Item 1. Business
General Background
Victory Energy Corporation was organized under the laws of the State of Nevada on January 7, 1982. The Company is authorized to issue 490,000,000 shares of $0.001 par value common stock. On January 12, 2012 the Company implemented a 50:1 reverse stock split. All information in this Form 10-K reflects the number of shares outstanding on December 31, 2011which was before the reverse stock split.
Prior to May 3, 2006 the Company operated as Victory Capital Holdings Corporation among other corporate names.
Copies of the initial Articles of Incorporation of our Company and the Certificates of Amendment to the Articles of Incorporation are incorporated by reference.
Company Overview
The Company is engaged in the exploration, acquisition, development and exploitation of domestic oil and gas properties. Current operations are primarily located onshore in Texas, New Mexico and Oklahoma. We are headquartered in Austin, Texas.
Victory may invest in oil and gas projects directly, or through its partnership with Aurora Energy Partners, a Texas General Partnership (“Aurora”). Currently all oil and gas assets are held through the Aurora partnership. Victory is the managing partner of Aurora and holds a 50% interest in Aurora’s oil and gas properties, profits and losses. Our future capital and exploration expenditures will focus primarily on oil or liquid-rich gas projects. The Company will develop its investment opportunities through both internal capabilities and strategic industry relationships.
The Company’s capital and exploration expenditures, including projects in work in progress at year end, totaled $1,148,918 for 2011. All oil and gas investments utilized proceeds from the private placement of Convertible Debentures.
During 2011 the Company participated in the drilling of nine (9) gross exploration wells and directly acquired an interest in three (3) gross producing oil wells. We also acquired a 2% working interest in an Oklahoma water flood project. Highlights follow:
·Colorado County - We acquired 3D seismic data late in 2011 for $75,000. This is an internally-generated prospect area and we plan to drill at least two exploratory wells in 2012 on a working interest basis of about 50%.
·Uno Mas - We hold a 10% working interest in this successful well drilled in Lea County, New Mexico.
·Bootleg Canyon - We hold a 5% working interest in the University 6 #1 well which was successfully completed in June 2011. The Operator of the prospect plans to drill additional wells in 2012 that will further develop this area.
·Clear Water Resource - We hold a 1.5% working interest in a multi-well program targeting the Wolfcamp shale. We acquired a working interest in two producing wells and completed one exploration well discovery in 2011. The Operator of the prospect plans four additional wells in 2012.
·Jones County - We hold a 2% and 2.5% working interest in two wells in Jones County, Texas. Two producing wells were flowing at December 31, 2011. In addition, we participated in four dry holes drilled in 2011.
During 2011 we began hiring a new management team. Having an experienced oil and gas team was essential to the successful execution of our strategic plan. Kenneth Hill joined the Company as its Chief Operating Officer on January 20, 2011. Mr. Hill was named Chief Executive Officer on January 18, 2012. Mr. Stanley Lindsey joined the Company as VP, Exploration and Development, on January 10, 2011. Mr. Mark W Biggers joined the Company as Chief Financial Officer on January 10, 2012. These three individuals have over 65 years of combined industry experience.
On March 30, 2011 Victory Energy filed its 2009 Annual Report on Form 10-K including audited financial statements for the 2007 (restated), 2008 and 2009 fiscal years and unaudited quarterly financial statements for 2008 (restated) and 2009. On May 16, 2011 Victory filed its Form 10-K Annual Report for 2010 and restated quarterly Form 10-Q reports for 2010. The trading restrictions on the Company’s stock as a result of the delay in making these filings have been lifted.
Between October 15, 2010, and December 31, 2011, the Company sold an aggregate of $3,395,000 of 10% Senior Secured Convertible Debentures (the “Debentures”) as a result of a Private Placement Memorandum. The Debentures are convertible into an aggregate of 679,000,000 shares of the Company’s common stock at a conversion price of $0.005 per share of common stock, subject to adjustment. The Company also issued 3,395,000 warrants to purchase the Company’s common stock at $.005 to the purchasers of the Debentures, with an exercise period of 5 years. There are no registration rights for the converted shares.
On December 8, 2011 Victory announced the signing of an amended $15 million partnership agreement with the Navitus Energy Group through Aurora Energy Partners. A Memo Tracking Account (MTA) was established with a balance of $11.7 million. The MTA provision requires Victory to fund 100% of any new Aurora investments, up to the $11.7 million MTA balance, as adjusted, made during the next five years term of the agreement. In return, Victory receives a 50% distribution of Aurora profits as defined in the partnership agreement. In return for this consideration, Victory’s interest in existing Aurora oil and gas properties increased from 15% to 50% effective October 1, 2011.
Strategy
The Company’s objective is to create long term shareholder value by increasing oil reserves, improving financial returns (higher production volumes and lower costs), and managing the capital on our balance sheet.
As noted in the Company Overview section above, in 2011 we hired a new management team, raised funds on a private placement basis, invested in oil and gas assets, and signed an amended partnership agreement with Navitus to facilitate access to new capital.
On March 29, 2012 the Company announced certain details about its exploration and production strategy for 2012 and provided guidance on its forecast exploration and capital expenditures for next year. That information is available on the Company’s website www.vyey.com. The March 29, 2012 announcement noted that estimated capital and exploration expenditures associated with current properties will be more than $4.0 million, and could involve a working interest in 15 or more gross wells (>3.3 net wells). That compares to $1.1 million in capital expenditures for 2011 (for 9 gross wells, 0.3 net wells). Our 2012 expenditure forecast includes, but is not limited to, provisions for development drilling in Bootleg Canyon (Pecos County, Texas), development drilling on Adams Baggett (Crockett County, Texas), and exploration drilling on recently-acquired acreage in Glasscock County. The investment program envisioned is consistent with our strategy of pursuing more opportunities that are internally-generated and/or at a higher working interest position.
Such expenditures are supported by cash proceeds in-hand from the private placement of debentures, cash flow from operations, the potential sale of conventional oil assets, and new convertible debentures funded by Navitus which has agreed to provide up to $15 million of new capital into the Aurora partnership.
Distribution Methods
Each of our fields that produce oil distributes oil through one purchaser for each field. There is significant demand for oil and there are several companies in our operating areas that purchase oil from small oil producers.
Each of our fields that produce natural gas distributes all of the natural gas that it produces through one purchaser for each field. We have distribution agreements with these natural gas purchasers that provide us a tap into a distribution line of a natural gas distribution company. We are to be paid for our natural gas at either a market price at the beginning of the month or market price at the time of delivery, less any transportation cost charged by the natural gas distribution company.
Competition
We encounter competition from other oil and natural gas companies in all areas of our operations. Because of record high prices for oil and natural gas, there are many companies competing for the leasehold rights to good oil and natural gas prospects. And, because so many companies are again exploring for oil and natural gas, there is often a shortage of equipment available to do drilling and work over projects. Many of our competitors are large, well-established companies that have been engaged in the oil and natural gas business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select properties and consummate transactions successfully in this highly competitive environment.
Source and Availability of Raw Materials
We have no significant raw materials. However, we make use of numerous oil field service companies in the drilling and work over of wells. We currently operate in areas where there are numerous oil field service and drilling companies that are available to us.
Marketing Arrangements
There is a ready market for the sale of crude oil and natural gas. Each of our fields currently sells all of its oil and gas production on the spot market basis.
Government Regulations
Our facilities in the United States are subject to federal, state and local environmental laws and regulations. Compliance with these provisions has not had any material adverse effect upon our capital expenditures, net earnings or competitive position. However, the legislative and regulatory burden placed on the industry raises our cost of doing business and therefore could impact profitability. Please refer to Item 1A, Risk Factors.
Regulation of the Sale and Transportation of Oil
Sales of crude oil, condensate, natural gas and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Sale and Transportation of Natural Gas
Historically, the transportation for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase our costs of getting gas to point of sale locations.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Such regulations govern conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Environmental, Health and Safety Regulation
Our operations are subject to stringent and complex federal, state, local and provincial laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:
·require the acquisition of various permits before drilling commences;
·restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
·limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
·require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.
The following is a summary of the material existing environmental, health and safety laws and regulations to which our business operations are subject.
Waste handling. The Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or “EPA”, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, also known as the Superfund law, imposes joint and several liabilities, without regard to fault or legality of conduct, in connection with the release of a hazardous substance into the environment. Persons potentially liable under CERCLA include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance to the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and 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.
We own and lease, and may in the future operate, numerous properties that have been used for oil and natural gas exploitation and production for many years. Hazardous substances may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been or are operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances were not under our control. These properties and the substances disposed or released on, at or under them may be subject to CERCLA, RCRA and analogous state laws. In certain circumstances, we could be responsible for the removal of previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. In addition, federal and state trustees can also seek substantial compensation for damages to natural resources resulting from spills or releases.
Water discharges. The Federal Water Pollution Control Act, or the “Clean Water Act”, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and other substances generated by our operations, into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
The Safe Drinking Water Act, or “SDWA”, and analogous state laws impose requirements relating to underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations relating to permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water.
Air emissions. The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA and certain states have developed and continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and analogous state laws and regulations.
The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not acted upon recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA”. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All exploration and production activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects on federal lands.
Health safety and disclosure regulation. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA” and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.
We expect to incur capital and other expenditures related to environmental compliance. Although we believe that our compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.
Intellectual Property
We do not have any trademarks, patents or other intellectual property.
Employees
As of December 31, 2011, we had two employees. During 2011, we contracted for the services of our CFO and CEO through Miranda & Associates, A Professional Accountancy Corporation. In January, 2011 we opened an office in Austin, Texas and moved our headquarters there. Our two employees work out of the Austin office and report to the CEO. During 2010, we had no employees.
On January 10, 2012, Mark Biggers was appointed CFO of the company.
On January 18, 2012, Kenneth Hill who previously was Vice President and Chief Operating Officer was elected President and CEO. Mr. Robert Miranda remains as Chairman of the Company.
Item1A. Risk Factors
We continue to incur operating losses through 2011.
We have operated at a loss each year since inception. Net losses for the fiscal years ended December 31, 2011 and 2010, were $3,953,697 and $432,713, respectively. The loss in 2011 includes $1,617,696 in non-cash interest charges associated with the 10% Secured Convertible Debentures.
While the Company has taken steps to reduce general and administrative costs and add further oil and gas reserves through additional investment, there is no guarantee the Company will become profitable, or have continued and sustained profitability over the longer term. Our profitability is affected by, among other factors, our ability to have continued access to high-potential reserves, our success in drilling operations, the economic life of any reserves developed, and the market price of crude oil or natural gas. Future losses may adversely our affect our business, financial condition and cash flows.
Our independent auditors have issued a report questioning our ability to continue as a going concern.
The report of our independent auditors contained in our financial statements for the years ended December 31, 2011 and 2010, includes a paragraph that explains that we have incurred substantial losses. For example, significant general and administrative expenses were incurred from 2009 through 2011to successfully litigate a malfeasance claim against a former drilling contractor and pay for accounting and audit fees to restate certain affected financial statements. This report could raise doubt about our ability to continue as a going concern. Reports of independent auditors questioning a company’s ability to continue as a going concern are generally viewed unfavorably by analysts and investors. This report may make it difficult for us to raise additional debt or equity financing necessary to continue the development of our oil and gas projects.
A decline in the price of our common stock could affect our ability to raise further working capital and adversely impact our operations.
A prolonged decline in the price of our common stock could result in a reduction in the liquidity of our common stock and a reduction in our ability to raise capital. Because our operations have been primarily financed through the sale of equity securities, a decline in the price of our common stock could be especially detrimental to our liquidity and our continued operations. Any reduction in our ability to raise equity capital in the future would force us to reallocate funds from other planned uses and would have a significant negative effect on our business plans and operations, including our ability to develop new projects and continue our current operations. If our stock price declines, we may not be able to raise additional capital or generate funds from operations sufficient to meet our obligations.
If we are not successful in continuing to grow our business, then we may have to scale back or even cease our ongoing business operations.
Our success is significantly dependent on a successful acquisition, drilling, completion and production program. We may be unable to locate recoverable reserves or operate on a profitable basis. If our business plan is not successful, and we are not able to operate profitably, investors may lose some or all of their investment in us.
Trading of our stock may be restricted by the SEC's "Penny Stock" regulations which may limit a stockholder's ability to buy and sell our stock.
The U.S. Securities and Exchange Commission defines and applies “penny stock” regulations to any equity security that has a market price of less $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 or "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 his or her 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 that 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.
FINRA sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.
In addition to the “penny stock” rules described above, 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, the 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 and have an adverse effect on the market for our shares.
Trading in our common shares has been volatile, making it more difficult for our stockholders to sell their shares or liquidate their investments with predictability.
Our common shares are currently quoted on the OTC Markets. The trading price of our common shares has been subject to wide fluctuations. Trading prices of our common shares may fluctuate in response to a number of factors, many of which will be beyond our control. The stock market has generally experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies with no current business operation. There can be no assurance that trading prices and price earnings ratios previously experienced by our common shares will be matched or maintained. These broad market and industry factors may adversely affect the market price of our common shares, regardless of our operating performance. In the past, following periods of volatility in the market price of a company's securities, securities class-action litigation has often been instituted. Such litigation, if instituted, could result in substantial costs for us and a diversion of management's attention and resources.
Our securities are considered highly speculative.
Our securities are considered highly speculative, generally because of the nature of our business and the early stage we are in of building a long life asset base. While operating revenues are planned to increase over time, through our capital and exploration program, there are risks associated with drilling success, oil and gas prices, and our ability to raise additional monies through share offerings or debt. Access to capital is vital and unless the revenue base grows over time that could prove difficult to accomplish.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
On December 15, 2009, the U.S. Environmental Protection Agency, or EPA, published its findings that emissions of carbon dioxide, or CO2, methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Federal Clean Air Act. The EPA has adopted two sets of regulations under the existing Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, in April 2010, the EPA proposed to expand its existing GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of GHG emissions from such facilities would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. The adoptions of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirement also could adversely affect demand for the oil and natural gas that we produce.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion or re-working of certain oil and natural gas wells, whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. This process is typically regulated by state oil and natural gas agencies and has not been subject to Federal regulation. However, due to concerns that hydraulic fracturing may adversely affect drinking water supplies, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. Additionally, legislation has been introduced in Congress to amend the Federal Safe Drinking Water Act to subject hydraulic fracturing processes to regulation under that Act and to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. If enacted, such a provision could require hydraulic fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping requirement, and meet plugging and abandonment requirements. In unrelated oil spill legislation being considered by the U.S. Senate in the aftermath of the April 2010 Macondo well release in the Gulf of Mexico, Senate Majority Leader Harry Reid has added a requirement that natural gas drillers disclose the chemicals that are pumped into the ground as part of the hydraulic fracturing process. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on our exploration and production activities, which could make it more difficult to perform hydraulic fracturing, resulting in reduced amounts of oil and natural gas being produced, as well as increase our costs of compliance and doing business.
The current global recession and uncertainty in global economic conditions may have significant negative effects on our liquidity and financial condition.
The global financial and credit crisis has and may continue to impact our liquidity and financial condition. The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.
We have substantial capital requirements that, if not met, may limit operations and reduce profitability
We have and expect to continue to have substantial capital needs as a result of our active acquisition, exploration and development program. We expect that additional external financing will be required in the future to fund our growth. The Company should have access to funds of up to $15 million from Navitus, through its partnership with Aurora Energy Partners. Victory may also seek to obtain equity or debt capital from sources beyond Aurora. We may not be able to obtain additional financing, and we have no financing under existing or new credit facilities and these may not be available in the future. Without additional capital resources, we may be forced to limit or defer capital and exploration expenditures, which will adversely affect profitability, cash flow and share value.
Oil and natural gas prices can be highly volatile, and lower prices will negatively affect our financial results.
Our revenue, profitability, cash flow, the value of oil and gas reserves, and our ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas. Historically, the markets for oil and gas have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control. These factors include:
·the level of consumer product demand;
·the domestic and foreign supply of oil and natural gas;
·overall economic conditions;
·weather conditions;
·domestic and foreign governmental regulations and taxes;
·the price and availability of alternative fuels;
·political conditions in or affecting oil and natural gas producing regions;
·the level and price of foreign imports of oil and liquefied natural gas; and
·the ability of the members of the Organization of Petroleum Exporting Countries and other state controlled oil companies to agree upon and maintain oil price and production controls.
Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity, and ability to finance planned capital expenditures and results of operations and may reduce the amount of oil and natural gas that we can produce economically.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our success largely depends on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling operations, including the following:
·delays imposed by or resulting from compliance with regulatory requirements;
·pressure or irregularities in geological formations;
·shortages of or delays in obtaining equipment and qualified personnel;
·equipment failures or accidents;
·adverse weather conditions;
·reductions in oil and natural gas prices; and
·oil and natural gas property title problems.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves. In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires that economic assumptions be made about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices received, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
There is no way to predict in advance of drilling and testing whether any particular drilling prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.
We may rely on seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.
We depend on successful exploration, development and acquisitions to maintain revenue in the future.
In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. In addition, we may be required to find partners for any future exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.
Our future acquisitions may yield revenues and/or production that vary significantly from our projections.
In acquiring producing properties we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to such properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities.
We may not inspect every well, and we may not be able to identify structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.
We cannot assure you that:
·we will be able to identify desirable natural gas and oil prospects and acquire leasehold or other ownership interests in such prospects at a desirable price;
·any completed, currently planned, or future acquisitions of ownership interests in natural gas and oil prospects will include prospects that contain proved natural gas or oil reserves;
·we will have the ability to develop prospects which contain proven natural gas or oil reserves;
·we will have the financial ability to consummate additional acquisitions of ownership interests in natural gas and oil prospects or to develop the prospects which we acquire to the point of production; or
·we will be able to consummate such additional acquisitions on terms favorable to us.
We may experience difficulty in achieving and managing future growth.
Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:
·our ability to obtain leases or options on properties;
·our ability to acquire geological & geophysical data;
·our ability to identify and acquire new development prospects;
·our ability to develop existing prospects;
·our ability to continue to retain and attract skilled personnel;
·our ability to maintain or enter into new relationships with project partners and independent contractors;
·the results of our drilling program;
·hydrocarbon prices; and
·our access to capital.
We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.
We face strong competition from other natural gas and oil companies.
We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proved properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for productive natural gas and oil properties and may be able to 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 be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate, and select suitable properties and consummate transactions successfully in this highly competitive environment.
The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.
Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. Demand for drilling rigs, equipment, supplies, and personnel are currently very high in the areas in which we operate. An increase in drilling activity in the areas in which we operate could further increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.
We cannot control activities on properties that we do not operate and are unable to ensure their proper operation and profitability.
We may not operate certain of the properties in the future in which we obtain a working interest. As a result, we would have a limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:
·timing and amount of capital expenditures;
·expertise and financial resources;
·inclusion of other participants in drilling wells; and
·use of technology.
We depend on key management personnel and technical experts. The loss of key employees or access to third party technical expertise could impact our ability to execute our business.
If we lose the services of the senior management, or access to independent land men, geologists and reservoir engineers with whom the Company has strategic relationships, our ability to function and grow could suffer, in turn, negatively affecting our business, financial condition and results of operations.
The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues.
The marketability of our natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we may not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, due to maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines.
We may not be able to keep pace with technological developments in our industry.
The natural gas and oil industry is characterized by rapid and significant technological advancements and introduction of new products and services which utilize new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we are able to. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.
If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.
Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. In the future should our properties serve as collateral for credit facilities, a write down in the carrying values of our properties could require us to repay debt earlier than would otherwise be required. A write-down would also constitute a non-cash charge to earnings. It is likely that the effect of such a write-down could also negatively impact the trading price of our securities.
We account for our oil and gas properties using the successful efforts method of accounting. Under this method, all development costs and acquisition costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, but charged to expenses if and when a well is determined to be unsuccessful. We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues.
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
The exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with such governmental regulations. Matters subject to regulation include:
·natural disasters;
·permits for drilling operations;
·drilling and plugging bonds;
·reports concerning operations;
·the spacing and density of wells;
·unitization and pooling of properties;
·environmental maintenance and cleanup of drill sites and surface facilities; and
·Protection of human health.
From time to time, regulatory agencies have also imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil.
Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.
Our operations may cause us to incur substantial liabilities for failure to comply with environmental laws and regulations.
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit or other authorizations before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, require permitting or authorization for release of pollutants into the environment, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas, and impose substantial liabilities for pollution resulting from historical and current operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as on the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, some of which may be owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.
Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.
The financial condition of our operators could negatively impact our ability to collect revenues from operations.
We may not operate all of the properties in the future in which we have working interests. In the event that an operator of our properties experiences financial difficulties, this may negatively impact our ability to receive payments for our share of net production that we are entitled to under our contractual arrangements with such operator. While we seek to minimize such risk by structuring our contractual arrangements to provide for production payments to be made directly to us by first purchasers of the hydrocarbons, there can be no assurances that we can do so in all situations covering our non-operated properties.
The Company, or our Operator partners, may not have enough insurance to cover all of the risks that we face and operations of prospects in which we participate may not maintain or may fail to obtain adequate insurance.
In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impacts of Hurricanes Katrina, Rita and Ike have resulted in escalating insurance costs and less favorable coverage terms.
Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In the projects in which we own a non-operating interest directly or own an equity interest in a limited partnership which in turn owns a non- operating interest, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance in place by our Operator partners are adequate. However, the occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.
Terrorist attacks aimed at our energy operations could adversely affect our business.
The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.
We may issue additional shares of capital stock that could affect the value of existing holders of the Company’s stock, stock options, or warrants.
Our board of directors is authorized to issue additional classes or series of shares of our capital stock without any action on the part of our stockholders. Our board of directors also has the power, without stockholder approval, to set the terms of any such classes or series of shares of our capital stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our existing class of common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue shares of our capital stock in the future that have preference over shares of our existing class of common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of capital stock with voting rights that dilute the voting power of shares of our existing class of common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock and, as a result, the market value of the options and warrants into shares of common stock could be adversely affected.
The market price of our common stock may be volatile.
As we are in the early stages of being a publicly traded stock, the trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:
·limited trading volume in our common stock;
·quarterly variations in operating results;
·our involvement in litigation;
·general financial market conditions;
·the prices of natural gas and oil;
·announcements by us and our competitors;
·our liquidity;
·our ability to raise additional funds;
·changes in government regulations; and
·other events.
Moreover, our common stock does not have substantial trading volume. As a result, relatively small trades of our common stock may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock.
Because of the possibility of limited trading volume of our common stock and the price volatility of our common stock, you may be unable to sell your shares of our common stock when you desire or at the price you desire. The inability to sell your shares of our common stock in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.
We have not previously paid cash dividends on the shares of our common stock and do not anticipate doing so in the foreseeable future.
We have not in the past paid any cash dividends on the shares of our common stock and do not anticipate that we will pay any cash dividends on our common stock in the foreseeable future. Any future decision to pay a dividend on our common stock and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.
Our results of operations could be adversely affected as a result of impairments of oil and gas properties.
While we provide that our assets will be depleted over the estimated productive reserves of the oil and gas wells, these assets must also be tested at least annually for impairment. Management makes certain estimates and assumptions when determining the fair value of net assets and liabilities, including, among other things, an assessment of market conditions, projected cash flows, investment rates, cost of capital and growth rates, which could significantly impact the reported value of drilling costs and other intangible assets. Fair value is determined using a combination of the discounted cash flow, market multiple and market capitalization valuation approaches. Absent any impairment indicators, we perform our impairment tests annually during the fourth quarter. Any future impairment, including impairments of the carrying values of drilling costs and other intangible assets, would negatively impact our results of operations for the period in which the impairment is recognized.
Pending litigation may place a financial burden on our resources and the outcome of the litigation may not be favorable to the Company.
We are currently defending two lawsuits filed against us by landowners for trespass. Litigation continues and the outcome is uncertain. The risk is that our investment in each of the two wells could be lost.
We are also prosecuting a lawsuit against our former drilling contractor, former operator, and other related parties. In that case, an interlocutory Default Judgment against the defendants was awarded to Victory and James Capital, which is a general partner of Navitus. The judgment amounted to $17,183,987. No monies have yet been received related to this favorable judgment.
Item 1B.
Item 1B. Unresolved Staff Comments
None
Item 2.
Item 2. Properties
Office Space Leases.
On January 25, 2011, we extended the one (1)-year lease of approximately 1,200 square feet of executive office space located in Austin, Texas. The initial lease for one year commenced on January 25, 2010, and has been extended to expire on January 31, 2013. The monthly lease cost is $1,750.
Our core properties are primarily based in West Texas and Southeast New Mexico. Commercial accumulations of hydrocarbons now occur in multiple horizons, at depths ranging from 4,700 to 13,100 feet.
At December 31, 2011, our proved developed reserves were 6.4% oil and 93.6% gas and liquids, respectively.
During 2011 we had a working interest in the drilling of eight (8) gross wells. Three of those eight wells became producing wells. Four of the five dry holes were drilled on the Jones County acreage.
Adams - Baggett Ranch, Crockett County, Texas
Aurora initially acquired leases in the Adams - Baggett Ranch area in Crockett County, Texas in January 2008. At the end of 2011, we held a 100% working interest in seven (7) producing gas wells and a 50% working interest in two (2) other gas wells within the boundary of our currently held acreage. Current production is liquids-rich and is derived from zones at depths of 4,600 - 4,800 feet. We plan to evaluate the hydrocarbon potential of others zones in these wells during the first half of 2012 and additional development on this existing acreage is highly probable during 2012 and 2013.
Lea County, New Mexico
Aurora holds a 10% working interest in the Uno Mas well, located in Lea County, New Mexico. The well was spud in October 2011 and targeted the Mississippian formation. The well was successfully completed late in December 2011. This is the largest single discovery for the Company to-date. Both oil and gas reserves were found. We expect to receive the first revenue from this well in April 2012. Its oil production life is estimated to be in the 5-8 year range. Due to the completion of the well late in 2011, there was insufficient data available to calculate and report proved reserves for this well in our reserve data for 2011.
Padre Island Gas Fields, South Padre Island, Texas
On December 31, 2010, Aurora entered into an option agreement to acquire an oil and gas lease in a 1,000 acre tract of South Padre Island, Texas. The option gave Aurora exclusive rights to acquire an oil and gas lease at the property for a period of one (1) year. Under the terms of the option, we had full access to the land and could have conducted geophysical or seismic testing of the land to ascertain the potential gas reserves. The option agreement was not exercised and has now expired.
Jones County, Texas
On February 28, 2011, Aurora acquired a 2.5 percent working interest in the Young No. 1 oil - producing well located in Jones County, Texas. Interest assignment was effective February 1, 2011. Oil production is from the Caddo formation. The agreement also included a working interest of no less than 1.5 percent in an eighty two square mile 3-D seismic shoot over the area. During 2011 a total of five additional exploration wells were drilled. The Olson #1, which we have a 2.0% working interest, was successfully completed and production commenced on August 1, 2011. The other four wells drilled with our participation were either dry or deemed non-commercial. We maintain a thirty (30)-day first right of refusal to participate in each new well.
Bootleg Canyon, Pecos County, Texas
On April 14, 2011, Aurora acquired a 5%working interest in the University 6 #1 oil and gas prospect (“Tunis Creek”), which has a land position of 2,397 gross acres. The Company holds a 5 percent working interest (WI) and a 3.75 percent net revenue interest (NRI). The well was successful and production commenced on July 9, 2011. The operator of the prospect plans to drill additional wells across the prospect area.
Clearwater Wolfberry Resource Play, Howard County, Texas
Aurora acquired a 1.5% working interest in this West Texas resource play in December 2011 which has an acreage position of 3,186 gross acres. Our initial buy-in covered costs associated with two producing wells and an exploration well in progress. At year-end 2011, there were three producing oil wells on this property. The Operator of the prospect believes that the acreage could support an additional seven wells.
Atwood Water Flood - Hughes County, Oklahoma
In May 2011, Aurora acquired a 2% working interest in the Atwood project in Oklahoma, which is operated by CO Energy. This 1,240 gross acre field previously produced over 500,000 barrels of oil. We have advanced funds to the Operator ahead of a water flood project planned for the second quarter of 2012. No new reserves had been booked at year-end 2011 because injection operations had not yet commenced.
Alwan West Natural Gas Prospect
On April 25, 2011, we acquired a 5% working interest in the Alwan West natural gas prospect which involved a land position of 175 gross acres. An exploration well was drilled in June 2011 to target the Frio and Yegua formations’ high potential for natural gas and associated natural gas liquids. Drilling was not successful and a dry hole expense was incurred.
Developed and Undeveloped Lease Acreage
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2011. “Developed Acreage” refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities. “Undeveloped Acreage” refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.
Summary of Oil and Gas Reserves as of Year-End 2011
The reserves as of December 31, 2011 were derived from reserve estimates prepared by an independent reserve engineer, Mr. James Nicolson. James A. Nicholson is an engineering consultant who specializes in preparing reservoir studies, reserve estimates, and property evaluations. Mr. Nicolson, a Registered Professional Engineer, is a member of the Society of Petroleum Engineers. He is former chairman of the Permian Basin Oil & Gas Recovery Conference. He holds a PhD ME from the University of Texas at Austin, an MSME from the University of Texas at Austin, and a BSME from Lamar University.
The reserve reports prepared by Mr. Nicolson were reviewed and approved by our independent consultants, including a geologist and an oil & gas operations professional. The PV-10 value was derived using average prices throughout the calendar year, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us.
The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2011.
(1) The PV 10% Value as of December 31, 2011 is pre-tax and was determined by using the average of the preceding, 12-month product prices, which ranged from $6.26 per MCF to $6.56 per MCF per gas well and $89.47 per BBL to $91.31 per BBL per oil well pursuant to SEC guidelines. Management believes that the presentation of PV-10 value may be considered a non-GAAP financial measure. Therefore, we have included a reconciliation of the most directly comparable GAAP financial measure (standard measure of discounted net cash flows in Note 16 below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies.
(2) Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and natural gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. The PV-10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
Productive Wells
Productive wells are producing wells or wells capable of production. This does not include water source wells, water injection wells or water disposal wells. Productive wells do not include any wells in the process of being drilled and completed that are not yet capable of production, but does include old productive wells that are currently shut-in, because they are still capable of production. The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2011 and 2010.
Technologies Used in Establishing Proved Reserves in 2011 and 2010
Our proved reserves in 2011 and 2010 were based on estimates generated through the integration of available and appropriate data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including high-quality 2-D and 3-D seismic data, calibrated with available well control. Surface geological information was also utilized in the preparation of the data where applicable. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.
Proved Undeveloped Reserves
At December 31, 2011 and 2010, our proved undeveloped reserves were none.
Oil and Gas Production, Production Prices and Production Costs
A.Oil and Gas Production
The table below summarizes production by final product sold and by geographic area as of December 31, 2011, 2010, and 2009.
B.Sales Prices and Production Costs
The table below summarizes average sales prices and average production costs by geographic area and by product type for the years ended December 31, 2011 and 2010.
Drilling and Other Exploratory and Development Activities
The table below summarizes the number of net productive and dry exploratory wells and net productive and dry development wells drilled by geographic area as of December 31, 2011, 2010 and 2009.
(1) During 2009, we incurred drilling costs on development wells of $290,665 and $4,942,579, respectively. We subsequently discovered that these drilling funds had been misappropriated. These funds were expensed as “Loss from Malfeasance” during 2009 and 2008. Based upon the contract drilling cost of $500,000 per well, we have estimated the number of dry productive wells that were supposed to have been drilled for the amount of funds incurred.
Present Activities
The table below summarizes the number of wells in the process of being drilled by geographic area as of December 31, 2011 and 2010.
Item 3.
Item 3. Legal Proceedings
Cause No. 08-04-07047-CV; Oz Gas Corporation v. Remuda Operating Company, et al. v. Victory Energy Corporation.; In the 112th District Court of Crockett County, Texas.
This is a lawsuit wherein Plaintiff Oz Gas Corporation sued various parties for bad faith trespass, among other claims regarding two wells that Oz claims were drilled on lands they have superior title to. Oz Gas agreed to keep Remuda Operating Company as the operator of the wells involved in the lawsuit so long as all the monies are paid into the Registry of the Court, which is currently being done. Victory Energy Corporation has a 50% interest in one of the named wells involved in this lawsuit (that being well 155-2 on the Adams Baggett Ranch in Crockett County, Texas). The lawsuit was originally filed around April 2008, but Victory Energy Corporation was not a party until it learned of this lawsuit and filed a Plea in Intervention on November 18, 2009.
Plaintiff Oz alleges a claim of bad faith trespass by Victory and other parties who drilled the wells. Victory merely purchased an interest in the well, and Victory takes the position that they had superior title when they purchased their interest in the well, and that they are not a bad faith trespasser.
This case was mediated, with no settlement reached. It went to trial February 8-9, 2012. Victory contested the allegations made in this lawsuit and argued that Oz did not have superior title, nor that Oz has more than a 40% interest in well 155-2 (Oz claims to own 100% interest in the well). When Oz purchased the lands and wells on the Adams Baggett Ranch, some of the leases had expired. In order to cure this defect, Oz obtained a revivor and ratification from two of three parties who held the interest. There is still an unleased interest owner of these lands. The Court found in favor of Oz on certain claims, but has not made all if its rulings on the entire case. A hearing in this case is currently set for April 17, 2012. Depending on the final rulings of the Court, Victory will appeal any findings of bad faith trespass, conversion, and punitive damages. We are confident of a positive outcome in the Court of Appeals as the rulings that have been made and could be made are contrary to current State law and evidence of Oz’s lack of superior was presented and proven by Victory at the trial court level.
Cause No. CV-47,230; James Capital Energy, LLC and Victory Energy Corporation v. Jim Dial, et al.; In the 142nd District Court of Midland County, Texas.
This is a lawsuit filed on or about January 19, 2010 by James Capital Energy, LLC and Victory Energy Corporation against numerous parties for fraud, fraudulent inducement, and negligent misrepresentation, breach of contract, breach of fiduciary duty, trespass, conversion and a few other related causes of action. This lawsuit stems from an investment both James Capital and Victory entered into for the purchase of six wells on the Adams Baggett Ranch with the right of first refusal on option acreage.
On December 9, 2010, Victory was granted an interlocutory Default Judgment against Defendants Jim Dial, 1st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Grifco International, Inc., and Precision Drilling & Exploration, Inc. The total judgment amounted to approximately $17,183,987.08.
Recently Victory and James Capital have added a few more parties to this lawsuit. Discovery is ongoing in this case and no trial date has been set at this time.
Victory and James Capital believe that they will be victorious against all the remaining Defendants in this case.
On October 20, 2011 Defendant Remuda filed a Motion to Consolidate and a Counterclaim against Victory. Remuda is seeking to consolidate this case with two other cases wherein Remuda is the named Defendant. An objection to this motion was filed and the cases have not been consolidated. Additionally, we do not believe that the counterclaim made by Remuda has any legal merit.
Cause No. 10-09-07213; Perry Howell, et al. v. Charles Gary Garlitz, et al.; In the 112th District Court of Crockett County, Texas.
The above referenced lawsuit was filed on or about September 6, 2010. This lawsuit alleges that Cambrian Management, Ltd. and Victory were trespassers on their land, and that they, along with other Defendants, drilled a well (115 #8) on land belonging to Plaintiffs. Plaintiffs claim trespass and unjust enrichment by certain Defendants because of the drilling of the 115 #8 well.
Discovery is ongoing in this case and there has not been a trial date set at this time. Victory and Cambrian are in the process of having some title work done on this piece of property so they can decide which direction to go with this case.
If Victory and Cambrian are not victorious in this case, they will be out their initial investment monies paid for the drilling of this well.
Item 4.
Item 4. (Removed and Reserved)
PART II
Item 5.
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is currently quoted on the OTC Markets under the symbol “VYEY.” The following table sets forth the high and low bid information for each quarter for the years ended December 31, 2011 and 2010. The information reflects prices between dealers, and does not include retail markup, markdown, or commission, and may not represent actual transactions.
Holders
The following table shows the number of holders of record and the number common shares outstanding as of December 31, 2011 and 2010 as determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies.
The transfer agent for our common stock is Transfer Online, Inc., 512 SE Salmon Street, Portland, Oregon 97214.
Dividend Policy
We have not paid any cash dividends on our common stock and do not expect to do so in the foreseeable future. We intend to apply our earnings, if any, in expanding our operations and related activities. The payment of cash dividends in the future will be at the discretion of the board of directors and will depend upon such factors as earnings levels, capital requirements, our financial condition and other factors deemed relevant by the board of directors.
Recent Sales of Unregistered Securities
For the Year Ended December 31, 2011:
During the period January 1 through September 30, 2011 the Company sold 10% Senior Secured Debentures and issued warrants as part of its Regulation D private placement offering, and issued warrants to directors of the Company for services as directors. These transactions have been reported in the Company’s respective Form 10-Q filed with the SEC on May 23, 2011, August 15, 2011, and November 14, 2011, respectively.
The following securities were issued during the period October 1, 2011 through December 31, 2011:
On October 4, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $150,000 to two individuals or investment entities who are non-affiliates of the Company in exchange for $150,000. The debentures are convertible into 30,000,000 shares of common stock at a conversion price of $0.005 per share.
On October 4, 2011, we issued warrants to purchase a total of 150,000 shares of common stock to two purchasers of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On October 21, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $10,000 to an individual who is a non-affiliate of the Company in exchange for $10,000. The debentures are convertible into 2,000,000 shares of common stock at a conversion price of $0.005 per share.
On October 21, 2011, we issued warrants to purchase a total of 10,000 shares of common stock to purchasers of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On November 8, 2011 we issued warrants to purchase a total of 1,500,000 shares of common stock to purchasers of the Company’s debentures at an exercise price of $.01 to a director of the Company for additional for services in the capacity of general counsel of the Company.
On November 8, 2011 we issued warrants to purchase a total of 3,000,000 shares of common stock to purchasers of the Company’s debentures at an exercise price of $.02 to a director of the Company for additional services in the capacity of general counsel of the Company.
On November 14, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $10,000 to an individual who is a non-affiliate of the Company in exchange for $10,000. The debentures are convertible into 2,000,000 shares of common stock at a conversion price of $0.005 per share.
On November 14, 2011, we issued warrants to purchase a total of 10,000 shares of common stock to a purchaser of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On November 22, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $130,000 to two individuals who are non-affiliates of the Company in exchange for $130,000. The debentures are convertible into 26,000,000 shares of common stock at a conversion price of $0.005 per share.
On November 22, 2011, we issued warrants to purchase a total of 130,000 shares of common stock to two purchasers of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On November 28, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $100,000 to an individual who is a non-affiliate of the Company in exchange for $100,000. The debentures are convertible into 20,000,000 shares of common stock at a conversion price of $0.005 per share.
On November 28, 2011, we issued warrants to purchase a total of 100,000 shares of common stock to a purchaser of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On December 2, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $100,000 to an individual who is a non-affiliate of the Company in exchange for $100,000. The debentures are convertible into 20,000,000 shares of common stock at a conversion price of $0.005 per share.
On December 2, 2011, we issued warrants to purchase a total of 100,000 shares of common stock to a purchaser of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On December 12, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $150,000 to an individual who is a non-affiliate of the Company in exchange for $150,000. The debentures are convertible into 30,000,000 shares of common stock at a conversion price of $0.005 per share.
On December 12, 2011, we issued warrants to purchase a total of 150,000 shares of common stock to a purchaser of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On December 13, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $50,000 to an individual who is a non-affiliate of the Company in exchange for $50,000. The debentures are convertible into 10,000,000 shares of common stock at a conversion price of $0.005 per share.
On December 13, 2011, we issued warrants to purchase a total of 50,000 shares of common stock to a purchaser of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On December 13, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $100,000 to an individual who is a non-affiliate of the Company in exchange for $100,000. The debentures are convertible into 20,000,000 shares of common stock at a conversion price of $0.005 per share.
On December 16, 2011, we issued warrants to purchase a total of 100,000 shares of common stock to a purchaser of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On December 29, 2011, we issued 10% Senior Secured Convertible Debentures with the total face value of $50,000 to an individual who is a non-affiliate of the Company in exchange for $50,000. The debentures are convertible into 10,000,000 shares of common stock at a conversion price of $0.005 per share.
On December 29, 2011, we issued warrants to purchase a total of 50,000 shares of common stock to a purchaser of the Company’s debentures at an exercise price of $.005 as part of the terms of the sale of the debentures.
On December 31, 2011, we issued warrants to purchase a total of 1,500,000 shares of common stock to five board members of the Company at an exercise price of $0.01 per share in exchange for services.
Item 6.
Item 6. Selected Financial Data
Not applicable.
Item 7.
Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.
The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of our financial position and results of operations during the periods included in the accompanying audited consolidated financial statements.
Forward Looking Statements
This Annual Report on Form 10-K contains forward-looking statements concerning our beliefs, plans, objectives, goals, expectations, anticipations, estimates, intentions, operations, future results and prospects, including statements that include the words “may,” “could,” “should,” “would,” “believe,” “expect,” “will,” “shall,” “anticipate,” “estimate,” “intend,” “plan” and similar expressions. These forward-looking statements are based upon current expectations and are subject to risk, uncertainties and assumptions. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, expected, projected, intended, committed or believed. We provide the following cautionary statement identifying important factors (some of which are beyond our control) which could cause the actual results or events to differ materially from those set forth in or implied by the forward-looking statements and related assumptions.
General Overview
We are an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas properties currently located onshore in Texas, New Mexico and Oklahoma.
During 2011 our capital and exploration investment program was focused primarily on oil properties in West Texas and southeast New Mexico. At the end of 2011, the Company had a working interest position in eight (8) new producing oil wells compared to no oil wells at the end of 2010. These properties, previously discussed in Parts I and II of this filing, are located in Jones, Howard and Pecos counties of Texas and Lea County, New Mexico and Hughes County, Oklahoma. The company still has its nine gas production wells in Crockett County, Texas and has further development plans for those assets.
Our revenue, profitability, cash flow, oil and natural gas reserves value, future growth, and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty, and a variety of additional factors beyond our control.
Going Concern
As presented in the consolidated financial statements, the Company has incurred a net loss of $3,953,697 during the twelve months ended December 31, 2011, and losses are expected to continue in the near term. The accumulated deficit is $36,091,289 at December 31, 2011. The Company has been funding its operations through the sale of senior convertible debentures. Management anticipates that significant additional capital expenditures will be necessary to develop the Company’s oil and natural gas properties, which consist of proved and unproved reserves, some of which may be non-producing, before significant positive operating cash flows will be achieved.
Management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that available operating cash flows will support.
The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if the Company were unable to continue as a going concern.
Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010
Our revenue, operating expenses, and net loss from operations for the year ended December 31, 2011 as compared to the year ended December 31, 2010 were as follows. Some balances on the prior’s year’s consolidated financial statements have been reclassified to conform to the current year presentation
Revenues: All of our revenue was derived from the sale of oil and natural gas. Revenues consist of the proceeds of sale net of royalty, gas transportation deductions and working interest partner share, if applicable, for each producing well. Our net revenue declined $80,709 or 20.9% to $305,180 for the twelve months ended December 31, 2011 from $385,889 for the twelve months ended December 31, 2010. The decrease reflects primarily the decline in volume of gas sold to 44,682 MCF (thousand cubic feet) in the year ended December 31, 2011 compared to 53,813 MCF for the twelve months ended December 31, 2010. At the same time, the average natural gas price increased to $6.59 per MCF for the year ended December 31, 2011 compared to $6.23 per MCF for the twelve months ended December 31, 2010. The decline in gas production volumes is normal in wells of this age.
Revenues also include oil production revenues which were $52,811 for the 12 months ended December 31, 2011. At December 31, 2011, we had interests in six producing oil wells. We did not have any interests in producing oil wells at December 31, 2010
Lease Operating Expenses (“LOE”): Lease operating expenses which includes the operating expenses of obtaining the oil and gas increased $61,253 or 101.5% to $121,580 for the twelve months ended December 31, 2011 from $60,327 for the twelve months ended December 31, 2010. LOE increase as our net lifting costs to produce oil and gas includes normal operating costs and well workover charges increased due to additional oil production in 2011.
Production Taxes: Production taxes are taxes charged at the well head for the production of gas and oil. Production taxes increased $2,402 or 6.5% to $39,156 for the twelve months ended December 31, 2011 from $36,754 for the twelve months ended December 31, 2010. Production taxed due to the additional oil production in 2011.
Exploration Expense: Exploration expense includes internal and external costs associated with the acquisition, processing and analysis of geological and geophysical data, the cost of drilling dry exploration wells, or the impairment of undeveloped land assets. Exploration expenses increased $391,646 or 233% to $559,523 for the twelve months ended December 31, 2011 from $167,877 for the twelve months ending December 31, 2010. The increase in 2011 was primarily due to the drilling of five dry holes at a charge of $112,000, the acquisition and processing 3D seismic data of $83,000, the write-off of our $25,000 option covering the South Padre Island acreage, plus the addition of internal staffing to this activity during the year.
General and Administrative Expense: General and administrative expenses increased $1,474,505 or 238% to $2,094,768 for the year ended December 31, 2011 from $620,263 for the year ending December 31, 2010. The increase in general and administrative expense reflects an increase in recurring and non-recurring charges:
The following may be considered recurring expenses:
·Approximately $258,000 for salary, stock based compensation, and benefits for the new personnel in 2011;
·Approximately $ 44,000 in increased travel related expenses
·Approximately $ 63,000 for investor relations programs;
·Approximately $166,000 in increased directors meeting fees which is paid in warrants; and
·Approximately $ 25,000 in rent and operating expenses associated with the opening of the new office in Austin.
The following may be considered non-recurring expenses
·Approximately $306,000 in accounting, audit, legal and management fees associated with the re-filing of relevant Form 10K and Form 10Q statements for 2007 (restated), 2008, 2009 and 2010;
·Approximately $210,000 in legal fees to defend our legal title to minerals on well 155-2 in Crockett County; this lawsuit is ongoing;
·Approximately $106,000 in consulting expenses associated with the transition to the new management team at the beginning of 2012;
·Approximately $132,300 in warrants on the appointment of a new general counsel;
·Approximately$ 75,000 in legal fees in support of our private placement memorandum under SEC Regulation D, in which we have raised $3,395,000 through December 31, 2011 in working capital to support the Company’s oil and gas programs, and,
·Approximately $ 75,000 in legal fees associated with the settlement with a former officer of the Company.
Depletion and Accretion: Depletion and accretion expenses declined $25,969 to $76,525 for the twelve months ended December 31, 2011 from $102,484 for the twelve months ended December 31, 2010. The decrease was due in part to the lower amount of gas well asset cost basis available to deplete following the impairment adjustment of 2010 and the lower gas volumes in 2011 through on which the depletion expense is modulated.
Impairment of Oil and Natural Gas Properties: Impairment of oil and natural gas properties declined $80,894 to $102,579 from $183,473 for the twelve months ended December 31, 2010. An impairment charge is recognized with the present value of the projected future cash flows from the well based on the reserve report is less than the book value of the individual well.
Interest Expense: Interest expense increased $1,762,991 to $1,815,038 for the twelve months ended December 31, 2011 from $52,047 for the twelve months ended December 31, 2010. Of this amount, $1,617,696 represents the amortization of the non-cash debt discount associated with the sale and conversion of the 10% Senior Secured Debentures which were sold during a time when the market price of our shares exceeded the conversion price referenced in the debenture agreement. That difference, referred to as a Beneficial Conversion Feature, is amortized over the life of the debenture term, or the shorter period if converted to common shares, and becomes non-cash interest expense on our income statement. The remaining balance of $197,342 represents the actual interest expense accrued (but not paid) on the 10% Senior Secured Convertible Debentures.
Income Taxes: There is no provision for income tax recorded for either the twelve months ended December 31, 2011 or ended December 31, 2010 due to the expected net operating losses (NOL) of both years. We had available Federal income tax net operating loss (“NOL”) carry forwards of approximately $13,130,000 at December 31, 2011. Our NOL generally begins to expire in 2025. We recognize the tax benefit of NOL carry forwards as assets to the extent that management believes that the realization of the NOL carry forward is more likely than not. The realization of future tax benefits is dependent on our ability to generate taxable income within the carry forward period. This valuation allowance is provided for all deferred tax assets.
The Company recognized a tax benefit of $550,292 due to the timing difference in tax effect between the accounting and tax basis of the Company’s 10% Senior Secured Convertible Debentures sold and converted during the twelve months ended December 31, 2011.
Net Loss: Net losses increased 814% or $3,520,984 to $3,953,697 for the twelve months ended December 31, 2011 from a net loss of $432,713 for the twelve months ended December 31, 2010. This net loss should be viewed in light of the cash flow from operations discussed below.
During the year ended December 31, 2011, as with the year ended December 31, 2010, after adjusting for one-time gains, we did not generate positive cash flow from on-going operations. As a result, we funded our operations through the private sale of equity and debt securities, the issuance of our securities in exchange for services, and loans.
Liquidity and Capital Resources
Our cash and cash equivalents, total current assets, total assets, total current liabilities, and total liabilities as of December 31, 2011 as compared to December 31, 2010, are as follows:
At December 31, 2011, we had a working capital deficit of $105,020 compared to a working capital deficit of $419,897 at December 31, 2010. Current liabilities increased to $689,383 at December 31, 2011 from $631,195 at December 31, 2010 primarily due to an increase of $139,766 in accrued interest on the Company’s 10% Secured Convertible Debentures, an increase of $80,338 in accrued royalties held in suspense, and an increase of $23,321 in other accrued liabilities.
Net cash used by operating activities for the twelve months ended December 31, 2011 totaled $1,988,643 after the cash used in the net loss of $3,953,697 was decreased by $1,692,777 in non-cash charges and by $272,277 in increases in the working capital accounts. This compares to cash used by operating activities for the twelve months ended December 31, 2010 of $335,727 after the net loss for the period of $432,713 was increased by $103,885 in non-cash charges and decreased by $200,771 in changes to the working capital accounts.
Net cash used in investing activities, excluding exploration-related charges taken directly to income, for the twelve months ended December 31, 2011 totaled $219,700 to develop producing oil wells and $369,695 for development work on other oil producing properties. This compares to $25,000 used in investing activities for the twelve months ended December 31, 2010 to purchase a drilling option on South Padre Island.
Net cash provided by financing activities for the twelve months ended December 31, 2011 was $2,950,148. Of this amount, $3,120,000 came from the sale of debentures and was offset by $68,667 to retire the Wells Fargo bank loan, $50,000 to payoff of amounts due a related party, and a distribution of $50,915 to a partner in Navitus. This compares to the $450,223 in cash provided by financing activities during the twelve months ended December 31, 2010, of which $275,000 came from the sale of debentures, $192,000 came from a note payable to a related party and $16,777 was used to pay down the bank loan.
Recently Issued Accounting Pronouncements
Recent Accounting Pronouncements
In September 2011, the FASB issued Accounting Standard Update (“ASU”) No. 2011-08, Intangible - Goodwill and Other (Topic 350), Testing Goodwill for Impairment. Under the amendments of this ASU, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit, as described in paragraph 350-20-35-4. If the carrying amount of a reporting unit exceeds its fair value, then the entity is required to perform the second step of the goodwill impairment test to measure the amount of the impairment loss, if any, as described in paragraph 350-20-35-9. Under the amendments in this Update, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. This ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company is evaluating the impact of the adoption of this ASU.
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220), Presentation of Comprehensive Income. Under the amendments of this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In a single continuous statement, the entity is required to present the components of net income and total net income, the components of other comprehensive income and a total for other comprehensive income, along with the total of comprehensive income in that statement. In the two-statement approach, an entity is required to present components of net income and total net income in the statement of net income. The statement of other comprehensive income should immediately follow the statement of net income and include the components of other comprehensive income and a total for other comprehensive income, along with a total for comprehensive income. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company is evaluating the impact of the adoption of this ASU.
In December 2010, the FASB issued ASU No. 2010-13, Compensation-Stock Compensation (Topic 718), Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU provides amendments to Topic 718 to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The adoption of this standard did not have a significant impact on the Company’s financial statements.
In December 2010, the FASB issued ASU No. 2010-28, Intangibles - Goodwill and Other (Topic 350), When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. The ASU modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. As a result, current GAAP will be improved by eliminating an entity’s ability to assert that a reporting unit is not required to perform Step 2 because the carrying amount of the reporting unit is zero or negative despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. As a result, goodwill impairments may be reported sooner than under current practice. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. The adoption of this standard did not have a significant impact on the Company’s financial statements.
In April 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-14, “Accounting for Extractive Activities - Oil & Gas, Amendments to Paragraph 932-10-S99-1” due to SEC Release No. 33-8995 (FR 78), “Modernization of Oil and Gas Reporting”. This amendment was effective January 1, 2010 and has been adopted by the Company in the presentation of the financial statements.
In January 2010, the FASB issued ASU No. 2010-16, “Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements”. ASU 2010-16 will require the reporting entity to 1) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers and 2) present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), This ASU also clarifies existing disclosures about levels of disaggregation and about inputs and valuation techniques. This ASU is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal periods. The Company has adopted the provisions of the ASU that were effective for reporting periods beginning after December 15, 2009 and it is current assessing the impact of the Level 3 disclosures. This standard did not have a significant impact on the Company’s financial statements.
In January 2010, the FASB issued ASU No. 2010-03, “Extractive Activities - Oil and Gas (Topic 932) - Oil and Gas Reserve Estimation and Disclosures”. The ASU expands and amends certain definition of terms used in the Topic, requires an entity to disclosure separately information about reserve quantities and financial statements amounts for geographic areas that represent 15 percent or more of proved reserves, clarifies that an entity’s equity method investments must be considered in determining whether it has significant oil - and gas- producing activities, required that an entity continue to disclosure separately the amounts and quantities for consolidated and equity method investments and requires that disclosures about equity method investments be in the same level of detail as is required for consolidated investments. Amendments to this Topic are effective to annual reporting periods ending on or after December 31, 2009. This standard did not have a significant impact on the Company’s financial statements.
In October 2009, the FASB issued an amendment to the accounting standards related to the accounting for revenue in arrangements with multiple deliverables including how the arrangement consideration is allocated among delivered and undelivered items of the arrangement. Among the amendments, this standard eliminates the use of the residual method for allocating arrangement consideration and requires an entity to allocate the overall consideration to each deliverable based on an estimated selling price of each individual deliverable in the arrangement in the absence of having vendor-specific objective evidence or other third party evidence of fair value of the undelivered items. This standard also provides further guidance on how to determine a separate unit of accounting in a multiple-deliverable revenue arrangement and expands the disclosure requirements about the judgments made in applying the estimated selling price method and how those judgments affect the timing or amount of revenue recognition. This standard will become effective for the Company on January 1, 2011 and did not have a significant impact on the Company’s financial statements.
In August 2009, the FASB issued an amendment to the accounting standards related to the measurement of liabilities that are recognized or disclosed at fair value on a recurring basis. This standard clarifies how a company should measure the fair value of liabilities and that restrictions preventing the transfer of a liability should not be considered as a factor in the measurement of liabilities within the scope of this standard. This standard was effective for the Company on October 1, 2009. This standard did not have a significant impact on the Company’s financial statements.
Summary of Critical Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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 periods reported. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of proved and unproved properties, future income taxes and related assets and liabilities, the fair value of various common stock, warrants and option transactions, and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the calculation of impairment, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data, the engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
These significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the fair value of the Company’s common stock and corresponding volatility, and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.
Oil and Natural Gas Properties
We account for investments in oil and gas properties using the successful efforts method of accounting. Under this method of accounting, only successful exploration drilling costs that directly result in the discovery of proved reserves are capitalized. Unsuccessful exploration drilling costs that do not result in an asset with future economic benefit are expensed. All development costs are capitalized because the purpose of development activities is considered to be building a producing system of wells, and related equipment facilities, rather than searching for oil and gas. Items charged to expense generally include geological and geophysical costs. Capitalized costs for producing wells and associated land are depleted using a Units of Production methodology based on the proved, developed reserves for the specific, relevant well. The capitalized cost of other oil and gas assets are also depleted using proved developed reserves, but on a field-by-field basis.
The net capitalized costs of proved oil and natural gas properties are subject to an impairment test which compares the net book value of assets, based on historical cost, to the discounted future cash flow of remaining oil and gas reserves based on current economic and operating conditions. Impairment of an individual producing oil and natural gas field is first determined by comparing the undiscounted future net cash flows associated with the proved property to the carrying value of the underlying property. If the cost of the underlying property is in excess of the undiscounted future net cash flows the carrying cost of the impaired property is compared to the estimated fair value and the difference is recorded as an impairment loss. Management’s estimate of fair value takes into account many factors such as the present value discount rate, pricing, and when appropriate, possible and probable reserves when activities justified by economic conditions and actual or planned drilling or other development.
Under the successful efforts method of accounting, the depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.
Long-lived Assets and Intangible Assets
The Company accounts for intangible assets in accordance with the provisions of the applicable Accounting Standards Code (“ASC”) standard. Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired.
For unproved property costs, management reviews these investments for impairment on a property-by-property basis if a triggering event should occur that may suggest that impairment may be required.
The Company reviews its long-lived assets and proved oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with the applicable ASC standard. Proved oil and gas assets are evaluated for impairment at least annually. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.
Stock Based Compensation
The Company adopted the ASC standard related to stock compensation to account for its warrants and options issued to key partners, directors and officers. The fair value of common warrants granted is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of the Company’s stock. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.
The Company from time to time may issue warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued are recorded on the basis of their fair value, which is measured as of the date issued. In accordance with the standard, the options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.
Earnings per Share
Basic earnings per share are computed using the weighted average number of common shares outstanding. Diluted earnings per share reflect the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss from continuing operations, basic and diluted loss per share are the same for the years ended December 31, 2011 and 2010 as all potentially dilutive common stock equivalents become anti-dilutive in nature.
Income Taxes
Under the applicable ASC standard, deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the reliability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.
Contingencies
Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.
Volatility of Oil and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.
Off-Balance Sheet Arrangements
For the years ended December 31, 2011 and 2010, we had no off-balance sheet arrangements that were reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is deemed by our management to be material to investors.
Contractual Obligations
The following table summarizes our contractual obligations and commercial commitments as of December 31, 2011:
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.
Volatility of Natural Gas Prices
As an indication of the dramatic way in which the price of natural gas can change, the following table provides the average price per million cubic feet (MCF) of gas which the Company received for the periods indicated:
Volatility of Oil Prices
The following table provides the average price per barrel of oil which the Company received for the periods indicated:
Item 8.
Item 8. Financial Statements and Supplementary Data
The information required by this Item 8 is incorporated by reference to the Index to Consolidated Financial Statements beginning at page of this Annual Report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
On March 18, 2009, our board of directors approved the dismissal of John Kinross-Kennedy (“Mr. Kinross-Kennedy”) as our independent auditor. Mr. Kinross-Kennedy served as our independent auditor for our fiscal years ended December 31, 2007, December 31, 2006, and December 31, 2005. Mr. Kinross-Kennedy was also responsible for the review of our interim financial statements for the quarterly periods ending March 31, 2008, June 30, 2008, and September 30, 2008.
On March 23, 2009, we filed an 8-K with the Commission announcing our dismissal of Mr. Kinross-Kennedy as our independent auditor and disclosing that during the fiscal years ended December 31, 2007, December 31, 2006, and December 31, 2005, and until Mr. Kinross-Kennedy’s termination, there were no disagreements with Mr. Kinross-Kennedy on any matter of accounting principles or practices, financial disclosure, or auditing scope or procedure. Subsequent to Mr. Kinross-Kennedy’s departure from the Company, we endeavored to determine the adequacy of his professional work undertaken for the Company. However, because of the disarray created by the lack of proper financial record-keeping, it was not possible to discover the nature of financial improprieties set in place by Mr. Kinross-Kennedy until an independent audit of the Company’s books and records was undertaken in late 2010. Through this independent audit process, we have now determined that the accounting for the financial statements for the fiscal years ended December 31, 2007, and the interim periods ended March 31, June 30, and September 30, 2008, were not prepared in accordance with GAAP. As a result, we restated our financial statements for the following periods: year ended December 31, 2007 and quarterly periods ended March 31, June 30, and September 30, 2008. In addition, we have filed a lawsuit against Mr. Kinross-Kennedy for professional negligence as disclosed under Item 3.
We, during the last two (2) fiscal years and any subsequent interim period to the date hereof, did not have discussions nor have we consulted with WilsonMorgan LLP regarding the following: (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, and neither a written report or oral advice was provided to us that Wilson concluded was an important factor considered by us in reaching a decision as to the accounting, auditing, or financial reporting issue, or (ii) any matter that was the subject of a disagreement or reportable event as defined in Regulation S-K, Item 304(a)(1)(iv) and Item 304(a)(1)(v), respectively.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Pursuant to Rule 13a-15(e) under the Exchange Act, the Company carried out an evaluation, with the participation of the Company’s management, including the Company’s Chief Executive Officer (“CEO”) (the Company's principal executive officer) and Chief Financial Officer (“CFO”) (the Company’s principal financial and accounting officer), of the effectiveness of the Company’s disclosure controls and procedures (as defined under Rule 13a-15(e) under the Exchange Act) as of December 31, 2011. Based upon that evaluation, our management concluded that our disclosure controls and procedures were not effective at the reasonable assurance level due to the material weaknesses identified and described below.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officer and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States and includes those policies and procedures that:
•Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and any disposition of our assets;
•Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
•Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or a 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 financial statements will not be prevented or detected on a timely basis. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. Based on this assessment, management identified the following two material weaknesses that have caused management to conclude that, as of December 31, 2011, our disclosure controls and procedures, and our internal control over financial reporting, were not effective at the reasonable assurance level:
1.	 We do not have written documentation of our internal control policies and procedures. Written documentation of key internal controls over financial reporting is a requirement of Section 404 of the Sarbanes-Oxley Act as of the year ending December 31, 2011. Management evaluated the impact of our failure to have written documentation of our internal controls and procedures on our assessment of our disclosure controls and procedures and has concluded that the control deficiency that resulted represented a material weakness.
2.	 We do not have sufficient segregation of duties within accounting functions, which is a basic internal control. Due to our size and nature, segregation of all conflicting duties may not always be possible and may not be economically feasible. However, to the extent possible, the initiation of transactions, the custody of assets and the recording of transactions should be performed by separate individuals. Management evaluated the impact of our failure to have segregation of duties on our assessment of our disclosure controls and procedures and has concluded that the control deficiency that resulted represented a material weakness.
To address these material weaknesses, management performed additional analyses and other procedures to ensure that the financial statements included herein fairly present, in all material respects, our financial position, results of operations and cash flows for the periods presented. Accordingly, we believe that the consolidated financial statements included in this report fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented.
This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only our management’s report in this Annual Report.
Management has taken steps to remediate the material weakness over our control over financial reporting and related disclosure controls and procedures by implementing the following controls:
·During February 2011, we engaged a corporate accountant who has significant SEC financial reporting and accounting experience. This individual assisted with the accounting update for the years ending December 31, 2007, 2008, 2009, and 2010, including preparation of the delinquent quarterly Forms 10Q, This individual is also assisting in the preparation of the 2011 quarterly reports for the periods ended March 31, 2011, June 30, 2011, and September 30, 2011., respectively as well as this Form 10K.
·In addition, management changes in 2012 separated the role of the CEO and the CFO.
No change in our system of internal control over financial reporting occurred during the period covered by this report, fourth quarter of the fiscal year ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting
Item 9B.
Item 9B. Other Information
There are no events required to be disclosed by this Item.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Business Experience and Background of Directors and Executive Officers as of December 31, 2011.
There are
Name (1)
Age
Positions Held
Robert J. Miranda
Director, Chairman, CEO, and Chief Financial Officer
Ronald Zamber
Director
Robert Grenley
Director
David McCall
Director, General Counsel (3)
Kenneth Hill
Director, Vice President, Chief Operating Officer (4)
(1)There are no family relationships among our executive officers and directors.
(2)On January 10, 2012, Mr. Miranda stepped down as CFO and Mark Biggers was appointed our Chief Financial Officer. On January 17, 2012, Mr. Miranda stepped down as President and CEO and Kenneth Hill was appointed our Chief Executive Officer. Mr. Miranda remains as our Chairman of the Board and a director.
(3)Mr. McCall was appointed to the Board of Directors on January 20, 2011.
(4)Mr. Hill was appointed Vice President and Chief Operating Officer on January 10, 2011. Mr. Hill was appointed to the Board of Directors on March 28, 2011. On January 17, 2012, Mr. Hill was appointed our Chief Executive Officer.
Robert J. Miranda, CPA - Was appointed as our Chief Financial Officer (CFO) on November 16, 2008. On April 28, 2009, he was appointed Chairman and interim President and CEO upon the resignation of our former President and CEO, Jon Fullenkamp. On March 28, 2011, he was appointed President and CEO. On January 10, 2012, Mr. Miranda stepped down as CFO with the appointment of Mark Biggers to that position. On January 17, 2012, Mr. Miranda stepped down as President and CEO of the company and remains Chairman of the Board and a director.
Since October 2007, Mr. Miranda has been managing director of Miranda & Associates, a professional accountancy corporation. From March 2003 through October 2007, Mr. Miranda was a Global Operations Director at Jefferson Wells, where he specialized in providing Sarbanes-Oxley compliance reviews for public companies. Mr. Miranda was a national director at Deloitte & Touche where he participated in numerous audits, corporate finance transactions, mergers, and acquisitions. Mr. Miranda is a licensed Certified Public Accountant and has over 35 years of experience in accounting, including experience in Sarbanes-Oxley compliance, auditing, business consulting, strategic planning and advisory services. Mr. Miranda holds a B.S. degree in Business Administration from the University of Southern California, a certificate from the Owner/President Management Program from the Harvard Business School and membership in the American Institute of Certified Public Accountants.
Ronald W. Zamber, M.D. Director - Was appointed director on January 24, 2009. Dr. Zamber brings more than 15 years of experience in corporate management and business development extending across public and private companies and non-profit organizations. Since 2000, Dr. Zamber has been president and CEO of The Eye Clinic of Fairbanks (ECF), a private, full service eye care practice based in Fairbanks, Alaska and serving the entire Alaska interior. Dr. Zamber received his bachelor's degree with high honors from the University of Notre Dame and his medical degree with honors from the University of Washington.
Robert Grenley - Was appointed director on June 1, 2010. Since May, 2007, Mr. Grenley is Chief Financial Officer of Ambient, Inc. a subsidiary of IDM Technologies, LLC, and a private company based in Gig Harbor, Washington. From 1996 through April, 2007, Mr. Grenley was President of ID Micro, a private company located in Tacoma, Washington. Mr. Grenley has over 25 years experience in financial management, business development and entrepreneurial experience, including nine years in Radio Frequency Identification (RFID) corporate development and investor relations. Mr. Grenley holds a BA in Economics from Duke University.
David McCall - Was appointed general counsel and director on January 20, 2011. Mr. McCall has over 35 years of experience in the oil and gas industry and has been with the law firm The McCall Firm in Austin, Texas for over five year. Mr. McCall’s law practice has centered on the activities of major and independent oil companies. Mr. McCall received a Bachelor of Arts in marketing from McMurry University, Abilene, Texas in 1971. He graduated from Texas Tech School of Law, Lubbock, Texas in 1974. He is a Member of the Bar, State of Texas; a Life Fellow, Texas Bar Foundation; and a Founding Fellow, Austin Bar Foundation.
Kenneth Hill - Was appointed Vice President and Chief Operating Officer on January 10, 2011 and was appointed director on March 28, 2011. On January 17, 2012, Mr. Hill was elected President and Chief Executive Officer of the Company. Prior to joining the Company, Mr. Hill held positions as Interim CEO, VP of Operations and VP of Investor Relations for the U.S. subsidiary of Austin Exploration Limited, a publicly traded oil and gas company on the Australian Stock Exchange. From 2001 through his tenure at Austin Exploration, Mr. Hill - via his private company Here We Go Again Partners - raised several million dollars of venture capital, personally invested in and consulted for a number of successful entrepreneurial ventures across a variety of industries, including oil and gas. Prior to Here We Go Again Partners, Hill was employed for 16 years at Dell, Inc. (formerly PC Limited and Dell Computer Corporation). As one of the first 20 employees at Dell he served in variety of management positions including manufacturing, sales, marketing, and business development. Prior to joining Dell, Mr. Hill studied Business Management and Business Marketing at Southwest Texas State University (now Texas State University). While at Dell, Mr. Hill continued his education at The University of Texas Graduate School of Business Executive Education program, The Aspen Institute and the Center for Creative Leadership.
Involvement in Certain Legal Proceedings
The foregoing directors or executive officers have not been involved during the last five years in any of the following events:
Bankruptcy petitions filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;
Conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring or suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or
Being found by a court of competition jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.
Board Composition
Our business and affairs are organized under the direction of our board of directors, which currently consists of five (5) members. The primary responsibilities of our board of directors are to provide oversight, strategic guidance, counseling and direction to our management. Our board of directors meets on a regular basis and additionally as required. Written board materials are distributed in advance as a general rule, and our board of directors schedules meetings with and presentations from members of our senior management on a regular basis and as required.
Our board of directors set schedules to meet throughout the year and also can hold special meetings and act by written consent under certain circumstances.
Limitation of Liability and Indemnification
We intend to enter into indemnification agreements with each of our directors and executive officers and certain other key employees. The form of agreement provides that we will indemnify each of our directors, executive officers, and such other key employees against any and all expenses incurred by that director, executive officer or key employee because of his or her status as one of our directors, executive officers or key employees, to the fullest extent permitted by law and our bylaws (except in a proceeding initiated by such person without board approval). In addition, the form agreement provides that, to the fullest extent permitted by law, we will advance all expenses incurred by our directors, executive officers, and such key employees in connection with a legal proceeding.
The Nevada Revised Statutes and our bylaws contain provisions relating to the limitation of liability and indemnification of directors and officers.
Our bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by law, as it now exists or may in the future be amended, against all expenses and liabilities reasonably incurred in connection with their service for or on our behalf. Our bylaws provide that we shall advance the expenses incurred by a director or officer in advance of the final disposition of an action or proceeding. Our bylaws also authorize us to indemnify any of our employees or agents and permit us to secure insurance on behalf of any officer, director, employee or agent for any liability arising out of their action in that capacity, whether or not the law would otherwise permit indemnification.
The Company maintains Directors and Officers insurance on behalf of if officers and directors.
Shareholder Communications
Any shareholder of the Company wishing to communicate to the Board of Directors may do so by sending written communication to the board of directors to the attention of Mr. Kenneth Hill, Chief Executive Officer, at the principal executive offices of the Company. The Board of Directors will consider any such written communication at its next regularly scheduled meeting.
Compliance with Section 16(a) of the Exchange Act:
Under the securities laws of the United States, the Company's directors, its executive officers and any persons holding more than 10% of our common stock are required to report their ownership of our common stock and any changes in that ownership to the Securities and Exchange Commission. Specific due dates for these reports have been established by rules adopted by the SEC and we are required to report in this Annual Report any failure to file by those deadlines.
Based solely upon a review of Forms 3, 4, and 5, and amendments to these forms furnished to us, except as provided below, all parties subject to the reporting requirements of Section 16(a) of the Exchange Act filed on a timely basis all such required reports during and with respect to our 2011 fiscal year.
To the best of our knowledge, the number of late reports for Ron Zamber was 1.
To the best of our knowledge, the number of late reports for Robert Miranda was 1.
To the best of our knowledge, the number of late reports for Robert Grenley was 1.
To the best of our knowledge, the number of late reports for Kenneth Hill was 1.
To the best of our knowledge, the number of late reports for David McCall was 1.
Code of Ethics
We have not adopted a code of ethics to apply to our principal executive officer, principal financial officer, principal accounting officer and controller, or persons performing similar functions. We expect to prepare a Code of Ethics in the near future.
Item 11.
Item 11. Executive Compensation
The following table sets forth the total compensation awarded to, earned by, or paid to our principal executive officers, and our other named executive officers for all services rendered in all capacities to us in 2011, 2010 and 2009.
(1) Appointed CFO on November 16, 2008; director on January 24, 2009; appointed Chairman, President & interim CEO on April 28, 2009; appointed CEO on March 28, 2011.
(2) Resigned as CFO on January 10, 2012 with the appointment of Mark Biggers as CFO effective on that date. Resigned as CEO on January 17, 2012 with the appointment of Kenneth Hill as President and CEO effective that date. Remains as Chairman of the Board.
(3) Represents the portion of the total consulting fees paid to Miranda & Associates, A Professional Accountancy Corporation, that is wholly-owned by Mr. Miranda, in consideration of services, attributable to the services provided by Mr. Miranda as an executive officer of Victory Energy Corporation.
(4) Appointed Vice President and Chief Operating officer on January 10, 2011, director on March28, 2011, appointed CEO on January 17, 2012.
(5) Appointed Vice President, Exploration and Development on January 17, 2011
(6) Jon Fullenkamp resigned effective April 28, 2009.
Director Compensation
The following table sets forth the total compensation awarded to, earned by, or paid to each person who served as a director during the years ended December 31, 2011 and 2010, other than a director who also served as a named executive officer. Our directors who are not executive officers did not receive any cash compensation for serving on our board of directors. We have a policy of reimbursing our directors for their reasonable out-of-pocket expenses incurred in attending Board and committee meetings. Each director is paid for his or her director services in the form of 100,000 warrants granted monthly for each month of service. These five (5) year warrants are exercisable into common stock at an exercise price $0.01, and vest immediately upon issuance.
1)Robert Grenley was appointed on June 1, 2010.
2)David McCall was appointed on January 20, 2011
3)Edgar Trotter resigned effective May 31, 2010
Outstanding Equity Awards at Fiscal Year-End
The following table sets forth certain information concerning outstanding stock awards held by the named executive officers as of December 31, 2011 and 2010.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information concerning the Company’s equity compensation plans as of December 31, 2011.
Security Ownership of Certain Beneficial Owners
Beneficial ownership is determined in accordance with the rules of the SEC, and generally includes voting power and/or investment power with respect to the securities held. Shares of common stock subject to options or warrants currently exercisable or exercisable within 60 days of December 31, 2011 and 2010, are deemed outstanding and beneficially owned by the person holding such options or warrants for purposes of computing the number of shares and percentage beneficially owned by such person, but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person. Except as indicated in the footnotes to these tables, and subject to applicable community property laws, the persons or entities named have sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by them.
The following table sets forth, as of December 31, 2011, certain information with respect to the Company’s equity securities owned or record or beneficially by (i) each officer and director of the Company; (ii) each person who owns beneficially more than 5% of each class of the Company’s outstanding equity securities; and (iii) all directors and executive officer as a group:
The following is the schedule of beneficial ownership as of December 31, 2011:
(1) All warrants are exercisable immediately
(2) Includes 7,500,000 shares issuable upon conversion of 10% Senior Secured Debentures
(3) Based on 382,307,294 shares outstanding.
(4) Includes 2,500,000 shares and 5,242,226 shares exercisable under warrants owned by James Capital Consulting; Ronald Zamber is controlling director and owner of of James Capital Consulting
(5) Includes 4,155,616 shares and 5,500,000 convertible shares owned by the Miranda & Associates 401k plan and 500,000 shares owned by Miranda & Associates, Robert Miranda is the trustee of the Miranda & Associates 401k plan and owner of Miranda & Associates
(6) Includes 7,261,644 shares owned by 1519 Partners LLC; David McCall is the controlling partner and of 1519 Partners LLC; David McCall was appointed as General Counsel and to the Board of Directors on January 20, 2011
(7) Includes 8,291,507 shares owned by Already Done That LLC; Kenneth Hill is the controlling partner and owner of Already Done That LLC; Kenneth Hill was appointed as Vice President and Chief Operating Officer on January 10, 2011; Mr. Hill was appointed to the Board of Directors on March 28, 2011
(8) Stanley Lindsey was appointed Vice President of Exploration and Development on January 7, 2011
There are no classes of stock other than common stock issued or outstanding.
The Company is not aware of any current arrangements which will result in a change in control.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Related Party Transactions
During the year ended December 31, 2011, we incurred a total of $622,819 of accounting, internal audit, CEO and CFO management, tax, and business turnaround consulting fees with Miranda & Associates, A Professional Accountancy Corporation (“Miranda”). Of these fees, $180,000 is attributable to the services of Robert Miranda as an executive officer of the Company pursuant to the consulting services agreement discussed below. The balance of $422,819 is attributable to the Company’s ongoing accounting and SEC filings requirements. A large part of the $422,819 expenditure includes charges attributable to the preparation and filing of the Company’s SEC Form 10K and quarterly 10Q filings for 2008 and 2009 which when filed along with the Company’s Form 10K and quarterly 10Q filings for 2010, brought the Company current on its public filing requirements with the SEC. As of December 31, 2011, Miranda & Associates was owed $90,779 for these professional services.
During 2011, the Company advanced $50,915 to Miranda & Associates at the request of James Capital Energy, LLC which is partner of Aurora Energy Partners. The advance was to pay professional fees otherwise due Miranda & Associate from James Capital Energy LLC and will be offset against future distributions made by Aurora Energy Partners to James Capital Energy, Inc.
During the year ended December 31, 2011, we incurred a total of $256,877 in legal fees with The McCall Firm. David McCall is a partner in The McCall Firm and a director of the Company. The fees are attributable to litigation involving the Company’s oil and gas operations in Texas. As of December 31, 2011, the Company owed The McCall Firm approximately $24,549 for these professional services.
During 2011, we paid Kenneth Hill $12,000 for consulting services to the Company in 2010 prior to his full time employment with the Company.
On January 7, 2011, the Company entered into an Employment Agreement with Kenneth Hill, wherein he agreed to serve as Vice President and Chief Operating Officer of the Company. The term of the agreement began on January 10, 2011, and will end upon notice by either party. Mr. Hill will receive a base annual salary of $180,000 per year and he will participate in the Company’s employee benefit plans made available to its executive officers generally.
During 2011, we paid Stanley Lindsey $12,000 for consulting services to the Company in 2010 prior to his full time employment with the Company.
On January 7, 2011, the Company entered into an Employment Agreement with Stanley Lindsey, wherein he agreed to serve as Vice President of Exploration and Development of the Company. The term of the agreement began on January 10, 2011, and will end upon notice by either party. Mr. Lindsey will receive a base annual salary of $180,000 per year and he will participate in the Company’s employee benefit plans made available to its executive officers generally.
On August 1, 2009, we entered into a consulting services agreement with Miranda & Associates, A Professional Accountancy Corporation. Under the terms of the agreement, Mr. Miranda agreed to serve as our President, Chief Executive Officer, and Chief Financial Officer on an at-will basis. The consulting services agreement has an effective date of August 1, 2009. The agreement replaces a prior agreement for CFO services dated November 16, 2008.
The agreement provides for an initial base retainer of $15,000 per month with an increase to be made quarterly as time and fees are incurred. We have agreed to maintain in effect a directors’ and officers’ liability insurance policy with a minimum limit of liability of $1 million and that we would enter into an indemnification agreement with Mr. Miranda upon terms mutually acceptable to us and Mr. Miranda.
On January 10, 2012, Mr. Miranda stepped down as CFO with the appointment of Mark Biggers to that position. On January 17, 2012, Mr. Miranda stepped down as President and CEO with the appointment of Kenneth Hill to that position. While Mr. Miranda remains as Chairman of the Board, as of January 17, 2012 the parties have effectively terminated the consulting services agreement for interim management services.
Director Independence
We are quoted on the OTC Markets. While the OTC Markets does not maintain director independence standards, we are taking the necessary steps to qualify as having independent directors under the guidelines of FINRA.
Item 14.
Item 14. Principal Accounting Fees and Services
Audit Fees
We did not file when due our Annual Report on Form 10-K for the fiscal years ended December 31, 2007, (restated), 2008, 2009, and 2010, or Quarterly Reports on Forms 10-Q for the respective interim 2008 (restated), 2009 and 2010 periods until March and May, 2011, respectively. Accordingly, the aggregate fees billed for the fiscal year ended December 31, 2011 for professional services rendered by the principal accountant for the audit of our annual financial statements and review of the financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for that fiscal year were higher than would otherwise be expected for a normal year. For the years ending December 31, 2011 and 2010 respectively, we paid $ 135,465 and $0, respectively, in fees to our principal accountants.
Audit - Related Fees
The aggregate fees billed in the fiscal year ended December 31, 2011 and 2010 for professional services rendered by the principal accountant for the review of the financial statements included in our Forms 10-Q for the quarterly periods applicable to these years were included in the audit fees above.
Tax Fees
For the fiscal years ended December 31, 2011 and 2010 our principal accountants did not render any services for tax compliance, tax advice, and tax planning work.
All Other Fees
None.
All fees described above for the years ended December 31, 2011 and 2010, were approved by the entire board of directors.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a)(1) and (2) Financial Statements and Schedules
(a)(3) Exhibits
Refer to (b) below.
(b)
Exhibits
3.1
Articles of Incorporation of All Things, Inc., filed on January 7, 1982 incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.2
Certificate of Amendment of Articles of Incorporation, filed on January 7, 1982 incorporated by reference to Exhibit 3.2 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.3
Certificate of Amendment of Articles of Incorporation, filed on March 21, 1985 incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.4
Certificate of Amendment of Articles of Incorporation, filed on November 1, 1995 incorporated by reference to Exhibit 3.4 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.5
Certificate of Amendment of Articles of Incorporation, filed on April 28, 2003 incorporated by reference to Exhibit 3.5 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.6
Certificate of Amendment of Articles of Incorporation, filed on May 3, 2006 incorporated by reference to Exhibit 3.6 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.7
Certificate of Amendment of Articles of Incorporation, filed on May 10, 2006 incorporated by reference to Exhibit 3.7 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.8
Certificate of Amendment of Articles of Incorporation, filed on August 22, 2006 incorporated by reference to Exhibit 3.8 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.9
Certificate of Amendment of Articles of Incorporation, filed on October 3, 2008 incorporated by reference to Exhibit 3.9 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
3.10
Certificate of Amendment of Articles of Incorporation, filed on November 18, 2011 as part of Form 14C. Attached to this Form 10K as Exhibit 3.10
3.11
Bylaws of Victory Energy Corporation incorporated by reference to Exhibit 3.10 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
10.1
Unsecured Promissory Notes (Zamber) incorporated by reference to Exhibit 10.1 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
10.2 Separation Agreement by and between Victory Energy Corporation and Jon Fullenkamp dated May 15, 2009 incorporated by reference to Exhibit 10.3 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
10.3 The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement by and between Victory Energy Corporation, James Capital Energy, LLC and James Capital Consulting dated December 31, 2009 incorporated by reference to Exhibit 10.2 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
10.4 Settlement Agreement and Mutual General Release by and between Jon Fullenkamp and Xploration, on the one hand; and Victory Energy Corporation, James Capital Energy, LLC, James Capital Consulting, LLC, James Capital, LLC, Aurora Energy Partners, Zamber Energy Investments, LLC, International Vision Quest, Miranda & Associates, Ronald Zamber, Robert Miranda, Richard May, and Tom Konz, on the other hand, incorporated by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
10.5 Consulting Services Agreement by and between Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation dated November 16, 2008 incorporated by reference to Exhibit 10.6 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
10.6 Consulting Services Agreement by and between the Victory Energy Corporation and Miranda & Associates, A Professional Accountancy Corporation, dated August 1, 2009 incorporated by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K filed with the SEC on March 29, 2011.
10.7 First Amendment to The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement, changing the name of the Partnership to “Aurora Energy Partners, A Texas General Partnership”, dated March 31, 2011
10.8 Option Agreement by and among Victory Energy Corporation, Santiago Resources, LP, 1519 Partners, LP, Via Fortuna Minerals, LLC, Wesley G. Ritchie, and Barrier Island Minerals, LLC dated December 20, 2010 incorporated by reference to Exhibit 99.1 of the Company’s Form 8-K filed with the SEC on January 4, 2011.
10.9 Second Amendment to The Victory Energy Corporation/James Capital Energy, LLC, Joint Venture Partnership Agreement, In which the Company agreed with The Navitus Energy Group (“Navitus”), James Capital Consulting, LLC (“JCC”), and James Capital Energy, LLC (“JCE”) to amend certain terms of the Aurora Energy Partners partnership (“Aurora”) and to substitute Navitus, a Texas general partnership composed of JCC, JCE, Rodinia Partners, LLC, and Navitus Partners, LLC, as partner for JCC and JCE in Aurora. The effective date of the Second Amended Partnership Agreement is October 1, 2011. In addition, the Second Amendment effectively increases the Company’s interest in the profits and losses of Aurora from 15% to 50%. The Second Amendment is incorporated by reference to Exhibit 99.1 of the Company’s Form 8-K filed with the SEC on December 9, 2011.
31.1 Rule 13a-14(a)/15d-14(a) Certification of Kenneth Hill
31.2 Rule 13a-14(a)/15d-14(a) Certification of Mark Biggers
32 Section 1350 Certification of Kenneth Hill and Mark Biggers
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: March 30, 2012 By: /s/ Ronald W. Zamber
Ronald W. Zamber
Director
Date: March 30, 2012 By: /s/ Robert Miranda
Robert Miranda
Chairman and Director
Date: March 30, 2012 By: /s/ Robert Grenley
Robert Grenley
Director
Date: March 30, 2012 By: /s/ David B. McCall
David B. McCall
General Counsel and Director
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of
Victory Energy Corporation
Austin, Texas
We have audited the accompanying balance sheets of Victory Energy Corporation (the “Company”) as of December 31, 2011 and 2010, and the related statements of operations, shareholders’ deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2011 and 2010, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming the Company will continue as a going concern. The Company has experienced recurring losses since inception and has an accumulated deficit. These conditions raise substantial doubt regarding the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are described in Note 1 to the financial statements. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.
/s/ WilsonMorgan LLP
Irvine, California
March 30, 2012
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
VICTORY ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
VICTORY ENERGY CORPORATION AND SUBSIDARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' DEFICIT
Victory Energy Corporation and Subsidiaries
Notes to the Consolidated Financial Statements
Note 1 - Financial Statement Presentation
Organization and nature of operations
Victory Energy Corporation (OTCBB symbol VYEY), formerly known as Victory Capital Holdings Corporation (the “Company”) was organized under the laws of the State of Nevada on January 7, 1982, under the name All Things, Inc. On March 21, 1985 the Corporation’s name was changed to New Environmental Technologies Corporation and on April 28, 2003 to Victory Capital Holdings Corporation. The name was changed finally to Victory Energy Corporation on May 3, 2006.
The business of the Company is to acquire, develop, produce and exploit oil and natural gas properties. The Company’s major oil and natural gas properties are located in Texas. The Company’s executive offices are located in Newport Beach, California and its operations offices are located in Austin, Texas.
The Company’s initial authorized capital consisted of 100,000,000 shares of $0.001 par value common voting stock and, as of the date of this filing, has authorized capital of 490,000,000 shares of $0.001 par value common stock.
Going Concern
As presented in the consolidated financial statements, the Company has incurred a net loss of $3,953,697 during the twelve months ended December 31, 2011, and losses are expected to continue in the near term. The accumulated deficit is $36,091,289 at December 31, 2011. The Company has been funding its operations through the sale of senior convertible debentures. Management anticipates that significant additional capital expenditures will be necessary to develop the Company’s oil and natural gas properties, which consist of proved and unproved reserves, some of which may be non-producing, before significant positive operating cash flows will be achieved.
A significant share of losses incurred in 2010 and 2011 are associated with general and administrative expenses involving legal fees related to the prosecution of a malfeasance case against a former drilling contractor and other parties. Costs were also incurred related to the re-filing of financial statements affected by these same irregularities. The Company’s prosecution of third parties for malfeasance was successful and all filings with the SEC are current. The Company has an expanded portfolio of oil and gas properties now and a plan for continued growth. Growth plans will require continued capital infusions beyond earnings from operations. Without additional outside investment from the sale of equity securities or debt financing operating activities and overhead expenses will be reduced to a pace that available operating cash flows will support.
The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if the Company were unable to continue as a going concern.
Note 2 - Summary of Significant Accounting Policies
Principles of consolidation
The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States of America. The consolidated financial statements include the accounts of the Company and Aurora Energy Partners, A Texas General Partnership. The Company holds a 50% equity interest in Aurora Energy Partners. Since the Company serves as managing partner and is responsible for managing all business operations of the partnership, the financial statements of Aurora have been consolidated with the Company. All significant intercompany transactions have been eliminated. The consolidated financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation.
Reclassification
Some balances on the prior’s year’s consolidated financial statements have been reclassified to conform to the current year presentation.
Property and equipment
Property and equipment are recorded at cost. Cost of repairs and maintenance are expensed as they are incurred. Major repairs that extend the useful life of equipment are capitalized and depreciated over the remaining estimated useful life. When property and equipment are sold or otherwise disposed, the related costs and accumulated depreciation are removed from the respective accounts and the gains or losses realized on the disposition are reflected in operations. The Company uses the straight-line method in computing depreciation for financial reporting purposes.
Revenue Recognition
The Company uses the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas and oil sold to purchasers. The volumes sold may differ from the volumes to which the company is entitled based on our interests in the properties. Differences between volumes sold and entitled volumes create oil and gas imbalances which are generally reflected as adjustments to reported proved oil and gas reserves and future cash flows in their supplemental oil and gas disclosures. If their excess takes of natural gas or oil exceed their estimated remaining proved reserves for a property, a natural gas or oil imbalance liability is recorded in the consolidated balance sheet.
Allowance for Doubtful Accounts
The Company recognizes an allowance for doubtful accounts to ensure trade receivables are not overstated due to uncollectability. Bad debt reserves are maintained for all customers based on a variety of factors, including the length of time receivables are past due, macroeconomic conditions, significant one-time events and historical experience. An additional reserve for individual accounts is recorded when they become aware of a customer's inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer's operating results or financial position. If circumstances related to customers change, estimates of the recoverability of receivables would be further adjusted.
Fair Value of Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, other assets, fixed assets, accounts payable, accrued liabilities and short-term debt. The estimated fair value of cash, accounts receivable, other assets, accounts payable and accrued liabilities approximated their carrying amounts due to the short-term nature of these instruments. The carrying value of short-term debt also approximates fair value since their terms are similar to those in the lending market for comparable loans with comparable risks. None of these instruments are held for trading purposes.
The Company utilizes various types of financing to fund its business needs, including debt with warrants attached and other instruments indexed to its stock. The Company reviews its warrants and conversion features of securities issued as to whether they are freestanding or contain an embedded derivative and if so, whether they are classified as a liability at each reporting period until the amount is settled and reclassified into equity with changes in fair value recognized in current earnings.
Inputs used in the valuation to derive fair value are classified based on a fair value hierarchy which distinguishes between assumptions based on market data (observable inputs) and an entity’s own assumptions (unobservable inputs). The hierarchy consists of three levels:
• Level one - Quoted market prices in active markets for identical assets or liabilities;
• Level two - Inputs other than level one inputs that are either directly or indirectly observable; and
• Level three - Unobservable inputs developed using estimates and assumptions, which are developed by the reporting entity and reflect those assumptions that a market participant would use.
Determining which category an asset or liability falls within the hierarchy requires significant judgment. The Company evaluates its hierarchy disclosures each quarter. The following table presents all assets that were measured and recognized at fair value as of December 31, 2011 and 2010, and for the twelve months then ended on a non-recurring basis. The assets shown below were presented at fair value due to the impairment analysis indicating an estimated fair value below the carrying value for the proved oil and gas properties.
Fair value of assets measured and recognized at fair value on a non-recurring basis as of December 31, 2011 and 2010 were as follows:
As of December 31, 2011 and for the year then ended:
As of December 31, 2010 and for the year then ended:
The Company valued the Proved Properties at their fair value in accordance with the applicable Financial Accounting Standards Board (“FASB”) standard due to the impairment indicators prevalent as of December 31, 2011 and 2010. The inputs that were used in determining the fair value of these assets were Level 3 inputs. These inputs consist of but are not limited to the following: estimates of reserve quantities, estimates of future production costs and taxes, estimates of consistent pricing of commodities, 10% discount rate, etc. Impairment expense was recorded at both year ends at the amount the carrying value of the assets exceeded their estimated fair values as of December 31, 2011 and 2010.
Recent Accounting Pronouncements
Recently Issued Accounting Standards
In September 2011, the FASB issued Accounting Standard Update (“ASU”) No. 2011-08, Intangible - Goodwill and Other (Topic 350), Testing Goodwill for Impairment. Under the amendments of this ASU, an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. However, if an entity concludes otherwise, then it is required to perform the first step of the two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit, as described in paragraph 350-20-35-4. If the carrying amount of a reporting unit exceeds its fair value, then the entity is required to perform the second step of the goodwill impairment test to measure the amount of the impairment loss, if any, as described in paragraph 350-20-35-9. Under the amendments in this Update, an entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. An entity may resume performing the qualitative assessment in any subsequent period. This ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company is evaluating the impact of the adoption of this ASU.
In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220), Presentation of Comprehensive Income. Under the amendments of this ASU, an entity has the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In a single continuous statement, the entity is required to present the components of net income and total net income, the components of other comprehensive income and a total for other comprehensive income, along with the total of comprehensive income in that statement. In the two-statement approach, an entity is required to present components of net income and total net income in the statement of net income. The statement of other comprehensive income should immediately follow the statement of net income and include the components of other comprehensive income and a total for other comprehensive income, along with a total for comprehensive income. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company is evaluating the impact of the adoption of this ASU.
In December 2010, the FASB issued ASU No. 2010-13, Compensation-Stock Compensation (Topic 718), Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU provides amendments to Topic 718 to clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This ASU is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010. The adoption of this standard did not have a significant impact on the Company’s financial statements.
In December 2010, the FASB issued ASU No. 2010-28, Intangibles - Goodwill and Other (Topic 350), When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. The ASU modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. As a result, current GAAP will be improved by eliminating an entity’s ability to assert that a reporting unit is not required to perform Step 2 because the carrying amount of the reporting unit is zero or negative despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. As a result, goodwill impairments may be reported sooner than under current practice. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. The adoption of this standard did not have a significant impact on the Company’s financial statements.
In April 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-14, “Accounting for Extractive Activities - Oil & Gas, Amendments to Paragraph 932-10-S99-1” due to SEC Release No. 33-8995 (FR 78), “Modernization of Oil and Gas Reporting”. This amendment was effective January 1, 2010 and has been adopted by the Company in the presentation of the financial statements.
In January 2010, the FASB issued ASU No. 2010-16, “Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements”. ASU 2010-16 will require the reporting entity to 1) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers and 2) present separately information about purchases, sales, issuances, and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), This ASU also clarifies existing disclosures about levels of disaggregation and about inputs and valuation techniques. This ASU is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal periods. The Company has adopted the provisions of the ASU that were effective for reporting periods beginning after December 15, 2009 and it is current assessing the impact of the Level 3 disclosures. This standard did not have a significant impact on the Company’s financial statements.
In January 2010, the FASB issued ASU No. 2010-03, “Extractive Activities - Oil and Gas (Topic 932) - Oil and Gas Reserve Estimation and Disclosures”. The ASU expands and amends certain definition of terms used in the Topic, requires an entity to disclosure separately information about reserve quantities and financial statements amounts for geographic areas that represent 15 percent or more of proved reserves, clarifies that an entity’s equity method investments must be considered in determining whether it has significant oil - and gas- producing activities, required that an entity continue to disclosure separately the amounts and quantities for consolidated and equity method investments and requires that disclosures about equity method investments be in the same level of detail as is required for consolidated investments. Amendments to this Topic are effective to annual reporting periods ending on or after December 31, 2009. This standard did not have a significant impact on the Company’s financial statements.
In October 2009, the FASB issued an amendment to the accounting standards related to the accounting for revenue in arrangements with multiple deliverables including how the arrangement consideration is allocated among delivered and undelivered items of the arrangement. Among the amendments, this standard eliminates the use of the residual method for allocating arrangement consideration and requires an entity to allocate the overall consideration to each deliverable based on an estimated selling price of each individual deliverable in the arrangement in the absence of having vendor-specific objective evidence or other third party evidence of fair value of the undelivered items. This standard also provides further guidance on how to determine a separate unit of accounting in a multiple-deliverable revenue arrangement and expands the disclosure requirements about the judgments made in applying the estimated selling price method and how those judgments affect the timing or amount of revenue recognition. This standard will become effective for the Company on January 1, 2011 and did not have a significant impact on the Company’s financial statements.
In August 2009, the FASB issued an amendment to the accounting standards related to the measurement of liabilities that are recognized or disclosed at fair value on a recurring basis. This standard clarifies how a company should measure the fair value of liabilities and that restrictions preventing the transfer of a liability should not be considered as a factor in the measurement of liabilities within the scope of this standard. This standard was effective for the Company on October 1, 2009. This standard did not have a significant impact on the Company’s financial statements.
Concentrations
There is a ready market for the sale of crude oil and natural gas. During 2011 and 2010, our gas field and our producing wells sold their respective gas and oil production to one purchaser for each field or well. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results
Accounting estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 periods reported. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of proved and unproved properties, future income taxes and related assets and liabilities, the fair value of various common stock, warrants and option transactions, and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the calculation of impairment, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data, the engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.
These significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the fair value of the Company’s common stock and corresponding volatility, and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.
Oil and natural gas properties
The Company accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, all costs associated with property acquisitions, successful exploratory wells, all development wells, including dry hole development wells, and asset retirement obligation assets are capitalized. Additionally, interest is capitalized while wells are being drilled and the underlying property is in development. Costs of exploratory wells are capitalized pending determination of whether each well has resulted in the discovery of proved reserves. Oil and natural gas mineral leasehold costs are capitalized as incurred. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells, and oil and natural gas production costs. Capitalized costs of proved properties including associated salvage are depleted on a well-by-well or field-by-field (common reservoir) basis using the units-of-production method based upon proved producing oil and natural gas reserves. The depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs with gain or loss recognized upon sale. A gain (loss) is recognized to the extent the sales price exceeds or is less than original cost or the carrying value, net of impairment. Oil and natural gas properties are also subject to impairment at the end of each reporting period. Unproved property costs are excluded from depletable costs until the related properties are developed. See impairment discussed in “Long-lived assets and intangible assets” below.
We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.
Long-lived assets and intangible assets
The Company accounts for intangible assets in accordance with the applicable ASC. Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed. Intangible assets are subject to impairment review at least annually or when there is an indication that an asset has been impaired. While there are prospects for possible capital funding (either debt or equity), much is left to the market and outside instability. As such, at this time, management cannot anticipate with a comfortable degree of certainty if the appropriate amount of funding will be achieved and any funding will be diverted fully to its E&P activities. This will further postpone the Company’s ability to dedicate financial as well as human resources to its technology division in the short term future. As such, the Company has eliminated the division entirely.
For unproved property costs, management reviews these investments for impairment on a property-by-property basis if a triggering event should occur that may suggest that impairment may be required.
The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows are discounted at 10%, which the Company believes approximates fair value, to determine the amount of impairment.
The Company recorded $102,579 and $183,473 for 2011 and 2010 respectively, upon determining that the oil and gas projects required impairment.
Asset retirement obligation
In accordance with the applicable ASC, the Company recognizes the fair value of the liability for asset retirement costs in an entity’s balance sheet, as both a liability and an increase in the carrying values of such assets, in the periods in which such liabilities can be reasonably estimated. The present value of the estimated future asset retirement obligation (“ARO”), as of the date of acquisition or the date at which a successful well is drilled, is capitalized as part of the costs of proved oil and natural gas properties and recorded as a liability. The asset retirement costs are depleted over the production life of the oil and natural gas property on a unit-of-production basis.
The ARO is recorded at fair value and accretion expense is recognized as the discounted liability and is accreted to its expected settlement value. The fair value of the ARO liability is measured by using expected future cash outflows discounted at the Company’s credit adjusted risk free interest rate.
Amounts incurred to settle plugging and abandonment obligations that are either less than or greater than amounts accrued are recorded as a gain or loss in current operations. Revisions to previous estimates, such as the estimated cost to plug a well or the estimated future economic life of a well, may require adjustments to the ARO and are capitalized as part of the costs of proved oil and natural gas property.
The following table is a reconciliation of the ARO liability for continuing operations for the twelve months ended December 31, 2011 and 2010.
Income taxes
The Company accounts for income taxes in accordance with ASC 740 “Income Taxes” which requires an asset and liability approach for financial accounting and reporting of income taxes. Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. Deferred tax assets include tax loss and credit carry forwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
On January 1, 2007, the Company adopted the Financial Accounting Standards Board (“FASB”) Interpretation on accounting for uncertainty in income taxes. The interpretation prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, the interpretation provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company will classify any interest and penalties associated with income taxes as interest expense.
Stock based compensation
Beginning January 1, 2006, the Company adopted the FASB standard for accounting for stock based compensation to account for its issuance of options and warrants to key partners, directors and officers. The standard requires all share-based payments, including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of options and warrants granted to key partners, directors and officers is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of the Company’s stock price. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.
The Company from time to time may issue stock options, warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued are recorded on the basis of their fair value, which is measured as of the date issued. The options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for options and warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.
The Company recognized stock-based directors fee and service incentive fee compensation expense from warrants granted to directors for the year ended December 31, 2011 and 2010 of $312,000 and $14,070, respectively.
The Company recognized stock-based officer compensation expense from stock options granted to officers of the company for the twelve months ended December 31, 2011 and 2010 of $152,700 and $0 respectively.
Earnings per share
Basic earnings per share are computed using the weighted average number of common shares outstanding. Diluted earnings per share reflect the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss from continuing operations during the twelve months ended December 31, 2011 and 2010, basic and diluted net loss per share are the same as all potentially dilutive common stock equivalents are anti-dilutive.
Note 3 - Oil and natural gas properties
Oil and natural gas properties are comprised of the following:
Depletion expense for the years ended December 31, 2011 and 2010 was $73,816 and $99,932, respectively. During the years ended December 31, 2011 and 2010, the Company recorded impairment losses of $73,816 and $183,472 respectively.
Note 4 - Unsecured notes payable to related parties
Unsecured notes payable to related parties were as follows:
Note 5 - Line of credit payable to Wells Fargo Bank
On October 7, 2008, the Company executed an unsecured Business Line of Credit Agreement with Wells Fargo Bank, National Association. The Credit Agreement provides the Company with a line of credit facility in the aggregate amount of $96,761. Interest on the loan is payable monthly, at the rate of 10.0% per annum. The line of credit was personally guaranteed by the Company’s former CEO and shareholder.
During the three months ended December 31, 2010, the Company defaulted on its monthly loan payments to Wells Fargo Bank and the loan was referred to the Wells Fargo Bank’s workout department. The balance outstanding, including accrued interest was $68,667 as of December 31, 2010. The Company negotiated an informal repayment program with the Wells Fargo Bank’s workout department whereby the Wells Fargo Bank did not institute collection actions provided the Company made monthly principal payments of $2,200 to Wells Fargo Bank. The note was settled for cash on August 4, 2011.
Note 6 - Separation Settlement Payable to former officer and shareholder
On May 15, 2009, the Company entered into a “Separation Agreement and General Release of Claims” with Jon Fullenkamp (“Fullenkamp”) and the Virgin Family Trust. The terms of the Agreement include (a) termination of an employment agreement between the Company and Fullenkamp; (b) payment of all accrued salaries, unreimbursed expenses, and shareholder advances previously made by Fullenkamp; (c) reduction of shareholder advances from estimated balance owed at the time of settlement of $1,665,375 to a balance of $500,000 (the “Separation Settlement”); (d) Payment terms of the Separation Settlement of $10,000 monthly commencing June 1, 2009, and payable over a fifty (50) month period, including imputed interest at the rate of 3.52% per annum; (e) cancellation of 2,000,000 shares of preferred stock, convertible at the rate of 100 shares of common, (d) lockup agreement with respect to all shares owned directly or indirectly by Fullenkamp for a period of five years, (e) Fullenkamp was to cooperate with the Company to recover misappropriated funds and agreed to bring litigation or induce others to bring litigation against the Company.
At the time of the agreement, Fullenkamp was owed the sum of approximately $1,665,375 in shareholder advances which were settled for $500,000, resulting in a gain on the settlement of this debt of $1,199,748. After the first payment of $10,000 the company recorded a discount of 3.25% on $490,000, the minimum federal rate in the amount of $34,373 against the note. The discount is amortized to interest expense over the period of estimated maturity. During the year ended December 31, 2009, the Company recorded interest expense of $8,997 and the note had an unamortized discount of $24,476. During the year ended December 31, 2009, the Company paid $51,004 of the principal of the Separation Settlement, reducing the outstanding balance as of December 31, 2009 to $404,623.
During the year ended December 31, 2009, Fullenkamp filed a lawsuit against the Company. The Company subsequently filed a lawsuit against Fullenkamp and others on January 19, 2010, in Midland County, Texas.
On March 24, 2011 the Company, James Capital Energy, LLC and other related parties entered into a comprehensive Settlement Agreement with Jon Fullenkamp. Under the Settlement Agreement, Victory agreed to i) dismiss Jon Fullenkamp from the Texas lawsuit with prejudice, ii) provide him with a general release from all acts related thereto, and iii) pay him $30,000 over 70 days. In turn, Jon Fullenkamp agreed to i) dismiss with prejudice the lawsuit he filed against the Company and others in California; ii) transfer to Victory 2,000,000 shares of Victory preferred stock for cancellation; iii) transfer to Victory 400,000 warrants for Victory common stock; iv) transfer to James Capital Energy, LLC 16,144,563 shares of Victory common stock; v) voluntarily appear for his deposition to discuss events that occurred at the Adams-Baggett Ranch; vi) waive the claim he had to the $430,000 severance payment under the May 15, 2009 Separation Agreement; and vii) provide Victory James Capital Energy, LLC and other related parties with a general release.
Note 7 - Senior Secured Convertible Debentures
Between October 15, 2010 and December 31, 2011, the Company entered into agreements with 56 accredited investors for the cash sale by the Company of an aggregate of $3,395,000 of 10% Senior Secured Convertible Debentures (the “Debentures”) which are convertible into an aggregate of 679,000,000 shares of the Company’s common stock at a conversion price of $0.005 per share of common stock, subject to adjustment. .
The maturity date of the Debentures is September 30, 2013, but may be extended at the sole discretion of the Company to December 31, 2013. The Debentures are immediately convertible by the holder into shares of the Company’s common stock at a conversion price of $0.005 per share, subject to customary adjustments for stock splits, stock dividends, recapitalizations and the like. The Company has the right to force conversion of the Debenture if, among other things, the closing sales price of the Company’s common stock is equal to or exceeds $0.025 for twenty (20) consecutive trading days. In connection with this offering, the Company also issued five (5) year warrants to purchase an aggregate of 3,395,000 shares of the Company’s common stock at an exercise price of $0.005 per share, subject to adjustment, to the investors. There are no registration rights for the converted shares
The cash proceeds of $3,395,000 were allocated to working capital. The Debentures are secured under the terms of a Security Agreement by a security interest in all of the Company’s personal property. The relative fair value of the warrants and beneficial conversion features of the debentures were determined at the time of issuance using the methodology prescribed by current accounting guidance.
On December 31, 2010, the Company exchanged notes payable of $497,000 and accrued interest of $55,275 both due to a related party for $552,275 of the Company’s 10% Senior Secured Convertible Debenture.
With each issuance, the Company determined the fair value of the appropriate beneficial conversion feature and the warrants issued using the Black-Scholes option pricing model assuming a 5 year life, and appropriate risk free rate, the appropriate volatility rate and a dividend rate of zero. The following table summarizes these data.
The senior secured convertible debentures consist of the following at December 31:
Amortization of debt discount totaled $714,788 and $811 for the years ended December 31, 2011 and 2010, respectively.
Note 8 - Liability for Unauthorized Preferred Stock Issued
During the year ended December 31, 2006, the Company authorized 10,000,000 shares of Preferred Stock, convertible to common stock at the rate of 100 shares of common for every share of preferred. During 2006, the Company issued 715,517 shares of this preferred stock for cash of $246,950. The Company subsequently issued additional preferred stock and had several preferred shareholders converted their shares into common stock during the years ended December 31, 2009, 2008, and 2007.
During the course of the Company’s internal investigation, it was determined by the Company’s legal counsel that the preferred shares had not been duly authorized by the State of Nevada. Since the Company had issued and received consideration for the preferred stock, notwithstanding that the stock was not legally authorized, the Company reclassified the preferred stock into a liability and does not present preferred stock in the equity section of the balance sheet. The Company has offered to settle the debt with the remaining holders of the unauthorized preferred stock by honoring the terms of conversion of one share of preferred into 100 shares of common stock. The Company intends to cancel the preferred stock once all remaining preferred stockholders have converted.
On April 25, 2011, 155,000 shares of the Companies preferred stock held by three affiliates of the Company were converted to 15,500,015 shares of the Company’s common stock in accordance with the terms on which such preferred stock has been converted.
There were 238,966 and 393,966 shares of unconverted preferred stock outstanding at December 31, 2011 and 2010, respectively.
The remaining liability for the unconverted preferred stock is based on the original cash tendered and consisted of the following as of:
Note 9 - Income Taxes
The provision for (benefit of) income taxes for the years ended December 31, 2011 and 2010 consists of the following:
The Internal Revenue Code of 1986, as amended, imposes substantial restrictions on the utilization of net operating losses in the event of an “ownership change” of a corporation. Accordingly, a company’s ability to use net operating losses may be limited as prescribed under Internal Revenue Code Section 382 (“IRC Section 382”). Events which may cause limitations in the amount of the net operating losses that the company may use in any one year include, but are not limited to, a cumulative ownership change of more than 50% over a three-year period. There have been transactions that have changed the Company’s ownership structure since inception that may have resulted in one or more ownership changes as defined by the Internal Revenue Code of 1986.
At December 31, 2011 and 2010, the Company had available Federal and state net operating loss and capital loss carry forwards to reduce future taxable income. The net operating loss carryovers available were approximately $13,130,000 and $2,896,000 at December 31, 2011 and 2010, respectively. The Federal net operating loss carry forward begins to expire in 2025. Capital loss carryovers may only be used to offset capital gains. The last of the capital loss carryover available was $50,900 and expired in 2010.
Given the Company’s history of net operating losses, management has determined that it is more-likely-than-not the Company will not be able to realize the tax benefit of the carry forwards. Current standards require that a valuation allowance be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.
Accordingly, the Company has recorded a full valuation allowance against its net deferred tax assets at December 31, 2011 and 2010. Upon the attainment of taxable income by the Company, management will assess the likelihood of realizing the tax benefit associated with the use of the carry forwards and will recognize a deferred tax asset at that time. For the years ended December 31, 2011 and 2010, the valuation allowance increased by $620,600 and $35,500, respectively.
Significant components of the Company’s deferred income tax assets are as follows:
Reconciliation of the effective income tax rate to the U.S. statutory rate is as follows:
The Company adopted authoritative guidance in accordance with GAAP which addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the current accounting guidelines, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. Current accounting guidelines also provide guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and require increased disclosures. At the date of adoption, and as of December 31, 2010 and 2009 the Company does not have a liability for unrecognized tax benefits.
Note 10 - Stockholders’ Equity
For the year ended December 31, 2011
Common stock
On June 30, 2011, $1,112,500 of the 10% Senior Secured Convertible Debentures plus accrued interest of $37,928 were converted to 230,087,670 shares of common stock.
During 2011, the Company granted 3,120,000 warrants to purchase the Company’s common stock with an exercise price of $0.005 per share as part of the Company’s 10% Senior Secured Convertible Debentures. These warrants expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $77,765.
During 2011, the Company granted 5,700,000 warrants to purchase the Company’s common stock with an exercise price of $0.01 per share to the Company’s Board of Directors in connection with the services rendered. These warrants expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $179,700.
During 2011, the Company granted 9,000,000 non-qualified stock options to purchase the Company’s common stock with an exercise price ranging from $0.01 to $.02 per share to the officers of the Company as part of their compensation. These options expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $243,000.
During 2011, the Company granted 1,500,000 warrants with an exercise price of $.01 and 3,000,000 warrants with an exercise price of $.02 to purchase the Company’s common stock to David McCall upon his assumption of the additional responsibilities as general counsel of the Company. These warrants expire in four and six years respectively from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $132,200.
For the year ended December 31, 2010
Common stock
No common stock was issued, converted, or retired in 2010.
During 2010, the Company granted 3,875,000 warrants to purchase the Company’s common stock with an exercise price ranging from $0.005 to $.01 per share to the Company’s Board of Directors in connection with the services rendered. These warrants expire in five years from the date of grant. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $14,070.
Note 11 - Warrants for Stock
At December 31, 2011, warrants outstanding for common stock of the Company were as follows:
At December 31, 2010, warrants outstanding for common stock of the Company were as follows:
The following table summarizes information about warrants for common stock of the Company outstanding and exercisable as of December 31, 2011:
The following table summarizes information about from the common stock of the Company outstanding and exercisable as of December 31, 2010:
All future changes in the fair value of these warrants will be recognized currently in earnings until such time as the warrants are exercised or expire. These common stock purchase warrants do not trade in an active securities market, and as such, we estimate the fair value of these warrants using the Black-Scholes option pricing model using the following assumptions:
Expected volatility is based primarily on historical volatility. Historical volatility was computed using weekly pricing observations for recent periods that correspond to the remaining life of the warrants. We believe this method produces an estimate that is representative of our expectations of future volatility over the expected term of these warrants. We currently have no reason to believe future volatility over the expected remaining life of these warrants is likely to differ materially from historical volatility. The expected life is based on the remaining term of the warrants. The risk-free interest rate is based on U.S. Treasury securities.
At December 31, 2011 and 2010 the aggregate intrinsic value of the warrants outstanding and exercisable was $417,060 and $17,668, respectively. The intrinsic value of a warrant is the amount by which the market value of the underlying warrant exercise price exceeds the market price of the stock December 31 of each year.
Note 12 - Stock Options
The following table summarizes stock option activity in the Company’s stock-based compensation plans for the year ended December 31, 2011. All options issued were non-qualified stock options. There were no stock options outstanding in the year ended December 31, 2010.
(1)The intrinsic value of a stock option is the amount by which the market value of the underlying stock exceeds the exercise price of the option at December 31, 2011. If the exercise price exceeds the market value, there is no intrinsic value.
The fair value of the stock option grants are amortized over the respective vesting period using the straight-line method and assuming no forfeitures and cancelations. The Company has no historical experience to estimate forfeitures and cancellations.
Compensation expense related to stock options included in Exploration Expense and General and Administrative Expense in the accompanying consolidated statement of operations for the year ended December 31, 2011, was $108,000. The estimated unrecognized compensation cost from unvested options as of December 31, 2011 was approximately $135,000, which is expected to be recognized over an average period of 1.7 years.
Stock options are granted at the fair market value of one share of common stock on the date of grant. Options granted to officers and other employees vest immediately or over 24 months as provided in the option at the date of grant.
The fair value of each option granted in 2011 was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair value of options granted during the periods presented.
The following table summarizes information about options outstanding at December 31, 2011.
At December 31, 2011, there were 5,000,000 unvested options outstanding with a weighted average exercise price of $.02 and an intrinsic value of $65,000. All unvested options will vest over the next 17 months.
Note 14 - Commitments and Contingencies
Leases
Rent expense for the years ended December 31, 2011 and 2010 was $17,600 and $23,095, respectively. The Company is committed for $22,750 through January 31, 2012, on an operating lease for office space in Austin, Texas.
Litigation
Cause No. 08-04-07047-CV; Oz Gas Corporation v. Remuda Operating Company, et al. v. Victory Energy Corporation.; In the 112th District Court of Crockett County, Texas.
This is a lawsuit wherein Plaintiff Oz Gas Corporation sued various parties for bad faith trespass, among other claims regarding two wells that Oz claims were drilled on lands they have superior title to. Oz Gas agreed to keep Remuda Operating Company as the operator of the wells involved in the lawsuit so long as all the monies are paid into the Registry of the Court, which is currently being done. Victory Energy Corporation has a 50% interest in one of the named wells involved in this lawsuit (that being well 155-2 on the Adams Baggett Ranch in Crockett County, Texas). The lawsuit was originally filed around April 2008, but Victory Energy Corporation was not a party until it learned of this lawsuit and filed a Plea in Intervention on November 18, 2009.
Plaintiff Oz alleges a claim of bad faith trespass by Victory and other parties who drilled the wells. Victory merely purchased an interest in the well, and Victory takes the position that they had superior title when they purchased their interest in the well, and that they are not a bad faith trespasser.
This case was mediated, with no settlement reached. It went to trial February 8-9, 2012. Victory contested the allegations made in this lawsuit and argued that Oz did not have superior title, nor that Oz has more than a 40% interest in well 155-2 (Oz claims to own 100% interest in the well). When Oz purchased the lands and wells on the Adams Baggett Ranch, some of the leases had expired. In order to cure this defect, Oz obtained a revivor and ratification from two of three parties who held the interest. There is still an unleased interest owner of these lands. The Court found in favor of Oz on certain claims, but has not made all if its rulings on the entire case. A hearing in this case is currently set for April 17, 2012. Depending on the final rulings of the Court, Victory will appeal any findings of bad faith trespass, conversion, and punitive damages. We are confident of a positive outcome in the Court of Appeals as the rulings that have been made and could be made are contrary to current State law and evidence of Oz’s lack of superior title was presented and proven by Victory at the trial court level.
Cause No. CV-47,230; James Capital Energy, LLC and Victory Energy Corporation v. Jim Dial, et al.; In the 142nd District Court of Midland County, Texas.
This is a lawsuit filed on or about January 19, 2010 by James Capital Energy, LLC and Victory Energy Corporation against numerous parties for fraud, fraudulent inducement, negligent misrepresentation, breach of contract, breach of fiduciary duty, trespass, conversion and a few other related causes of action. This lawsuit stems from an investment both James Capital and Victory entered into for the purchase of six wells on the Adams Baggett Ranch with the right of first refusal on option acreage.
On December 9, 2010, Victory was granted an interlocutory Default Judgment against Defendants Jim Dial, 1st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Grifco International, Inc., and Precision Drilling & Exploration, Inc. The total judgment amounted to approximately seventeen million, one-hundred eighty-three thousand, nine-hundred eighty-seven dollars and eight cents ($17,183,987.08).
Recently Victory and James Capital have added a few more parties to this lawsuit. Discovery is ongoing in this case and no trial date has been set at this time.
Victory and James Capital believe that they will be victorious against all the remaining Defendants in this case.
On October 20, 2011 Defendant Remuda filed a Motion to Consolidate and a Counterclaim against Victory. Remuda is seeking to consolidate this case with two other cases wherein Remuda is the named Defendant. An objection to this motion was filed and the cases have not been consolidated. Additionally, we do not believe that the counterclaim made by Remuda has any legal merit.
Cause No. 10-09-07213; Perry Howell, et al. v. Charles Gary Garlitz, et al.; In the 112th District Court of Crockett County, Texas.
The above referenced lawsuit was filed on or about September 6, 2010. This lawsuit alleges that Cambrian Management, Ltd. and Victory were trespassers on their land, and that they, along with other Defendants, drilled a well (115 #8) on land belonging to Plaintiffs. Plaintiffs claim trespass and unjust enrichment by certain Defendants because of the drilling of the 115 #8 well.
Discovery is ongoing in this case and there has not been a trial date set at this time. Victory and Cambrian are in the process of having some title work done on this piece of property so they can decide which direction to go with this case.
If Victory and Cambrian are not victorious in this case, they will be out their initial investment monies paid for the drilling of this well.
Note 15 - Related Party Transactions
During 2010, the Company entered into unsecured notes payable totaling $302,000 with Visionary Investments, LLC. (“Visionary”). Ronald Zamber, a director and major stockholder of the Company, is the sole member of Visionary. These notes bear interest at a fixed rate of 10% and mature on December 31, 2010.
On December 31, 2010, the Company entered into a Loan Extension Agreement with Visionary to convert various unsecured promissory notes held by Visionary (the “Notes”) into a 10% Senior Secured Convertible Debenture (the “Debenture”).
The Notes have a total principal amount of $497,000 and have accumulated interest in the amount of $55,275. In consideration of the loan extension, the Notes and all accumulated interest were cancelled and the Company issued the Debenture to Visionary with a total face value of $552,275. The Debenture bears interest at the rate of 10% per year payable at maturity. The maturity date of the Debenture is September 30, 2013, but may be extended at the sole discretion of the Company to December 31, 2013. The Debenture is immediately convertible by the holder into shares of the Company’s common stock at a conversion price of $0.005 per share, subject to customary adjustments for stock splits, stock dividends, recapitalizations and the like. The Company has the right to force conversion of the Debenture if, among other things, the closing sales price of the Company’s common stock is equal to or exceeds $0.025 for twenty (20) consecutive trading days. The total number of shares of common stock issuable upon conversion of the Debenture is 110,455,000.
During the year ended December 31, 2011, we incurred a total of $549,471 of accounting, internal audit, CEO & CFO management, and tax, and business turnaround consulting fees with Miranda & Associates, A Professional Accountancy Corporation (“Miranda”). Of these fees, $180,000 is attributable to the services of Robert Miranda as an executive officer of the Company. The balance of approximately $120,500 is related to the work done on the Company’s SEC filings for 2007 through 2010 with the remaining balance of 248,971 going for internal audit, tax, and advisory services provided by other members of the Miranda firm. As of December 31, 2011, Miranda & Associates was owed $66,230 for these professional services. Mr. Miranda also receives warrants for services as a director of the Company.
During the year ended December 31, 2011, we incurred a total of $210,332 in legal fees with The McCall Firm primarily for work in relation to the trespass law suits and other lawsuits related to the recovery of the malfeasance losses in 2008 and 009. In November, 2011, David McCall, a principal in the The McCall Firm was appointed general counsel of the Company and was given a total of 4,500,000 warrants representing a value of approximately $132,200 based on Black-Scholes analysis as a result. As of December 31, 2011, The McCall Firm was owed $24,549 for these processional services. Mr. McCall also receives warrants for services as a director of the Company.
Note 16 - Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)
The following disclosures provide unaudited information required by the FASB standard on oil and gas producing activities.
Results of operations from oil and natural gas producing activities
The Company’s oil and natural gas properties are located within the United States. The Company currently has no operations in foreign jurisdictions. Results of operations from oil and natural gas producing activities are summarized below for the years ended December 31:
Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years ended December 31:
Oil and natural gas reserves
Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.
Proved oil and natural gas reserve quantities at December 31, 2011 and 2010, and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. The reserves as of December 31, 2011 were derived from reserve estimates prepared by the independent reserve engineer; James Nicolson. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. In 2009 the SEC issued guidance requiring oil and gas companies to calculate the value of proved reserves using prices that were calculated as the average price of the first day of the twelve months in the year. This guidance differed from the previous standard of valuing prices according to the end of year prices. The guidance does not require that prior year information be revised for the new method. As a result, this change in methods of pricing should be taken into account while reviewing the comparable information for 2011 and 2010 within this disclosure.
Standardized measure
The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves for the years ended December 31, 2011 and 2010 are shown below:
The average quarterly product prices for natural gas revenue for 2011 and 2010 ranged from $5.73/MCF to $8.91/MCF. The average quarterly product price for oil revenue for 2011 ranged from $87.3 to $95.30 per bbl (barrel). In neither year was the Company allowed to value assets attributable to Proved Undeveloped or Probable Reserves because of the SEC guidelines requiring available capital to monetize the projects.
Future income taxes are based on year-end statutory rates, adjusted for tax basis of oil and natural gas properties and availability of applicable tax assets, such as net operating losses. A discount factor of 10% was used to reflect the timing of future net cash flows.
The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value may also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and may require a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Changes in standardized measure
Included within standardized measure are reserves purchased in place. The purchase of reserves in place includes undeveloped reserves which were acquired at minimal value that have been estimated by independent reserve engineers to be recoverable through existing wells utilizing equipment and operating methods available to the Company and that are expected to be developed in the near term based on an approved plan of development contingent on available capital.
Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31 is summarized below:
Note 17 - Subsequent Events
Reverse Stock Split
On January 12, 2012, the Financial Industry Regulatory Authority approved the Reverse Stock Split and the Amended and Restated Articles became effective at 7:00 a.m., Eastern Daylight Time, on January 13, 2012. Pursuant to and upon the effectiveness of the Amended and Restated Articles, each 50 shares of common stock of the Company issued and outstanding at the time of such effectiveness were combined into one share of common stock of the Company and the total number of shares of common stock outstanding was reduced from approximately 490,000,000 shares to approximately 9,800,000 shares.
Change of Officers
On January 10, 2012, Mark Biggers became Chief Financial Officer of the Company. As part of his compensation, Mr. Biggers will receive a five year option to purchase 1,500,000 shares of the Company’s common stock at an exercise price of $0.01 and an additional option to purchase 3,000,000 shares of the Company’s common stock, vesting monthly at the rate of 125,000 shares per month, at an exercise price of $0.02 per share, such additional options expiring at the end of the calendar year 2017.
On January 17, 2012, Kenneth Hill, Vice President, Chief Operating Officer, and a Director of the Company was elected President and Chief Executive Officer.
Conversion of Debentures to Common Stock
On March 6, 2012, the Company announced that all the outstanding 10% Convertible Secured Debentures and accrued interest thereon had been converted to common stock as of February 29, 2012