drilling programs referenced above in
"Item 1, Business."
Production Data
|
Year Ended December 31
|
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
|
USA
|
|
USA
|
|
USA
|
|
Production -
|
|
|
|
|
|
|
Oil (Bbls)
|
3,442
|
|
4,424
|
|
8,228
|
|
Gas (Mcf)
|
34,940
|
|
25,399
|
|
108,978
|
|
Average Sales Price -
|
|
|
|
|
|
|
Oil (Bbls)
|
$104.61
|
|
$99.00
|
|
$96.00
|
|
Gas (Mcf)
|
$3.41
|
|
$3.00
|
|
$4.01
|
|
Average Production Costs
|
|
|
|
|
|
|
Oil (Bbls)
|
$8.65
|
|
$9.00
|
|
$8.00
|
|
Gas (Mcf)
|
$1.76
|
|
$1.00
|
|
$1.00
|
|
Production costs may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include severance taxes, administrative overhead, maintenance and repair, labor and utilities.
The table below sets forth summary information regarding production by final product for each field that contains 15% or more of our total proved reserves expressed on a BOE basis for the years ended December 31, 2013, 2012 and 2011.
Production Data
|
Year Ended December 31
|
|
2013
|
2012
|
2011
|
|
Oil (Bbls)
|
Gas (Mcf)
|
Oil (Bbls)
|
Gas (Mcf)
|
Oil (Bbls)
|
Gas (Mcf)
|
Production -
|
|
|
|
|
|
|
Garvin & Murray County, Oklahoma, USA
1
|
1,031
|
3,001
|
1,958
|
5,533
|
4,435
|
6,959
|
Newton County, Texas, USA
(Texas Prospect)
|
2,412
|
31,939
|
2.466
|
19,866
|
3,794
|
-
|
Colusa County, California, USA
(Lonestar Prospect)
2
|
-
|
-
|
-
|
-
|
-
|
102,019
|
1
|
We disposed of our interests in the Oklahoma prospect during 2013.
|
2
|
We disposed of our interests in the Lonestar Prospect on December 1, 2011.
|
Productive Wells and Acreage
The following table shows our producing wells and acreage as of December 31, 2013:
|
Producing Wells
3
|
Developed Acreage
|
|
Oil
|
Gas
|
|
Gross
1
|
Net
2
|
Gross
1
|
Net
2
|
Gross
1
|
Net
2
|
|
|
|
|
|
|
|
Garvin & Murray County, Oklahoma, USA
4
|
0
|
0
|
0
|
0
|
0
|
0
|
|
|
|
|
|
|
|
Newton County, Texas, USA
(Texas Prospect)
|
2
|
0.68
|
0
|
0
|
155
|
105
|
|
|
|
|
|
|
|
USA TOTALS
|
2
|
0.68
|
0
|
0
|
155
|
105
|
1
|
A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
|
2
|
A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or
acres equals one. The number of net wells or acres is the sum of the fractional working interest owned in gross wells or acres expressed as hole numbers and fractions thereof.
|
3
|
Productive wells are producing wells and wells capable of production.
|
4
|
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in “Item 1, Business” were disposed during 2013.
|
Undeveloped Acreage
The following table set forth undeveloped acreage as of December 31, 2013:
|
Undeveloped Acreage
1
as of December 31, 2013
|
Gross
|
Net
|
|
|
|
Garvin & Murray County, Oklahoma, USA
2
|
0
|
0
|
|
|
|
Newton County, Texas, USA
(Texas Prospect)
|
209
|
75
|
|
|
|
USA TOTALS
|
209
|
75
|
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.
|
|
|
2
|
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in “Item 1, Business” were sold during 2013.
|
Drilling Activity
The following table sets forth information on our drilling activity for the last three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.
Geographical Area
|
Net Exploratory Wells Drilled
|
Net Development Wells Drilled
|
Productive
1
|
Dry
2
|
Productive
1
|
Dry
2
|
Garvin Murray Counties, Oklahoma, USA
3
|
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0
|
0
|
0
|
0
|
Newton County, Texas, USA
(Texas Prospect)
|
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0
|
0
|
0
|
0
|
Colusa County, California, USA
(Lonestar Prospect)
4
|
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0.25
|
0
|
0
|
0
|
King City, California, USA
|
2013
|
0
|
0
|
0
|
0
|
2012
|
0.20
|
0
|
0
|
0
|
2011
|
0
|
0
|
0
|
0
|
The table below sets forth summary information regarding our drilling activity for the last three years for the country in which we engaged in drilling activity for the years ended December 31, 2013, 2012 and 2011.
Geographical Area
|
Net Exploratory Wells Drilled
|
Net Development Wells Drilled
|
Productive
1
|
Dry
2
|
Productive
1
|
Dry
2
|
USA
|
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0
|
0
|
0.32
|
0
|
1
|
A productive well is an exploratory or development well that is not a dry well. Although a well may be classified as productive upon completion, future changes in oil and gas prices, operating costs and production may result in the well becoming uneconomical.
|
2
|
A dry well (hole) is an exploratory or development well found to be incapable of producing either
oil or gas in sufficient quantities to justify completion as an oil or gas well.
|
3
|
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in “Item 1, Business”, which were sold during 2013.
|
4
|
We disposed of our interests in the Lonestar Prospect on December 1, 2011.
|
Present Activities
A discussion of present activities on our property interests is included in the description of business disclosure set forth above.
Delivery Commitments
We are not obligated to provide a fixed and determined quantity of oil or gas in the future. During the last three fiscal years, we have not had, nor do we now have, any long-term supply or similar agreement with any government or governmental authority.
We are not obligated to provide a fixed and determinable quantity of oil or natural gas in the near future under existing contracts or agreements. Further, during the last three years we had no significant delivery commitments.
None.
Not Applicable.